<PAGE> 1
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
[X] Quarterly Report Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
For the quarterly period ended September 30, 1998
or
[ ] Transition Report Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
For the transition period from _____ to _____
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 Identification No.)
organization)
NationsBank, N.A.
901 Main Street, Suite 1700
Dallas, Texas 75202
(Address of principal executive offices)
(Zip code)
(214) 508-2304
(Registrant's telephone number, including area code)
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 [ ]
Number of units of beneficial interest outstanding at October 23,
1998: 8,800,000
<PAGE> 2
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements.
The condensed financial statements included herein have been
prepared by NationsBank, N.A., as successor to NationsBank of Texas, N.A., as
Trustee (the "Trustee") of Burlington Resources Coal Seam Gas Royalty Trust (the
"Trust"), pursuant to the rules and regulations of the Securities and Exchange
Commission. Certain information and footnote disclosures normally included in
annual financial statements have been condensed or omitted pursuant to such
rules and regulations, although the Trustee believes that the disclosures are
adequate to make the information presented not misleading. The condensed
financial statements of the Trust presented herein are unaudited, except for
balances as of December 31, 1997, and therefore are subject to year-end
adjustments. It is suggested that these condensed financial statements be read
in conjunction with the financial statements and notes thereto in the Trust's
Annual Report on Form 10-K for the year ended December 31, 1997. The December
31, 1997 balance sheet is derived from the audited balance sheet of that date.
In the opinion of the Trustee, all adjustments necessary to present fairly the
assets, liabilities and trust corpus of the Trust as of September 30, 1998, the
distributable income for the three month and nine month periods ended September
30, 1998 and 1997 and the changes in trust corpus for the nine month periods
ended September 30, 1998 and 1997, have been included. The distributable income
for such interim periods is not necessarily indicative of the distributable
income for the full year.
The condensed financial statements as of September 30, 1998 and for
the three month and nine month periods ended September 30, 1998 and 1997,
included herein, have been reviewed by Deloitte & Touche LLP, independent
certified public accountants, as stated in their report appearing herein.
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Independent Accountants' Report
NationsBank, N.A.,
as Trustee of Burlington Resources
Coal Seam Gas Royalty Trust
We have reviewed the accompanying condensed statement of assets, liabilities and
trust corpus of the Burlington Resources Coal Seam Gas Royalty Trust as of
September 30, 1998, and the related condensed statements of distributable income
for the three month and nine month periods ended September 30, 1998 and 1997 and
changes in trust corpus for the nine month periods ended September 30, 1998 and
1997. These condensed financial statements are the responsibility of the
Trustee.
We conducted our review in accordance with standards established by the American
Institute of Certified Public Accountants. A review of interim financial
information consists principally of applying analytical procedures to financial
data and of making inquiries of persons responsible for financial and accounting
matters. It is substantially less in scope than an audit conducted in accordance
with generally accepted auditing standards, the objective of which is the
expression of an opinion regarding the financial statements taken as a whole.
Accordingly, we do not express such an opinion.
As described in Note 2 to the condensed financial statements, these condensed
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.
Based on our review, we are not aware of any material modifications that should
be made to such condensed financial statements for them to be in conformity with
the basis of accounting described in Note 2.
We have previously audited, in accordance with generally accepted auditing
standards, the statement of assets, liabilities and trust corpus of Burlington
Resources Coal Seam Gas Royalty Trust as of December 31, 1997, and the related
statements of distributable income and changes in trust corpus for the year then
ended (not presented herein); and in our report dated March 27, 1998, we
expressed an unqualified opinion on those financial statements. In our opinion,
the information set forth in the accompanying condensed statement of assets,
liabilities and trust corpus as of December 31, 1997, is fairly stated, in all
material respects, in relation to the statement of assets, liabilities and trust
corpus from which it has been derived.
/s/ Deloitte & Touche LLP
Dallas, Texas
November 6, 1998
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BURLINGTON RESOURCES COAL SEAM GAS ROYALTY TRUST
CONDENSED STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
<TABLE>
<CAPTION>
September 30, December 31,
1998 1997
----------- -----------
(unaudited)
<S> <C> <C>
ASSETS
Cash and cash equivalents $ 55,626 $ 50,819
Royalty interests in gas
properties (less accumulated
amortization of $100,947,315
at September 30, 1998 and $86,861,742
at December 31, 1997) 79,452,685 93,538,258
----------- -----------
TOTAL ASSETS $79,508,311 $93,589,077
=========== ===========
LIABILITIES AND TRUST CORPUS
Trust expenses payable $ 106,352 $ 104,149
Trust corpus -
8,800,000 units of beneficial
interest authorized, issued and
outstanding 79,401,959 93,484,928
----------- -----------
TOTAL LIABILITIES
AND TRUST CORPUS $79,508,311 $93,589,077
=========== ===========
</TABLE>
The accompanying notes are an integral part of these
condensed financial statements.
4
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BURLINGTON RESOURCES COAL SEAM GAS ROYALTY TRUST
CONDENSED STATEMENTS OF DISTRIBUTABLE INCOME (UNAUDITED)
<TABLE>
<CAPTION>
FOR FOR
THE THREE THE THREE
MONTHS ENDED MONTHS ENDED
September 30, 1998 September 30, 1997
------------------ ------------------
<S> <C> <C>
Royalty income $ 2,026,429 $ 1,987,036
Interest income 5,488 5,237
------------ ------------
2,031,917 1,992,273
General and administrative
expenses (122,856) (120,391)
------------ ------------
Distributable income $ 1,909,061 $ 1,871,882
============ ============
Distributable income per
unit (8,800,000 units) $ .22 $ .21
============ ============
</TABLE>
The accompanying notes are an integral part of these
condensed financial statements.
5
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BURLINGTON RESOURCES COAL SEAM GAS ROYALTY TRUST
CONDENSED STATEMENTS OF DISTRIBUTABLE INCOME (UNAUDITED)
<TABLE>
<CAPTION>
FOR FOR
THE NINE THE NINE
MONTHS ENDED MONTHS ENDED
September 30, 1998 September 30, 1997
------------------ ------------------
<S> <C> <C>
Royalty income $ 5,479,285 $ 5,077,755
Interest income 15,686 12,826
--------------- ---------------
5,494,971 5,090,581
General and administrative
expenses (531,129) (538,911)
--------------- ---------------
Distributable income $ 4,963,842 $ 4,551,670
=============== ===============
Distributable income per
unit (8,800,000 units) $ .56 $ .52
=============== ===============
</TABLE>
The accompanying notes are an integral part of these
condensed financial statements.
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BURLINGTON RESOURCES COAL SEAM GAS ROYALTY TRUST
CONDENSED STATEMENTS OF CHANGES IN TRUST CORPUS (UNAUDITED)
<TABLE>
<CAPTION>
FOR FOR
THE NINE THE NINE
MONTHS ENDED MONTHS ENDED
September 30, 1998 September 30, 1997
--------------- ---------------
<S> <C> <C>
Trust corpus, beginning
of period $ 93,484,928 $ 107,328,165
Amortization of royalty
interest (14,085,573) (11,737,658)
Distributable income 4,963,842 4,551,670
Distributions to
unitholders (4,961,238) (4,527,269)
--------------- ---------------
Trust corpus, end
of period $ 79,401,959 $ 95,614,908
=============== ===============
Distributions per unit
(8,800,000 units) $ .56 $ .51
=============== ===============
</TABLE>
The accompanying notes are an integral part of these
condensed financial statements.
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BURLINGTON RESOURCES COAL SEAM GAS ROYALTY TRUST
NOTES TO CONDENSED FINANCIAL STATEMENTS (UNAUDITED)
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 (the "Trustee"), and Mellon Bank (DE) National
Association, a national banking association (the "Delaware Trustee"), as
trustees. The trustees are independent financial institutions. Effective January
1, 1996, Meridian Oil Production Inc. ("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
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, with regard to the period prior to the date of such name changes,
references in this Form 10-Q to BROG refer to MOPI, references to BRTI refer to
MOTI and references to BRGI refer to MOGI.
The Trust is a grantor trust formed to acquire and hold certain net
profits interests (the "Royalty Interests") in BROG's interest in the Fruitland
coal formation underlying the Northeast Blanco Unit in the San Juan Basin of New
Mexico (the "Underlying Properties"). The Trust was initially created by the
filing of a Certificate of Trust with the Secretary of State of Delaware on May
5, 1993. In accordance with the Trust Agreement, 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 sold such Units to the public at $20.50 per Unit 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 BROG's interest in the Underlying Properties are expected to
decline substantially during the term of the Trust and a portion of each cash
distribution made by the Trust will, therefore, be analogous to a return of
capital. Accordingly, cash yields attributable to the Units are expected to
decline over the term of the Trust.
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The Trustee has all powers to collect and distribute proceeds received
by the Trust and to pay Trust liabilities and expenses. The Delaware Trustee has
only such powers as are set forth in the Trust Agreement or are required by law
and is not empowered to otherwise manage or take part in the business of the
Trust. The Royalty Interests are passive in nature and neither the Delaware
Trustee nor the Trustee has any control over or any responsibility relating to
the operation of the Underlying Properties or BROG's interest therein.
The Trust will terminate no later than December 31, 2012, subject to
earlier termination under certain circumstances described in the Trust Agreement
(the "Termination Date"). Cancellation of the Trust will occur on or following
the Termination Date when all Trust assets have been sold and the net proceeds
thereof are distributed to the holders of the Units ("Unitholders").
As reported in the Trust's Current Report on Form 8-K filed September
25, 1998 (the "Form 8-K") with the Securities and Exchange Commission ("SEC"),
on September 17, 1998, San Juan Partners L.L.C. and certain affiliated parties
including EnCap Energy Capital Fund III, L.P., EnCap Energy Capital Fund III-B,
Inc., ECIC Corporation, EnCap Energy Partners, L.P., First Union Investors,
Inc., Andover Group, Inc., Charles T. McCord III, O'Sullivan Oil & Gas Company,
Inc., Christopher P. Scully, Scott W. Smith Funding, L.L.C., and John V. Whiting
(collectively, "San Juan"), filed an Amendment No. 22 (the "San Juan Amendment")
to the Schedule 13D filed by San Juan with the SEC on January 20, 1998 with
respect to San Juan's ownership of Units.
As stated in the San Juan Amendment, San Juan's purpose in acquiring
its Units is to pursue the termination of the Trust, resulting in a liquidation
of the Trust's assets and a distribution of available proceeds therefrom to the
holders of Units ("Unitholders"). Because termination of the Trust requires the
affirmative vote in favor of termination by the holders of at least 66 2/3% of
the outstanding Units, San Juan indicated in the San Juan Amendment that it
might seek to obtain the requisite vote by (i) acquiring additional Units or
(ii) seeking consents from a limited number of other Unitholders, such that San
Juan will own or have the right to vote at least 66 2/3% of the outstanding
Units. Since the date of the Amendment, San Juan has acquired through a series
of open market transactions additional Units resulting in aggregate holdings, as
disclosed in an Amendment No. 25 to San Juan's 13D filed by San Juan with the
SEC on October 6, 1998, of 5,867,968 Units, constituting approximately 66.68% of
the total number of Units issued and outstanding as of such date.
As described in the San Juan Amendment, pursuant to the terms of the
Trust Agreement, filed as Exhibit 4.1 to the Registrant's Quarterly Report on
Form 10-Q for the quarter ended June 30, 1993, and described in the Form 10-K
under "Item 1 - Description of the Trust Termination and Liquidation," the Trust
may terminate prior to January 1, 2003, only upon the affirmative vote in favor
of termination of the trust by the holders of at least 66 2/3% of the
outstanding Units. Pursuant to the Trust Agreement, a meeting of the Unitholders
may be called by the holders of at least 10% of the then outstanding Units. The
Trust is required to provide
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Unitholders written notice of any such meeting no less than 20 nor more than 60
days in advance thereof. At such meeting, if the holders of at least 66 2/3% of
the Units vote in favor of terminating the Trust, the Trustee will commence the
liquidation process, and the Trust will continue until all of the assets of the
Trust are liquidated and the Trust's affairs are wound up.
On October 29, 1998, the Trustee received written notice from San Juan
that San Juan was taking action to call a meeting of Unitholders for the purpose
of voting on a proposal by San Juan to terminate the Trust and certain related
matters. According to the San Juan Amendment, San Juan intends to vote any and
all Units it owns or over which it has voting control in favor of termination of
the Trust at such meeting. Assuming San Juan does in fact so vote such Units,
the termination and wind up of the Trust pursuant to the terms and provisions of
the Trust Agreement will occur.
The only assets of the Trust, other than cash and cash equivalents
being held for the payment of expenses and liabilities and for distribution to
Unitholders, are the Royalty Interests. The Royalty Interests consist primarily
of a net profits interest (the "NPI") in BROG's interest in the Underlying
Properties. The NPI generally entitles the Trust to receive 95 percent of the
NPI Net Proceeds, as defined below. The Royalty Interests also include a 20
percent interest in the Infill Net Proceeds, as defined below, from the sale of
production if well spacing rules are effectively modified and additional wells
are drilled on producing drilling blocks in the Northeast Blanco Unit ("Infill
Wells") during the term of the Trust. With respect to the NPI, the term "NPI Net
Proceeds" generally means the aggregate proceeds attributable to BROG's net
revenue interest in the Underlying Properties (excluding the proceeds, if any,
from Infill Wells) calculated at the price paid by 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 BROG's interest in the
Underlying Properties less BROG'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 BROG's net revenue interest calculated at the
price paid by BRTI at the Central Gathering Point for the entitled volume of gas
produced and sold from BROG's interest in any Infill Wells less BROG'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. The definitions, formulas and
accounting procedures and other terms governing the computation of the Royalty
Interests are set forth in the Conveyance.
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Because of the passive nature of the Trust and the restrictions and
limitations on the powers and activities of the Trustee contained in the Trust
Agreement, the Trustee does not consider any of the officers and employees of
the Trustee to be "officers" or "executive officers" of the Trust as such terms
are defined under the applicable rules and regulations adopted under the
Securities Exchange Act of 1934.
2. BASIS OF ACCOUNTING
The financial statements of the Trust are prepared on a modified cash
basis and are not intended to present financial position and results of
operations in conformity with generally accepted accounting principles ("GAAP").
Preparation of the Trust's financial statements on such basis includes the
following:
- - Royalty income and interest income are recorded in the period in which
amounts are received by the Trust rather than in the months of
production.
- - General and administrative expenses recorded are based on liabilities
paid and cash reserves established out of cash received.
- - Amortization of the Royalty Interests is calculated on a
unit-of-production basis and charged directly to trust corpus when
revenues are received.
- - Distributions to Unitholders are recorded when declared by the Trustee
(see Note 4).
The financial statements of the Trust differ from financial statements
prepared in accordance with GAAP because royalty income is not accrued in the
period of production, general and administrative expenses recorded are based on
liabilities paid and cash reserves established rather than on an accrual basis,
and amortization of the Royalty Interests is not charged against operating
results.
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 unescalated product prices plus the estimated future Section 29
credits for federal income tax purposes. If the net cost of royalty interests in
gas properties exceed the aggregate of these amounts, an impairment provision is
recorded and charged to the trust corpus.
3. FEDERAL INCOME TAXES
The Trust is a grantor trust for Federal income tax purposes. As a
grantor trust, the Trust will not be required to pay Federal or state income
taxes. Accordingly, no provision for income taxes has been made in these
condensed financial statements.
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Because the Trust will be treated as a grantor trust, and because a
Unitholder will be treated as directly owning an interest in the Royalty
Interests, each Unitholder will be taxed directly on his per Unit share of
income attributable to the Royalty Interests consistent with the Unitholder's
method of accounting and without regard to the taxable year or accounting method
employed by the Trust.
Production from coal seam gas wells drilled after December 31, 1979 and
prior to January 1, 1993, qualifies 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. The Trustee is provided Section 29 tax credit information related to
Trust Properties by BROG. In 1997, the Tax Court upheld the IRS position that
nonconventional fuel such as coal seam gas does not qualify for the Section 29
credit unless the producer received a formal certification from the Federal
Energy Regulatory Commission (FERC). The FERC's certification authority expired
effective January 1, 1993. Many producers believe that wells meeting the
certification requirements are eligible for the Section 29 credit regardless of
FERC certification. However, this position is not in accordance with the IRS
position or the decision of the Tax Court. The court decision is on appeal and
it is not possible to predict the likely outcome. In the event the appeal is not
successful, the ability of the Trust to realize the carrying value of its
reserves and the ability of the Unitholders to utilize allocated Section 29
credits could be in question with respect to any uncertificated wells. However,
the Trustee has been advised by BROG that certification of the wells producing
from the Underlying Properties has been received. Each Unitholder should consult
his tax advisor regarding Trust tax compliance matters.
4. DISTRIBUTIONS TO UNITHOLDERS
The Trustee determines for each quarter the amount of cash available
for distribution to Unitholders. Such amount (the "Quarterly Distribution
Amount") is an amount equal to the excess, if any, of the cash received by the
Trust, on or before the last business day before the 50th day following the end
of each calendar quarter from the Royalty Interests attributable to production
during such quarter, plus, with certain exceptions, any other cash receipts of
the Trust during such quarter, over the liabilities of the Trust paid during
such quarter, subject to adjustments for changes made by the Trustee during such
quarter in any cash reserves established for the payment of contingent or future
obligations of the Trust.
The Quarterly Distribution Amount for each quarter is payable to
Unitholders of record on the 63rd day following the end of such calendar quarter
unless such day is not a business day in which case the record date is the next
business day thereafter. The Trustee distributes the Quarterly Distribution
Amount on or prior to the 75th day after the end of each calendar quarter
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to each person who was a Unitholder of record on the associated record date,
together with interest estimated to be earned on such amount from the date of
receipt thereof by the Trustee to the payment date.
The Royalty Interests may be sold under certain circumstances and will
be sold following termination of the Trust. A special distribution will be made
of undistributed net sales proceeds and other amounts received by the Trust
aggregating in excess of $10,000,000 (a "Special Distribution Amount"). The
record date for a Special Distribution Amount will be the 15th day following
receipt of amounts aggregating a Special Distribution Amount by the Trust
(unless such day is not a business day in which case the record date will be the
next business day thereafter) unless such day is within 10 days prior to the
record date for a Quarterly Distribution Amount in which case the record date
will be the date as is established for the next Quarterly Distribution Amount.
Distribution to Unitholders of a Special Distribution Amount will be made no
later than 15 days after the Special Distribution Amount record date. (See Note
1 regarding the discussion of the proposed liquidation of the Trust.)
5. CONTINGENCIES
Production attributable to BROG's interest in the Underlying Properties
is generally sold pursuant to a gas purchase contract between BROG and BRTI. The
gas purchase contract provides certain protections for BRTI in the form of price
credits and for Unitholders when the applicable Blanco Hub Spot Price falls
below $1.65 per MMBtu and provides certain benefits for BRIT when the Blanco Hub
Spot Price exceeds $2.10 per MMBtu. The gas purchase contract also provides that
the price paid for gas by BRTI is reduced by the amount of gathering and/or
transportation charges, taxes, treating and processing costs and all other costs
payable in connection with such services from the central gathering point to
main line delivery paid by BRTI.
The Blanco Hub Spot Price was above $1.65 per MMBtu during 1997 except
for March and April of 1997, and was also above such price throughout the first,
second and third quarters of 1998 except for the month of September. The price
remained above $1.65 per MMBtu for October 1998. Historically, the Blanco Hub
Spot Price has periodically been below $1.65 per MMBtu, however, pursuant to the
terms of the gas purchase contract, in those months in which such price was
below $1.65 per MMBtu, BRTI continued to purchase gas attributable to BROG'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 BROG for each MMBtu of natural
gas so purchased by BRTI equal to the difference between the $1.60 per MMBtu
purchase price and the applicable index price (which price is equal to 97
percent of the applicable Blanco Hub Spot Price). With the Blanco Hub Spot Price
above $1.65 per MMBtu during April, May and June 1998, royalty income otherwise
receivable by the Trust during the third quarter of 1998 was reduced due to
partial recoupment of the aggregate price credits. Approximately $632,000 of
price credits were recouped by BRTI due to the higher Blanco Hub Spot Prices in
April, May and June of 1998. BRTI estimates that as of
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<PAGE> 14
June 30, 1998, BRTI had aggregate price credits of approximately $4.3
million of which the Trust's 95 percent interest was approximately $4.1 million.
The entitlement of BRTI to recoup the price credits means that if and
when the applicable Blanco Hub Spot Price is above $1.65 per MMBtu, future
royalty income paid to the Trust will be reduced until such time as all accrued
and unrecouped price credits have been recovered by BRTI. As was the case in the
third quarter of 1998, reduced royalty income correspondingly reduces cash
distributions to Unitholders.
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Item 2. Trustee's Discussion and Analysis of Financial Condition and Results
of Operations
The Trust makes quarterly cash distributions to holders of units of
beneficial interest ("Units") in the Trust ("Unitholders"). The only assets of
the Trust, other than cash and cash equivalents being held for the payment of
expenses and liabilities and for distribution to Unitholders, are certain net
profits interests (the "Royalty Interests") in certain proved coal seam gas
properties located in the Fruitland coal formation underlying the Northeast
Blanco Unit in the San Juan Basin of New Mexico (the "Underlying Properties").
The Royalty Interests owned by the Trust burden the net revenue interest in the
Underlying Properties that is owned by Burlington Resources Oil & Gas Company
("BROG") and not the Trust. Effective January 1, 1996, Meridian Oil Production
Inc. ("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 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, with regard to the
period prior to the date of such name changes, references in this Form 10-Q to
BROG refer to MOPI, references to BRTI refer to MOTI and references to BRGI
refer to MOGI.
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 (as defined in Note 1 to the
condensed financial statements of the Trust appearing elsewhere in this Form
10-Q ("Note 1")) until its subsequent distribution to Unitholders.
The amount of distributable income of the Trust for any quarter may
differ from the amount of cash available for distribution to Unitholders in such
quarter due to differences in the treatment of the expenses of the Trust in the
determination of those amounts. The condensed 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 quarter is
determined by deducting from the income received by the Trust the amount of
expenses paid by the Trust during such quarter. The amount of cash available for
distribution to Unitholders, however, is determined in accordance with the
provisions of the Trust Agreement and reflects the income actually received by
the Trust less the amount of expenses actually paid by the Trust and adjustment
for changes in reserves for unpaid liabilities. See Note 4 to the condensed
financial statements of the Trust appearing elsewhere in this Form 10-Q for
additional information regarding the determination of the amount of cash
available for distribution to Unitholders.
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Three Months and Nine Months Ended September 30, 1998 Compared to Three Months
and Nine Months Ended September 30, 1997
Royalty income received by the Trust in a given calendar quarter
generally consists of 95% of the NPI Net Proceeds (as defined in Note 1) during
the preceding calendar quarter. Royalty income for the third quarter of 1998
amounted to $2,026,429 as compared to $1,987,036 for the same quarter in 1997.
For the nine months ended September 30, 1998, royalty income received by the
Trust amounted to $5,479,285 as compared to $5,077,755 received for the same
period in 1997. Gas production related to the royalty income received by the
Trust in the third quarter of 1998 was 3.2 Bcf compared to 2.5 Bcf for the same
quarter in 1997. The higher gas production in the third quarter of 1998 as
compared to the same period in 1997 is largely the result of capital
improvements made during 1997 which in turn were slightly offset by the natural
decline of production from the coal seam formation. In addition, the increase in
royalty income to the Trust in the third quarter of 1998 as compared to the same
period in 1997 reflects the aforementioned increase in production and a small
increase in the net price received for gas produced. The average net price for
gas after consideration of costs in the third quarter of 1998 was $1.08/MMBtu
compared to $1.03/MMBtu in the third quarter of 1997.
Costs deducted to determine the net proceeds received include
production taxes, which are calculated on gross proceeds, operating costs and
certain capital costs. Production tax fluctuations are in correlation to changes
in royalty proceeds and operating costs and have remained relatively stable.
During the quarter ended September 30, 1998, approximately $370,000 was charged
against the gross proceeds of the Trust relating to the installation of low
pressure separators, the recavitation of wells and other improvements. Capital
costs of this nature are allowed under the Conveyance Agreement.
Interest income for the quarter ended September 30, 1998 was $5,488 as
compared to $5,237 for the same quarter in 1997. Interest income for the nine
months ended September 30, 1998 was $15,686 as compared to $12,826 for the same
period for 1997. These increases are due to increased funds available for
investment as a result of increased royalty income as discussed above. General
and administrative expenses, which did not vary significantly from the periods
presented, are primarily related to administrative services provided to the
Trust. The general and administrative expenses during the quarter ended
September 30, 1998 amounted to $122,856 compared to $120,391 for the same
quarter in 1997. General and administrative expenses for the nine month period
ended September 30, 1998 were $531,129 as compared to $538,911 for the same
period for 1997.
Distributable income for the quarter ended September 30, 1998 was
$1,909,061 or $.22 per Unit compared to $1,871,882 or $.21 per Unit for the
third quarter of 1997. Distributable income for the nine month period ended
September 30, 1998 was $4,963,842 as compared to $4,551,670 for the same period
for 1997. The Trust made a distribution on September 11, 1998 of $.210220 per
Unit to Unitholders of record on September 1, 1998.
16
<PAGE> 17
Royalty income to the Trust is attributable to the sale of depleting
assets. All of the Underlying Properties burdened by the NPI consist of
producing properties. Accordingly, the proved reserves attributable to BROG's
interest in the Underlying Properties are expected to decline substantially
during the term of the Trust and a portion of each cash distribution made by the
Trust will, therefore, be analogous to a return of capital. Accordingly, cash
yields attributable to the Units are expected to decline over the term of the
Trust.
Royalty income received by the Trust in a given calendar quarter will
generally reflect the proceeds from the sale of gas produced from the Underlying
Properties during the preceding quarter. Accordingly, the royalty income
included in distributable income for the quarter ended September 30, 1998 was
based on production volumes and natural gas prices for the period April 1, 1998
through June 30, 1998 in accordance with the terms of the conveyance of the
Royalty Interests to the Trust, as shown in the table below. The production
volumes included in the table below are actual net production volumes from
BROG's interest in the Underlying Properties, and not for production
attributable to the Trust's Royalty Interests.
<TABLE>
<CAPTION>
For the For the
Three Months Three Months
Ended Ended
June 30, 1998 June 30, 1997
------------- -------------
<S> <C> <C>
Production (Bcf)(1).................... 3.317 2.603
Production (Trillion Btu)(2)........... 2.906 2.344
Average Inside FERC Price
($/MMBtu)(3)................... $ 1.94 $ 1.82
BROG Average Entitled Price
Received ($/MMBtu)(4).......... $ 1.08 $ 1.14
</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.
Production attributable to BROG's interest in the Underlying Properties
is generally sold pursuant to a gas purchase contract between BROG and BRTI. The
gas purchase contract provides certain protections for BRTI in the form of price
credits and for Unitholders when the applicable Blanco Hub Spot Price falls
below $1.65 per MMBtu and provides certain benefits for BRTI when the Blanco Hub
Spot Price exceeds $2.10 per MMBtu. The gas purchase contract also provides that
the price paid for gas by BRTI is reduced by the amount of gathering and/or
transportation charges, taxes, treating and processing costs and all other costs
payable in connection with such services from the central gathering point to
main line delivery paid by BRTI.
17
<PAGE> 18
The Blanco Hub Spot Price was above $1.65 per MMBtu during 1997 except
for March and April of 1997, and was also above such price throughout the first,
second and third quarters of 1998 except for the month of September. The price
remained above $1.65 per MMBtu for October 1998. Historically, the Blanco Hub
Spot Price has periodically been below $1.65 per MMBtu, however, pursuant to the
terms of the gas purchase contract, in those months in which such price was
below $1.65 per MMBtu, BRTI continued to purchase gas attributable to BROG'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 BROG for each MMBtu of natural
gas so purchased by BRTI equal to the difference between the $1.60 per MMBtu
purchase price and the applicable index price (which price is equal to 97
percent of the applicable Blanco Hub Spot Price). With the Blanco Hub Spot Price
above $1.65 per MMBtu during April, May and June of 1998, royalty income
otherwise receivable by the Trust during the third quarter of 1998 was reduced
due to partial recoupment of the aggregate price credits. Approximately $632,000
of price credits were recouped by BRTI due to the higher Blanco Hub Spot Prices
in April, May and June of 1998. BRTI estimates that as of June 30, 1998,
BRTI had aggregate price credits of approximately $4.3 million of which the
Trust's 95 percent interest was approximately $4.1 million.
The entitlement of BRTI to recoup the price credits means that if and
when the applicable Blanco Hub Spot Price is above $1.65 per MMBtu, future
royalty income paid to the Trust will be reduced until such time as all accrued
and unrecouped price credits have been recovered by BRTI. As was the case in the
third quarter of 1998, reduced royalty income correspondingly reduces cash
distributions to Unitholders.
The information in this Form 10-Q concerning production and prices
relating to BROG's interest in the Underlying Properties is based on information
prepared and furnished by BROG to the Trustee. The Trustee has no control over
and no responsibility relating to the operation of the Underlying Properties.
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. The Trustee has
identified the General Ledger/Accounts Payable System as its primary system that
is vulnerable to the Year 2000 issue. The Trust selected a system that has been
warranted to be Year 2000 compliant and completed the installation of the new
system at the beginning of 1998. The cost of the system was approximately
$6,000. To date the Trustee has incurred no other costs in connection with its
efforts to identify, assess, remediate and test the Trust's systems for Year
2000 compliance.
18
<PAGE> 19
The Trustee is in the process of identifying and assessing other
information technology ("IT") systems used in connection with the Trust as well
as other systems, for Year 2000 compliance. Non-IT systems are generally more
difficult to assess because they often contain embedded technology that may be
subject to Year 2000 problems. The total cost of the Trustee's Year 2000 efforts
is expected to be approximately $10,000 (including the $6,000 referred to
above), all of which will be incurred and paid during the last quarter of 1998
and the first quarter of 1999. Of this amount, the Trustee expects to pay $4,000
for identification and assessment of affected systems.
The Trustee has additionally identified those vendors it believes could
have an impact on its day-to-day operations if their operations were interrupted
as a result of Year 2000 problems. The Trustee has developed a questionnaire
regarding the vendor's Year 2000 status. These vendors, consisting primarily of
BROG and NationsBank, N.A., will be contacted before January 1, 1999 to
determine their Year 2000 status.
The Trustee has no reason to believe that its vendors will not be Year
2000 compliant. In the event the Trustee learns that a vendor's system will not
be Year 2000 compliant, the Trustee will assess the potential risk and develop
contingency plans at that time.
The Trust is a passive entity with no business operations, and the IT
systems employed by the Trustee in connection with its duties on behalf of the
Trust are less extensive than the systems employed by many business entities.
The Trust has no formal IT budget, and the Trustee does not anticipate making
any other significant expenditures relating to the Trustee's IT systems used in
connection with Trust during 1998 or 1999. Thus, the expenditures expected to be
made in connection with the Year 2000 efforts described above will represent
substantially all of the Trustee's IT-related expenditures on behalf of the
Trust during 1998 and 1999. These expenses will be expensed within the financial
statements of the Trust.
Because the royalty interests held by the Trust are fixed, the Trustee
is dependent upon the third parties (primarily BROG and NationsBank, N.A.) that
hold operating interests with respect thereto for the receipt of royalty income.
Thus, if any such third party failed to deliver royalty income, the Trustee
would have available no alternative source for such income. The Trustee believes
that the worst case scenario would be the failure by the Trustee and one or more
third parties who pay royalties to the Trust to identify or remediate Year 2000
problems on a timely basis, which could cause the Trustee to be unable to make
required distributions to Unitholders. Such inability could result in the
incurrence by the Trust of interest charges or other liabilities to Unitholders.
The Trustee believes that in the event of a failure of any of its internal
systems it would be able to replace such systems in a relatively short period of
time, relying on internal resources of NationsBank, N.A., which serves as the
Trustee, although there can be no assurance that such replacement would not be
costly or that it would be completed without resulting in a significant delay in
the distributions to Unitholders. With respect to a failure by a third party to
deliver royalty income on a timely basis, the Trustee believes that it would
have no control over
19
<PAGE> 20
the efforts of such third party to correct the problems, and significant delays
in the receipt of royalty income could result.
The Trust will utilize both internal and external resources to achieve
Year 2000 compliance. The Trustee estimates that its identification and
assessment activities are approximately 80% complete. It expects that all of its
Year 2000 efforts related to the Trust's internal systems will be completed by
the end of the first quarter of 1999. However, there can be no guarantee that
the Trustee will be able to identify all potential Year 2000 problems or to
fully remediate all Year 2000 problems identified on a timely basis. There also
can be no assurance that the systems of third party vendors on which the Trust
relies will be timely remediated. The failure by the Trustee or any such third
party to fully remediate its Year 2000 problems on a timely basis could have a
material adverse affect on the Trustee's ability to account for and make timely
distribution of the Trust's distributable income.
Certain of the statements made above regarding the Trustee's Year 2000
program are forward-looking statements, and there can be no assurance that the
Trustee will be able to achieve Year 2000 compliance in the manner and by the
dates indicated.
Forward-Looking Statements
This report on Form 10-Q includes "forward-looking statements" within
the meaning of Section 27A of the Securities Act of 1933, as amended, and
Section 21E of the Securities Exchange Act of 1934, as amended. All statements
other than statements of historical fact included in this Form 10-Q, including,
without limitation, statements contained in this "Trustee's Discussion and
Analysis of Financial Condition and Results of Operations" regarding the Trust's
financial position and industry conditions, are forward-looking statements.
Although the Trustee believes that the expectations reflected in such
forward-looking statements are reasonable, it can give no assurance that such
expectations will prove to have been correct.
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
Not applicable.
20
<PAGE> 21
PART II - OTHER INFORMATION
Item 5. Other Information.
Expected Unitholder Proposal to Terminate the Trust
As reported in the Trust's Current Report on Form 8-K filed September
25, 1998 (the "Form 8-K") with the Securities and Exchange Commission ("SEC"),
on September 17, 1998, San Juan Partners L.L.C. and certain affiliated parties
including EnCap Energy Capital Fund III, L.P., EnCap Energy Capital Fund III-B,
Inc., ECIC Corporation, EnCap Energy Partners, L.P., First Union Investors,
Inc., Andover Group, Inc., Charles T. McCord III, O'Sullivan Oil & Gas Company,
Inc., Christopher P. Scully, Scott W. Smith Funding, L.L.C., and John V.
Whiting, (collectively "San Juan") filed an Amendment No. 22 (the "San Juan
Amendment") to the Schedule 13D filed by San Juan with the SEC on January 20,
1998 with respect to San Juan's ownership of Units.
As previously reported in the Trust's Annual Report on Form 10-K for
the year ending December 31, 1997 (the "Form 10-K") under "Item 12-- Security
Ownership of Certain Beneficial Owners and Management" and in the Trust's
Quarterly Report on Form 10-Q for the quarter ending March 31, 1998 under "Item
5-- Other Matters", on January 20, 1998, San Juan initiated a tender offer to
purchase exactly (and not less than) 5,446,860 of the Units. San Juan failed to
receive tender acceptances for the minimum number of Units required by the
tender offer, and consequently the tender offer expired according to its terms
on February 17, 1998. Following the expiration of the tender offer and through
the date of the Amendment, San Juan had acquired through a series of open market
and privately negotiated transactions additional Units resulting in aggregate
holdings, as disclosed in the San Juan Amendment, as of September 17, 1998, of
5,331,468 Units, constituting approximately 60.58% of the total number of Units
issued and outstanding.
As stated in the San Juan Amendment, San Juan's purpose in acquiring
its Units is to pursue the termination of the Trust, resulting in a liquidation
of the Trust's assets and a distribution of available proceeds therefrom to the
holders of Units ("Unitholders"). Because, as described below, termination of
the Trust requires the affirmative vote in favor of termination by the holders
of at least 66 2/3% of the outstanding Units, San Juan indicated in the San Juan
Amendment that it might seek to obtain the requisite vote by (i) acquiring
additional Units or (ii) seeking consents from a limited number of other
Unitholders, such that San Juan will own or have the right to vote at least
66 2/3% of the outstanding Units. Since the date of the Amendment, San Juan has
acquired through a series of open market transactions additional Units resulting
in aggregate holdings, as disclosed in an Amendment No. 25 to San Juan's 13D
filed by San Juan with the SEC on October 6, 1998, of 5,867,968 Units,
constituting approximately 66.68% of the total number of Units issued and
outstanding as of such date.
21
<PAGE> 22
As described in the San Juan Amendment, pursuant to the terms of the
Trust Agreement, filed as Exhibit 4.1 to the Registrant's Quarterly Report on
Form 10-Q for the quarter ended June 30, 1993, and described in the Form 10-K
under "Item 1 -- Description of the Trust Termination and Liquidation", the
Trust may terminate prior to January 1, 2003, only upon the affirmative vote in
favor of termination of the trust by the holders of at least 66 2/3% of the
outstanding Units. Pursuant to the Trust Agreement, a meeting of the Unitholders
may be called by the holders of at least 10% of the then outstanding Units. The
Trust is required to provide Unitholders written notice of any such meeting no
less than 20 nor more than 60 days in advance thereof. At such meeting, if the
holders of at least 66 2/3% of the Units vote in favor of terminating the Trust,
the Trustee will commence the liquidation process, and the Trust will continue
until all of the assets of the Trust are liquidated and the Trust's affairs are
wound up.
On October 29, 1998, the Trustee received written notice from San Juan
that San Juan was taking action to call a meeting of Unitholders for the purpose
of voting on a proposal by San Juan to terminate the Trust and certain related
matters. According to the San Juan Amendment, San Juan intends to vote any and
all Units it owns or over which it has voting control in favor of termination of
the Trust at such meeting. Assuming San Juan does in fact so vote such Units,
the termination and wind up of the Trust pursuant to the terms and provisions of
the Trust Agreement will occur.
Also as described in the Form 8-K, the San Juan Amendment states that a
letter of intent (the "Letter of Intent") was entered into on September 17,
1998, by and among San Juan and BROG. As described in the Amendment, the Letter
of Intent contemplates the entry by San Juan and BROG into a definitive
agreement whereby San Juan would purchase from BROG (i) certain interests of
BROG in and to the Fruitland coal formation in the Northeast Blanco Hub Unit,
including, without limitation, certain interests in leases covering lands
burdened by the Trust's Net Profits Interest (as defined in the Form 10-K) to
the Trust (the "Trust Interest"), (ii) certain other interests in other leases
covering lands in the Northeast Blanco Hub Unit (the "Non-Trust Interest") and
(iii) associated rights and obligations of BROG and its affiliates in the Trust,
including all of Burlington Resources duties, obligations and rights under and
pursuant to the Trust Agreement. Among the rights under the Trust Agreement
which would be assigned to San Juan pursuant to the Letter of Intent are BROG's
preferential rights to purchase the remaining Royalty Interests in the event of
the termination and liquidation of the Trust, including the right to submit an
initial bid on the Trust assets to the Trustee and the right to either match or
top the highest bid received for the Trust assets in the liquidation process.
These rights are set forth in Sections 9.03(c) and (e) of the Trust Agreement
and described in the Form 10-K under "Item 1 -- Description of the Trust
Termination and Liquidation."
According to the San Juan Amendment, the consummation of the
transactions contemplated by the Letter of Intent will occur only after the
termination of the Trust pursuant to an affirmative vote of Unitholders
satisfying the requirements of Sections 9.02 and 9.03 of the Trust Agreement,
and is subject to various other conditions.
As disclosed by an Amendment No. 26 to San Juan's 13D dated October
21, 1998, on such date San Juan and BROG entered into a definitive Purchase and
Sale Agreement of substantially the terms and effect as contemplated by the
letter of intent.
22
<PAGE> 23
In connection with San Juan's proposal to terminate the Trust, the
Trust engaged Netherland Sewell & Associates, Inc., independent petroleum
engineers, to prepare updated reports on the Trust's estimated reserves and
estimated future revenues and on the Trusts estimated Section 29 tax credits
attributable to the Royalty Interests. These reports are included as Exhibit
99.1 and Exhibit 99.2, respectively, to this Form 10-Q. The cost of preparing
such reports was borne by San Juan and not the Trust.
Unitholders are advised to consult the Form 8-K and the above
referenced filings by San Juan and the exhibits thereto for additional
information regarding the foregoing.
Item 6. Exhibits and Reports on Form 8-K.
(a) Exhibit No. Description
23 Consent of Netherland, Sewell & Associates, Inc.
27 Financial Data Schedule
99.1 Reserve Report, dated November 9, 1998, on the
estimated reserves, estimated future net revenues and
discounted future net revenues attributable to the
Royalty Interests and BROG's interest in the
Underlying Properties as of August 31, 1998, prepared
by Netherland, Sewell & Associates, Inc., independent
petroleum engineers.
99.2 Report, dated November 10, 1998, on the estimated
Section 29 Tax credits attributable to the Royalty
Interests as of August 31, 1998, prepared by
Netherland, Sewell & Associates, Inc., independent
petroleum engineers.
(b) Reports on Form 8-K.
The Trust filed a report on Form 8-K with the Securities and
Exchange Commission on September 25, 1998. The items reported in the
Form 8-K are described under "Item 5 -- Other Information -- Expected
Unitholder Proposal to Terminate the Trust" in this Form 10-Q.
23
<PAGE> 24
SIGNATURES
Pursuant to the requirements 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 Hooper
----------------------------------
Ron Hooper
Vice President
Date: November 16, 1998
(The Trust has no directors or executive officers.)
24
<PAGE> 25
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
Exhibit No. Description
----------- -----------
<S> <C>
23 Consent of Netherland, Sewell & Associates, Inc.
27 Financial Data Schedule
99.1 Reserve Report, dated November 9, 1998, on the
estimated reserves, estimated future net revenues and
discounted future net revenues attributable to the
Royalty Interests and BROG's interest in the
Underlying Properties as of August 31, 1998, prepared
by Netherland, Sewell & Associates, Inc., independent
petroleum engineers.
99.2 Report, dated November 10, 1998, on the estimated
Section 29 Tax credits attributable to the Royalty
Interests as of August 31, 1998, prepared by
Netherland, Sewell & Associates, Inc., independent
petroleum engineers.
</TABLE>
<PAGE> 1
EXHIBIT 23
[Letterhead of Netherland, Sewell & Associates, Inc.]
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS
We hereby consent to the references to Netherland, Sewell & Associates,
Inc. and to the use of its reports listed below regarding the Burlington
Resources Coal Seam Gas Royalty Trust proved reserves and estimated Section 29
tax credits in the Quarterly Report on Form 10-Q for the period ending September
30, 1998, to be filed by the Burlington Resources Coal Seam Gas Royalty Trust
with the Securities and Exchange Commission.
1. Report dated November 9, 1998 for reserves as of August 31, 1998.
2. Report dated November 10, 1998 for estimated Section 29 tax credits as
of August 31, 1998.
NETHERLAND, SEWELL & ASSOCIATES, INC.
By: /s/ Danny Simmons
---------------------------------
Danny Simmons,
Senior Vice President
Houston, Texas
November 16, 1998
<TABLE> <S> <C>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1998
<PERIOD-END> SEP-30-1998
<CASH> 55,626
<SECURITIES> 0
<RECEIVABLES> 0
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 55,626
<PP&E> 180,400,000
<DEPRECIATION> 100,947,315
<TOTAL-ASSETS> 89,475,473
<CURRENT-LIABILITIES> 106,352
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 79,401,959
<TOTAL-LIABILITY-AND-EQUITY> 79,508,311
<SALES> 5,479,285
<TOTAL-REVENUES> 5,494,971
<CGS> 0
<TOTAL-COSTS> 531,129
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 4,963,842
<INCOME-TAX> 0
<INCOME-CONTINUING> 0
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 4,963,842
<EPS-PRIMARY> .56
<EPS-DILUTED> .56
</TABLE>
<PAGE> 1
[NETHERLAND, SEWELL & ASSOCIATES, INC. LETTERHEAD]
EXHIBIT 99.1
November 9, 1998
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 August 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 August 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 67,837,801 $47,782,200 $29,766,200
</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 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
[NSAI LETTERHEAD]
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 August 1998 net price
received, adjusted for BTU content, 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. These costs include the per-well overhead expenses
allowed under joint operating agreements along with costs estimated to be
incurred at and below the district and field levels. General and administrative
overhead expenses of the Trustee are not included. Lease and well operating
costs are held constant in accordance with SEC guidelines. Capital costs are
included as required for workovers and production equipment.
We have made no investigation of potential gas volume and value
imbalances which may have resulted from overdelivery or underdelivery to the
Burlington interest. Therefore, our estimates of reserves and future revenue do
not include adjustments for the settlement of any such imbalances; our
projections are based on Burlington receiving its net revenue interest share of
estimated future gross gas production.
The reserves included in this report are estimates only and should not
be construed as exact quantities. They may or may not be recovered; if
recovered, the revenues therefrom and the costs related thereto could be more or
less than the estimated amounts. The sales rates, prices received for the
reserves, and costs incurred in recovering such reserves may vary from
assumptions included in this report due to governmental policies and
uncertainties of supply and demand. Also, estimates of reserves may increase or
decrease as a result of future operations.
<PAGE> 3
[NSAI LETTERHEAD]
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 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,
[SEAL]
/s/ FREDERICK D. SEWELL
DDS:PJA
<PAGE> 1
[NETHERLAND, SEWELL & ASSOCIATES, INC. LETTERHEAD]
EXHIBIT 99.2
November 10, 1998
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 August 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 November 9, 1998. 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 August 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 26,758,942 $25,711,700 $21,587,100
</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 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
<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.
For the purposes of this report, a field inspection of the properties
has not been performed nor has the mechanical operation or condition of the
wells and their related facilities been examined. We have not investigated
possible environmental liability related to the properties; therefore, our
estimates do not include any costs which may be incurred due to such possible
liability. Also, our estimates do not include any salvage value for the lease
and well equipment nor the cost of abandoning the properties.
An estimated 1998 tax credit of $1.07 per MMBTU is held constant in
accordance with SEC guidelines.
Lease and well operating costs are based on operating expense records
provided by Burlington. These costs include the per-well overhead expenses
allowed under joint operating agreements along with costs estimated to be
incurred at and below the district and field levels. General and administrative
overhead expenses of the Trustee are not included. Lease and well operating
costs are held constant in accordance with SEC guidelines. Capital costs are
included as required for workovers and production equipment.
We have made no investigation of potential gas volume and value
imbalances which may have resulted from overdelivery or underdelivery to the
Burlington interest. Therefore, our estimates of reserves and tax credit do not
include adjustments for the settlement of any such imbalances; our projections
are based on Burlington receiving its net revenue interest share of estimated
future gross gas production.
The reserves included in this report are estimates only and should not
be construed as exact quantities. They may or may not be recovered; if
recovered, the tax credit therefrom and the costs related thereto could be more
or less than the estimated amounts. The sales rates, prices received for the
reserves, and costs incurred in recovering such reserves may vary from
assumptions included in this report due to governmental policies and
uncertainties of supply and demand. Also, estimates of reserves may increase or
decrease as a result of future operations.
In evaluating the information at our disposal concerning this report,
we have excluded from our consideration all matters as to which legal or
accounting, rather than engineering and geological, interpretation may be
controlling. As in all aspects of oil and gas evaluation, there are
uncertainties inherent in the interpretation of engineering and geological data;
therefore, our conclusions necessarily represent only informed professional
judgments.
The titles to the properties have not been examined by Netherland,
Sewell & Associates, Inc., nor has the actual degree or type of interest owned
been independently confirmed. The data used in our estimates were obtained from
Burlington Resources Oil & Gas Company 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
<PAGE> 3
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
