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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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(Mark One) FORM 10-K
[ [x] ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1996
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR
15(D) OF THE SECURITIES EXCHANGE ACT OF 1934
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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 of Texas, N.A.
NationsBank Plaza
901 Main Street, Suite 1700
Dallas, Texas 75202
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE:
(214) 508-2304
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
NAME OF EACH EXCHANGE ON
TITLE OF EACH CLASS WHICH REGISTERED
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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]
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At March 17, 1997, there were 8,800,000 units of beneficial interest
outstanding and the aggregate market value of such units (based on the closing
sale price on the New York Stock Exchange) held by non-affiliates of the
registrant was approximately $70,400,000.
DOCUMENTS INCORPORATED BY REFERENCE
Listed below are documents parts of which are incorporated herein by reference
and the part of this report into which the document is incorporated:
1996 Annual Report to Unitholders - Part II.
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TABLE OF CONTENTS
PAGE
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PART I
Item 1. Business.......................................................... 1
GLOSSARY............................................................... 1
DESCRIPTION OF THE TRUST............................................... 5
Creation and Organization of the Trust............................ 5
Assets of the Trust............................................... 6
Liabilities of the Trust.......................................... 6
Duties and Limited Powers of the Trustee.......................... 6
Liabilities of the Delaware Trustee and the Trustee............... 7
Termination and Liquidation of the Trust.......................... 7
Arbitration and Derivative Actions................................ 8
DESCRIPTION OF UNITS................................................... 9
Distributions and Income Computations............................. 10
Conditional Right of Repurchase................................... 10
Possible Divestiture of Units..................................... 11
Periodic Reports to Unitholders................................... 12
Voting Rights of Unitholders...................................... 12
Liability of Unitholders.......................................... 13
Transfer Agent.................................................... 13
FEDERAL INCOME TAXATION................................................ 13
Summary of Certain Federal Income Tax Consequences................ 14
ERISA CONSIDERATIONS................................................... 18
STATE TAX CONSIDERATIONS............................................... 18
REGULATION AND PRICES.................................................. 18
Regulation of Natural Gas......................................... 18
Environmental Regulation.......................................... 19
Competition, Markets and Prices................................... 20
Item 2. Properties........................................................ 21
THE ROYALTY INTERESTS..................................... ............ 21
The Underlying Properties......................................... 21
The NPI........................................................... 23
Reserve Report.................................................... 24
Historical Gas Sales Prices and Production........................ 25
Possible NPI Percentage Reduction................................. 25
Gas Purchase Contract............................................. 26
Gas Gathering Contract............................................ 28
Federal Lands..................................................... 29
Sale and Abandonment of Underlying Properties..................... 30
The Infill NPI.................................................... 31
Burlington Resources' Performance Assurances...................... 31
Title to Properties............................................... 31
Item 3. Legal Proceedings................................................. 32
Item 4. Submission of Matters to a Vote of Security Holders............... 32
(i)
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PAGE
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PART II
Item 5. Market for Registrant's Common Equity and Related
Unitholder Matters................................................ 32
Item 6. Selected Financial Data........................................... 32
Item 7. Trustee's Discussion and Analysis of Financial Condition
and Results of Operations......................................... 33
Item 8. Financial Statements and Supplementary Data....................... 33
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.............................................. 33
PART III
Item 10. Directors and Executive Officers of the Registrant................ 33
Item 11. Executive Compensation............................................ 33
Item 12. Security Ownership of Certain Beneficial Owners and Management.... 34
Item 13. Certain Relationships and Related Transactions.................... 34
Administrative Services Agreement............................... 34
Burlington Resources' Conditional Right of Repurchase........... 34
Potential Conflicts of Interest................................. 34
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K... 36
Financial Statements............................................ 36
Financial Statement Schedules................................... 36
Exhibits........................................................ 36
Reports on Form 8-K............................................. 38
(ii)
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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, MOTI has a one-time option to elect to substitute for the foregoing as
the Blanco Hub Spot Price either (i) the average of the two posted index prices
reported each month in Inside FERC's Gas Market Report for "El Paso Natural Gas
Company, San Juan" or (ii) the Blanco Hub posted index price reported by Inside
FERC's Gas Market Report, if either such price is then published in such
publication. For purposes hereof, "average" prices refer to averages of the
relevant monthly prices reported in Inside FERC's Gas Market Report.
"Btu" means British Thermal Unit, the common unit of gross heating value
measurement for natural gas.
"Burlington Resources" means Burlington Resources Inc.
"Central Gathering Point" means any one of four central delivery points in the
unit gathering system of the Northeast Blanco Unit or any one of two wellhead
delivery points.
"Citibank's Base Rate" means a fluctuating interest rate per annum (compounded
quarterly) as shall be in effect from time to time which rate per annum shall at
all times be equal to the rate of interest announced publicly by Citibank, N.A.
in New York, New York, from time to time, as its base rate.
"Conveyance" means the Net Profits Interest Conveyance from MOPI to the Trust,
a copy of which is filed as an exhibit to this Form 10-K.
"December 31, 1993 Reserve Report" means the Reserve Report, dated March 25,
1994, on the estimated MOPI reserves, estimated future net revenues and the
discounted estimated future net revenues distributable to the Royalty Interests
and the Underlying Properties as of December 31, 1993, prepared by Netherland,
Sewell & Associates, Inc., independenet petroleum engineers, a copy of which is
filed as an exhibit to this Form 10-K.
"December 31, 1994 Reserve Report" means the Reserve Report, dated March 15,
1995, on the estimated MOPI reserves, estimated future net revenues and the
discounted estimated future net revenues attributable to the Royalty Interests
and the Underlying Properties as of December 31, 1994, prepared by Netherland,
Sewell & Associates, Inc., independent petroleum engineers, a copy of which is
filed as an exhibit to this Form 10-K.
"December 31, 1994 Section 29 Tax Credit Report" means the report, dated March
16, 1995, on the estimated MOPI reserves and estimated Section 29 tax credits
attributable to the Royalty Interests and the Underlying Properties as of
December 31, 1994, prepared by Netherland, Sewell & Associates, Inc.,
independent petroleum engineers, a copy of which is filed as an exhibit to this
Form 10-K.
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"December 31, 1995 Reserve Report" means the Reserve Report, dated March 18,
1996, on the estimated MOPI reserves, estimated future net revenues and the
discounted estimated future net revenues attributable to the Royalty Interests
and the Underlying Properties as of December 31, 1995, prepared by Netherland,
Sewell & Associates, Inc., independent petroleum engineers, a copy of which is
filed as an exhibit to this Form 10-K.
"December 31, 1995 Section 29 Tax Credit Report" means the report, dated March
19, 1996, on the estimated MOPI reserves and estimated Section 29 tax credits
attributable to the Royalty Interests and the Underlying Properties as of
December 31, 1995, prepared by Netherland, Sewell & Associates, Inc.,
independent petroleum engineers, a copy of which is filed as an exhibit to this
Form 10-K.
"December 31, 1996 Reserve Report" means the Reserve Report, dated March 20,
1997, on the estimated MOPI reserves, estimated future net revenues and the
discounted estimated future net revenues attributable to the Royalty Interests
and the Underlying Properties as of December 31, 1996, prepared by Netherland,
Sewell & Associates, Inc., independent petroleum engineers, a copy of which is
filed as an exhibit to this Form 10-K.
"December 31, 1996 Section 29 Tax Credit Report" means the report, dated March
21, 1997, on the estimated MOPI reserves and estimated Section 29 tax credits
attributable to the Royalty Interests and the Underlying Properties as of
December 31, 1996, prepared by Netherland, Sewell & Associates, Inc.,
independent petroleum engineers, a copy of which is filed as an exhibit to this
Form 10-K.
"Delaware Code" means the Delaware Business Trust Act, Title 12, Chapter 38 of
the Delaware Code, Sections 3801 et seq.
"Delaware Trustee" means Mellon Bank (DE) National Association, in its
capacity as a trustee of the Trust.
"Gas Gathering Contract" means the Gas Gathering, Dehydrating and Treating
Agreement, dated as of May 3, 1990, between MOGI and MOTI, as amended, a copy of
which is filed as an exhibit to this Form 10-K.
"Gas Purchase Contract" means the Gas Purchase Contract, dated as of May 1,
1993, between MOPI and MOTI, a copy of which is filed as an exhibit to this Form
10-K.
"Grantor trust" means a trust as to which the grantor, or his successor, has
retained an interest in the income from the trust.
"Gross acres" means the total number of surface acres of land.
"Gross wells" means the total whole number of gas wells.
"Index Price" means, for each month, 97 percent of the Blanco Hub Spot Price
(such 3 percent deduction constituting a discount to compensate MOTI for
marketing the gas).
"Infill Net Proceeds" consists generally of the aggregate proceeds based on
the price at the Central Gathering Point of gas attributable to MOPI's interest
in any Infill Wells less (a) MOPI's working interest share of property,
production and related taxes (including severance taxes) in respect of such
Infill Wells; (b) MOPI's working interest share of lease operating expenses in
respect of such Infill Wells; (c) MOPI's working interest share of capital costs
in respect of such Infill Wells, including the costs of drilling and completing
such Infill Wells and the costs of associated surface facilities; and (d)
interest on the unrecovered portion, if any, of the foregoing costs at
Citibank's Base Rate. In no event will any amounts relating to environmental
liabilities related to activities occurring on or under, or in connection with,
or conditions existing on or under, the Underlying Properties before June 17,
1993 (which liabilities will be borne by MOPI) be deducted in calculating Infill
Net Proceeds.
"Infill NPI" refers to one of the net profits interests conveyed to the Trust,
entitling the Trust to receive a 20 percent interest in the Infill Net Proceeds.
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"Infill Wells" means any additional wells drilled on the Underlying Properties
after the date of the Conveyance pursuant to a change in spacing rules or a
change allowing additional wells to be drilled on a spacing or proration unit,
in either case made effective after such date.
"IRC" means the Internal Revenue Code of 1986, as amended.
"IRR" means the annual discount rate (compounded quarterly) that equates the
present value of the After-tax Cash Flow per Unit to the $20.50 per Unit initial
price to the public of the Units in the Public Offering.
"Mcf" means thousand cubic feet of natural gas. Natural gas volumes are stated
herein at the legal pressure base of 14.73 pounds per square inch absolute at 60
degrees Fahrenheit.
"Minimum Purchase Price" means $1.60 per MMBtu, subject to increase by 2 1/2
percent annually as of May 1 of each year commencing in 2003.
"MMBtu" means million Btu.
"MMcf" means million cubic feet of natural gas.
"MOGI" means Burlington Resources Gathering Inc. (formerly named Meridian Oil
Gathering Inc.), a wholly owned subsidiary of Burlington Resources.
"MOPI" means Burlington Resources Oil & Gas Company (formerly named Meridian
Oil Inc., which is the successor by merger to Meridian Oil Production Inc.)
"MOPI Payment Obligations" has the meaning assigned to such term under "Item
2--The Royalty Interests--Burlington Resources' Performance Assurances."
"MOTI" means Burlington Resources Trading Inc. (formerly named Meridian Oil
Trading Inc.), a wholly owned subsidiary of Burlington Resources.
"MOTI Payment Obligations" has the meaning assigned to such term under "Item
2--The Royalty Interests--Burlington Resources' Performance Assurances."
"Net profits interest" generally refers to a real property interest entitling
the owner to receive as a royalty a specified percentage of the net proceeds
from the sale of production attributable to the properties burdened thereby, the
amount of which is based on a revenue formula specified in such net profits
interest.
"Net revenue interest" means working interest or mineral interest less any
applicable royalties, overriding royalties or similar burdens on production.
"Net wells" and "net acres" are calculated by multiplying gross wells or gross
acres by the working interest in such wells or acres.
"Northeast Blanco Unit" means the unit area covered by that certain Unit
Agreement For The Development And Operation of The Northeast Blanco Unit Area,
dated July 16, 1951, and includes the rights attributable to such area in one
communitized gross well with acreage in both the Northeast Blanco Unit and the
adjoining San Juan 30-6 Unit (the "San Juan 30-6 Unit").
"NPI" refers to one of the net profits interests conveyed to the Trust,
generally entitling the Trust to receive 95 percent of the NPI Net Proceeds. The
NPI is subject to reduction as described under "Item 2--The Royalty Interests--
Possible NPI Percentage Reduction."
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"NPI Net Proceeds" consists generally of the aggregate proceeds attributable
to MOPI's net revenue interest in the Underlying Properties (other than its
interest by virtue of Infill Wells) based on the sale at the Central Gathering
Point of gas produced from the Underlying Properties, less (i) MOPI's working
interest share of property, production and related taxes (including severance
taxes) on the Underlying Properties; (ii) MOPI's working interest share of lease
operating expenses on the Underlying Properties; (iii) MOPI's working interest
share of capital costs on the Underlying Properties (other than capital costs
incurred prior to January 1, 1994, which costs were borne by MOPI to the extent
of its working interest share); (iv) royalties, if any, required to be paid that
are based on the value of Section 29 tax credits attributable to such working
interest share; and (v) interest on the unrecovered portion, if any, of the
foregoing costs at Citibank's Base Rate. In no event will any amounts relating
to environmental liabilities related to activities occurring on or under, or in
connection with, or conditions existing on or under, the Underlying Properties
before June 17, 1993 (which liabilities will be borne by MOPI) be deducted in
calculating NPI Net Proceeds.
"Price Credit" means the credit received by MOTI from MOPI for each MMBtu of
natural gas purchased by MOTI after December 31, 1993 when the Index Price is
less than the Minimum Purchase Price, equal to the difference between the
Minimum Purchase Price and the Index Price.
"Price Credit Account" means the account established by MOTI containing the
accrued and unrecouped amount of any Price Credits.
"Price Differential" means 50 percent of the excess of the Index Price over
the Sharing Price.
"Prior Reserve Reports" means, collectively, the December 31, 1993 Reserve
Report, December 31, 1994 Reserve Report and December 31, 1995 Reserve Report.
"Prior Tax Credit Reports" means, collectively, the December 31, 1994 Section
29 Tax Credit Report and December 31, 1995 Section 29 Tax Credit Report.
"Public Offering" has the meaning assigned to such term under "--Description
of the Trust--Creation and Organization of the Trust."
"Public Offering Prospectus" has the meaning assigned to such term herein
under "Item 1 - Federal Income Taxation."
"Royalty" means an interest entitling the holder thereof to a certain
percentage of the gas produced from the wells, which generally is free of all
expenses of production, but may be subject to certain post-production costs.
"Royalty Interests" means the NPI and the Infill NPI conveyed to the Trust.
"Sharing Price" means $2.04 per MMBtu, subject to increase by 2 1/2 percent
annually as of May 1 of each year commencing in 2003.
"Trust" means Burlington Resources Coal Seam Gas Royalty Trust, a Delaware
business trust formed pursuant to the Trust Agreement.
"Trust Agreement" means the Trust Agreement, dated as of May 1, 1993, among
Burlington Resources, MOPI, as grantor, Mellon Bank (DE) National Association,
as the Delaware Trustee, and NationsBank of Texas, N.A., as the Trustee, a copy
of which is filed as an exhibit to this Form 10-K.
"Trustee" means NationsBank of Texas, N.A., in its capacity as a trustee of
the Trust.
"Underlying Properties" means the Fruitland coal formation underlying the
Northeast Blanco Unit.
"Units" means the 8,800,000 units of beneficial interest issued by, and
evidencing the entire beneficial interest in, the Trust.
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"Working interest" generally refers to the lessee's interest in an oil, gas or
mineral lease which entitles the owner to receive a specified percentage of oil
and gas production, but requiring the owner of such working interest to bear a
specified percentage of the costs to explore for, develop, produce and market
such oil and gas.
DESCRIPTION OF THE TRUST
Burlington Resources Coal Seam Gas Royalty Trust (the "Trust") was formed as a
Delaware business trust under the Delaware Business Trust Act, Title 12, Chapter
38 of the Delaware Code, Sections 3801 et seq. (the "Delaware Code"). The
following information is subject to the detailed provisions of (i) the Trust
Agreement of Burlington Resources Coal Seam Gas Royalty Trust (the "Trust
Agreement"), dated as of May 1, 1993, among Burlington Resources Inc., a
Delaware corporation ("Burlington Resources"), Meridian Oil Production Inc., a
Delaware corporation ("MOPI"), as grantor, Mellon Bank (DE) National
Association, a national banking association (the "Delaware Trustee"), and
NationsBank of Texas, N.A., a national banking association (the "Trustee"), as
trustees, and (ii) the Net Profits Interest Conveyance (the "Conveyance") dated
effective as of May 1, 1993 from MOPI to the Trust. Effective January 1, 1996,
MOPI was merged with and into Meridian Oil Inc. ("MOI"), a wholly owned
subsidiary of Burlington Resources. Effective July 11, 1996, MOI changed its
name to Burlington Resources Oil & Gas Company ("BROG") and Meridian Oil Trading
Inc. ("MOTI") and Meridian Oil Gathering Inc. ("MOGI"), both affiliates of MOI,
changed their names to Burlington Resources Trading Inc. ("BRTI") and Burlington
Resources Gathering Inc. ("BRGI"), respectively. Accordingly, in this Form 10-K
references to MOPI refer to BROG after the date of such merger, references to
MOTI refer to BRTI and references to MOGI refer to BRGI. Copies of the Trust
Agreement and of the Conveyance are filed as exhibits to this Form 10-K. The
provisions governing the Trust are complex and extensive and no attempt has been
made below to describe or reference all of such provisions. The following is a
general description of the basic framework of the Trust and a summary of the
material terms of the Trust Agreement, and detailed provisions concerning the
Trust may be found in the Trust Agreement.
CREATION AND ORGANIZATION OF THE TRUST
All of the authorized units of beneficial interest in the Trust ("Units") were
issued to MOPI on June 17, 1993. On that date, MOPI transferred its Units to its
parent, Burlington Resources, by dividend. Burlington Resources, in turn, sold,
by means of a prospectus dated June 10, 1993, 7,700,000 Units on June 17, 1993,
and an additional 1,100,000 Units on June 23, 1993, to the public through
various underwriters (the "Public Offering").
The Trust has been formed under Delaware law pursuant to the terms of the
Trust Agreement to acquire and hold certain net profits interests (the "Royalty
Interests") in MOPI's interest in the Fruitland coal formation underlying the
Northeast Blanco Unit (the "Underlying Properties"). The Royalty Interests were
conveyed to the Trust on June 17, 1993 pursuant to the Conveyance for the
benefit of the Unitholders. The Trustee has all powers to collect and distribute
proceeds received by the Trust and to pay Trust liabilities and expenses. The
Delaware Trustee has only such powers as are set forth in the Trust Agreement or
are required by law and is not empowered to otherwise manage or take part in the
business of the Trust. The Royalty Interests are passive in nature and neither
the Delaware Trustee nor the Trustee has any control over or any responsibility
relating to the operation of the Underlying Properties. Neither MOPI nor the
operator of the Underlying Properties has any contractual commitments to the
Trust to further develop the Underlying Properties, to remain as operator with
respect to the Northeast Blanco Unit or to maintain its ownership interest in
any of the properties. However, after the conveyance of the Royalty Interests,
MOPI retained its interest in the Underlying Properties, which interest is
burdened by the Royalty Interests. MOPI may sell its interest in the Underlying
Properties subject to and burdened by the Royalty Interests. For a description
of the Underlying Properties and other information relating to such properties,
see "Item 2--The Royalty Interests."
The Delaware Trustee and the Trustee may resign at any time upon 60 days'
prior written notice or be removed with or without cause at any time by a vote
of a majority of the outstanding Units, provided in each case that a successor
trustee has been appointed and has accepted its appointment. Any successor
trustee must be a bank or trust company meeting certain requirements including
having combined capital, surplus and undivided profits of at least $20,000,000,
in the case of the Delaware Trustee, and $100,000,000, in the case of the
Trustee.
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ASSETS OF THE TRUST
The only assets of the Trust, other than cash and temporary investments being
held for the payment of expenses and liabilities and for distribution to
Unitholders, are the Royalty Interests. The Royalty Interests consist primarily
of a net profits interest (the "NPI") in the Underlying Properties, generally
entitling the Trust to receive 95 percent of the NPI Net Proceeds. "NPI Net
Proceeds" consists generally of the aggregate proceeds attributable to MOPI's
net revenue interest in the Underlying Properties (other than its interest by
virtue of Infill Wells, as defined below) based on the sale at the Central
Gathering Point (as defined) of gas produced from the Underlying Properties,
less (i) MOPI's working interest share of property, production and related taxes
(including severance taxes) on the Underlying Properties; (ii) MOPI's working
interest share of lease operating expenses on the Underlying Properties; (iii)
MOPI's working interest share of capital costs on the Underlying Properties
(other than capital costs incurred prior to January 1, 1994, which costs were
borne by MOPI to the extent of its working interest share); (iv) royalties, if
any, required to be paid that are based on the value of Section 29 tax credits
attributable to such working interest share; and (v) interest on the unrecovered
portion, if any, of the foregoing costs at Citibank's Base Rate. The Royalty
Interests also include a net profits interest (the "Infill NPI") entitling the
Trust to receive a 20 percent interest in the Infill Net Proceeds, as defined
below, from the sale of production from any additional wells drilled on the
Underlying Properties after May 1, 1993 pursuant to a change in spacing rules or
a change allowing additional wells to be drilled on a spacing or proration unit
("Infill Wells"). "Infill Net Proceeds" consists generally of the aggregate
proceeds based on the price at the Central Gathering Point of gas attributable
to MOPI's interest in any Infill Wells less MOPI's working interest share of
taxes, lease operating expenses, capital costs, and interest on the unrecovered
portion, if any, of the foregoing costs. See "Item 2--The Royalty Interests" for
more information.
LIABILITIES OF THE TRUST
Because of the passive nature of the Trust assets and the restrictions on the
activities of the Trustee, it is anticipated that the only liabilities the Trust
will incur are those for routine administrative expenses, such as the trustees'
fees and accounting, engineering, legal and other professional fees and the
administrative services fee paid to Burlington Resources. However, as discussed
under "--Federal Income Taxation," if a court were to hold that the Trust is
taxable as a corporation, then the Trust would be subject to Federal income
taxes.
DUTIES AND LIMITED POWERS OF THE TRUSTEE
Under the Trust Agreement, the Trustee receives the payments attributable to
the Royalty Interests and pays all expenses, liabilities and obligations of the
Trust. With respect to any liability that is contingent or uncertain in amount
or that otherwise is not currently due and payable, the Trustee has the
discretion to establish a cash reserve for the payment of such liability. The
Trustee is entitled to cause the Trust to borrow money to pay expenses,
liabilities and obligations that cannot be paid out of cash held by the Trust.
Any such borrowing may be from any source, including from the entity serving as
Trustee or Delaware Trustee, provided that the entity serving as Trustee or
Delaware Trustee shall not be obligated to lend to the Trust. To secure payment
of any such indebtedness (including any indebtedness to the entity serving as
Trustee or Delaware Trustee), the Trustee is authorized to (i) mortgage and
otherwise encumber the entire Trust estate or any portion thereof, including the
Royalty Interests; (ii) carve out and convey production payments; (iii) include
all terms, powers, remedies, covenants and provisions it deems necessary or
advisable, including confession of judgment and the power of sale with or
without judicial proceedings; and (iv) provide for the exercise of those and
other remedies available to a secured lender in the event of a default on such
loan. The terms of such indebtedness and security interest, if funds were loaned
by the entity serving as Trustee or Delaware Trustee, must be similar to the
terms which such entity would grant to a similarly situated commercial customer
with whom it did not have a fiduciary relationship, and such entity shall be
entitled to enforce its rights with respect to any such indebtedness and
security interest as if it were not then serving as trustee.
The Trustee is authorized and directed to sell and convey the Royalty
Interests without Unitholder approval in certain instances as described in the
Trust Agreement, including upon termination of the Trust. The Trustee is
empowered by the Trust Agreement to employ consultants and agents (including
MOPI and Burlington Resources)
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and to make payments of all fees for services or expenses out of the assets of
the Trust. The Trust has no employees. The administrative functions of the
Trust are performed by the Trustee.
The Trust Agreement authorizes the Trustee to take such action as in its
judgment is necessary or advisable to achieve the purposes of the Trust. The
Trustee is authorized to agree to modifications of the terms of the Conveyance
and to settle disputes with respect thereto, so long as such modifications or
settlements do not result in treatment of the Trust for Federal income tax
purposes as an association taxable as a corporation and such modifications or
settlements do not alter the nature of the Royalty Interests as a right to
receive a share of production or the proceeds of production from the Underlying
Properties which, with respect to the Trust, are free of any operating rights,
expenses or obligations. The Trust Agreement provides that cash being held by
the Trustee as a reserve for liabilities or for distribution at the next
distribution date will be placed in demand accounts, U.S. government
obligations, repurchase agreements secured by such obligations, or certificates
of deposit, but the Trustee is otherwise prohibited from acquiring any asset
other than the initial cash deposit and the Royalty Interests or engaging in any
business or investment activity of any kind whatsoever. The Trustee may deposit
funds awaiting distribution in an account with the Trustee or Delaware Trustee
provided the interest paid equals the amount paid by the Trustee or Delaware
Trustee, as the case may be, on similar deposits.
LIABILITIES OF THE DELAWARE TRUSTEE AND THE TRUSTEE
Each of the Delaware Trustee and the Trustee may act in its discretion and
shall be personally or individually liable only for fraud or acts or omissions
in bad faith or which constitute gross negligence (and for taxes, fees and other
charges based on any fees, commissions or compensation received pursuant to the
Trust Agreement) and will not be otherwise liable for any act or omission of any
agent or employee unless such trustee has acted in bad faith or with gross
negligence in the selection or retention of such agent or employee. Each of the
Delaware Trustee and the Trustee (and their respective agents) is indemnified by
Burlington Resources and MOPI and from the Trust assets for certain
environmental liabilities, and for any other liability, expense, claim, damage
or other loss incurred in performing its duties, unless resulting from gross
negligence, fraud or bad faith (each of the Delaware Trustee and the Trustee
being indemnified from the Trust assets against its own negligence which does
not constitute gross negligence), and will have a first lien against the assets
of the Trust as security for such indemnification and for reimbursements and
compensation to which it is entitled, provided that the Trustee and the Delaware
Trustee are generally required to first be indemnified from Trust assets before
seeking indemnification from Burlington Resources. Burlington Resources has also
indemnified the Trustee and the Delaware Trustee against certain securities laws
liabilities. Neither the Delaware Trustee nor the Trustee is entitled to
indemnification from Unitholders (except in connection with lost or destroyed
Unit certificates).
TERMINATION AND LIQUIDATION OF THE TRUST
The Trust will not terminate prior to January 1, 2003, except upon the
affirmative vote of the holders of not less than 66-2/3% percent of the
outstanding Units to liquidate the Trust. Thereafter, and subject to Burlington
Resources' conditional right of repurchase (see "--Description of Units--
Conditional Right of Repurchase"), the Trust will terminate upon the first to
occur (such date, the "Termination Date") of (i) an affirmative vote of the
holders of not less than 66-2/3% percent of the outstanding Units to terminate
the Trust; (ii) such time as the ratio of the cash amounts received by the Trust
from the Royalty Interests (excluding deductions for capital expenditures) to
administrative costs of the Trust is less than 1.2 to 1.0 for three consecutive
quarters; (iii) such time as the Royalty Interests held by the Trust have been
sold by the Trust; (iv) March 1 of any calendar year if, based on a reserve
report as of December 31 of the prior year, it is determined that, as of such
date, the net present value (discounted at 10 percent) of the estimated future
net revenues (calculated in accordance with criteria established by the
Securities and Exchange Commission (the "Commission") except that such
calculation will utilize as the gas price in such calculation the average
monthly gas price (before deduction of costs) paid under the Gas Purchase
Contract for production attributable to MOPI's interest in the Underlying
Properties during the 12 months ending on such December 31) of proved reserves
attributable to the Royalty Interests is equal to or less than $30 million; and
(v) December 31, 2012. Following termination, the Trustee and the Delaware
Trustee will continue to act as trustees of the Trust until all remaining Trust
assets have been sold and the net proceeds from such sales distributed to
Unitholders.
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Upon the termination of the Trust, the Trustee will use its best efforts (as
defined in the Trust Agreement) to sell any remaining Royalty Interests for cash
pursuant to the procedures described herein. The Trustee will retain an
investment banking firm (the "Advisor") on behalf of the Trust who will assist
the Trustee in selling the remaining Royalty Interests then owned by the Trust.
MOPI has the right, but not the obligation, to purchase all remaining Royalty
Interests following termination of the Trust as described in the following
paragraph.
MOPI may, within 60 days following the Termination Date, make a cash offer to
purchase all of the remaining Royalty Interests then held by the Trust. In the
event such an offer is made by MOPI, the Trustee will decide, based on the
recommendation of the Advisor, to either (i) accept such offer (in which case no
sale to MOPI will be made unless a fairness opinion is given by the Advisor that
the purchase price is fair to the Unitholders) or (ii) defer action on the offer
for approximately 60 days and seek to locate other buyers for the remaining
Royalty Interests. If the Trustee defers action on MOPI's offer, the offer will
be deemed withdrawn and the Trustee will then use best efforts (as defined in
the Trust Agreement), assisted by the Advisor, to locate other buyers for the
Royalty Interests. At the end of a 120-day period following the Termination
Date, the Trustee is required to notify MOPI of the highest of any other offers
acceptable to the Trustee (which must be an all cash offer) received during such
period (the "Highest Offer Price"). MOPI then has the right (whether or not it
made an initial offer), but not the obligation, to purchase all remaining
Royalty Interests for a cash purchase price computed as follows: (i) if the
Highest Offer Price is more than 105 percent of MOPI's original offer (or if
MOPI did not make an initial offer), the purchase price will be 105 percent of
the Highest Offer Price, or (ii) if the Highest Offer Price is equal to or less
than 105 percent of MOPI's original offer, the purchase price will be equal to
the Highest Offer Price. If no other acceptable offers are received for all
remaining Royalty Interests, the Trustee may request MOPI to submit another
offer for consideration by the Trustee and may accept or reject such offer.
If a sale of the Royalty Interests is made or a definitive contract for sale
of the Royalty Interests is entered into within a 150-day period following the
Termination Date, the buyer of the Royalty Interests, and not the Trust or
Unitholders, will be entitled to all proceeds of production attributable to the
Royalty Interests following the Termination Date.
In the event that MOPI does not purchase the Royalty Interests, the Trustee
may accept any offer for all or any part of the Royalty Interests as it deems to
be in the best interests of the Trust and Unitholders and may continue, for up
to one calendar year after the Termination Date, to attempt to locate a buyer or
buyers of the remaining Royalty Interests in order to sell such interests in an
orderly fashion. If any Royalty Interests have not been sold or a definitive
agreement for sale has not been entered into by the end of such calendar year,
the Trustee is required to sell the remaining Royalty Interests at public
auction, which sale may be to MOPI or any of its affiliates.
MOPI's purchase rights, as described, may be exercised by MOPI and each of its
successors in interest and assigns. MOPI's purchase rights are fully assignable
by MOPI to any person or entity. The costs of liquidation, including the fees
and expenses of the Advisor, and the Trustee's liquidation fee will be paid by
the Trust. Unitholders are not entitled to any rights of appraisal or similar
rights in connection with the termination of the Trust.
ARBITRATION AND DERIVATIVE ACTIONS
Pursuant to the Trust Agreement, any dispute, controversy or claim that may
arise between or among (i) Burlington Resources or MOPI, on the one hand, and
the Trustee, the Delaware Trustee and the Trust, on the other hand, in
connection with or otherwise relating to the Trust Agreement or the application,
implementation, validity or breach of the Trust Agreement or any provision
thereof or (ii) MOPI, on the one hand, and the Trust, on the other hand, in
connection with or otherwise relating to the Conveyance or the application,
implementation, validity or breach of the Conveyance or any provision thereof,
shall be finally, conclusively and exclusively settled by final and binding
arbitration in Houston, Texas in accordance with the Rules of Practice and
Procedure for the arbitration of commercial disputes of Judicial Arbitration &
Mediation Services, Inc. (or any successor thereto) then in effect. The Gas
Purchase Contract also includes a provision that will require MOPI and MOTI to
submit any dispute regarding such contract to alternative dispute resolution
before litigating such matter.
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The procedures for the arbitration of disputes enumerated in the Trust
Agreement neither bar nor restrict the statutory right of any Unitholder under
Section 3816 of the Delaware Code to bring a derivative action. Pursuant to
Section 3816 of the Delaware Code, a derivative action in the right of the Trust
may be brought by a Unitholder in the Delaware Court of Chancery against
Burlington Resources or MOPI (or any other person) to recover a judgment in
favor of the Trust if the Trustee has refused to bring such action or if an
effort to cause the Trustee to bring such action is not likely to succeed.
Pursuant to Section 3816 of the Delaware Code, a plaintiff in a derivative
action must be a beneficial owner at the time such action is brought and (a) at
the time of the transaction subject to such complaint or (b) the plaintiff's
status as a beneficial owner must have devolved upon it by operation of law or
pursuant to the terms of the governing instrument of the trust from a person or
entity who was a beneficial owner at the time of the transaction giving rise to
the complaint. If a derivative action is successful, in whole or in part, or if
anything is received by the trust as a result of a judgment, compromise or
settlement of any such action, the Delaware Chancery Court may award the
plaintiff reasonable expenses, including reasonable attorney's fees. If any
award is so received by the plaintiff, the Delaware Chancery Court shall make
such award of the plaintiff's expenses payable out of those proceeds and direct
plaintiff to remit to the trust the remainder thereof. If the proceeds are
insufficient to reimburse plaintiff's reasonable expenses in bringing the
derivative action, the Delaware Chancery Court may direct that any such award of
plaintiff's expenses or a portion thereof be paid by the trust. In addition,
under Section 3816 a beneficial owner's right to bring a derivative action may
be subject to such additional standards and restrictions, if any, as are set
forth in the governing instrument of the trust, including, without limitation,
the requirement that beneficial owners owning a specified beneficial interest in
the trust join in the bringing of the derivative action. The rights of the
Unitholders to bring a derivative action on behalf of the Trust provided
pursuant to Section 3816 of the Delaware Code are substantially similar to the
derivative rights afforded stockholders under Section 327 of Chapter 8 of the
Delaware General Corporation Law and applicable Delaware case law.
Despite the latitude afforded pursuant to Section 3816, the Trust Agreement
does not impose any such additional standards or restrictions on a Unitholder
with respect to its right to bring a derivative action (other than as discussed
below with respect to "MOPI Payment Obligations" and "MOTI Payment Obligations"
(as such terms are defined herein)). In the event that any Unitholder was
successful in bringing a derivative action on behalf of the Trust to enforce
rights on behalf of the Trust against Burlington Resources or MOPI, then such
Unitholder could, on behalf of the Trust, pursue such rights against Burlington
Resources or MOPI, as the case may be, in the Delaware Chancery Court. The Trust
Agreement does not require, and expressly provides that it shall not be
construed to require, arbitration of a claim or dispute solely between the
Trustee and the Delaware Trustee or of any claim or dispute brought by any
person or entity, including, without limitation, any Unitholder (whether in its
own right or through a derivative action in the right of the Trust), who is not
a party to the Trust Agreement.
The right of a Unitholder to bring a derivative action on behalf of the Trust
with respect to Burlington Resources' obligation to cure any deficiency in MOPI
Payment Obligations or MOTI Payment Obligations is subject to the restriction
that such right may only be exercised by Unitholders owning of record not less
than 25 percent of the Units then outstanding (treated as a single class) and
then only absent action by the Trustee to enforce any such obligation within 10
days following receipt by the Trustee of a written request served upon the
Trustee by such Unitholders to take such action. In such an event, Unitholders
owning of record not less than 25 percent of the Units then outstanding may,
acting as a single class and on behalf of the Trust, seek to enforce such
obligations.
DESCRIPTION OF UNITS
Each Unit represents an equal undivided share of beneficial interest in the
Trust and is evidenced by a transferable certificate issued by the Trustee. Each
Unit entitles its holder to the same rights as the holder of any other Unit, and
the Trust has no other authorized or outstanding class of equity security. At
March 15, 1997, there were 8,800,000 Units outstanding. The Trust may not issue
additional Units.
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DISTRIBUTIONS AND INCOME COMPUTATIONS
The Trustee determines for each quarter the amount of cash available for
distribution to Unitholders. Such amount (the "Quarterly Distribution Amount")
is equal to the excess, if any, of the cash received by the Trust, on or prior
to the last business day before the 50th day following the end of each calendar
quarter ending prior to the dissolution of the Trust from the Royalty Interests
then held by the Trust attributable to production during such quarter, plus,
with certain exceptions, any other cash receipts of the Trust during such
quarter (which might include sales proceeds not sufficient in amount to qualify
for special distribution (as described in the next paragraph) and interest),
over the liabilities of the Trust paid during such quarter, subject to
adjustments for changes made by the Trustee during such quarter in any cash
reserves established for the payment of contingent or future obligations of the
Trust. Based on the payment procedures relating to the Royalty Interests, cash
received by the Trustee in a particular quarter from the Royalty Interests
generally represents proceeds from the sale of gas produced during the preceding
calendar quarter. The Quarterly Distribution Amount for each quarter is payable
to Unitholders of record on the 63rd day following the end of such calendar
quarter unless such day is not a business day in which case the record date will
be the next business day thereafter. The Trustee distributes the Quarterly
Distribution Amount on or prior to 75 days after the end of each calendar
quarter to each person who was a Unitholder of record on the associated record
date, together with interest estimated to be earned on such Quarterly
Distribution Amount from the date of receipt thereof by the Trustee to the
payment date.
The Royalty Interests may be sold under certain circumstances and will be sold
following termination of the Trust. Any proceeds from sales of the Royalty
Interests, less liabilities and expenses of the Trust and amounts used for cash
reserves, will be distributed, together with any interest expected to be earned
thereon, to Unitholders of record on the record date established for such
distribution. A special distribution will be made of undistributed sales
proceeds and other amounts received by the Trust aggregating in excess of
$10,000,000 (a "Special Distribution Amount"). The record date for a Special
Distribution Amount will be the 15th day following receipt of amounts
aggregating a Special Distribution Amount by the Trust (unless such day is not a
business day in which case the record date will be the next business day
thereafter) unless such day is within 10 days of the record date for a Quarterly
Distribution Amount in which case the record date will be the date as is
established for the next Quarterly Distribution Amount. Distribution to
Unitholders will be made no later than 15 days after the Special Distribution
Amount record date.
The terms of the Trust Agreement seek to assure to the extent practicable that
gross income attributable to cash being distributed will be reported by the
Unitholder who receives such distributions assuming that such Unitholder is the
owner of record on the applicable record date. In certain circumstances,
however, a Unitholder will not receive the cash giving rise to such income. For
example, the Trustee maintains a cash reserve, and is authorized to borrow money
under certain conditions, in order to pay or provide for the payment of Trust
liabilities. Income associated with the cash used to increase that reserve or
to repay any such borrowing must be reported by the Unitholder, even though that
cash is not distributed to him. Likewise, if a portion of a cash distribution
is attributable to a reduction in the cash reserve maintained by the Trustee,
such cash is treated as a reduction to the Unitholder's basis in his Units and
is not treated as taxable income to such Unitholder (assuming such Unitholder's
basis exceeds the amount of the distribution of cash reserve).
CONDITIONAL RIGHT OF REPURCHASE
Burlington Resources and any of its successors and affiliates retain in the
Trust Agreement the right to repurchase all (but not less than all) outstanding
Units at any time at which 15 percent or less of the outstanding Units is owned
by persons or entities other than Burlington Resources and its affiliates.
Subject to the following sentence, any such repurchase would be at a price equal
to the greater of (i) the highest price at which Burlington Resources or any of
its affiliates acquired Units during the 90 days immediately preceding the date
(the "Determination Date") which is three New York Stock Exchange trading days
prior to the date on which notice of such exercise is delivered to Unitholders
and (ii) the average closing price of Units on the New York Stock Exchange for
the 30 trading days immediately preceding the Determination Date. If Burlington
Resources or any of its affiliates acquires Units (other than an acquisition
from Burlington Resources or any affiliate) during the period that is three
trading days after the Determination Date at a price per Unit greater than that
at which an
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acquisition was made during the 90-day period referred to in clause (i) of the
preceding sentence, then for purposes of clause (i) of the preceding sentence
the highest price used therein shall be such greater price. Any such repurchase
would be conducted in accordance with applicable Federal and state securities
laws.
In the event that Burlington Resources elects to purchase all Units,
Burlington Resources and the Trustee will, prior to the date fixed for purchase,
give all Unitholders of record not less than 15 days' nor more than 60 days'
written notice specifying the time and place of such repurchase, calling upon
each such Unitholder to surrender to Burlington Resources on the repurchase date
at the place designated in such notice its certificate or certificates
representing the number of Units specified in such notice of repurchase. On or
after the repurchase date, each holder of Units to be repurchased must present
and surrender its certificates for such Units to Burlington Resources at the
place designated in such notice and thereupon the purchase price of such Units
shall be paid to or on the order of the person or entity whose name appears on
such certificate or certificates as the owner thereof. In no event may fewer
than all of the outstanding Units represented by the certificates be repurchased
(except for any Units held by Burlington Resources and any of its affiliates).
If Burlington Resources and the Trustee give a notice of repurchase and if, on
or before the date fixed for repurchase, the funds necessary for such repurchase
shall have been set aside by Burlington Resources, separate and apart from its
other funds, in trust for the pro rata benefit of the holders of the Units so
noticed for repurchase then, notwithstanding that any certificate for such Units
has not been surrendered, at the close of business on the repurchase date the
holders of such Units shall cease to be Unitholders and shall have no interest
in or claims against Burlington Resources, MOPI, the Trust, the Delaware Trustee
or the Trustee by virtue thereof and shall have no voting or other rights with
respect to such Units, except the right to receive the purchase price payable
upon such repurchase, without interest thereon and without any other
distributions for record dates after the date of notice of the repurchase, upon
surrender (and endorsement, if required by Burlington Resources) of their
certificates, and the Units evidenced thereby shall no longer be held of record
in the names of such Unitholders. Subject to applicable escheat laws, any monies
so set aside by Burlington Resources and unclaimed at the end of two years from
the repurchase date shall revert to the general funds of Burlington Resources,
after which reversion the holders of such Units so noticed for repurchase could
look only to the general funds of Burlington Resources for the payment of the
purchase price. Any interest accrued on funds so deposited would be paid to
Burlington Resources from time to time as requested by Burlington Resources.
In the event that Burlington Resources exercises and consummates its right of
repurchase, then at its option it may cause the Trust to be terminated by
providing written notice thereof to the Trustee and the Delaware Trustee. Within
30 days following written notice of Burlington Resources' decision to terminate
the Trust, the Trustee and the Delaware Trustee must cause all Royalty Interests
(and, subject to the rights of Unitholders with respect to the receipt of
distributions for which a record date has been determined, all proceeds of
production attributable to the Royalty Interests) and any other assets of the
Trust to be conveyed to Burlington Resources or its assignee (subject to the
right of such trustees to create reasonable reserves in connection with the
liquidation of the Trust).
POSSIBLE DIVESTITURE OF UNITS
The Trust Agreement imposes no restrictions based on nationality or other
status of Unitholders. However, the Trust Agreement provides that in the event
of certain judicial or administrative proceedings seeking the cancellation or
forfeiture of any property in which the Trust has an interest, or asserting the
invalidity of or otherwise challenging any portion of the Royalty Interests,
because of the nationality, citizenship or any other status of any one or more
Unitholders, the Trustee will give written notice thereof to each Unitholder
whose nationality, citizenship or other status is an issue in the proceeding,
which notice will constitute a demand that such Unitholder dispose of his Units
within 30 days. If any Unitholder fails to dispose of his Units within 90 days
after expiration of the 30 day period, the Trustee shall cancel all outstanding
certificates issued in the name of such Unitholder, transfer all Units held by
such Unitholder to the Trustee and sell such Units (including by private sale).
The proceeds of such sale (net of sales expenses), pending delivery of
certificates representing the Units, will be held by the Trustee in a non-
interest-bearing escrow account for the benefit of the Unitholder and will be
paid to the Unitholder upon surrender of such certificates. Cash distributions
payable to such Unitholder will also be held in a non-interest-bearing escrow
account pending disposition by the Unitholder of the Units or cancellation of
certificates representing the Units by the Trustee.
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PERIODIC REPORTS TO UNITHOLDERS
Within 75 days following the end of each of the first three calendar quarters
of each calendar year, the Trustee mails to each person or entity who was a
Unitholder of record (i) on the quarterly record date for such quarter or (ii)
on each Special Distribution Amount record date occurring during such quarter, a
report which shows in reasonable detail the assets and liabilities and receipts
and disbursements of the Trust and the revenues and direct operating expenses of
MOPI's interest in the Underlying Properties for such quarter. Within 120 days
following the end of each fiscal year or such shorter period of time as may be
required by the rules of the New York Stock Exchange, the Trustee mails to
Unitholders of record as of a date to be selected by the Trustee an annual
report containing audited financial statements relating to the Trust and MOPI's
interest in the Underlying Properties.
The Trustee files such returns for Federal income tax purposes as it is
required to comply with applicable law. The Trustee mails to each person or
entity who was a Unitholder of record (i) on the quarterly record date for such
quarter or (ii) on each Special Distribution Amount record date occurring during
such quarter, a report which shows in reasonable detail the information
necessary to permit each Unitholder to make all calculations reasonably
necessary for tax purposes. The Trustee treats all income, credits and
deductions recognized during each calendar quarter during the term of the Trust
as having been recognized by holders of record on the quarterly record date
established for the distribution unless otherwise advised by counsel. Available
year-end tax information permitting each Unitholder to make all calculations
reasonably necessary for tax purposes is distributed by the Trustee to
Unitholders no later than March 15 of the following year.
Each Unitholder and his duly authorized agents and attorneys have the right
during reasonable business hours upon reasonable prior notice to examine and
inspect records of the Trust, the Trustee and the Delaware Trustee.
VOTING RIGHTS OF UNITHOLDERS
While Unitholders have certain voting rights as provided in the Trust
Agreement, such rights differ from and are more limited than those of
stockholders of a corporation. For example, there is no requirement for annual
meetings of Unitholders or for annual or other periodic re-election of the
Trustee or the Delaware Trustee.
Meetings of Unitholders may be called by the Trustee or by Unitholders owning
not less than 10 percent in number of the outstanding Units. All such meetings
shall be held in Houston, Texas and written notice of every such meeting setting
forth the time and place of the meeting and the matters proposed to be acted
upon shall be given not more than 60 nor less than 20 days before such meeting.
The presence in person or by proxy of Unitholders representing a majority of the
outstanding Units is necessary to constitute a quorum. Unitholders have the
right to vote at all meetings of Unitholders and each Unitholder shall be
entitled to one vote for each Unit owned by such Unitholder. The Trustee will
call such meetings to consider amendments, waivers, consents and other changes
relating to the Gas Purchase Contract, the Gas Gathering Contract or the
Conveyance, if requested in writing by MOPI. No matter other than that stated in
the notice of the Unitholder meeting shall be voted on and no action by the
Unitholders may be taken without a meeting.
Generally, amendments to the Trust Agreement require approval of a majority of
the outstanding Units (except that amendment of required voting percentages
requires approval of at least 80 percent of the outstanding Units), but no
provision of the Trust Agreement may be amended that would (i) increase the
power of the Delaware Trustee or the Trustee to engage in business or investment
activities or (ii) alter the rights of the Unitholders as among themselves.
Without the written consent of Burlington Resources and the approval of not less
than 66-2/3% percent of the outstanding Units, no provision of the Trust
Agreement may be amended with respect to (a) the sale or disposition of all or
any part of the Trust estate, including the Royalty Interests, except as
specifically provided in the Trust Agreement, (b) termination of the Trust and
the disposition of Trust assets upon liquidation of the Trust or (c) MOPI's
right of first refusal with respect to purchase of any remaining Royalty
Interests upon termination of the Trust. Without the written consent of
Burlington Resources and the approval of a majority of the outstanding Units, no
amendment may be made to the Trust Agreement that would alter Burlington
Resources' conditional right to repurchase all outstanding Units at any time at
which 15 percent or less of the outstanding Units is owned by persons or
entities other than Burlington Resources and its affiliates. Additionally, any
amendment that increases the obligations, duties or liabilities of or affects
the rights of the Delaware Trustee or the Trustee must be consented
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to by such entity. The Trustee, the Delaware Trustee, Burlington Resources and
MOPI may, without approval of the Unitholders, from time to time supplement or
amend the Trust Agreement in order to cure any ambiguity or to correct or
supplement any defective or inconsistent provisions, provided such supplement or
amendment is not adverse to the interests of the Unitholders. In addition,
Burlington Resources may direct the Trustee to change the name of the Trust
without approval of the Unitholders. Removal of the Trustee and the Delaware
Trustee, approval of amendments, waivers, consents and other changes relating to
the Gas Purchase Contract, the Gas Gathering Contract and the Conveyance, and
the approval of the merger or consolidation of the Trust into one or more
entities require approval of a majority of the outstanding Units. Except as set
forth under "--Description of the Trust--Termination and Liquidation of the
Trust," all other actions may be approved by a majority vote of the Units
represented at a meeting at which a quorum is present or represented.
LIABILITY OF UNITHOLDERS
Consistent with Delaware law, the Trust Agreement provides that the
Unitholders will have the same limitation on personal liability as is accorded
under the laws of such state to stockholders of a corporation for profit. No
assurance can be given, however, that the courts in jurisdictions outside of
Delaware will give effect to such limitation.
TRANSFER AGENT
The Trustee has appointed Boston Equiserve Shareholder Service transfer agent
and registrar for the Units (the "Transfer Agent").
FEDERAL INCOME TAXATION
THE TAX CONSEQUENCES TO A UNITHOLDER OF THE OWNERSHIP AND SALE OF UNITS WILL
DEPEND IN PART ON THE UNITHOLDER'S TAX CIRCUMSTANCES. EACH UNITHOLDER SHOULD
THEREFORE CONSULT THE UNITHOLDER'S TAX ADVISOR ABOUT THE FEDERAL, STATE AND
LOCAL TAX CONSEQUENCES TO THE UNITHOLDER OF THE OWNERSHIP OF UNITS.
The sections entitled "Federal Income Tax Consequences" and "Risk Factors--
Risks Associated With the Units--Tax Considerations" appearing in the Prospectus
(the "Public Offering Prospectus") dated June 10, 1993, which constitutes a part
of the Registration Statement on Form S-3 of Burlington Resources (Registration
No. 33-61164) filed in connection with the registration of the Units under the
Securities Act of 1933 for offer and sale in the Public Offering, set forth,
respectively, a summary of Federal income tax matters of general application
that addresses all material tax consequences of the ownership and sale of the
Units acquired in the Public Offering and a discussion of certain risk factors
associated with matters of Federal income taxation as applied to the Trust and
such Unitholders. A copy of such sections of the Public Offering Prospectus is
filed as an exhibit to this Form 10-K.
In connection with the registration of the Units for offer and sale in the
Public Offering, Burlington Resources and the underwriters of the Units received
certain opinions of counsel to Burlington Resources (upon which the Trustee and
the Delaware Trustee were entitled to rely), including, without limitation,
opinions as to the material Federal income tax consequences of the ownership and
sale of the Units acquired in the Public Offering. The opinions of counsel to
Burlington Resources as to such Federal income tax consequences were based on
provisions of the Internal Revenue Code of 1986, as amended (the "IRC"), as of
June 17, 1993, the date of the closing of the Public Offering, existing and
proposed regulations thereunder and administrative rulings and court decisions
as of June 17, 1993, all of which are subject to changes that may or may not be
retroactively applied. Some of the applicable provisions of the IRC have not
been interpreted by the courts or the Internal Revenue Service ("IRS"). In
addition, such opinions of counsel to Burlington Resources were based on various
representations as to factual matters made by Burlington Resources and MOPI in
connection with the Public Offering. As is typically the case, these opinions
were limited in their application to certain investors purchasing Units in the
Public Offering and, as a result, provide no assurance to investors purchasing
Units following the Public Offering.
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Neither counsel to the Trust, the Trustee nor the Delaware Trustee,
respectively, has rendered any opinions with respect to any tax matters
associated with the Trust or the Units.
No ruling was requested by Burlington Resources, as the sponsor of the Trust,
from the IRS with respect to any matter affecting the Trust or Unitholders. No
assurance can be provided that the opinions of counsel to Burlington Resources
(which do not bind the IRS) will not be challenged by the IRS or will be
sustained by a court if so challenged.
SUMMARY OF CERTAIN FEDERAL INCOME TAX CONSEQUENCES
The following summary of certain Federal income tax consequences of acquiring,
owning and disposing of Units is based on the opinions of counsel to Burlington
Resources on Federal income tax matters, which are set forth in the Public
Offering Prospectus, and is qualified in its entirety by express reference to
the sections of the Public Offering Prospectus identified in the first paragraph
of this "Federal Income Taxation" section. Although the Trust believes that the
following summary contains a description of all of the material matters
discussed in the opinions referenced above, the summary is not exhaustive and
many other provisions of the Federal tax laws may affect individual Unitholders.
Furthermore, the summary does not purport to be complete or to address the tax
issues potentially affecting Unitholders acquiring Units other than by purchase
through the Public Offering. Each Unitholder should consult the Unitholder's tax
advisor with respect to the effects of the Unitholder's ownership of Units on
the Unitholder's personal tax situation.
Classification and Taxation
of the Trust.............. The Trust will be treated as a grantor trust and not
as an association taxable as a corporation. As a
grantor trust, the Trust will not be subject to
Federal income tax. There can be no assurance that
the IRS will not challenge this treatment. The tax
treatment of the Trust and Unitholders could be
materially different if the IRS were to successfully
challenge this treatment.
Taxation of Unitholders.... Each Unitholder will be taxed directly on his
proportionate share of income, deductions, and
credits of the Trust attributable to the Royalty
Interests consistent with such Unitholder's taxable
year and method of accounting, and without regard to
the taxable year or method of accounting employed by
the Trust.
Income and Deductions...... The income of the Trust consists primarily of
a specified share of the proceeds from the sale of
coal seam gas produced from the Underlying
Properties. During 1996, the Trust earned interest
income on funds held for distribution and made
adjustments to the cash reserve maintained for the
payment of contingent or future obligations of the
Trust. The deductions of the Trust consist of
severance taxes and administrative expenses. In
addition, each Unitholder is entitled to depletion
deductions. See "Unitholder's Depletion Allowance"
below.
Limits on Deductions
and Credits............... Generally, a taxpayer is entitled to claim
deductions and tax credits generated by an
investment only if the investment has economic
substance. The application of this principle in the
context of the production and sale of
nonconventional fuels (like coal seam gas) which
generate the Section 29 tax credit is uncertain
because such application has not been addressed
either by a court or the IRS. An investment has
economic substance if the investor can demonstrate
that there is a reasonable possibility of deriving
an economic profit from the investment in excess of
a de minimis
14
<PAGE>
amount, apart from tax benefits. In many cases,
economic profit has been computed by comparing the
taxpayer's total cash investment to the total cash
reasonably expected to be received by the taxpayer
as a result of the investment. At the time of the
Public Offering, Burlington Resources, after
consultation with its counsel, expressed its belief
only in connection with the Public Offering that the
purchaser of a Unit in the Public Offering, who did
not borrow funds in order to purchase his Unit, had
a reasonable possibility of deriving an economic
profit in excess of a de minimis amount apart from
tax benefits associated with ownership of the Unit.
No assurance is given either by the Trustee or
counsel to the Trustee to a purchaser of Units in or
following the Public Offering as to whether (and to
what extent) such purchaser will be entitled to
claim deductions and the Section 29 tax credit
generated with respect to such Units.
Section 29 Tax Credit...... Unitholders will be entitled, provided certain
requirements are met, to claim tax credits pursuant
to Section 29 of the IRC with respect to sales of
coal seam gas production attributable to the NPI,
the gross income from which is included in their
taxable income. The Section 29 tax credit provides
to a taxpayer a dollar-for-dollar reduction in his
regular Federal income tax liability, and,
therefore, generally provides to him a greater
benefit than a deduction which merely reduces the
amount of his taxable income. The Section 29 tax
credit applies to coal seam gas produced and sold
prior to January 1, 2003 from qualifying wells. For
a Unitholder who owned the same Units of record on
all four quarterly record dates during 1996, the
available Section 29 tax credit is approximately
$1.116934 per Unit, based on the first estimate of
the GNP implicit price deflator published by the
Bureau of Economic Analysis.
The availability of Section 29 tax credits is
dependent upon meeting a number of requirements,
many of which are factual in nature. Burlington
Resources represented only in connection with the
Public Offering that those factual requirements were
met and Burlington Resources expressed its belief in
connection with the Public Offering that
substantially all of the production attributable to
the NPI from the coal seam gas wells identified in
the reserve estimate as of May 1, 1993, prepared by
MOPI in connection with the Public Offering,
qualified for Section 29 tax credits. At the time of
the Public Offering, counsel to Burlington Resources
opined as to those requirements which are statutory
or legal in nature. If any of the factual
requirements are not met, or the opinion not
followed, some or all of the expected Section 29 tax
credits may not be available.
In addition, if the production units or
participating areas are expanded to include
additional production which does not qualify for the
Section 29 tax credit, the amount of Section 29 tax
credits available to a Unitholder will be reduced
even though his share of production does not
diminish. Neither MOPI nor the Trust can control
whether a production unit or participating area is
expanded.
15
<PAGE>
No Section 29 tax credits will be available under
current law to a Unitholder with respect to
production attributable to the Infill NPI even if an
Infill Well recovers a portion of the reserves that
prior to the drilling and completion of an Infill
Well were recoverable from a well burdened by the
NPI that qualified for Section 29 tax credits.
Limits on Unitholder's Use
of Credits................ In any year, a Unitholder is permitted to
reduce his regular Federal income tax liability by
the Section 29 tax credits allocated to such
Unitholder for such year on a dollar-for-dollar
basis, but only to the extent such Unitholder's
regular tax liability exceeds his alternative
minimum tax liability (with certain adjustments).
Any amount of Section 29 tax credit in excess of a
Unitholder's total regular Federal income tax
liability for a year is permanently lost. Section
29 tax credits cannot be used to reduce a
Unitholder's liability for any alternative minimum
tax for any taxable year but can be carried forward
to reduce his regular tax liability in a subsequent
year (subject to the applicable rules governing such
carryforward(s)).
Quarterly Allocations...... Under the IRC, a Unitholder is entitled to
Section 29 tax credits only to the extent that he is
an owner of the economic interest at the time the
coal seam gas is produced. The Trustee allocates
the income received by the Trust for a quarter, and
the Section 29 tax credit allocable to such income,
to Unitholders of record on the quarterly record
date for such quarter. Such an allocation may be
challenged by the IRS, but any challenge is likely
to have a material adverse effect only if successful
and only for Unitholders who do not own Units for a
full quarter for each record date, particularly
Unitholders who acquire Units shortly before a
record date and sell shortly after a record date.
Unitholder's Depletion
Allowance................. Each Unitholder is entitled to amortize the
cost of the Units through cost depletion over the
life of the NPI (or if greater, through percentage
depletion equal to 15 percent of gross income). If
any portion of the NPI is treated as a production
payment or is not treated as an economic interest,
however, a Unitholder will not be entitled to
depletion in respect of such portion.
Non-Passive Activity Income,
Credits and Loss.......... The income, credits and expenses of the Trust
will not be taken into account in computing the
passive activity losses and income under Section 469
of the IRC for a Unitholder who acquires and holds
Units as an investment and did not acquire them in
the ordinary course of a trade or business. Section
29 tax credits generated by an investment in Units,
therefore, can be utilized to offset regular tax
liability on income from any source, whether active
or passive, subject to other limitations discussed
herein or arising from the individual tax
circumstances of each Unitholder. See "Limits on
Unitholder's Use of Credits" above.
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<PAGE>
Unitholder Reporting
Information............... The Trustee furnishes to Unitholders tax information
concerning royalty income, depletion and the Section
29 tax credits on an annual basis. Year-end tax
information is furnished to Unitholders no later
than March 15 of the following year. See the second
paragraph under "Description of Units -- Periodic
Reports to Unitholders."
Tax Shelter Registration... The Trust is registered as a "tax shelter" and its
tax shelter registration number is 93-147000231.
Issuance of a tax shelter registration number does
not indicate that the investment in Units or the
claimed tax benefits have been reviewed, examined or
approved by the IRS.
Substantial Understatement
Penalty................... Section 6662 of the IRC imposes a penalty in certain
circumstances for a substantial understatement of
taxes if a taxpayer's tax liability is understated
by more than the greater of (a) 10 percent of the
taxes required to be shown on the return and (b)
$5,000 ($10,000 for most corporations). The penalty
(which is not deductible) is 20 percent of the
understatement.
Except in the case of understatements attributable
to "tax shelter" items, which are subject to special
rules discussed below, an item of understatement
will not give rise to the penalty if: (i) there is
or was "substantial authority" for the taxpayer's
treatment of the item or (ii) all the facts relevant
to the tax treatment of the item are adequately
disclosed on the return or on a statement attached
to the return and there is a reasonable basis for
the tax treatment of such item. In the case of
Units, an individual Unitholder may make adequate
disclosure with respect to particular tax items if
certain conditions are met. Special rules enacted
in December 1994 could affect the application of
these provisions with regard to a corporation
acquiring Units after December 8, 1994, to the
extent such provisions were found to apply to the
ownership of Units.
In the case of understatements attributable to "tax
shelter" items, the substantial understatement
penalty may be avoided only if the taxpayer
establishes that, in addition to having substantial
authority for his position, he reasonably believed
that the treatment claimed was more likely than not
the proper treatment of the item. A "tax shelter"
item is one that arises from a form of investment if
its principal purpose was the avoidance or evasion
of Federal income tax. Regulations promulgated by
the IRS indicate that an entity or person has a
principal purpose of avoidance or evasion of Federal
income tax if that purpose "exceeds any other
purpose." No assurance is given either by the
Trustee or counsel to the Trustee as to the possible
application of this penalty, in part because such
application depends largely upon the individual
circumstances under which the Units were acquired.
As a result, purchasers of Units in and after the
Public Offering should consult with their personal
tax advisors.
17
<PAGE>
ERISA CONSIDERATIONS
The section entitled "ERISA Considerations" appearing in the Public Offering
Prospectus sets forth certain information regarding the applicability of the
Employee Retirement Income Security Act of 1974, as amended, and the IRC to
pension, profit-sharing and other employee benefit plans, and is incorporated
herein by reference.
Due to the complexity of the prohibited transaction rules and the penalties
imposed upon persons involved in prohibited transactions, it is important that
potential Qualified Plan investors consult with their counsel regarding the
consequences under ERISA and the IRC of their acquisition and ownership of
Units.
STATE TAX CONSIDERATIONS
The following is intended as a brief summary of certain information regarding
state income taxes and other state tax matters affecting individuals who are
Unitholders. Unitholders are urged to consult their own legal and tax advisors
with respect to these matters.
Unitholders should consider state and local tax consequences of holding Units.
The Trust owns Royalty Interests burdening gas properties located in New Mexico.
New Mexico has an income tax applicable to individuals. In addition to any tax
reporting and payment obligations of his state of residence, a Unitholder is
generally required to file state income tax returns and/or pay taxes in New
Mexico and may be subject to penalties for failure to comply with such
requirements. In addition, New Mexico in the future may require the Trust to
withhold tax from distributions to Unitholders. Unitholders should consult their
own tax advisors to determine their income tax filing requirements in New Mexico
with respect to their share of income of the Trust.
The Trust has been structured to cause the Units to be treated for certain
state law purposes, including state taxation other than income taxation,
essentially the same as other securities, that is, as interests in intangible
personal property rather than as interests in real property. If the Units are
held to be real property or an interest in real property under the laws of New
Mexico, a Unitholder, even if not a resident of such state, could be subject to
devolution, probate and administration laws, and inheritance or estate and
similar taxes, under the laws of such state.
REGULATION AND PRICES
REGULATION OF NATURAL GAS
The production, transportation and sale of natural gas from the Underlying
Properties are subject to Federal and state governmental regulation, including
regulation of tariffs charged by pipelines, taxes, the prevention of waste, the
conservation of gas, pollution controls and various other matters. The United
States has governmental power to impose pollution control measures.
Federal Regulation of Gas. The Underlying Properties are subject to the
jurisdiction of the Federal Energy Regulatory Commission ("FERC") with respect
to various aspects of gas operations including marketing and production of gas.
As a result of the Natural Gas Policy Act of 1978 ("NGPA") and the Natural Gas
Wellhead Decontrol Act of 1989 ("NGWDA"), as of January 1, 1993, the wellhead
price for natural gas is no longer subject to federal regulation. All sales of
natural gas produced from the Underlying Properties are considered under NGPA
and NGWDA to be sold at the wellhead (as opposed to downstream sales or resales)
for purposes of pricing and therefore are not subject to federal regulation.
The transportation of natural gas in interstate commerce is subject to federal
regulation by FERC under the Natural Gas Act ("NGA") and the NGPA. FERC has
initiated a number of regulatory policy initiatives that may affect the
transportation of natural gas from the wellhead to the market and thus may
affect the marketing of natural gas. Such initiatives include regulations which
are intended to further open access to interstate pipelines by requiring such
pipelines to unbundle their transportation services from sales services and
allow customers to choose
18
<PAGE>
and pay for only the services they require, regardless of whether the customer
purchases natural gas from such pipelines or from other suppliers. Although
these regulations should generally facilitate the transportation of natural gas
produced from the Underlying Properties to natural gas markets, the impact of
these regulations on marketing production from the Underlying Properties cannot
be predicted at this time, and such impacts could be significant.
Legislative Proposals. In the past, Congress has been very active in the area
of gas regulation. Legislation enacted in recent years repeals incremental
pricing requirements and gas use restraints previously applicable. At the
present time, it is impossible to predict what proposals, if any, might actually
be enacted by Congress or the various state legislatures and what effect, if
any, such proposals might have on the Underlying Properties and the Trust.
State Regulation. Many state jurisdictions have at times imposed limitations
on the production of gas by restricting the rate of flow for gas wells below
their actual capacity to produce and by imposing acreage limitations for the
drilling of a well. States may also impose additional regulation of these
matters. Most states regulate the production of gas, including requirements for
obtaining drilling permits, the method of developing new fields, provisions for
the unitization or pooling of gas properties, the spacing, operation, plugging
and abandonment of wells and the prevention of waste of gas resources. The rate
of production may be regulated and the maximum daily production allowable from
gas wells may be established on a market demand or conservation basis or both.
Several states have in recent years enacted or proposed regulations intended
to revise significantly current systems of prorationing gas production. If
modified in New Mexico, such modified rules may decrease the total amount of gas
produced in New Mexico, and could result in an increase in market prices for
gas. The foregoing developments have fostered debate regarding the purpose and
effect of the new prorationing rules, with opponents of such rules arguing that
the primary purpose thereof is to increase gas prices by withholding supplies
from the market. The Trustee cannot predict what effect, if any, proration rules
will have on the availability of or prices for the Underlying Properties' gas
supplies.
ENVIRONMENTAL REGULATION
General. Activities on the Underlying Properties are subject to existing
Federal, state and local laws (including case law), rules and regulations
governing health, safety, environmental quality and pollution control. It is
anticipated that, absent the occurrence of an extraordinary event, compliance
with existing Federal, state and local laws, rules and regulations regulating
health, safety, the release of materials into the environment or otherwise
relating to the protection of the environment will not have a material adverse
effect upon the Trust or Unitholders. The Trustee cannot predict what effect
additional regulation or legislation, enforcement policies thereunder, and
claims for damages to property, employees, other persons and the environment
resulting from operations on the Underlying Properties could have on the Trust
or Unitholders. However, any costs or expenses incurred by MOPI in connection
with environmental liabilities arising out of or relating to activities
occurring on, in or in connection with, or conditions existing on or under, the
Underlying Properties before June 17, 1993 will be borne by MOPI and not the
Trust (and MOPI has indemnified the Trust with respect thereto) and such costs
and expenses will not be deducted in calculating NPI Net Proceeds or Infill Net
Proceeds. Any environmental costs or expenses that are attributable to MOPI's
interest in the Underlying Properties that do not fall within the preceding
sentence (including indemnification obligations payable to or on behalf of the
Trustee or the Delaware Trustee relating to matters occurring on or after June
17, 1993) will be paid by MOPI but will be deducted in calculating NPI Net
Proceeds or Infill Net Proceeds and will, therefore, reduce amounts payable to
the Trust.
Solid and Hazardous Waste. The Underlying Properties are carved out of
leasehold interests in certain properties that have produced gas from other
formations for many years. Burlington Resources and MOPI have advised the
Trustee that to their knowledge the operator of the Underlying Properties has
utilized operating and disposal practices that were standard in the industry at
the time, although hydrocarbons or other solid or hazardous wastes may have been
disposed or released on or under the Underlying Properties by the current or
previous operators. Federal, state and local laws applicable to gas-related
wastes and properties have become increasingly more stringent. Under these laws,
the operator of the Underlying Properties or the working interest owners could
be required to remove or remediate previously disposed wastes or property
contamination (including groundwater contamination) or to perform remedial
plugging operations to prevent future contamination.
19
<PAGE>
The operations of the Underlying Properties may generate wastes that are
subject to the Federal Resource Conservation and Recovery Act ("RCRA") and
comparable state statutes. The Environmental Protection Agency (the "EPA") has
limited the disposal options for certain hazardous wastes and may adopt more
stringent disposal standards for nonhazardous wastes.
The operations of the Underlying Properties include the disposal of produced
saltwater by reinjection into the subsurface. Such operations are subject to
Federal and state regulations concerning Class II underground injection control
disposal systems, which are used to dispose of fluids in connection with oil or
natural gas production. To protect against contamination of drinking water,
existing regulations contain stringent requirements relating to the
construction, operation, monitoring, plugging and abandonment of underground
injection wells. If the operator of the reinjection wells fails to maintain the
mechanical integrity of the reinjection wells, the operator of the Underlying
Properties or the working interest owners could be required to cease injection
and perform additional construction, operation, monitoring or corrective action.
Superfund. The Comprehensive Environmental Response, Compensation and
Liability Act ("CERCLA"), also known as the "superfund" law, imposes liability,
regardless of fault or the legality of the original conduct, on certain classes
of persons that contributed to the release of a "hazardous substance" into the
environment. These persons include the current or previous owner and operator of
a site and companies that disposed, or arranged for the disposal, of the
hazardous substance found at a site. CERCLA also authorizes the EPA and, in some
cases, private parties to take actions in response to threats to the public
health or the environment and to seek recovery from such responsible classes of
persons of the costs of such action. In the course of its operations, the
operator of the Underlying Properties has generated and will generate wastes
that may fall within CERCLA's definition of "hazardous substances." The operator
of the Underlying Properties or the working interest owners may be responsible
under CERCLA for all or part of the costs to clean up sites at which such
substances have been disposed. Any such CERCLA liabilities borne by MOPI may be
passed on, proportionately, to the Trust (through deduction of such amounts in
calculating NPI Net Proceeds) only to the extent that any such liability relates
to activities occurring on or under, or in connection with, or conditions
existing on or under, the Underlying Properties on or after June 17, 1993. All
other CERCLA liabilities in connection with MOPI's interest in the Underlying
Properties were retained by MOPI.
Air Emissions. The operations of the Underlying Properties are subject to
Federal, state and local regulations concerning the control of emissions from
sources of air contaminants. Administrative enforcement actions for failure to
comply strictly with air regulations or permits are generally resolved by
payment of a monetary penalty and correction of any identified deficiencies.
Regulatory agencies could require the operators to forego or modify construction
or operation of certain air emission sources.
OSHA. The operations of the Underlying Properties are subject to the
requirements of the Federal Occupational Safety and Health Act ("OSHA") and
comparable state statutes. The OSHA hazard communication standard, the EPA
community right-to-know regulations under Title III of the Federal Superfund
Amendment and Reauthorization Act and similar state statutes require that
information be organized and maintained about hazardous materials used or
produced in the operations. Certain of this information must be provided to
employees, state and local government authorities and citizens.
COMPETITION, MARKETS AND PRICES
The revenues of the Trust and the amount of cash distributions to Unitholders
depend upon, among other things, the effect of competition and other factors in
the market for natural gas. The gas industry is highly competitive in all of its
phases. MOPI encounters competition from major oil and gas companies,
independent oil and gas concerns, and individual producers and operators. Many
of these competitors have greater financial and other resources than MOPI.
Competition may also be presented by alternative fuel sources, including heating
oil and other fossil fuels.
The supply of natural gas capable of being produced in the United States has
exceeded demand in recent years generally as a result of decreased demand for
natural gas in response to economic factors, conservation, lower prices for
alternative energy sources and other factors. As a result of this excess supply
of natural gas, natural gas
20
<PAGE>
producers have experienced increased competitive pressure and significantly
lower prices. Due to the restructuring of the industry over the last nine years
and the producers' method of marketing their gas production, caused mainly by
FERC regulations, minimal gas is sold to pipelines under the past take-or-pay
style long-term (15-20 year) contracts. Pipelines have either renegotiated their
obligations to reflect more market responsive terms, or reduced or ceased
altogether their purchase of gas.
Demand for natural gas production has historically been seasonal in nature and
prices for gas fluctuate accordingly. Due to unseasonably warm weather over the
last several years and the ability of markets to access storage, lower prices
have been received by producers than in prior years. Consequently, on an energy
equivalent basis, gas has sold at a discount to oil for the past several years.
However, during 1996 inventories were drawn down and severe weather created more
demand for natural gas in the second half of the year. Such price fluctuations
and the continuation of a depressed market for natural gas will directly impact
Trust distributions, estimates of Trust reserves and estimated future net
revenue from Trust reserves.
Prices for natural gas are subject to wide fluctuations in response to
relatively minor changes in supply, market uncertainty and a variety of
additional factors that are beyond the control of the Trust and Burlington
Resources. These factors include political conditions in the Middle East, the
price and quantity of imported oil and gas, the level of consumer product
demand, the severity of weather conditions, government regulations, the price
and availability of alternative fuels and overall economic conditions.
Additionally, lower natural gas prices may reduce the amount of gas that is
economic to produce from the Underlying Properties. In view of the many
uncertainties affecting the supply and demand for natural gas, the Trust and
Burlington Resources are unable to make reliable predictions of future gas
prices and demand or the overall effect they will have on the Trust.
ITEM 2. PROPERTIES.
THE ROYALTY INTERESTS
The Royalty Interests conveyed to the Trust entitle the Unitholders to receive
95 percent of the NPI Net Proceeds attributable to MOPI's interest in the
Underlying Properties and 20 percent of MOPI's interest in the Infill Net
Proceeds attributable to any Infill Wells that may be drilled after May 1, 1993.
The Royalty Interests were conveyed to the Trust by means of a single instrument
of conveyance. The Conveyance was recorded in the appropriate real property
records in San Juan and Rio Arriba counties in New Mexico so as to give notice
of the Royalty Interests to creditors and any transferees, who would take an
interest in the Underlying Properties subject to the Royalty Interests. The
Conveyance was intended to convey the Royalty Interests as real property
interests under New Mexico law.
Burlington Resources, through MOPI, owns an interest in the Underlying
Properties subject to and burdened by the Royalty Interests conveyed to the
Trust pursuant to the Conveyance. MOPI receives all payments relating to its
interest in the Underlying Properties and is required, pursuant to the
Conveyance, to pay to the Trust the portion thereof attributable to the Royalty
Interests. Under the Conveyance, the amounts payable by MOPI with respect to the
Royalty Interests are computed with respect to each calendar quarter ending
prior to termination of the Trust, and such amounts are to be paid to the Trust
not later than the 50th day following the end of each calendar quarter. The
amounts paid to the Trust will not include interest on any amounts payable with
respect to the Royalty Interests which are held by MOPI prior to payment to the
Trust. MOPI is entitled to retain all amounts attributable to its interest in
the Underlying Properties which are not required to be paid to the Trust with
respect to the Royalty Interests.
The following description contains a summary of the material terms of the
Conveyance and is subject to and qualified by the more detailed provisions of
the Conveyance, a copy of which is filed as an exhibit to this 10-K.
THE UNDERLYING PROPERTIES
The Royalty Interests were conveyed by MOPI to the Trust out of its net
revenue interest in the Underlying Properties. All of the production from the
Underlying Properties is from the Northeast Blanco Unit in the Fruitland
21
<PAGE>
coal formation in the San Juan Basin in San Juan and Rio Arriba counties in New
Mexico. For the purpose of determining the extent of the Underlying Properties,
as used in this Form 10-K the term "Northeast Blanco Unit" comprises the
Northeast Blanco Unit, a 32,595 acre unit originally formed on July 16, 1951, as
well as rights in one communitized gross well with acreage in both the Northeast
Blanco Unit and the adjoining San Juan 30-6 Unit. The Underlying Properties do
not include MOPI's interest in formations other than the Fruitland coal
formation underlying the Northeast Blanco Unit. The Northeast Blanco Unit is
located in the north-central portion of the San Juan Basin. The San Juan Basin
has been an active area for coal seam gas development, and wells have been
drilled on each of the 320 acre drill blocks within the Northeast Blanco Unit.
The Royalty Interests transferred in the Conveyance to the Trust do not burden
the mineral interests or overriding royalty interests owned by El Paso
Production Company (a wholly owned subsidiary of Burlington Resources), the
royalty and overriding royalty interests owned by Southland Royalty Company (a
wholly owned subsidiary of Burlington Resources and the sponsor of the San Juan
Basin Royalty Trust) or the interests owned by the San Juan Basin Royalty Trust,
respectively, in the Northeast Blanco Unit. El Paso Production Company owns a
.138 percent working interest and a .178 percent net revenue interest in the
Northeast Blanco Unit attributable to its mineral interests and overriding
royalty interests. Southland Royalty Company owns a .221 percent net revenue
interest in the Northeast Blanco Unit attributable to its royalty interests and
overriding royalty interests.
Unitized Areas. Pursuant to the Federal Mineral Leasing Act of 1920, as
amended, and applicable state regulations, owners of oil and gas leases in New
Mexico created large unitized areas consisting of numerous contiguous sections
for the orderly development and conservation of oil and gas reserves. All of the
Fruitland coal seam gas wells on the Underlying Properties are located within
such a unitized area. Operation and development of the Northeast Blanco Unit is
governed by a unit agreement and a unit operating agreement (collectively, the
"Unit Agreement"). Under the Unit Agreement and applicable government
regulations, the unit operator requests regulatory approval from the New Mexico
Commission of Public Lands, the New Mexico Oil Conservation Division and the
Bureau of Land Management of the U.S. Department of Interior (the "Bureau of
Land Management") to establish or expand participating areas which produce oil
and gas in paying quantities from designated formations. The working interests
of participants in a participating area are based on the surface acreage
included in the participating area. Under the terms of the Unit Agreement, the
operator, selected by a vote of the respective working interest owners, performs
all operating functions.
The Underlying Properties currently include 102 gross coal seam wells. One
additional previously existing well in the Northeast Blanco Unit has ceased
production, and no reserves have been attributed to such well in the December
31, 1996 Reserve Report. If subsequently deemed appropriate by the Northeast
Blanco Unit working interest owners, such well could be redrilled and, if
returned to production, MOPI's interest in that well would be burdened by the
NPI. MOPI's working interest share of the capital costs of any such redrilling
would be deducted in calculating NPI Net Proceeds and would, therefore, reduce
amounts payable to the Trust. In addition, any production from that redrilled
well would not entitle Unitholders to Section 29 tax credits. As of December 31,
1996, MOPI had a working interest of approximately 19.6 percent in the
Underlying Properties and a net revenue interest of approximately 16.5 percent
in the Underlying Properties. The operator of the Underlying Properties is
Blackwood & Nichols Co. ("B&N"), an affiliate of Devon Energy Corporation
("Devon") (although the single communitized well included within the Underlying
Properties is operated by MOPI).
Adjacent Properties. In addition to the San Juan 30-6 Unit, MOPI and its
affiliates own significant interests in five other Federal units and eleven non-
unitized wells that are adjacent to the Northeast Blanco Unit. Three of the
Federal units (the San Juan 30-6 Unit, the Allison Unit and the Rosa Unit) are
operated by MOPI or its affiliates. It is possible that production from these
properties could drain coal seam gas from the Underlying Properties and
therefore reduce production from the wells burdened by the Royalty Interests.
However, if drainage were to occur it should be insignificant because of the
well spacing rules and well "set back" rules that have been established by the
New Mexico Oil Conservation Division. These rules are designed to protect the
correlative rights of each owner by limiting the number of wells that can be
drilled and establishing a reasonable distance from adjoining lease or unit
boundaries that each well can be drilled. Currently, the rules in effect for the
Fruitland coal formation provide for one well to be drilled on a 320 acre
drillblock and require each well to be drilled no closer than 790 feet from the
adjacent lease boundary.
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<PAGE>
Working Interest Owners. The following is a list of working interest owners in
the Underlying Properties owning at least a one percent working interest as of
December 31, 1996.
<TABLE>
<CAPTION>
WORKING INTEREST OWNERS WORKING INTEREST PERCENTAGE
----------------------- ---------------------------
<S> <C>
Amoco Production Co.................... 35.4
MOPI................................... 19.6
B&N.................................... 14.6
Devon Blanco Ltd....................... 13.9
EOG Inc................................ 5.6
Phillips - San Juan Partners L.P....... 3.8
Conoco, Inc............................ 2.5
</TABLE>
Well Count and Acreage Summary. The following table shows as of December 31,
1994, 1995 and 1996 the gross and net wells and acreage for the Underlying
Properties.
<TABLE>
<CAPTION>
NUMBER OF WELLS ACRES
--------------- -------------
DECEMBER 31, GROSS NET GROSS NET
- ------------ -------- ----- ------ -----
<S> <C> <C> <C> <C>
1994............................... 102 20 32,595 6,404
1995............................... 102 20 32,595 6,404
1996............................... 102 20 32,595 6,404
</TABLE>
THE NPI
The NPI generally entitles the Trust to receive 95 percent of the NPI Net
Proceeds attributable to MOPI's interest in the Underlying Properties, subject
to possible decrease as described under "--Possible NPI Percentage Reduction."
MOPI will pay its working interest share of capital costs incurred on the
Underlying Properties. Such capital costs will be equal to MOPI's working
interest share of the amounts expended by the operator of the Northeast Blanco
Unit and MOPI will be invoiced for its share of those costs by the operator.
However, the operator and working interest owners of the wells could elect at
any time to implement measures to increase the producible reserves. These
measures, if implemented, could involve additional compression or enhanced or
secondary recovery operations requiring substantial capital expenditures which
would be proportionately borne by the NPI. During 1996 significant capital
expenditures were made in conjunction with the installation of a looped gas
gathering system.
All cumulative lease operating expenses paid after May 1, 1993, and capital
expenses paid on or after January 1, 1994, attributable to MOPI's working
interest in the Underlying Properties (other than any environmental liabilities
related to activities occurring on or under, or in connection with, or
conditions existing on or under, the Underlying Properties before June 17, 1993,
which liabilities will be borne by MOPI and for which MOPI has indemnified the
Trust) will be deducted in calculating NPI Net Proceeds and, therefore, will
reduce amounts payable to the Trust.
If, during any calendar quarter, costs and expenses paid by MOPI and
deducted in calculating the NPI Net Proceeds exceed gross proceeds (such excess
referred to as a "Deficit"), neither the Trust nor Unitholders will be liable to
pay such Deficit directly, but the Trust will receive no payments for
distribution to Unitholders (although MOPI will pay to the Trust amounts
sufficient to pay the administrative expenses of the Trust) until future gross
proceeds exceed future costs and expenses plus the cumulative Deficit and
interest on such cumulative Deficit at Citibank's Base Rate; provided, however,
that in any calendar quarter in which the cumulative Deficit at the end of such
quarter is less than $3,000,000, MOPI will pay to the Trust for distribution to
Unitholders no less than 20 percent of such quarter's NPI Net Proceeds
(calculated before deducting capital costs for such calendar quarter); and
provided further, that if at the end of any calendar quarter, the cumulative
Deficit is $3,000,000 or more, MOPI will not be obligated to make any payment to
the Trust for distribution to Unitholders (although MOPI will pay to the Trust
amounts sufficient to pay the administrative expenses of the Trust) until such
cumulative Deficit is reduced to less than $3,000,000. As of December 31, 1996
no such deficit existed.
23
<PAGE>
RESERVE REPORT
The following table summarizes net proved reserves estimated as of December
31, 1996, and certain related information for the Royalty Interests and MOPI's
interest in the Underlying Properties from the December 31, 1996 Reserve Report
prepared by Netherland, Sewell & Associates, Inc., independent petroleum
engineers. All of such reserves constitute proved developed reserves. Summaries
of the December 31, 1996 Reserve Report, the Prior Reserve Reports and the Prior
Tax Credit Reports are filed as exhibits to this Form 10-K and incorporated
herein by reference. See Note 9 of the Notes to Financial Statements
incorporated by reference in Item 8 hereof for additional information regarding
the net proved reserves of the Trust.
A net profits interest does not entitle the Trust to a specific quantity of
gas but to a portion of gas sufficient to yield a specified portion of the net
proceeds derived therefrom. Proved reserves attributable to a net profits
interest are calculated by deducting an amount of gas sufficient, if sold at the
prices used in preparing the reserve estimates for such net profits interest, to
pay the future estimated costs and expenses deducted in the calculation of the
net proceeds of such interest. Accordingly, the reserves presented for the
Royalty Interests reflect quantities of gas that are free of future costs and
expenses if the price and cost assumptions used in the December 31, 1996 Reserve
Report occur. The December 31, 1996 Reserve Report was prepared in accordance
with criteria established by the Securities and Exchange Commission. At December
31, 1996, the price the Trust was entitled to receive under the Gas Purchase
Contract was $2.74 per MMBtu subject to accrued and unrecouped Price Credits in
the Price Credit Account (see "-- The Royalty Interests -- Gas Purchase
Contract"). For purposes of the preparation of the December 31, 1996 Reserve
Report, however, pricing was held constant at the Minimum Purchase Price of
$1.60 per MMBtu until the accrued Price Credits were recouped by MOTI, after
which $2.74 per MMBtu was utilized for the remaining life of the Royalty
Interests.
<TABLE>
<CAPTION>
MOPI'S INTEREST
ROYALTY IN THE
INTERESTS UNDERLYING PROPERTIES
--------------- ---------------------
<S> <C> <C>
Net Proved Gas Reserves (Bcf)(a)(b)......................... 71.6 80.2
Estimated Future Net Revenues (in millions) (c)............. $116.3 $122.4
Discounted Estimated Future Net Revenues (in millions) (c).. $ 67.3 $ 70.8
</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, 1996, the Blanco Hub Spot Price has decreased
substantially.
(b) The gas reserves were estimated by Netherland, Sewell & Associates, Inc. by
applying volumetric and decline curve analyses.
(c) Estimated future net revenues are defined as the total revenues attributable
to MOPI's interest in the Underlying Properties and to the Royalty Interests
less the relevant share (MOPI's interest share, in the case of MOPI's
interest in the Underlying Properties, and 95 percent thereof, in the case
of the Royalty Interests) of royalties, production, property and related
taxes (including severance taxes), lease operating expenses and future
capital expenditures. Overhead costs (beyond the standard overhead charges
for the nonoperated properties) have not been included, nor have the effects
of depreciation, depletion and Federal income tax. Estimated future net
revenues and discounted estimated future net revenues are not intended and
should not be interpreted as representing the fair market value for the
estimated reserves.
Based upon the production estimates used in the December 31, 1996 Section 29
Tax Credit Report for the January 1, 1997 through December 31, 2002 period, and
assuming constant future Section 29 tax credits at the estimated 1996 rate of
$1.05 per MMBtu, the estimated total future tax credits available from the
production and sale of the net proved reserves from the Royalty Interests would
be approximately $36.1 million, having a discounted present value (assuming a 10
percent discount rate) of approximately $28.5 million.
24
<PAGE>
There are many uncertainties inherent in estimating quantities and values of
proved reserves and in projecting future rates of production and the timing of
development expenditures. The reserve data set forth herein are estimates only,
and actual quantities and values of natural gas are likely to differ from the
estimated amounts set forth herein. In addition, the reserve estimates for the
Royalty Interests will be affected by future changes in sales prices for natural
gas produced and costs that are deducted in calculating NPI Net Proceeds and
Infill Net Proceeds. Further, the discounted present values shown herein were
prepared using guidelines established by the Securities and Exchange Commission
for disclosure of reserves and should not be considered representative of the
market value of such reserves or the Units. A market value determination would
include many additional factors.
HISTORICAL GAS SALES PRICES AND PRODUCTION
The following table sets forth the actual net production volumes from MOPI's
interest in the Underlying Properties, weighted average lifting costs and
information regarding historical gas sales prices for each of the years ended
December 31, 1994, 1995 and 1996:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------
1994 1995 1996
----- ----- -----
<S> <C> <C> <C>
Production from MOPI's interest in the Underlying Properties (Bcf)........ 16.8 14.7 12.2
Weighted average production costs (dollars per Mcf)....................... $0.15 $0.09 $0.12
Weighted average sales price of gas produced from MOPI's interest in the
Underlying Properties (dollars per Mcf).................................. $1.17 $1.08 $1.04
Average Blanco Hub Spot Price (dollars per MMBtu)......................... $1.63 $1.18 $1.66
</TABLE>
POSSIBLE NPI PERCENTAGE REDUCTION
If there has been cumulative production after April 30, 1993 (other than
production attributable to Infill Wells) of at least 161.8 Bcf of natural gas
attributable to MOPI's interest in the Underlying Properties burdened by the
NPI, the percentage of NPI Net Proceeds payable in respect of the NPI will be
reduced with respect to any additional production from MOPI's interest in the
Underlying Properties if the IRR of the "After-tax Cash Flow per Unit" (as
defined below) exceeds 11 percent (or if, as set forth below, a greater amount
of gas has been produced and certain other financial tests are met). For
purposes hereof, "After-tax Cash Flow per Unit" is equal to the sum of the
following amounts that a hypothetical purchaser of a Unit in the Public Offering
would have received or been allocated if such Unit were held through the date of
such determination: (a) total cash distributions per Unit plus (b) total tax
credits available per Unit under Section 29 of the IRC less (c) the total net
taxes payable per Unit (assuming a 31 percent tax rate, the highest effective
Federal income tax rate applicable to individuals at the time of the Public
Offering). IRR is the annual discount rate (compounded quarterly) that equates
the present value of the After-tax Cash Flow per Unit to the $20.50 initial
price to the public of the Units in the Public Offering. Set forth below is a
table that reflects the cumulative production from MOPI's interest in the
Underlying Properties after April 30, 1993 (other than production attributable
to Infill Wells) and the corresponding percentage of NPI Net Proceeds
represented by the NPI and the retained interest of MOPI in the NPI Net
Proceeds:
<TABLE>
<CAPTION>
PERCENTAGE OF NPI
NET PROCEEDS
-----------------
THE TRUST MOPI
--------- ----
<S> <C> <C>
Cumulative Production:
Less than 161.8 Bcf............................. 95 5
161.8 Bcf to 176.5 Bcf.......................... 75 25
More than 176.5 Bcf............................. 50 50
</TABLE>
In addition to the foregoing, the percentage of NPI Net Proceeds payable to
the Trust will be reduced to 25 percent and MOPI's retained percentage of NPI
Net Proceeds will be increased to 75 percent (whether or not the IRR of the
After-tax Cash Flow per Unit exceeds 11 percent) if (i)(a) after April 30, 1993
there has been total production (other than production attributable to Infill
Wells) attributable to MOPI's interest in the Underlying Properties of more than
191.2 Bcf of natural gas, (b) a hypothetical purchaser of a Unit in the Public
Offering would have received a cash return (equal to total cash distributions
per Unit) of not less than the $20.50 initial
25
<PAGE>
offering price in the Public Offering and (c) total capital expenditures
(excluding capital expenditures in connection with any Infill Wells) incurred
between May 1, 1993 and December 31, 2002 and attributable to MOPI's interest in
the Underlying Properties do not exceed $20 million (adjusted for inflation
between May 1, 1993 and December 31, 2002), or (ii)(a) after April 30, 1993
there has been total production (other than production attributable to Infill
Wells) attributable to MOPI's interest in the Underlying Properties of more than
220.7 Bcf of natural gas and (b) a hypothetical purchaser of a Unit in the
Public Offering would have received a cash return satisfying the criteria set
forth in (i)(b) above.
The percentage of NPI Net Proceeds payable in respect of the NPI will be
reduced at any time and from time to time in the amounts set forth above if the
criteria specified in the preceding paragraphs are met. If a reduction in the
percentage of NPI Net Proceeds constituting the NPI occurs, that reduced
percentage shall continue in effect thereafter unless and until a further
reduction occurs. As of December 31, 1996 none of the criteria described above
had been met.
GAS PURCHASE CONTRACT
Under the terms of the Gas Purchase Contract, MOTI is obligated to purchase
the natural gas attributable to MOPI's interest in the Underlying Properties at
the Central Gathering Point. The Gas Purchase Contract commenced as of May 1,
1993, and expires on the termination of the Trust. The monthly price to be paid
by MOTI for natural gas purchased pursuant to the Gas Purchase Contract is,
subject to applicable adjustment, (i) the $1.60 per MMBtu Minimum Purchase Price
less (ii) all costs to be incurred in connection with gathering and/or
transportation charges, taxes, treating and processing costs and other costs
payable in connection with such services from the Central Gathering Point to
main line delivery (collectively, "Deductible Costs"). Additionally, if MOTI's
arrangements for gathering, treating, processing and transporting gas from the
Central Gathering Point are altered by any governmental order, decree,
legislation or regulation relating generally to gathering and transportation
arrangements in the natural gas industry and such alterations materially
increase MOTI's costs of performing its obligations under the Gas Purchase
Contract, such increased costs shall be included in Deductible Costs to the
extent that such increased costs are not recouped by MOTI from its gas
purchaser. The monthly price is subject to adjustments under certain
circumstances as described below:
(a) If the Index Price in any month is greater than the $2.04 per MMBtu
Sharing Price, then MOTI will pay MOPI an amount for each MMBtu of gas
purchased equal to the Sharing Price for such month, less the Deductible Costs
for such month, plus 50 percent of the excess of the Index Price for such
month over the Sharing Price (the "Price Differential") for such month,
provided MOTI has no accrued and unrecouped Price Credits (defined below) in
the Price Credit Account (defined below). If MOTI has accrued and unrecouped
Price Credits in the Price Credit Account, then MOTI will be entitled to
reduce the amount in excess of the Minimum Purchase Price (before deducting
the Deductible Costs) that otherwise would be payable for such month by the
quotient of the balance of accrued and unrecouped Price Credits in the Price
Credit Account as of the beginning of such month divided by the quantity of
MOPI's gas purchased for such month under the Gas Purchase Contract.
(b) If the Index Price in any month is greater than or equal to the Minimum
Purchase Price but less than or equal to the Sharing Price for such month,
then MOTI will pay MOPI an amount for each MMBtu of gas purchased during such
month equal to the Index Price for such month less the Deductible Costs for
such month provided MOTI has no accrued and unrecouped Price Credits in the
Price Credit Account. If MOTI has accrued and unrecouped Price Credits in the
Price Credit Account, then MOTI will be entitled to reduce the amount in
excess of the Minimum Purchase Price (before deducting the Deductible Costs)
that otherwise would be payable for such month by the quotient of the balance
of accrued and unrecouped Price Credits in the Price Credit Account as of the
beginning of such month divided by the quantity of MOPI's gas purchased for
such month under the Gas Purchase Contract.
(c) If the Index Price in any month commencing after December 31, 1993 is
less than the Minimum Purchase Price, then MOTI will pay for each MMBtu of gas
purchased the Minimum Purchase Price less the Deductible Costs for such month,
and MOTI will receive a credit (a "Price Credit") from MOPI for each MMBtu of
natural gas so purchased by MOTI equal to the difference between the Minimum
Purchase Price
26
<PAGE>
and the Index Price. MOTI is required to establish and maintain an account
(the "Price Credit Account") containing the accrued and unrecouped amount of
such Price Credits.
The Index Price was below the Minimum Purchase Price from June 1994 through
1996, with the exception of the months of August, November and December of 1996.
MOTI estimates that, as of December 31, 1996, MOTI had aggregate Price Credits
in the Price Credit Account of approximately $8.9 million of which the Trust's
95 percent interest was approximately $8.5 million.
This entitlement to recoup the Price Credits means that if and when the Index
Price is above the Minimum Purchase Price, future royalty income paid to the
Trust would be reduced until such time as such Price Credits have been fully
recouped. Corresponding cash distributions to Unitholders would also be
reduced.
Each of the Minimum Purchase Price and the Sharing Price will increase by 2.5
percent per annum as of May 1 of each year commencing in 2003.
The Central Gathering Point price in the Gas Purchase Contract is determined
by utilizing a published price (which is before deduction of Deductible Costs),
and then deducting Deductible Costs. As used herein, "Index Price" means for
each month 97 percent of the Blanco Hub Spot Price (such 3 percent deduction
constituting a discount to compensate MOTI for marketing the gas). The Blanco
Hub Spot Price is a posted index price in dollars per MMBtu on a dry basis
published in the first issue of such month in Inside FERC's Gas Market Report
for "El Paso Natural Gas Company, San Juan." Pursuant to the Gas Purchase
Contract, MOTI will have a one-time option to elect to substitute for the
foregoing as the Blanco Hub Spot Price either (i) the average of the two posted
index prices reported each month in Inside FERC's Gas Market Report for "El Paso
Natural Gas Company, San Juan" or (ii) the Blanco Hub posted index price
reported by Inside FERC's Gas Market Report, if either such price is then
published in such publication. All prices used as index prices are delivered
prices at the specified point of delivery and are, therefore, before deducting
Deductible Costs.
In any month in which MOTI recoups Price Credits under the Gas Purchase
Contract, MOPI may be required to calculate royalty payments attributable to
production from the Underlying Properties based on the higher price MOTI
receives when it resells the gas production instead of the lower price payable
by MOTI to MOPI under the Gas Purchase Contract (which price takes into account
the Price Credits recouped by MOTI in such month). Royalties that are payable by
MOPI in respect of such higher gas price will not reduce the NPI Net Proceeds
payable to the Trust. However, the portion of the recouped Price Credits that is
attributable to the royalty percentage of the gas sold in such month shall be
returned to the Price Credit Account by MOTI and recouped by MOTI in future
months.
The Underlying Properties are subject to a gas balancing agreement which,
under certain circumstances, allows any working interest owner (including MOPI)
to take more or less than his working interest share of gas produced. NPI Net
Proceeds and Infill Net Proceeds are calculated on an "entitlements basis,"
whereby the aggregate proceeds from the sale of gas are determined by MOPI as if
MOPI had produced and sold its share of production from the Underlying
Properties, even if the actual volumes delivered to and sold by MOPI are
different from its entitled interest volumes. The effect of such an entitlements
basis calculation is that NPI Net Proceeds or Infill Net Proceeds and,
therefore, the amount thereof paid to the Trust, may include amounts in respect
of production not taken by MOPI because of an imbalance (an imbalance is where
an interest owner is delivered more or less than the actual share of production
to which it is entitled). Likewise, in the event MOPI actually takes and sells
more than its share of production but pays the NPI Net Proceeds or the Infill
Net Proceeds on an entitlements basis, MOPI will receive revenues in excess of
those distributed to the Trust. In the event the price of gas is lower when the
other interest owners make-up the overproduction taken and sold by MOPI than the
price received by MOPI, MOPI will retain the excess of such higher price over
the lower price.
MOPI bases such entitlements calculations upon production estimates furnished
to MOPI by the operator of the Underlying Properties, which estimates may be
subject to subsequent adjustment by the operator after the collection and
evaluation of field data. Because the operator may not determine that such an
adjustment is required until several months after the original estimates are
furnished to MOPI, it is possible that an adjustment with respect to
27
<PAGE>
a particular quarter will not be made until cash amounts have been distributed,
and depletion and Section 29 tax credits have been allocated to Unitholders by
the Trust. MOPI will take such an adjustment into account for the quarter in
which MOPI is advised of such adjustment. The cash distributions made, and
depletion deductions and Section 29 tax credits allocated, in respect of a
future quarterly period on a Unit could be based in part upon such an
adjustment, notwithstanding that the owner of such Unit did not own the Unit
during the quarter in respect of which such adjustment is made.
MOTI's obligation to purchase natural gas pursuant to the Gas Purchase
Contract (as well as MOPI's obligation to sell such gas) may be suspended to the
extent affected by the occurrence of any event that renders the affected party
unable to perform its obligations under the Gas Purchase Contract if the event
could not have been prevented with reasonable foresight, at reasonable cost and
by the exercise of reasonable diligence including: (i) acts of God, lightning,
fires, explosions and other casualties, (ii) strikes and other industrial
disturbances, (iii) acts of the public enemy, wars, epidemics, restraints of
government, civil disturbances, and acts, orders and regulations of governmental
agencies, (iv) inability to acquire or delay in acquiring materials, equipment,
rights-of-way and approvals of regulatory bodies, (v) physical constraint or
restriction of, or accident or blockage of or to, equipment or lines of pipe and
(vi) interruption of MOTI's gathering, treating, processing or transportation
arrangements relating to production from the Underlying Properties, including
such arrangements under the Gas Gathering Contract. Following any such event,
the affected party's obligations under the Gas Purchase Contract will be
suspended during the period of its inability to perform, and such party will use
reasonable efforts to remedy the event and resume full performance as quickly as
reasonably practical.
Although MOTI will likely utilize the natural gas purchased from MOPI pursuant
to the Gas Purchase Contract to satisfy its obligations under a number of resale
agreements with third parties, none of the gas purchased by MOTI pursuant to any
gas purchase agreement (including the Gas Purchase Contract) has been dedicated
to any particular resale agreement, and the arrangements made by MOTI with
respect to reselling any gas purchased by it vary from time to time. The prices
to be paid by third party purchasers, therefore, may also be expected to vary
from time to time, and may be either less than or greater than the price paid by
MOTI pursuant to the Gas Purchase Contract. At times when the Minimum Purchase
Price exceeds the Index Price, MOTI will be required to purchase gas at a price
based on the Minimum Purchase Price. At times when the Index Price exceeds the
Sharing Price, MOTI will receive a benefit from being able to resell gas at
prices generally reflecting the full amount of the excess of the Index Price
over the Sharing Price, while paying MOPI and, therefore, the Trust an amount
generally reflecting only 50 percent of such excess.
The Gas Purchase Contract may not be terminated without the consent of MOTI
and MOPI. Further, it may not be amended in a manner that would materially
adversely affect the revenues to the Trust without the approval of the holders
of a majority of the Units then outstanding. The Gas Purchase Contract is filed
as an exhibit to this Form 10-K. The foregoing summary of the material
provisions of the Gas Purchase Contract is qualified in its entirety by
reference to the terms of such agreement as set forth in such exhibit.
GAS GATHERING CONTRACT
The prices to be paid to MOPI pursuant to the Gas Purchase Contract are prices
payable for the value of gas purchased for production at the Central Gathering
Point. Title to the gas purchased pursuant to the Gas Purchase Contract,
therefore, passes to MOTI at the Central Gathering Point. MOTI is responsible
for gathering, treating, processing and marketing from the Central Gathering
Point all gas purchased pursuant to the Gas Purchase Contract. The price paid by
MOTI pursuant to the Gas Purchase Contract is after deducting Deductible Costs
from the Central Gathering Point. Pursuant to the Gas Gathering Contract, MOGI
gathers, treats and processes all of the production attributable to MOPI's
interest in the Underlying Properties (excluding production attributable to five
wells) from the Central Gathering Point. MOGI, under the Gas Gathering Contract,
treats the gas gathered for MOTI to remove carbon dioxide and water and to
otherwise bring the gas into compliance with the specifications of the Gas
Gathering Contract. At December 31, 1996, MOGI's rates for performing its
services under the Gas Gathering Contract varied from approximately $.30 to
approximately $.43 per Mcf, depending upon the specific point of delivery to
MOGI. MOTI reduces the price that it pays for the gas by the value of gas used
by MOGI as fuel for compression and other facilities. These reductions can not
exceed 6.5 percent of the value of volumes of gas gathered for MOTI. The rates
payable to MOGI pursuant to the Gas Gathering Contract are subject to annual
adjustment on January 1 of each year
28
<PAGE>
on the basis of increases or decreases in a published index measuring consumer
prices. Additionally, these rates may be increased by the amount of any
additional costs incurred by MOGI as a direct result of any governmental action
relating generally to gathering and/or treating agreements in the natural gas
industry. The term of the Gas Gathering Contract will continue until December
31, 2012; thereafter, such contract will continue in effect on a month-to-month
basis.
All of the gas gathered pursuant to the Gas Gathering Contract must first be
gathered from the wellhead to the Central Gathering Point by a unit gathering
system owned by the working interest owners of the Northeast Blanco Unit. The
costs of such initial gathering (including maintenance of the gathering system)
are borne by such working interest owners (including MOPI) and deducted as lease
operating expenses in calculating the NPI Net Proceeds or Infill Net Proceeds,
as the case may be. MOPI does not anticipate any changes in the manner in which
gas will be gathered at the wellhead and transported to the Central Gathering
Point, or in the arrangements relating to use and maintenance of the Northeast
Blanco Unit gathering system.
The Gas Gathering Contract may not be amended in a manner that would
materially adversely affect the revenues to the Trust without the approval of
the holders of a majority of the Units then outstanding. The Gas Gathering
Contract is filed as an exhibit to this Form 10-K. The foregoing summary of the
material provisions of the Gas Gathering Contract is qualified in its entirety
by reference to the terms of such agreement as set forth in such exhibit.
FEDERAL LANDS
Approximately 80 percent of the Underlying Properties are burdened by royalty
interests held by the Federal government. Royalty payments due to the U.S.
government for gas produced from Federal lands included in the Underlying
Properties must be calculated in conformance with a working interest owner's
interpretation of regulations issued by the Minerals Management Service ("MMS"),
a subagency of the U.S. Department of the Interior that administers and receives
revenues from Federal royalties on behalf of the U.S. government. The MMS
regulations cover both valuation standards which establish the basis for placing
a value on production and cost allowances which define those post-production
costs that are deductible by the lessee.
Where gas is sold by a lessee to an affiliate such as MOTI, the MMS
regulations (as well as state regulations with respect to severance taxes) may
ignore the lessee-affiliate transaction and consider the arm's-length sale by
the affiliate as the point of valuation for royalty purposes. Accordingly, MOPI
may be required to calculate royalty payments and severance taxes based on the
price MOTI receives when it markets the gas production (the "Resale Price"),
notwithstanding the price payable by MOTI to MOPI pursuant to the Gas Purchase
Contract. Although the NPI Net Proceeds, 95 percent of which is payable to the
Trust, will reflect the deduction of all royalty and overriding royalty burdens
and state severance taxes, to the extent that the Resale Price exceeds the price
paid for production purchased under the Gas Purchase Contract, NPI Net Proceeds
will not be reduced by the royalties, but will be reduced by the severance
taxes, payable in respect of such excess. Royalties payable in respect of such
excess will be borne by MOPI.
The MMS regulations permit a lessee to deduct from its gross proceeds its
reasonable actual costs of transportation and processing to transport the gas
from the lease to the point of sale in calculating the market value of its
production. Although MOPI will deduct (i) the Deductible Costs paid by MOTI
pursuant to the Gas Gathering Contract and (ii) the gathering charges payable by
MOPI as a working interest owner of the Northeast Blanco Unit gathering system
in calculating the wellhead price of gas produced by MOPI, the MMS could
disallow the deduction of some portion of such charges after review of such
charges on audit of MOPI's royalty as discussed below. If some portion of such
charges is disallowed, the MMS will likely demand additional royalties plus
interest on the amount of the underpayment.
The Trustee has been advised by MOPI that the MMS has from time to time
considered the inclusion of the value of the Section 29 tax credits attributable
to coal seam gas production in the calculation of gross proceeds for purposes of
calculating the royalty that is payable to the MMS. On August 30, 1993, the U.S.
Office of the Inspector General (the "OIG") issued an audit report stating the
view that Section 29 tax credits should be included in the calculation of gross
proceeds and recommending that the MMS pursue collection of additional royalties
with
29
<PAGE>
respect to past and future production. On December 8, 1993, however, the Office
of the Solicitor of the U.S. Department of the Interior gave its opinion to the
MMS that the report of the OIG was incorrect and that Section 29 tax credits are
not part of gross proceeds for the purpose of federal royalty calculations. MOPI
believes that any inclusion of the value of Section 29 tax credits for purposes
of calculating royalty payments required to be made on Federal lands would be
inappropriate since all mineral interest owners, including royalty owners, are
entitled to Section 29 tax credits for their proportionate share of qualifying
coal seam gas production. MOPI has advised the Trustee that it would vigorously
oppose any attempt by the MMS to require the inclusion of the value of Section
29 tax credits in the calculation of gross proceeds. However, if regulations so
to include such value were adopted and upheld, royalty payments would be
increased which would decrease NPI Net Proceeds and, therefore, amounts payable
to the Trust. The reduction in amounts payable to the Trust would cause a
corresponding reduction in associated Section 29 tax credits available to
Unitholders.
The MMS generally audits royalty payments within a six-year period. Although
MOPI calculates royalty payments in accordance with its interpretation of the
then applicable MMS regulations, MOPI does not know whether the royalty payments
made to the U.S. government are totally in conformity with MMS standards until
the payments are audited. If an MMS audit, or any other audit by a Federal or
state body, results in additional royalty charges, together with interest,
relating to production from and after the consummation of the Public Offering in
respect of MOPI's interest in the Underlying Properties, certain of such charges
and interest will be deducted in calculating NPI Net Proceeds for the quarter in
which the charges are paid and in each quarter thereafter until the full amount
of the additional royalty charges and interest have been recovered.
The Trust is subject to certain rules of the Bureau of Land Management under
which the holding of interests in leases by persons other than citizens,
nationals and legal resident aliens of the United States ("Eligible Citizens")
may be limited. As a result, non-Eligible Citizens may be prohibited from owning
Units. If any Units are acquired by persons or entities not constituting
Eligible Citizens, such Unitholders may be required to sell such Units pursuant
to a procedure set forth in the Trust Agreement. See "Item 1--Description of
Units--Possible Divestiture of Units."
SALE AND ABANDONMENT OF UNDERLYING PROPERTIES
MOPI does not have the right to abandon its interest in any well on the
Underlying Properties. However, MOPI does not have control over any decisions
which may be made by the operator and other working interest owners of the
Underlying Properties to abandon any well or property on the Underlying
Properties (although MOPI does exercise influence over such decisions to the
extent of its working interest). Since MOPI does not operate any of the wells on
the Underlying Properties (although MOI operates a single communitized well),
MOPI does not normally control the timing of plugging and abandoning wells. The
Conveyance provides that MOPI's working interest share of the costs of plugging
and abandoning uneconomic wells will be deducted in calculating NPI Net Proceeds
or Infill Net Proceeds, as the case may be.
MOPI may sell its interest in the Underlying Properties, subject to and
burdened by the Royalty Interests, without the consent of the Trust or the
Unitholders. Any purchaser of such interest will be subject to the same
standards, and will possess the same influence, set forth in the preceding
paragraph. Under the Trust Agreement, MOPI has certain rights (but not the
obligation) to purchase the Royalty Interests upon termination of the Trust. See
"Item 1--Description of the Trust--Termination and Liquidation of the Trust."
THE INFILL NPI
The Royalty Interests include the Infill NPI, a net profits interest in any
Infill Wells completed on the Underlying Properties. No Infill Wells have been
drilled and none will be drilled unless, prior to any decision to drill any such
wells by the working interest owners of the Underlying Properties, the well
spacing limitations for coal seam wells in the San Juan Basin are reduced. If
such changes occur and Infill Wells are drilled, the Infill NPI will entitle the
Trust to receive 20 percent of the Infill Net Proceeds. No reserves have been
attributed in the December 31, 1996 Reserve Report or the Prior Reserve Reports
to any Infill Wells.
The Trustee has been advised by Burlington Resources that it believes,
although no assurances are given, that Infill Wells will be drilled on the
Underlying Properties only if the owners of the working interests in such
30
<PAGE>
properties believe that the expenditures required to drill and complete such
Infill Wells will be justified by the expected increase in recoverable reserves
therefrom. Infill Wells may recover a portion of the reserves producible from
wells burdened by the NPI. Accordingly, the drilling of Infill Wells may reduce
the proved reserves attributable to wells burdened by the NPI, although
Burlington Resources has advised the Trustee that it believes that such
reduction will be offset, at least in part, by the reserves then attributable to
such Infill NPI. Because the NPI generally entitles the Trust to 95 percent of
the NPI Net Proceeds and the Infill NPI entitles the Trust to only 20 percent of
the Infill Net Proceeds, no assurance can be given that amounts payable to the
Trust will not be reduced if Infill Wells are drilled. Further, under current
law no Section 29 tax credits will be available with respect to production
attributable to the Infill NPI even if an Infill Well recovers a portion of the
reserves that qualified for Section 29 tax credits because prior to the drilling
and completion of such Infill Well, they were recoverable from a well burdened
by the NPI.
MOPI's working interest share of capital expenditures and operating expenses
relating to any Infill Wells will be deducted in calculating the Infill Net
Proceeds. Such amounts bear no relation to capital and operating costs which
will be deducted in calculating the NPI Net Proceeds. See "--The NPI." During
the term of the Trust, MOPI will account for each of the NPI and the Infill NPI
separately, with the result that no amounts deductible in calculating the NPI
Net Proceeds will be deducted from the Infill NPI revenue stream, and vice
versa. If, during any period, costs and expenses (including interest expenses)
deductible in calculating the portion of the Infill Net Proceeds payable to the
Trust exceed gross proceeds with respect to Infill Wells, neither the Trust nor
Unitholders will be liable for such excess, but the Trust will receive no
payments for distribution to Unitholders with respect to the Infill NPI until
future gross proceeds with respect to such wells exceed future costs and
expenses with respect thereto plus the cumulative excess of such costs and
expenses plus interest thereon at Citibank's Base Rate.
BURLINGTON RESOURCES' PERFORMANCE ASSURANCES
Pursuant to the Trust Agreement, Burlington Resources has agreed to pay each
of the following to the extent not paid by MOPI when due and payable: (i) all
liabilities and capital and lease operating expenses which MOPI is required
under the Conveyance to pay as a working interest owner of the Underlying
Properties; (ii) all NPI Net Proceeds, Infill Net Proceeds and other amounts
which MOPI is obligated to pay to the Trust under the Conveyance; (iii) any
proceeds from a sale of any remaining Royalty Interests that MOPI may elect to
purchase upon termination of the Trust; and (iv) certain indemnification
obligations relating to environmental liabilities in connection with MOPI's
interest in the Underlying Properties (collectively, "MOPI Payment
Obligations"). Burlington Resources has also agreed to pay, to the extent not
paid by MOTI when due and payable, all amounts which MOTI is required to pay to
MOPI in respect of production attributable to the Royalty Interests pursuant to
the terms of the Gas Purchase Contract ("MOTI Payment Obligations"). Burlington
Resources may assign such performance assurance obligations, and may be relieved
of such obligations, upon the occurrence of certain events and to an entity or
entities meeting certain criteria.
TITLE TO PROPERTIES
Burlington Resources has advised the Trustee that it believes that MOPI's
title to its interest in the Underlying Properties is, and the Trust's title to
the Royalty Interests is, good and defensible in accordance with standards
generally accepted in the gas industry, subject to such exceptions which, in the
opinion of Burlington Resources, are not so material as to detract substantially
from the use or value of MOPI's interest in the Underlying Properties or the
Royalty Interests.
The Underlying Properties are typically subject, in one degree or another, to
one or more of the following: (i) royalties and other burdens and obligations,
expressed and implied, under oil and gas leases; (ii) overriding royalties and
other burdens created by MOPI or its predecessors in title; (iii) a variety of
contractual obligations (including, in some cases, development obligations)
arising under operating agreements, farmout agreements, production sales
contracts and other agreements that may affect the properties or their titles;
(iv) liens that arise in the normal course of operations, such as those for
unpaid taxes, statutory liens securing unpaid suppliers and contractors and
contractual liens under operating agreements; (v) pooling, unitization and
communitization agreements, declarations and orders; (vi) irregularities or
ambiguities in the instruments of title; and (vii) easements, restrictions,
rights-of-way and other matters that commonly affect property. To the extent
that such burdens and obligations affect MOPI's
31
<PAGE>
rights to production and the value of production from the Underlying Properties,
they have been taken into account in calculating the Trust's interests and in
estimating the size and discounted net present value of the reserves
attributable to the Royalty Interests. Except as noted below, Burlington
Resources believes that the burdens and obligations affecting MOPI's interest in
the Underlying Properties and Royalty Interests are conventional in the industry
for similar properties, do not, in the aggregate, materially interfere with the
use of the Underlying Properties and will not materially and adversely affect
the discounted net present value of the Royalty Interests.
Although the matter is not entirely free from doubt, Burlington Resources has
advised the Trustee that it believes (based upon the opinions of local counsel
to Burlington Resources with respect to matters of New Mexico law) that the
Royalty Interests should constitute property interests under applicable state
law. Consistent therewith, the Conveyance states that the Royalty Interests
constitute property interests and it was recorded in the appropriate real
property records of San Juan and Rio Arriba counties, New Mexico, the counties
in which the Underlying Properties are located, in accordance with local
recordation provisions. If, during the term of the Trust, MOPI becomes involved
as a debtor in bankruptcy proceedings under the Federal Bankruptcy Code, it is
not entirely clear that all of the Royalty Interests would be treated as
property interests under the laws of New Mexico. If in such a proceeding a
determination were made that the Royalty Interests constitute property
interests, the Royalty Interests should be unaffected in any material respect by
such bankruptcy proceeding. If in such a proceeding a determination were made
that the Royalty Interests constitute executory contracts (a term used, but not
defined, in the Federal Bankruptcy Code to refer to a contract under which the
obligations of both the debtor and the other party to such contract are so
unsatisfied that the failure of either to complete performance would constitute
a material breach excusing performance by the other) and not a property interest
under applicable state law, and if such contract were not to be assumed in a
bankruptcy proceeding involving MOPI, the Trust would be entitled to damages for
breach of such contract covered by the termination of such contract in such
bankruptcy proceeding and, with respect to such entitlement, the Trust would be
treated as an unsecured creditor of MOPI in the pending bankruptcy. Although no
assurance is given, Burlington Resources does not believe that the Royalty
Interests should be subject to rejection in a bankruptcy proceeding as executory
contracts.
ITEM 3. LEGAL PROCEEDINGS.
There are no material pending legal proceedings to which the Trust is a party
or of which any of its property is the subject.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
Not applicable.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED UNITHOLDER MATTERS.
Certain information with respect to the Units of the Trust and the market
therefor is set forth on the inside front cover of the Trust's Annual Report to
Unitholders for the year ended December 31, 1996 under the section entitled
"Units of Beneficial Interest" and is incorporated herein by reference.
ITEM 6. SELECTED FINANCIAL DATA.
Selected financial data of the Trust is set forth on the inside front cover of
the Trust's Annual Report to Unitholders for the year ended December 31, 1996
under "Selected Financial Data" and is incorporated herein by reference.
32
<PAGE>
ITEM 7. TRUSTEE'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS.
The "Trustee's Discussion and Analysis of Financial Condition and Results of
Operations" appearing on pages 2 and 3 of the Trust's Annual Report to
Unitholders for the year ended December 31, 1996 is incorporated herein by
reference.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
The financial statements of the Trust and the notes thereto, together with the
report thereon of Deloitte & Touche LLP, independent auditors, dated March 21,
1997, appearing on pages 4 through 11 of the Trust's Annual Report to
Unitholders for the year ended December 31, 1996 are incorporated herein by
reference.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
The Trust has no directors or executive officers. Each of the Trustee and the
Delaware Trustee is a corporate trustee that may be removed as trustee under the
Trust Agreement, with or without cause, at a meeting duly called and held by the
affirmative vote of Unitholders of not less than a majority of all the Units
then outstanding. Any such removal of the Delaware Trustee shall be effective
only at such time as a successor Delaware Trustee fulfilling the requirements of
Section 3807(a) of the Delaware Code has been appointed and has accepted such
appointment, and any such removal of the Trustee shall be effective only at such
time as a successor Trustee has been appointed and has accepted such
appointment.
ITEM 11. EXECUTIVE COMPENSATION.
The following is a description of certain fees and expenses anticipated to be
paid or borne by the Trust, including fees expected to be paid to Burlington
Resources, the Trustee, the Delaware Trustee, the Transfer Agent, or their
affiliates.
Ongoing Administrative Expenses. The Trust is responsible for paying all
legal, accounting, engineering and stock exchange fees, printing costs and other
administrative and out-of-pocket expenses incurred by or at the direction of the
Trustee or Delaware Trustee and the out-of-pocket expenses of the Transfer
Agent.
Compensation of the Trustee, Delaware Trustee and Transfer Agent. The Trust
Agreement provides for compensation to the Trustee and the Delaware Trustee for
administrative services, out of the Trust assets. The Trustee was paid a 1996
base amount of $39,147, plus an hourly charge for services in excess of a
combined total of 300 hours annually at the Trustee's then standard rate. The
Trustee received total compensation for 1996 of $39,147. The Trustee's annual
base fee escalates at the rate of 3 percent per year. The Delaware Trustee is
paid a fixed annual amount of $10,000. The Trustee and the Delaware Trustee are
each entitled to reimbursement for out-of-pocket expenses. Upon termination of
the Trust, the Trustee will receive, in addition to its out-of-pocket expenses,
a termination fee in the amount of $10,000. If a trustee resigns and a successor
has not been appointed in accordance with the terms of the Trust Agreement
within 210 days after the notice of resignation is received, the fees payable to
that trustee will increase significantly until a new trustee is appointed.
The Transfer Agent receives a transfer agency fee of $5.30 annually per
account (minimum of $15,000 annually), subject to increase or decrease each
December, based upon the change in the Producers' Price Index as published by
the Department of Labor, Bureau of Labor Statistics, plus $1.00 for each
certificate issued in excess of 10,000 annually. The total of fees paid by the
Trust to the Transfer Agent in 1996 was $12,472.
33
<PAGE>
Fees to Burlington Resources. Burlington Resources will receive throughout the
term of the Trust, an administrative services fee for accounting, bookkeeping
and other administrative services relating to the Royalty Interests as described
below in "Item 13 --Administrative Services Agreement".
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
(a) Security Ownership of Certain Beneficial Owners. The Trustee knows of no
Unitholder which is a beneficial owner of more than 5 percent of the outstanding
Units.
(b) Security Ownership of Management. The Trust has no directors or executive
officers. As of March 15, 1997, NationsBank of Texas, N.A., the Trustee, did not
beneficially own any Units. As of March 15, 1997, Mellon Bank (DE) National
Association, the Delaware Trustee, did not beneficially own any Units.
(c) Changes in Control. The Trustee knows of no arrangements the operation of
which may at a subsequent date result in a change in control of the Trust.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
ADMINISTRATIVE SERVICES AGREEMENT
Pursuant to the Trust Agreement, Burlington Resources and the Trust entered
into an Administrative Services Agreement effective May 1, 1993. A copy of the
Administrative Services Agreement is filed as an exhibit to this Form 10-K.
The Administrative Services Agreement obligates the Trust to pay to Burlington
Resources each quarter an administrative services fee for accounting,
bookkeeping and other administrative services relating to the Royalty Interests
and the Underlying Properties. The annual fee for 1996, payable in equal
quarterly installments, was $313,157, and the fee will be adjusted annually,
based upon the change in the Producers' Price Index.
BURLINGTON RESOURCES' CONDITIONAL RIGHT OF REPURCHASE
Burlington Resources retains in the Trust Agreement the right to repurchase
all (but not less than all) outstanding Units at any time at which 15 percent or
less of the outstanding Units is owned by persons or entities other than
Burlington Resources and its affiliates. Any such repurchase would generally be
at a price equal to the greater of (i) the highest price at which Burlington
Resources or any of its affiliates acquired Units during the 90 days immediately
preceding the Determination Date and (ii) the average closing price of Units on
the New York Stock Exchange for the 30 trading days immediately preceding the
Determination Date. Any such repurchase would be conducted in accordance with
applicable Federal and state securities laws. See "Item 1--Description of Units-
- -Conditional Right of Repurchase."
POTENTIAL CONFLICTS OF INTEREST
The interests of Burlington Resources and its subsidiaries and the interests
of the Trust and the Unitholders with respect to the Underlying Properties could
at times be different. As an interest owner in the Underlying Properties, MOPI
could have interests that conflict with the interests of the Trust and
Unitholders. For example, such conflicts could be due to a number of factors
including, but not limited to, future budgetary considerations and the absence
of any contractual obligation on the part of MOPI to spend for development of
the Underlying Properties, except as noted herein. Such decisions may have the
effect of changing the amount or timing of future distributions to Unitholders.
MOPI's interest may also conflict with those of the Trust and Unitholders in
situations involving the sale or abandonment of Underlying Properties. MOPI has
the right at any time, pursuant to the terms of the Conveyance, to sell any of
its interest in the Underlying Properties subject to the Royalty Interests. Such
sales may not be in the best interest of the Trust. Except for amendments to the
Gas Purchase Contract, the Gas Gathering Contract or the Conveyance which must
be approved by the vote of the holders of a majority of all Units then
outstanding if such amendment would materially adversely affect Trust revenues,
no mechanism or procedure has
34
<PAGE>
been included to resolve potential conflicts of interest between the Trust and
Burlington Resources, MOPI, MOTI or MOGI. To the extent that any matters are
brought to a vote of Unitholders where the interests of Burlington Resources
conflict, or potentially conflict, with the interests of the Trust or
Unitholders, Burlington Resources can be expected to vote in its own self
interest. See "Item 2--The Royalty Interests--Sale and Abandonment of Underlying
Properties," "--Gas Purchase Contract" and "--Gas Gathering Contract."
35
<PAGE>
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
(a) The following documents are filed as a part of this report:
1. Financial Statements (incorporated by reference in Item 8. of this report)
PAGE IN 1996
ANNUAL REPORT
TO UNITHOLDERS
(INCORPORATED
BY REFERENCE)
--------------
Independent Auditors' Report................................... 4
Statements of Assets, Liabilities and Trust
Corpus as of December 31, 1996 and 1995....................... 5
Statements of Distributable Income for the years ended
December 31, 1996, 1995 and 1994............................. 5
Statements of Changes in Trust Corpus for the years ended
December 31, 1996, 1995 and 1994............................. 5
Notes to Financial Statements.................................. 6
2. Financial Statement Schedules
Financial statement schedules are omitted because of the absence of conditions
under which they are required or because the required information is included in
the financial statements and notes thereto.
3. Exhibits
EXHIBIT
NUMBER EXHIBIT
------ -------
3.1 -- Certificate of Trust of Burlington Resources Coal Seam Gas Royalty
Trust (filed as Exhibit 3.1 to the Registrant's Form 10-K for the
year ended December 31, 1993 and incorporated herein by reference).
3.2 -- Certificate of Amendment to the Certificate of Trust of Burlington
Resources Coal Seam Gas Royalty Trust (filed as Exhibit 3.2 to the
Registrant's Form 10-K for the year ended December 31, 1993 and
incorporated herein by reference).
4.1 -- Trust Agreement of Burlington Resources Coal Seam Gas Royalty Trust
effective as of May 1, 1993, by and among Meridian Oil Production
Inc., Burlington Resources Inc. and Mellon Bank (DE) National
Association and NationsBank of Texas, N.A., as trustees (filed as
Exhibit 4.1 to the Registrant's Form 10-Q for the quarter ended June
30, 1993 and incorporated herein by reference).
36
<PAGE>
EXHIBIT
NUMBER EXHIBIT
------ -------
10.1 -- Net Profits Interest Conveyance effective as of May 1, 1993, from
Meridian Oil Production Inc. to Burlington Resources Coal Seam Gas
Royalty Trust (filed as Exhibit 10.1 to the Registrant's Form 10-Q
for the quarter ended June 30, 1993 and incorporated herein by
reference).
10.2 -- Administrative Services Agreement effective May 1, 1993, by and
between Burlington Resources Inc. and Burlington Resources Coal Seam
Gas Royalty Trust (filed as Exhibit 10.2 to the Registrant's Form
10-Q for the quarter ended June 30, 1993 and incorporated herein by
reference).
10.3 -- Gas Purchase Contract dated as of May 1, 1993, by and between
Meridian Oil Production Inc. and Meridian Oil Trading Inc. (filed as
Exhibit 10.3 to the Registrant's Form 10-Q for the quarter ended
June 30, 1993 and incorporated herein by reference).
10.4 -- Gas Gathering, Dehydrating and Treating Agreement dated as of May 3,
1990 between Meridian Oil Gathering Inc. and Meridian Oil Trading
Inc., as amended (filed as Exhibit 10.4 to the Registrant's Form 10-
Q for the quarter ended June 30, 1993 and incorporated herein by
reference).
13.1 -- 1996 Annual Report to Unitholders.
23.1 -- Consent of Netherland, Sewell & Associates, Inc.
27.1 -- Financial Data Schedule.
99.1 -- The information under the section captioned "Tax Considerations" on
pages 26-27, the information under the section captioned "Federal
Income Tax Consequences" on pages 57-64, the information under the
section captioned "ERISA Considerations" on pages 64-65, and Exhibit
A of the Prospectus dated June 10, 1993, which constitutes a part of
the Registration Statement on Form S-3 of Burlington Resources Inc.
(Registration No. 33-61164) is incorporated herein by reference to
such Registration Statement.
99.2 -- Reserve Report, dated March 25, 1994, on the estimated reserves,
estimated future net revenues and discounted estimated future net
revenues attributable to the Royalty Interests and MOPI's interest
in the Underlying Properties as of December 31, 1993, prepared by
Netherland, Sewell & Associates, Inc., independent petroleum
engineers (filed as Exhibit 99.2 to the Registrant's Form 10-K for
the year ended December 31, 1993 and incorporated herein by
reference).
99.3 -- Reserve Report, dated March 15, 1995, on the estimated reserves,
estimated future net revenues and discounted estimated future net
revenues attributable to the Royalty Interests and MOPI's interest
in the Underlying Properties as of December 31, 1994, prepared by
Netherland, Sewell & Associates, Inc., independent petroleum
engineers (filed as Exhibit 99.3 to the Registrant's Form 10-K for
the year ended December 31, 1994 and incorporated herein by
reference).
99.4 -- Report, dated March 16, 1995, on the estimated Section 29 tax
credits attributable to the Royalty Interests as of December 31,
1994, prepared by Netherland, Sewell & Associates, Inc., independent
petroleum engineers (filed as Exhibit 99.4 to the Registrant's Form
10-K for the year ended December 31, 1994 and incorporated herein by
reference).
99.5 -- Reserve Report, dated March 18, 1996, on the estimated reserves,
estimated future net revenues and discounted estimated future net
revenues attributable to the Royalty Interests and MOPI's interest
in the Underlying Properties as of December 31, 1995, prepared by
Netherland, Sewell & Associates, Inc., independent petroleum
engineers (filed as Exhibit 99.5 to the Registrant's Form 10-K for
the year ended December 31, 1995 and incorporated herein by
reference).
37
<PAGE>
EXHIBIT
NUMBER EXHIBIT
------ -------
99.6 -- Report, dated March 19, 1996, on the estimated Section 29 tax
credits attributable to the Royalty Interests as of December 31,
1995, prepared by Netherland, Sewell & Associates, Inc., independent
petroleum engineers (filed as Exhibit 99.6 to the Registrant's Form
10-K for the year ended December 31, 1995 and incorporated herein by
reference).
99.7 -- Reserve Report, dated March 20, 1997, on the estimated reserves,
estimated future net revenues and discounted estimated future net
revenues attributable to the Royalty Interests and MOPI's interest
in the Underlying Properties as of December 31, 1996, prepared by
Netherland, Sewell & Associates, Inc., independent petroleum
engineers.
99.8 -- Report, dated March 21, 1997, on the estimated Section 29 tax
credits attributable to the Royalty Interests as of December 31,
1996, prepared by Netherland, Sewell & Associates, Inc., independent
petroleum engineers.
(b) Reports on Form 8-K. No report on Form 8-K was filed by the Registrant
during the last quarter of the period covered by this report.
38
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
BURLINGTON RESOURCES COAL
SEAM GAS ROYALTY TRUST
By: NATIONSBANK OF TEXAS, N.A.,
Trustee
By: /s/ Ron E. Hooper
----------------------------------------
Ron E. Hooper
Vice President and Administrator
Date: March 31, 1997
(The Registrant has no directors or executive officers.)
39
<PAGE>
EXHIBIT 13.1
BURLINGTON RESOURCES COAL SEAM GAS ROYALTY TRUST
1996 ANNUAL REPORT AND FORM 10-K
THE TRUST
Burlington Resources Coal Seam Gas Royalty Trust (the "Trust") was formed as a
Delaware business trust pursuant to the Trust Agreement of Burlington Resources
Coal Seam Gas Royalty Trust entered into effective as of May 1, 1993 by and
among Meridian Oil Production Inc. ("MOPI"), as trustor, Burlington Resources
Inc. ("Burlington Resources"), the parent company of MOPI, and NationsBank of
Texas, N.A. (the "Trustee") and Mellon Bank (DE) National Association (the
"Delaware Trustee"), as trustees. Effective January 1, 1996, MOPI was merged
with and into Meridian Oil Inc. ("MOI"), a wholly owned subsidiary of Burlington
Resources. Effective July 11, 1996, MOI changed its name to Burlington Resources
Oil & Gas Company ("BROG") and Meridian Oil Trading Inc. ("MOTI") and Meridian
Oil Gathering Inc. ("MOGI"), both affiliates of MOI, changed their names to
Burlington Resources Trading Inc. ("BRTI") and Burlington Resources Gathering
Inc. ("BRGI"), respectively. Accordingly, references in this Annual Report to
MOPI refer to BROG, references to MOTI refer to BRTI and references to MOGI
refer to BRGI. The Trust owns certain net profits interests (the" Royalty
Interests") in MOPI's interest in the Fruitland coal formation underlying the
Northeast Blanco Unit in the San Juan Basin of New Mexico (the "Underlying
Properties"). The Royalty Interests are the only assets of the Trust, other than
cash and temporary investments being held for the payment of expenses and
liabilities and for distribution to Unitholders.
The Trust makes quarterly cash distributions to Unitholders. The record date of
the quarterly cash distribution of the Trust is the 63rd day following the end
of the calendar quarter unless such day is not a business day in which case the
record date will be the next business day. The quarterly cash distribution is
payable on or before 75 days after the end of the calendar quarter.
Royalty income to the Trust is attributable to the sale of depleting assets. All
of the Underlying Properties burdened by the Royalty Interests consist of
producing properties. Accordingly, the proved reserves attributable to MOPI's
interest in the Underlying Properties are expected to decline substantially
during the term of the Trust and a portion of each cash distribution made by the
Trust will, therefore, be analogous to a return of capital. Accordingly, cash
yields attributable to the Units are expected to decline over the term of the
Trust.
<TABLE>
<CAPTION>
1997 1998
<S> <C> <C> <C> <C>
Record Dates June 2 September 2 December 2 March 4
Distribution Dates June 13 September 12 December 12 March 16
UNITS OF BENEFICIAL INTEREST
</TABLE>
The units of beneficial interest ("Units") in the Trust are listed and traded on
the New York Stock Exchange under the symbol "BRU." The following table sets
forth, for the periods indicated, the high and low sales prices per Unit on the
New York Stock Exchange and the amount of quarterly cash distributions per Unit
made by the Trust.
<TABLE>
<CAPTION>
Price Distributions
High Low per Unit
<S> <C> <C> <C>
1996
First Quarter $ 13-5/8 $ 10-1/8 $ 0.332882
Second Quarter $ 11-3/4 $ 8-3/4 $ 0.298843
Third Quarter $ 10 $ 8-3/4 $ 0.255385
Fourth Quarter $ 10 $ 8-1/4 $ 0.250990
1995
First Quarter $ 17-5/8 $ 15-1/8 $ 0.364168
Second Quarter $ 17-1/8 $ 14-3/4 $ 0.399989
Third Quarter $ 16 $ 14-3/8 $ 0.385197
Fourth Quarter $ 15-3/8 $ 12-3/8 $ 0.375008
</TABLE>
At March 18, 1997, there were 8,800,000 Units outstanding and approximately
1,188 Unitholders of record.
<PAGE>
SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
FOR THE PERIOD FROM
MAY 5, 1993
FOR THE YEAR ENDED DECEMBER 31, (DATE OF INCEPTION)
---------------------------------------------------- TO DECEMBER 31,
1996 1995 1994 1993
------------ ------------ ------------ --------------------
<S> <C> <C> <C> <C>
ROYALTY INCOME................. $ 10,671,428 $ 14,076,780 $ 17,115,969 $ 6,900,747
DISTRIBUTABLE INCOME........... $ 10,040,541 $ 13,402,397 $ 16,423,579 $ 6,549,172
DISTRIBUTABLE INCOME PER
UNIT.......................... $1.14 $1.52 $1.87 $0.74
DISTRIBUTIONS PER UNIT......... $1.14 $1.52 $1.88 $0.72
TOTAL ASSETS, DECEMBER 31...... $107,530,131 $123,634,960 $147,565,760 $172,184,435
TRUST CORPUS, DECEMBER 31...... $107,328,165 $123,534,740 $147,459,837 $172,153,000
</TABLE>
TO UNITHOLDERS:
We are pleased to present the 1996 Annual Report to Unitholders of Burlington
Resources Coal Seam Gas Royalty Trust (the "Trust"). The report includes a copy
of the Trust's annual report on Form 10-K for the year ended December 31, 1996.
The Form 10-K contains important information concerning the creation and
administration of the Trust, and the assets of the Trust, including coal seam
gas reserves attributable to the net profits interests owned by the Trust
estimated as of December 31, 1996.
The Trust was formed as a Delaware business trust under the Delaware Business
Trust Act pursuant to the Trust Agreement of Burlington Resources Coal Seam Gas
Royalty Trust (the "Trust Agreement") entered into effective as of May 1, 1993
by and among Meridian Oil Production Inc. ("MOPI"), as trustor, Burlington
Resources Inc. ("Burlington Resources"), the parent company of MOPI, and
NationsBank of Texas, N.A. (the "Trustee") and Mellon Bank (DE) National
Association, as trustees. The Trust was formed to acquire and hold certain net
profits interests (the "Royalty Interests") in MOPI's interest in the Fruitland
coal formation underlying the Northeast Blanco Unit in the San Juan Basin of New
Mexico. The Royalty Interests are the only assets of the Trust, other than cash
and temporary investments being held for the payment of expenses and liabilities
and for distribution to Unitholders.
Royalty income to the Trust is attributable to the sale of depleting assets. All
of the Underlying Properties burdened by the Royalty Interests consist of
producing properties. Accordingly, the proved reserves attributable to MOPI's
<PAGE>
interest in the Underlying Properties are expected to decline substantially
during the term of the Trust and a portion of each cash distribution made by the
Trust will, therefore, be analogous to a return of capital. Accordingly, cash
yields attributable to the Units are expected to decline over the term of the
Trust. For additional information concerning the reserves please refer to Note 9
"Supplemental Oil and Gas Information" to the financial statements.
The year 1996 marked the Trust's third full year of operations. Distributable
income for the year ended December 31, 1996 was $10,040,541 or $1.14 per Unit as
compared to $13,402,397 or $1.52 per Unit for 1995. Royalty income for the year
totaled $10,671,428 as compared to $14,076,780 for 1995. The Trust also earned
interest of $28,339 from temporary investments of funds prior to quarterly
distributions being made as compared to $37,576 for 1995. General and
administrative expenses for the year were $659,226 as compared to $711,959 for
1995.
Under the Trust Agreement, the Trustee has the responsibility to collect
proceeds attributable to the Royalty Interests and to make quarterly cash
distributions to Unitholders after deducting administrative expenses and any
amounts necessary for cash reserves. The quarterly record date is the 63rd day
following the end of the calendar quarter unless such day is not a business day
in which case the record date will be the next business day. The quarterly
distribution date is on or prior to 75 days after the end of the calendar
quarter.
Tax information for calendar year 1996 permitting each Unitholder to make all
calculations reasonably necessary for tax purposes was distributed by the
Trustee to Unitholders prior to March 15, 1997, in accordance with the Trust
Agreement. Such income tax information will be provided annually to Unitholders
by the Trustee not later than March 15th of each year.
BURLINGTON RESOURCES COAL SEAM GAS ROYALTY TRUST
BY: NATIONSBANK OF TEXAS, N.A., TRUSTEE
BY:/SIG/RON E. HOOPER
VICE PRESIDENT
MARCH 31, 1997
TRUSTEE'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
The Trust makes quarterly cash distributions to Unitholders. The only assets of
the Trust, other than cash and cash equivalents being held for the payment of
expenses and liabilities and for distribution to Unitholders, are the Royalty
Interests. The Royalty Interests owned by the Trust burden the net revenue
interest in the Underlying Properties which are owned by MOPI and not the Trust.
Distributable income of the Trust consists of the excess of royalty income plus
interest income over the general and administrative expenses of the Trust. Upon
receipt by the Trust, royalty income is invested in short-term investments in
accordance with the Trust Agreement until its subsequent distribution to
Unitholders.
The amount of distributable income of the Trust for any calendar year may differ
from the amount of cash available for distribution to the Unitholders in such
year due to differences in the treatment of the expenses of the Trust in the
determination of those amounts. The financial statements of the Trust are
prepared on a modified cash basis pursuant to which the expenses of the Trust
are recognized when paid or reserves are established for them. Consequently, the
reported distributable income of the Trust for any year is determined by
deducting from the income received by the Trust the amount of expenses paid by
the Trust during such year. The amount of cash available for distribution to
Unitholders, however, is determined in accordance with the provisions of the
Trust Agreement and reflects the deduction from the income actually received by
the Trust of the amount of expenses actually paid by the Trust and adjustment
for changes in reserves for unpaid liabilities. See Note
<PAGE>
5 to the financial statements of the Trust appearing elsewhere in this Annual
Report to Unitholders for additional information regarding the determination of
the amount of cash available for distribution to Unitholders.
Royalty income to the Trust is attributable to the sale of depleting assets. All
of the Underlying Properties burdened by the Royalty Interests consist of
producing properties. Accordingly, the proved reserves attributable to MOPI's
interest in the Underlying Properties are expected to decline substantially
during the term of the Trust and a portion of each cash distribution made by the
Trust will, therefore, be analogous to a return of capital. Accordingly, cash
yields attributable to the Units are expected to decline over the term of the
Trust. For additional information concerning the reserves please refer to Note 9
"Supplemental Oil and Gas Information" of the financial statements.
The year 1996 marked the third full year of operations for the Trust. Royalty
income for 1996 was $10,671,428 as compared to $14,076,780 for 1995 and
$17,115,969 for 1994. Production of 12,122,587 Mcf for 1996 declined from
14,212,659 Mcf for 1995 and 16,706,193 Mcf for 1994 due to the natural decline
of production from the coal seam formation. Natural gas prices received for 1996
were $1.06 per Mcf compared to $1.08 per Mcf for 1995 and $1.22 per Mcf for
1994.
Royalty income received by the Trust in a given calendar year will generally
reflect the proceeds from the sale of gas produced from the Underlying
Properties during the first three quarters of that year and the fourth quarter
of the preceding calendar year less any operating and capital costs.
Accordingly, the royalty income included in distributable income for the years
ended December 31, 1996, 1995 and 1994 was based on production volumes and
natural gas prices for the twelve months ended September 30, 1996, 1995 and
1994, respectively, in accordance with the terms of the conveyance of the
Royalty Interests to the Trust, as shown in the table below. The production
volumes included in the table are actual net production volumes attributable to
MOPI's interest in the Underlying Properties, and not production attributable to
the Royalty Interests owned by the Trust.
<TABLE>
<CAPTION>
For the Twelve Months Ended September 30,
-----------------------------------------
1996 1995 1994
------- ------- -------
<S> <C> <C> <C>
Production (Bcf)(1)................... 12.761 14.961 17.585
Production (Trillion Btu)(2).......... 11.515 13.519 15.881
Average Inside FERC Price
($/MMBtu)(3)......................... $ 1.34 $ 1.22 $ 1.76
MOPI Average Entitled Price Received
($/MMBtu)(4)......................... $ 1.18 $ 1.20 $ 1.36
</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, 1995 and 1994, the Trust's net carrying value of its investment
in royalty interests exceeded the sum of the future net cash flows plus the
estimated future Section 29 tax credit benefits from the production of the
Trust's reserves by $561,809 and $995,048, respectively. Accordingly, the Trust
was required to record an impairment allowance in 1995 and 1994 to
<PAGE>
reduce its carrying value of royalty interests in gas reserves. The reduction in
the carrying value of its investments was charged directly to trust corpus. For
further discussion of impairment, please refer to Notes 2 and 10 in the
financial statements. There was no impairment for 1996.
Production attributable to MOPI's interest in the Underlying Properties is
generally sold pursuant to a gas purchase contract between MOPI and Meridian Oil
Trading Inc. ("MOTI"). The gas purchase contract provides certain protections
for MOTI in the form of price credits and for Unitholders when the applicable
Blanco Hub Spot Price falls below $1.65 per MMBtu and provides certain benefits
for MOTI when the Blanco Hub Spot Price exceeds $2.10 per MMBtu. The gas
purchase contract also provides that the price paid for gas by MOTI is reduced
by the amount of gathering and/or transportation charges, taxes, treating and
processing costs and all other costs in connection with such services from the
central gathering point to main line delivery paid by MOTI. For more detailed
information regarding the terms and conditions of the gas purchase contract, see
"Item 2. Properties -- Gas Purchase Contract" in the Form 10-K of the Trust
appearing elsewhere in this Annual Report to Unitholders.
The Blanco Hub Spot Price was below $1.65 per MMBtu for all months during 1996
except August, November and December. The Blanco Hub Spot Price was below $1.65
per MMBtu in each month during 1995 and during the second, third and fourth
quarters of 1994. However, pursuant to the terms of the gas purchase contract,
MOTI continued to purchase gas attributable to MOPI's interest in the Underlying
Properties at the $1.60 per MMBtu minimum purchase price, less deductible costs
paid by MOTI, established by the gas purchase contract; and MOTI received a
price credit from MOPI for each MMBtu of natural gas so purchased by MOTI equal
to the difference between the $1.60 per MMBtu minimum purchase price and the
applicable index price (which price is equal to 97 percent of the applicable
Blanco Hub Spot Price). MOTI estimates that, as of December 31, 1996, MOTI had
aggregate price credits of approximately $8.9 million of which the Trust's 95
percent interest was approximately $8.5 million. The Blanco Hub Spot Price was
above $1.65 per MMBtu in January and February 1997 although there can be no
assurance that it will not again fall below such price level. With the Blanco
Hub Spot Price being above the minimum purchase price for several months of
1996, MOTI recouped price credits totaling $1.2 million. The entitlement of MOTI
to recoup the price credits means that even though the applicable Blanco Hub
Spot Price is above $1.65 per MMBtu, royalty income otherwise payable to the
Trust will be reduced until such time as all accrued and unrecouped price
credits have been recovered by MOTI. Reduced royalty income to the Trust
correspondingly reduces cash distributions to Unitholders.
The information in this Annual Report to Unitholders concerning production and
prices relating to MOPI's interest in the Underlying Properties is based on
information prepared and furnished by MOPI to the Trustee. The Trustee has no
control over and no responsibility relating to the operation of the Underlying
Properties.
This Annual Report and the accompanying Form 10-K include "forward-looking
statements" within the meaning of Section 21E of the Securities Exchange Act of
1934, which are intended to be covered by the safe harbors created thereby. All
statements other than statements of historical fact included in this Annual
Report and the accompanying Form 10-K are forward-looking statements. Such
statements include, without limitation, the reserve information and other
statements contained in Item 2, "Properties" of the accompanying Form 10-K.
Although the Trust believes that the expectations reflected in such forward-
looking statements are reasonable, such expectations are subject to numerous
risks and uncertainties and the Trust can give no assurance that they will prove
correct. There are many factors, none of which is within the Trust's control,
that may cause such expectations not to be realized, including, among other
things, factors identified in this Annual Report and the accompanying Form 10-K
affecting oil and gas prices and the recoverability of reserves, and future
economic, competitive and market conditions.
FINANCIAL STATEMENTS
Audited Statements of Assets, Liabilities and Trust Corpus of the Trust as of
December 31, 1996 and 1995, and the related Statements of Distributable Income
and Changes in Trust Corpus for the years ended December 31, 1996, 1995 and 1994
are included in this Annual Report to Unitholders immediately following the
Independent Auditors' Report below.
The Royalty Interests owned by the Trust burden the Underlying Properties, which
are owned by MOPI and not the Trust. For the information of Unitholders, an
audited Statement of Revenues and Direct Operating Expenses of the Underlying
Properties for each of the three years in the period ended December 31, 1996 has
been prepared and furnished by MOPI to the Trustee for inclusion in this Annual
Report to Unitholders. The financial statements furnished by MOPI appear
immediately preceding the Form 10-K of the Trust.
<PAGE>
INDEPENDENT AUDITORS' REPORT
NATIONSBANK OF TEXAS, N.A.,
AS TRUSTEE OF BURLINGTON RESOURCES COAL SEAM GAS ROYALTY TRUST
We have audited the accompanying statements of assets, liabilities and trust
corpus of Burlington Resources Coal Seam Gas Royalty Trust as of December 31,
1996 and 1995, and the related statements of distributable income and changes in
trust corpus for each of the three years in the period ended December 31, 1996.
These financial statements are the responsibility of the Trustee. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
As described in Note 2 to the financial statements, these financial statements
have been prepared on a modified cash basis of accounting, which is a
comprehensive basis of accounting other than generally accepted accounting
principles.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the assets, liabilities and trust corpus of the
Burlington Resources Coal Seam Gas Royalty Trust at December 31, 1996, and 1995,
and its distributable income and changes in trust corpus for each of the three
years in the period ended December 31, 1996, on the basis of accounting
described in Note 2.
/SIG/DELOITTE & TOUCHE LLP
Dallas, Texas
March 21, 1997
<PAGE>
FINANCIAL STATEMENTS
BURLINGTON RESOURCES COAL SEAM GAS ROYALTY TRUST
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
<TABLE>
<CAPTION>
December 31, 1996 1995
<S> <C> <C>
ASSETS
CASH AND CASH EQUIVALENTS.............................................................. $ 158,251 $ 31,260
Royalty interests in oil and gas properties (less accumulated amortization and......... 107,371,880 123,603,700
impairment of $73,028,120 and $56,796,300)(Note 10)
TOTAL ASSETS..................................................................... $107,530,131 $123,634,960
LIABILITIES AND TRUST CORPUS
Trust expenses payable................................................................. $ 201,966 $ 100,220
Trust corpus (8,800,000 units of beneficial interest authorized and outstanding)....... 107,328,165 123,534,740
TOTAL LIABILITIES AND TRUST CORPUS..................................................... $107,530,131 $123,634,960
</TABLE>
STATEMENTS OF DISTRIBUTABLE INCOME
<TABLE>
<CAPTION>
<S> <C> <C> <C>
YEAR ENDED DECEMBER 31 1996 1995 1994
ROYALTY INCOME............................ $10,671,428 $ 14,076,780 $ 17,115,969
Interest income........................... 28,339 37,576 36,323
10,699,767 14,114,356 17,152,292
GENERAL AND ADMINISTRATIVE EXPENSES
(NOTE 4)................................. (659,226) (711,959) (728,713)
DISTRIBUTABLE INCOME...................... $10,040,541 $ 13,402,397 $ 16,423,579
DISTRIBUTABLE INCOME PER UNIT
(8,800,000 UNITS)........................ $1.14 $1.52 $1.87
Distributions per unit.................... $1.14 $1.52 $1.88
</TABLE>
STATEMENTS OF CHANGES IN TRUST CORPUS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31 1996 1995 1994
<S> <C> <C> <C>
TRUST CORPUS, BEGINNING OF PERIOD....... $123,534,740 $147,459,837 $172,153,000
Amortization and impairment of royalty
interests.............................. (16,231,820) (23,913,096) (24,564,144)
DISTRIBUTABLE INCOME.................... 10,040,541 13,402,397 16,423,579
DISTRIBUTIONS TO UNITHOLDERS............ (10,015,296) (13,414,398) (16,552,598)
Trust corpus, end of period............. $107,328,165 $123,534,740 $147,459,837
</TABLE>
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.
NOTES TO FINANCIAL STATEMENTS
1. TRUST ORGANIZATION AND PROVISIONS
Burlington Resources Coal Seam Gas Royalty Trust (the "Trust") was formed as a
Delaware business trust pursuant to the terms of the Trust Agreement of
Burlington Resources Coal Seam Gas Royalty Trust (the "Trust Agreement") entered
into effective as of May 1, 1993 by and among Meridian Oil Production Inc., a
Delaware corporation ("MOPI"), as trustor, Burlington Resources Inc., a Delaware
corporation ("Burlington Resources"), and NationsBank of Texas, N.A., a national
banking association (the "Trustee"), and Mellon Bank (DE)
<PAGE>
National Association, a national banking association (the "Delaware Trustee"),
as trustees. Effective January 1, 1996, MOPI was merged with and into Meridian
Oil Inc. ("MOI"), a wholly owned subsidiary of Burlington Resources. Effective
July 11, 1996, MOI changed its name to Burlington Resources Oil & Gas
Company("BROG"), and Meridian Oil Trading Inc. ("MOTI") and Meridian Oil
Gathering Inc.("MOGI"), both affiliates of MOI, changed their names to
Burlington Resources Trading Inc. ("BRTI") and Burlington Resources Gathering
Inc.("BRGI"), respectively. Accordingly, references in this Annual Report to
MOPI refer to BROG, references to MOTI refer to BRTI and references to MOGI
refer to BRGI. The trustees are independent financial institutions.
The Trust is a grantor trust formed to acquire and hold certain net profits
interests (the "Royalty Interests") in MOPI's interest in the Fruitland coal
formation underlying the Northeast Blanco Unit in the San Juan Basin of New
Mexico (the "Underlying Properties"). The Trust was initially created by the
filing of a Certificate of Trust with the Secretary of State of Delaware on May
5, 1993. In accordance with the Trust Agreement, MOPI contributed $1,000 as the
initial trust corpus of the Trust. On June 17, 1993, the Royalty Interests were
conveyed to the Trust by MOPI pursuant to the Net Profits Interest Conveyance
(the "Conveyance") dated effective as of May 1, 1993, in consideration for all
8,800,000 authorized units of beneficial interest ("Units") in the Trust. MOPI
transferred its Units by dividend to its parent, Meridian Oil Holding Inc.,
which transferred such Units by dividend to its parent, Burlington Resources,
which sold such Units to the public through various underwriters in June 1993
(the "Public Offering"). All of the production attributable to the Underlying
Properties is from the Fruitland coal formation and currently constitutes "coal
seam" gas that entitles the owners of such production, provided certain
requirements are met, to tax credits pursuant to Section 29 of the Internal
Revenue Code of 1986, as amended.
Royalty income to the Trust is attributable to the sale of depleting assets. All
of the Underlying Properties burdened by the NPI (as hereinafter defined)
consist of producing properties. Accordingly, the proved reserves attributable
to MOPI's interest in the Underlying Properties are expected to decline
substantially during the term of the Trust and a portion of each cash
distribution made by the Trust will, therefore, be analogous to a return of
capital. Accordingly, cash yields attributable to the Units are expected to
decline over the term of the Trust.
The Trustee has all powers to collect and distribute proceeds received by the
Trust and to pay Trust liabilities and expenses. The Delaware Trustee has only
such powers as are set forth in the Trust Agreement or are required by law and
is not empowered to otherwise manage or take part in the business of the Trust.
The Royalty Interests are passive in nature and neither the Delaware Trustee nor
the Trustee has any control over or any responsibility relating to the operation
of the Underlying Properties or MOPI's interest therein.
The Trust will terminate no later than December 31, 2012, subject to earlier
termination under certain circumstances described in the Trust Agreement (the
"Termination Date"). Cancellation of the Trust will occur on or following the
Termination Date when all Trust assets have been sold and the net proceeds
thereof are distributed to the Unitholders.
The only assets of the Trust, other than cash and cash equivalents being held
for the payment of expenses and liabilities and for distribution to Unitholders,
are the Royalty Interests. The Royalty Interests consist primarily of a net
profits interest (the "NPI") in MOPI's interest in the Underlying Properties.
The NPI generally entitles the Trust to receive 95 percent of the NPI Net
Proceeds, as defined below. The Royalty Interests also include a 20 percent
interest in the Infill Net Proceeds, as defined below, from the sale of
production if well spacing rules are effectively modified and additional wells
are drilled on producing drilling blocks in the Northeast
<PAGE>
Blanco Unit ("Infill Wells") during the term of the Trust. With respect to the
NPI, the term "NPI Net Proceeds" generally means the aggregate proceeds
attributable to MOPI's net revenue interest in the Underlying Properties
(excluding the proceeds, if any, from Infill Wells) calculated at the price paid
by MOTI at any one of four central delivery points in the Northeast Blanco Unit
gathering system or either of two wellhead delivery points (collectively, the
"Central Gathering Point") for the entitled volume of gas produced and sold from
MOPI's interest in the Underlying Properties less MOPI's working interest share
of (i) property, production and related taxes (including severance taxes); (ii)
lease operating expenses; (iii) capital costs (if paid after January 1, 1994);
(iv) royalties, if any, required to be paid that are based on the value of
Section 29 tax credits attributable to such working interest share; and (v)
interest on the unrecovered portion, if any, of the foregoing costs at a rate
equal to the base rate (compounded quarterly) as announced from time to time by
Citibank, N.A. ("Citibank's Base Rate"). The term "Infill Net Proceeds"
generally means the aggregate proceeds attributable to MOPI's net revenue
interest calculated at the price paid by MOTI at the Central Gathering Point for
the entitled volume of gas produced and sold from MOPI's interest in any Infill
Wells less MOPI's working interest share of (a) property, production and related
taxes (including severance taxes) on such Infill Wells; (b) lease operating
expenses with respect to such Infill Wells; (c) capital costs with respect to
such Infill Wells; and (d) interest on the unrecovered portion, if any, of the
foregoing costs at Citibank's Base Rate. The complete definitions of NPI Net
Proceeds and Infill Net Proceeds are set forth in the Conveyance.
Because of the passive nature of the Trust and the restrictions and limitations
on the powers and activities of the Trustee contained in the Trust Agreement,
the Trustee does not consider any of the officers and employees of the Trustee
to be "officers" or "executive officers" of the Trust as such terms are defined
under the applicable rules and regulations adopted under the Securities Exchange
Act of 1934.
2. BASIS OF ACCOUNTING
The financial statements of the Trust are prepared on a modified cash basis and
are not intended to present financial position and results of operations in
conformity with generally accepted accounting principles ("GAAP"). Preparation
of the Trust's financial statements on such basis includes the following:
.Royalty income and interest income are recorded in the period in which amounts
are received by the Trust rather than in the months of production.
.General and administrative expenses recorded are based on liabilities paid and
cash reserves established out of cash received.
.Amortization of the Royalty Interests is calculated on a unit-of-production
basis and charged directly to trust corpus based upon when revenues are
received.
.Distributions to Unitholders are recorded when declared by the Trustee (see
Note 5).
The financial statements of the Trust differ from financial statements prepared
in accordance with GAAP because royalty income is not accrued in the period of
production, general and administrative expenses recorded are based on
liabilities paid and cash reserves established rather than on an accrual basis,
and amortization and impairment of the Royalty Interests is not charged against
operating results.
Burlington Resources sold an aggregate of 8,800,000 Units in the Public
Offering. Accordingly, the carrying value of the Trust's Royalty interest in oil
and gas properties at December 31, 1996 and 1995 reflect 8,800,000 Units at the
public offering price of $20.50 per Unit, less accumulated amortization and
impairment.
<PAGE>
The net amount of royalty interests in gas properties is limited to the sum of
the future net cash flows attributable to the Trust's gas reserves at year end
using current product prices plus the estimated future Section 29 credits for
federal income tax purposes. If the net cost of royalty interests in gas
properties exceeds this amount, an impairment provision is recorded and charged
to the trust corpus.
USE OF ESTIMATES
The preparation of financial statements in conformity with the basis of
accounting described above requires management to make estimates and assumptions
that affect reported amounts of certain assets, liabilities, revenues and
expenses as of and for the reporting periods. Actual results may differ from
such estimates.
NEW ACCOUNTING STANDARDS
Statements of Financial Accounting Standards ("SFAS") No. 121 "Accounting for
the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of"
establishes accounting standards for the impairment of long-lived assets,
certain identifiable intangibles, and goodwill related to those assets to be
held and used and for long-lived assets and certain identifiable intangibles to
be disposed of. SFAS No. 121 requires the review of long-lived assets and
certain identifiable intangibles for impairment. If an impairment event occurs
and it is determined that the carrying value of the asset may not be
recoverable, an impairment loss will be recognized as measured by the amount by
which the carrying amount of the assets exceeds the fair value of the asset. The
Trustee adopted SFAS No. 121 effective January 1, 1996 . Such implementation did
not have any impact on the financial statements of the Trust (see Note 10).
3. FEDERAL INCOME TAXES
The Trust is a grantor trust for Federal income tax purposes. As a grantor
trust, the Trust will not be required to pay federal or state income taxes.
Accordingly, no provision for income taxes has been made in these financial
statements.
Because the Trust will be treated as a grantor trust, and because a Unitholder
will be treated as directly owning an interest in the Royalty Interests, each
Unitholder will be taxed directly on his per Unit share of income attributable
to the Royalty Interests consistent with the Unitholder's method of accounting
without regard to the taxable year or accounting method employed by the Trust.
Production from coal seam gas wells drilled after December 31, 1979 and prior to
January 1, 1993, qualifies for the Federal income tax credit for producing
nonconventional fuels under Section 29 of the Internal Revenue Code. This tax
credit is calculated annually based on each year's qualified production through
the year 2002. Such credit, based on the Unitholder's pro rata share of
qualifying production, may not reduce his regular tax liability (after the
foreign tax credit and certain other non-refundable credits) below his
alternative minimum tax. Any part of the Section 29 credit not allowed for the
tax year solely because of this limitation is subject to certain carryover
provisions. Each Unitholder should consult his tax advisor regarding Trust tax
compliance matters.
4. RELATED PARTY TRANSACTIONS
Burlington Resources provides accounting, bookkeeping and informational services
to the Trust in accordance with an Administrative Services Agreement effective
May 1, 1993. The fee is $75,000 per quarter, adjusted annually, based upon the
change in the Producer's Price Index each January 1 commencing January 1, 1994.
Aggregate fees paid by the Trust to Burlington Resources in 1996, 1995 and 1994
were $313,157, $305,695 and $300,600, respectively.
Aggregate fees paid by the Trust to the Trustee in 1996, 1995 and 1994 were
$39,147, $38,192 and $37,080, respectively. The Delaware Trustee was paid a
flat fee of $10,000 for each of the respective years.
<PAGE>
5. DISTRIBUTIONS TO UNITHOLDERS
The Trustee determines for each quarter the amount of cash available for
distribution to Unitholders. Such amount (the "Quarterly Distribution Amount")
is an amount equal to the excess, if any, of the cash received by the Trust, on
or before the last business day before the 50th day following the end of each
calendar quarter from the Royalty Interests attributable to production during
such quarter, plus, with certain exceptions, any other cash receipts of the
Trust during such quarter, over the liabilities of the Trust paid during such
quarter, subject to adjustments for changes made by the Trustee during such
quarter in any cash reserves established for the payment of contingent or future
obligations of the Trust.
The Quarterly Distribution Amount for each quarter is payable to Unitholders of
record on the 63rd day following the end of such calendar quarter unless such
day is not a business day in which case the record date is the next business day
thereafter. The Trustee distributes the Quarterly Distribution Amount on or
prior to the 75th day after the end of each calendar quarter to each person who
was a Unitholder of record on the associated record date, together with interest
estimated to be earned on such amount from the date of receipt thereof by the
Trustee to the payment date.
The Royalty Interests may be sold under certain circumstances and will be sold
following termination of the Trust. A special distribution will be made of
undistributed net sales proceeds and other amounts received by the Trust
aggregating in excess of $10,000,000 (a "Special Distribution Amount"). The
record date for a Special Distribution Amount will be the 15th day following
receipt of amounts aggregating a Special Distribution Amount by the Trust
(unless such day is not a business day in which case the record date will be the
next business day thereafter) unless such day is within 10 days prior to the
record date for a Quarterly Distribution Amount in which case the record date
will be the date as is established for the next Quarterly Distribution Amount.
Distribution to Unitholders of a Special Distribution Amount will be made no
later than 15 days after the Special Distribution Amount record date.
6. CONTINGENCIES
Under the terms of the gas purchase contract entered into between MOPI and an
affiliate of MOPI (the "Gas Purchase Contract"), additional revenues may be paid
to the Trust to meet the minimum purchase price provision of $1.60 per MMBtu
(the "Minimum Purchase Price") (less applicable deductions). This additional
revenue is subject to recoupment by MOPI from future revenues received from
production when the applicable index price in such month exceeds the Minimum
Purchase Price.
The applicable index price was below the Minimum Purchase Price during 1996
except for the months of August, November and December, and in each month during
1995 and during the second, third and fourth quarters of 1994. Pursuant to the
terms of the Gas Purchase Contract, MOTI established a price credit account.
MOTI estimates that, as of December 31, 1996, MOTI had aggregate price credits
in the price credit account of approximately $8.9 million of which the Trust's
95 percent interest was approximately $8.5 million. The applicable index price
was above the Minimum Purchase Price in January and February 1997.
The Trustee has been advised by MOPI that the Minerals Management Service
("MMS"), a subagency of the U.S. Department of the Interior, has from time to
time considered the inclusion of the value of the Section 29 tax credits
attributable to coal seam gas production in the calculation of gross proceeds
for purposes of calculating the royalty that is payable to the MMS. On August
31, 1993, the U.S. Office of the Inspector General (the "OIG") issued an audit
report stating the view that Section 29 tax credits should be included in the
calculation of gross proceeds and recommended that the MMS pursue collection of
additional royalties with respect to past and future production. On December 8,
1993, however, the Office of the Solicitor of the U.S. Department of the
Interior gave its opinion to the MMS that the report of the OIG was
<PAGE>
incorrect and that Section 29 tax credits are not part of gross proceeds for the
purpose of Federal royalty calculations. MOPI believes that any inclusion of the
value of Section 29 tax credits for purposes of calculating royalty payments
required to be made on Federal lands would be inappropriate since all mineral
interest owners, including royalty owners, are entitled to Section 29 tax
credits for their proportionate share of qualifying coal seam gas production.
MOPI has advised the Trustee that it would vigorously oppose any attempt by the
MMS to require the inclusion of the value of Section 29 tax credits in the
calculation of gross proceeds. However, if such regulations were adopted and
upheld, royalty payments would be increased which would decrease NPI Net
Proceeds and, therefore, amounts payable to the Trust. The reduction in amounts
payable to the Trust would cause a corresponding reduction in associated Section
29 tax credits available to Unitholders.
Per the terms of the Gas Purchase Contract, all royalty income of the Trust was
derived from MOPI.
7. SUBSEQUENT EVENT
Subsequent to December 31, 1996, the Trust declared the following distribution:
Quarterly Record Date Payment Date Distribution per Unit
March 4, 1997 March 14, 1997 $.147801
The Trustee has estimated the Section 29 tax credit associated with the March
14, 1997 quarterly distribution to be $.18 per Unit (unaudited).
8. QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly financial data for the periods ended December 31, 1996
and 1995 are as follows (in thousands except per unit amount):
<TABLE>
<CAPTION>
Calendar Quarter Royalty Income Distributable Distributable
Income Income per Unit
<S> <C> <C> <C>
1996
First $ 3,101 $ 2,920 $ .33
Second 2,852 2,638 .30
Third 2,423 2,309 .26
Fourth 2,295 2,174 .25
$10,671 $10,041 $1.14
1995
First $ 3,308 $ 3,174 $ .36
Second 3,812 3,517 .40
Third 3,528 3,398 .39
Fourth 3,429 3,313 .37
$14,077 $13,402 $1.52
</TABLE>
<PAGE>
Selected 1996 fourth quarter data are as follows (in thousands except per unit
amounts):
<TABLE>
<S> <C>
Royalty income......................................... $ 2,295
Interest income........................................ 6
General and administrative expenses.................... (127)
-------
Distributable income................................... $ 2,174
=======
Distributable income per unit.......................... $ .25
=======
Distribution per unit.................................. $ .25
=======
</TABLE>
Due to the significant upward revision in estimated reserve quantities (see Note
9), estimated amortization of royalty interests was adjusted downward by
approximately $3.3 million during the fourth quarter of 1996. This adjustment
did not have an impact on the Trust's distributable income.
9. SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
The net proved reserves attributable to the Royalty Interests, all located
within the United States, have been estimated as of December 31, 1996, 1995 and
1994 by independent petroleum engineers.
In accordance with Statement of Financial Accounting Standards No. 69, estimates
of future net revenues from proved reserves have been prepared either using end-
of-period or contractual gas prices as appropriate and related costs. The
standardized measure of future net revenues from the gas reserves is calculated
based on discounting such future net revenues at an annual rate of 10 percent.
At December 31, 1996, the price the Trust was entitled to receive under the Gas
Purchase Contract was $2.74 per MMBtu subject to accrued and unrecouped price
credits (see Note 6). For purposes of preparation of the reserve report as of
December 31, 1996, however, pricing was held constant at the minimum purchase
price ($1.60 per MMBtu) until the accrued price credits were recouped by MOTI,
after which $2.74 per MMBtu was utilized for the remaining life of the Royalty
Interests.
Numerous uncertainties are inherent in estimating volumes and value of proved
developed reserves and in projecting future production rates. Such reserve
estimates are subject to change as additional information becomes available. The
reserves actually recovered and the timing of production may be substantially
different from the original estimates.
The reserve estimates for the Royalty Interests are based on a percentage share
of NPI Net Proceeds payable to the Trust of 95 percent. A net profits interest
does not entitle the Trust to a specific quantity of gas but to a portion of gas
sufficient to yield a specified portion of the net proceeds derived therefrom.
Proved reserves attributable to a net profits interest are calculated by
deducting an amount of gas sufficient, if sold at the prices used in preparing
the reserve estimates for such net profits interest, to pay the future estimated
costs and expenses deducted in the calculation of the net proceeds of such
interest. Accordingly, the reserves presented for the Royalty Interests reflect
quantities of gas that are free of future costs and expenses if the price and
cost assumptions used in the reserve report prepared as of December 31, 1996
occur.
<TABLE>
<CAPTION>
Natural Gas (MMcf)
<S> <C>
Proved reserves at January 1, 1994...... 108,025
Revisions of previous estimates.......... (1,752)
Production............................... (15,941)
-------
Proved reserves at December 31, 1994..... 90,332
Revisions of previous estimates.......... 208
Production............................... (13,995)
-------
Proved reserves at December 31, 1995..... 76,545
Revisions of previous estimates.......... 6,671
Production............................... (11,582)
-------
Proved reserves at December 31,1996...... 71,634
=======
</TABLE>
<PAGE>
All proved reserve estimates presented above are proved developed.
Proved reserves are estimated quantities of natural gas which geological and
engineering data indicate with reasonable certainty to be recoverable in future
years from known reservoirs under existing economic and operating conditions.
Proved developed reserves are proved reserves which can be expected to be
recovered through existing wells with existing equipment and operating methods.
The following table sets forth the standardized measure of discounted future net
revenues at December 31, 1996, 1995 and 1994 relating to proved reserves (in
thousands):
<TABLE>
<CAPTION>
1996 1995 1994
<S> <C> <C> <C>
Future cash inflows................. $ 143,716 $ 94,079 $ 110,439
Future production taxes,
operating costs, and capital
expenditures...................... (27,410) 19,048 (24,470)
--------- --------- ---------
Future net cash flows............... 116,306 75,031 85,969
10% discount factor................. (49,001) (27,461) (30,286)
--------- --------- ---------
Standardized measure of
discounted future net revenues.... $ 67,305 $ 47,570 $ 55,683
========= ========= =========
</TABLE>
The following table sets forth the changes in the aggregate standardized measure
of discounted future net revenues from proved reserves during the years ended
December 31, 1996, 1995 and 1994 (in thousands):
<TABLE>
<CAPTION>
1996 1995 1994
<S> <C> <C> <C>
Balance at January 1.............. $47,570 $ 55,683 $ 91,423
Increase (decrease) due to:
Net sales of coal seam gas....... (9,042) (13,826) (15,906)
Net changes in prices and costs.. 18,444 (80) (25,600)
Changes in estimated volumes..... 5,576 225 (3,376)
Accretion of discount............. 4,757 5,568 9,142
------- -------- --------
Balance at December 31............ $67,305 $ 47,570 $ 55,683
======= ======== ========
</TABLE>
The above reserves do not include undiscounted Section 29 tax credits of
approximately $36,055,600 as estimated by an independent petroleum engineer. The
present discounted (10%) value of these tax credits is approximately
$28,479,900.
Subsequent to year end 1996, the price of gas decreased significantly. As of
March 21,1997, published natural gas prices were approximately 1.53 per MMBtu as
compared to prices utilized in the Trust's calculation of its year end
standardized measure of discounted future net cash flow. The use of prices
currently being received would result in a lower standardized measure of
discounted future net cash flows.
<PAGE>
10. IMPAIRMENT OF ROYALTY INTERESTS
At December 31, 1995 and 1994, the Trust's net carrying value of its investment
in royalty interests exceeded the sum of the future net cash flows plus the
estimated future Section 29 tax credit benefits from the production of the
Trust's reserves by $561,809 and $995,048, respectively. Accordingly, the Trust
was required to record an impairment allowance during 1995 and 1994 to reduce
its carrying value of royalty interests in gas reserves. The reduction in the
carrying value of its investments was charged directly to trust corpus. There
was no impairment in 1996. For further discussion of impairment see Note 2. As
more fully discussed in Note 2, beginning in 1996 the Trust was required to
adopt SFAS No. 121. SFAS No. 121 requires that if an impairment event occurs and
it is determined that the carrying value of the Trust's royalty interests may
not be recoverable, an impairment will be recognized as measured by the amount
by which the carrying amount of the royalty interests exceeds the fair value of
these assets, which would likely be measured by discounting projected cash
flows. Should the aggregate dollar amount of the Trust's reserves and Section 29
credits decline, an additional impairment provision, which could be material,
will be required. There can be no assurance such a writedown will not occur.
SUPPLEMENTAL INFORMATION REGARDING THE UNDERLYING PROPERTIES
The Royalty Interests owned by the Trust burden MOPI's interest in the
Underlying Properties. The Royalty Interests are passive in nature and neither
the Trustee nor the Delaware Trustee has any control over or responsibility
relating to the operation of the Underlying Properties or MOPI's interest
therein. For the information of Unitholders, the following Statement of Revenues
and Direct Operating Expenses of MOPI's interest in the Underlying Properties
for each of the three years in the period ended December 31, 1996, auditied by
Coopers & Lybrand L.L.P., independent accountants, has been prepared and
furnished by MOPI to the Trustee for inclusion herein.
<PAGE>
REPORT OF INDEPENDENT ACCOUNTANTS
TO BOARD OF DIRECTORS OF
BURLINGTON RESOURCES INC.:
We have audited the accompanying Statement of Revenues and Direct Operating
Expenses ("Statement") of certain coal seam gas producing properties of
Burlington Resources Oil & Gas Company ("the Underlying Properties") for each of
the three years in the period ended December 31, 1996. In 1996, Meridian Oil
Inc., the successor by merger of Meridian Oil Production Inc., changed its name
to Burlington Resources Oil & Gas Company (the "Company"). The financial
statement is the responsibility of Company's management. Our responsibility is
to express an opinion on this financial statement based upon our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statement is free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statement. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall statement presentation. We believe
that our audits provide a reasonable basis for our opinion.
The accompanying Statement reflects the revenue and direct operating expenses
attributable to the Company's interest in the Underlying Properties as described
in Note 2 and is not intended to be a complete presentation of the revenues and
expenses of the Company's interest in the Underlying Properties.
In our opinion, the Statement presents fairly, in all material respects, the
revenues and direct operating expenses of the Company's interest in the
Underlying Properties as described in Note 2 for each of the three years in the
period ended December 31, 1996, in conformity with generally accepted accounting
principles.
/SIG/COOPERS & LYBRAND L.L.P.
Fort Worth, Texas
March 21, 1997
<PAGE>
BURLINGTON RESOURCES OIL & GAS COMPANY'S INTEREST IN THE UNDERLYING PROPERTIES
STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES
<TABLE>
<CAPTION>
(In thousands)
Years Ended December 31,
1996 1995 1994
<S> <C> <C> <C>
Revenues $12,682 $16,009 $19,573
------- ------- -------
Direct operating expenses
Taxes on production and property 1,228 1,111 1,871
Lease operating expenses 455 433 624
------- ------- -------
1,683 1,544 2,495
------- ------- -------
Excess of revenues over direct
operating expenses $10,999 $14,465 $17,078
======= ======= =======
</TABLE>
The accompanying notes are an integral part of this financial statement.
BURLINGTON RESOURCES OIL & GAS COOMPANY'S INTEREST IN THE UNDERLYING PROPERTIES
NOTES TO THE FINANCIAL STATEMENTS
1. BURLINGTON RESOURCES OIL & GAS COMPANY'S INTEREST IN THE UNDERLYING
PROPERTIES
The interest of Burlington Resources Oil & Gas Company in certain coal seam gas
producing properties (the "Underlying Properties") consists of certain interests
in the Fruitland Coal formation owned by Burlington Resources Inc. through the
Company. The Underlying Properties, substantially all of which are located in
the Northeast Blanco Unit in the San Juan Basin of New Mexico, are burdened by a
Net Profits Interest Conveyance from Meridian Oil Production Inc. to the
Burlington Resources Coal Seam Gas Royalty Trust ("Trust") dated May 1, 1993
("Conveyance"). In 1996, Meridian Oil Inc., the successor by merger of Meridian
Oil Production Inc., changed its name to Burlington Resources Oil & Gas Company
(the "Company").
2. BASIS OF PRESENTATION
The accompanying financial statement does not include depreciation, depletion
and amortization, interest, general and administrative expenses or income taxes
as such information is either not readily available on an individual property
basis or relevant for purposes of the Trust. During the periods presented, the
Underlying Properties were not accounted for as a separate entity. Accordingly,
the financial statement is not intended to represent the financial position,
results of operations, or cash flows of the Underlying Properties in conformity
with generally accepted accounting principles.
Revenues are presented on an accrual basis using the production entitlement
method as set forth in the Conveyance. The Company's revenues are recorded based
upon its Net Revenue Interest Percentage (as defined in the Conveyance).
Revenues are reflected net of existing royalties, overriding royalties and
gathering, treating and processing expenses. The Company's actual cash receipts
may vary from accrued revenues due to timing delays of receipt of cash from the
operators of the Underlying Properties or purchasers, and due to wellhead and
pipeline volume balancing agreements or practices. The Company produced and sold
more gas than its entitled share based upon its working interest in the
Underlying Properties, and thus is in an over-produced position of approximately
297 million cubic feet ("MMcf"), 258 MMcf and 1,100 MMcf as of December 31,
1996, 1995 and 1994, respectively. Expenses are presented on an accrual basis.
The preparation of the financial statement requires the Company to make
estimates and assumptions that affect the reported amounts of revenues and
direct operating expenses during the reporting periods. Actual results could
differ from such estimates.
<PAGE>
3. RELATED PARTY TRANSACTIONS
Prior to May 1, 1993, the Company's production from the Underlying Properties
was sold to Meridian Oil Trading Inc. ("MOTI"), an affiliate of the Company,
based on MOTI's posted price. Beginning May 1, 1993, the Company's production
from the Underlying Properties was sold to MOTI under the terms of the Gas
Purchase Contract between the Company and MOTI dated May 1, 1993 ("Gas Purchase
Contract"). In 1996, MOTI changed its name to Burlington Resources Trading Inc.
("BRTI"). The monthly price paid by BRTI for natural gas purchased pursuant to
the Gas Purchase Contract is (i) the greater of (a) $1.60 per million British
thermal units ("Minimum Purchase Price") and (b) the Index Price (as defined in
the Gas Purchase Contract) up to the Sharing Price (as defined in the Gas
Purchase Contract), less, in each case, (ii) gathering, treating and processing
charges incurred in connection with such production, and plus (iii) a price
differential, if any, when the Index Price exceeds the Sharing Price. After
December 31, 1993, to the extent BRTI was required pursuant to the Gas Purchase
Contract to pay a price based on the Minimum Purchase Price rather than the
Index Price, BRTI is entitled to accrue certain price credits that will be used
to reduce the purchase price of gas under the Gas Purchase Contract when the
Index Price exceeds the Minimum Purchase Price. BRTI has the right to recover
price credits of $8.9 million and $7.4 million as of December 31, 1996 and
1995, respectively. During 1996, BRTI accrued an additional $2.7 million in
price credits and recovered price credits totaling $1.2 million.
The Company's production from the Underlying Properties is gathered, treated and
processed under the terms of the Gas Gathering, Dehydrating and Treating
Agreement between the Company and Meridian Oil Gathering Inc. ("MOGI") dated May
3, 1990, as amended May 1, 1993 ("Gas Gathering , Dehydrating and Treating
Agreement"). In 1996, MOGI changed its name to Burlington Resources Gathering
Inc. ("BRGI"). The fees charged by BRGI totaled approximately $4.1 million, $4.8
million and $5.3 million for the years ended December 31, 1996, 1995 and 1994,
respectively, and are in accordance with the rates defined in the Gas Gathering,
Dehydrating and Treatment Agreement.
TRUSTEE
NationsBank of Texas, N.A.
Dallas, Texas
Delaware Trustee
Mellon Bank(DE) National Association
Wilmington, Delaware
TRANSFER AGENT AND REGISTRAR
Boston Equiserve Shareholder Service
Boston, Massachusetts and New York, New York
TRUST AUDITORS
Deloitte & Touche LLP
Dallas, Texas
TRUST ENGINEERING CONSULTANTS
Netherland, Sewell & Associates, Inc.
Houston, Texas
TRUSTEE COUNSEL
Thompson & Knight,
A Professional Corporation
Dallas, Texas
FORM 10-K
A copy of the Form 10-K of the Trust for the year ended December 31, 1996 as
filed with the Securities and Exchange Commission has been provided with this
Annual Report to Unitholders. Additional copies of the Form 10-K will be
provided, without charge, upon written request to:
Burlington Resources Coal Seam Gas Royalty Trust
NationsBank of Texas, N.A., Trustee
NationsBank Plaza
901 Main Street, Suite 1700
Dallas, Texas 75283-0650
<PAGE>
BURLINGTON RESOURCES COAL SEAM GAS ROYALTY TRUST
NATIONSBANK OF TEXAS, N.A., TRUSTEE
NATIONSBANK PLAZA
901 MAIN STREET, SUITE 1700
DALLAS, TEXAS 75283-0650
1-800-365-6547
<PAGE>
EXHIBIT 23.1
[NETHERLAND, SEWELL & ASSOCIATES LETTERHEAD APPEARS HERE]
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS
We hereby consent to the references to Netherland, Sewell & Associates,
Inc. and to the use of its reports listed below regarding the Burlington
Resources Coal Seam Gas Royalty Trust proved reserves and estimated Section 29
tax credits in the Annual Report on Form 10-K to be filed by the Burlington
Resources Coal Seam Gas Royalty Trust with the Securities and Exchange
Commission.
1. Report dated March 25, 1994 for reserves as of
December 31, 1993.
2. Report dated March 15, 1995 for reserves as of
December 31, 1994.
3. Report dated March 16, 1995 for estimated Section 29
tax credits as of December 31, 1994.
4. Report dated March 18, 1996 for reserves as of
December 31, 1995.
5. Report dated March 19, 1996 for estimated Section 29
tax credits as of December 31, 1995.
6. Report date March 20, 1997 for reserves as of December 31, 1996.
7. Report dated March 21, 1997 for estimated Section 29 tax credits
as of December 31, 1995.
NETHERLAND, SEWELL & ASSOCIATES, INC.
By: /s/ Danny D. Simmons
----------------------------------
Danny D. Simmons
Senior Vice President
Houston, Texas
March 28, 1997
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-START> JAN-01-1996
<PERIOD-END> DEC-31-1995
<CASH> 158,251
<SECURITIES> 0
<RECEIVABLES> 0
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 158,251
<PP&E> 180,400,000
<DEPRECIATION> 73,028,120
<TOTAL-ASSETS> 107,530,131
<CURRENT-LIABILITIES> 201,966
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 107,328,165
<TOTAL-LIABILITY-AND-EQUITY> 107,530,131
<SALES> 10,671,428
<TOTAL-REVENUES> 10,699,767
<CGS> 0
<TOTAL-COSTS> 659,226
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 10,040,541
<INCOME-TAX> 0
<INCOME-CONTINUING> 0
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 10,040,541
<EPS-PRIMARY> 1.14
<EPS-DILUTED> 0
</TABLE>
<PAGE>
[NSA LETTERHEAD APPEARS HERE]
EXHIBIT 99.7
March 20, 1997
Mr. Ron E. Hooper
Burlington Resources Coal Seam Gas Royalty Trust
NationsBank of Texas, N.A., Trustee
NationsBank Plaza
901 Main Street, 17th Floor
Dallas, Texas 75202
Dear Mr. Hooper:
In accordance with your request, we have estimated, as of January 1, 1997, (1)
the future net revenue to the Burlington Resources Coal Seam Gas Royalty Trust
(Trust) net profits interest and (2) the proved reserves to the Burlington
Resources Coal Seam Gas Royalty Trust (Burlington) interest in the Fruitland
Coal Formation underlying the Northeast Blanco Unit, Rio Arriba and San Juan
Counties, New Mexico, as listed in the accompanying tabulations. The Trust net
profits interest is derived from the Burlington interest in such proved
reserves. This report has been prepared using constant prices and costs and
conforms to the guidelines of the Securities and Exchange Commission (SEC).
The estimated net proved reserves in this report are defined as the portion of
the gross reserves attributable to the Burlington interest to which the net
profits interest is applied. As presented in the accompanying summary
projection, Table I, we estimate the Burlington net reserves and the future net
revenue to the Trust net profits interest, as of January 1, 1997, to be:
<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 80,189,707 $116,306,100 $67,304,900
</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 at this time. In accordance with SEC
guidelines, our estimates do not include any value for probable or possible
reserves which may exist for these properties. This report does not include any
value which could be attributed to interests in undeveloped acreage.
Future gross revenue in this report is to the Burlington interest prior to
deducting state production taxes and ad valorem taxes. Future net revenue is the
95 percent net profits interest to the Trust after deducting the Burlington
working interest share of these taxes and operating expenses, but before
consideration of federal income taxes. Our estimates of future net revenue have
not been adjusted to account for the Section 29 nonconventional fuels federal
income tax credit. In accordance with
<PAGE>
SEC guidelines, the future net revenue has been discounted at an annual rate of
10 percent to determine its "present worth." The present worth is shown to
indicate the effect of time on the value of money and should not be construed
as being the fair market value of the Trust net profits interests.
For the purposes of this report, a field inspection of the properties has not
been performed nor has the mechanical operation or condition of the wells and
their related facilities been examined. We have not investigated possible
environmental liability related to the properties; therefore, our estimates do
not include any costs which may be incurred due to such possible liability.
Also, our estimates do not include any salvage value for the lease and well
equipment nor the cost of abandoning the properties.
The gas price used in this report is based on the December 1996 net price
received; adjusted for BTU content, gathering fee, and shrinkage. The price is
also adjusted as specified in the gas purchase contract under provisions
related to the sharing price and price credit account and held constant in
accordance with SEC guidelines.
Lease and well operating costs are based on operating expense records
provided by Burlington. These costs include the per-well overhead expenses
allowed under joint operating agreements along with costs estimated to be
incurred at and below the district and field levels. General and administrative
overhead expenses of the Trustee are not included. Lease and well operating
costs are held constant in accordance with SEC guidelines. Capital costs are
included as required for workovers and production equipment.
We have made no investigation of potential gas volume and value imbalances
which may have resulted from overdelivery or underdelivery to the Burlington
interest. Therefore, our estimates of reserves and future revenue do not
include adjustments for the settlement of any such imbalances; our projections
are based on Burlington receiving its net revenue interest share of estimated
future gross gas production.
The reserves included in this report are estimates only and should not be
construed as exact quantities. They may or may not be recovered; if recovered,
the revenues therefrom and the costs related thereto could be more or less than
the estimated amounts. The sales rates, prices received for the reserves, and
costs incurred in recovering such reserves may vary from assumptions included
in this report due to governmental policies and uncertainties of supply and
demand. Also, estimates of reserves may increase or decrease as a result of
future operations.
In evaluating the information at our disposal concerning this report, we have
excluded from our consideration all matters as to which legal or accounting,
rather than engineering and geological, interpretation may be controlling. As
in all aspects of oil and gas evaluation, there are uncertainties inherent in
the interpretation of engineering and geological data; therefore, our
conclusions necessarily represent only informed professional judgments.
The titles to the properties have not been examined by Netherland, Sewell &
Associates, Inc., nor has the actual degree or type of interest owned been
independently confirmed. The data used in our estimates were obtained from
Burlington Resources Oil & Gas, Inc. and the nonconfidential files of
Netherland, Sewell & Associates, Inc. and were accepted as accurate. We are
independent petroleum engineers, geologists and geophysicists; we do not own an
interest in these properties and are not employed on a contingent basis. Basic
geologic and field performance data together with our engineering work sheets
are maintained on file in our office.
Very truly yours,
/s/ Frederic D. Sewell
<PAGE>
[NSA LETTERHEAD APPEARS HERE]
EXHIBIT 99.8
March 21, 1997
Mr. Ron E. Hooper
Burlington Resources Coal Seam Gas Royalty Trust
NationsBank of Texas, N.A., Trustee
NationsBank Plaza
901 Main Street, 17th Floor
Dallas, Texas 75202
Dear Mr. Hooper:
In accordance with your request, we have estimated, as of January 1, 1997,
the Section 29 nonconventional fuels federal income tax credit attributable to
the Burlington Resources Coal Seam Gas Royalty Trust (Trust) net profits
interest in the Fruitland Coal Formation underlying the Northeast Blanco Unit,
Rio Arriba and San Juan Counties, New Mexico, as listed in the accompanying
tabulations. The tax credit is derived from the Burlington Resources Oil & Gas,
Inc. (Burlington) interest in the proved gas reserves as estimated in our report
dated March 20, 1997. This report has been prepared using constant prices and
costs and conforms to the guidelines of the Securities and Exchange Commission
(SEC).
The estimated net proved reserves in this report are defined as the portion
of the gross reserves attributable to the Trust net profits interest. These
reserves were reduced by the amount of gas reserves necessary to cover the
lease operating costs at the current gas price. As presented in the
accompanying summary projection, Table I, we estimate the Trust net reserves
and the tax credit attributable to the Trust net profits interest, as of
January 1, 1997, to be:
<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 38,197,677 $36,055,600 $28,479,900
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Gas volumes are expressed in thousands of standard cubic feet (MCF) at the
contract temperature and pressure bases. These properties no longer produce
commercial volumes of condensate.
This report includes a summary projection of reserves and future tax credit
along with one-line summaries of reserves, economics, and basic data by lease.
For the purposes of this report, the term "lease" refers to a single economic
projection.
The estimated reserves and future tax credit shown in this report are for
proved developed reserves only. Our study indicates that there are no proved
undeveloped reserves for these properties at this time. In accordance with SEC
guidelines, our estimates do not include any value for probable or possible
reserves which may exist for these properties. This report does not include any
value which could be attributed to interests in undeveloped acreage.
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For the purposes of this report, a field inspection of the properties has not
been performed nor has the mechanical operation or condition of the wells and
their related facilities been examined. We have not investigated possible
environmental liability related to the properties; therefore, our estimates do
not include any costs which may be incurred due to such possible liability.
Also, our estimates do not include any salvage value for the lease and well
equipment nor the cost of abandoning the properties.
An estimated 1996 tax credit of $1.05 per MMBTU is held constant in
accordance with SEC guidelines.
Lease and well operating costs are based on operating expense records
provided by Burlington. These costs include the per-well overhead expenses
allowed under joint operating agreements along with costs estimated to be
incurred at and below the district and field levels. General and administrative
overhead expenses of the Trustee are not included. Lease and well operating
costs are held constant in accordance with SEC guidelines. Capital costs are
included as required for workovers and production equipment.
We have made no investigation of potential gas volume and value imbalances
which may have resulted from overdelivery or underdelivery to the Burlington
interest. Therefore, our estimates of reserves and tax credit do not include
adjustments for the settlement of any such imbalances; our projections are
based on Burlington receiving its net revenue interest share of estimated future
gross gas production.
The reserves included in this report are estimates only and should not be
construed as exact quantities. They may or may not be recovered; if recovered,
the tax credit therefrom and the costs related thereto could be more or less
than the estimated amounts. The sales rates, prices received for the reserves,
and costs incurred in recovering such reserves may vary from assumptions
included in this report due to governmental policies and uncertainties of
supply and demand. Also, estimates of reserves may increase or decrease as a
result of future operations.
In evaluating the information at our disposal concerning this report, we have
excluded from our consideration all matters as to which legal or accounting,
rather than engineering and geological, interpretation may be controlling. As
in all aspects of oil and gas evaluation, there are uncertainties inherent in
the interpretation of engineering and geological data; therefore, our
conclusions necessarily represent only informed professional judgments.
The titles to the properties have not been examined by Netherland, Sewell &
Associates, Inc., nor has the actual degree or type of interest owned been
independently confirmed. The data used in our estimates were obtained from
Burlington Resources Oil & Gas, Inc. and the nonconfidential files of
Netherland, Sewell & Associates, Inc. and were accepted as accurate. We are
independent petroleum engineers, geologists and geophysicists; we do not own an
interest in these properties and are not employed on a contingent basis. Basic
geologic and field performance data together with our engineering work sheets
are maintained on file in our office.
Very truly yours,
/s/ Frederic D. Sewell
