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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-K
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(MARK ONE)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 (FEE REQUIRED)
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1998
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED)
COMMISSION FILE NUMBER: 1-8518
LL&E ROYALTY TRUST
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
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TEXAS 76-6007940
(STATE OR OTHER JURISDICTION (I.R.S. EMPLOYER IDENTIFICATION NO.)
OF INCORPORATION OR ORGANIZATION)
CHASE BANK OF TEXAS NATIONAL ASSOCIATION, TRUSTEE
CORPORATE TRUST DIVISION
712 MAIN STREET
HOUSTON, TEXAS 77002
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)
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REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (713) 216-5447
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
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NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
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Units of Beneficial Interest New York Stock Exchange
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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 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
As of March 19, 1999, 18,991,304 Units of Beneficial Interest were
outstanding, and the aggregate market value of Units (based upon the closing
price of the Units on the New York Stock Exchange as reported in The Wall Street
Journal) held by nonaffiliates was approximately $52,226,086.
DOCUMENTS INCORPORATED BY REFERENCE: NONE
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TABLE OF CONTENTS
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PART I
ITEM 1 -- Business......................................... 1
Introduction........................................... 1
Terms and Operation of the Trust....................... 2
Creation and Operation of the Trust............... 2
Terms of the Conveyances.......................... 2
The Partnership................................... 4
Receipts and Payments............................. 4
Liabilities and Contingency Reserves.............. 4
Duration and Termination of the Trust............. 5
The Royalties.......................................... 5
Overriding Royalties.............................. 5
Fee Lands Royalties............................... 7
Analysis of the Working Interest Owner's
Calculation of the Royalties...................... 8
The Units.............................................. 9
Distributions and Income Computations............. 9
Transfer of Units................................. 9
Periodic Reports.................................. 9
Possible Requirement that Units be Divested....... 10
Liability of Unit Holders......................... 10
Voting by Unit Holders............................ 11
Certain State Law Considerations.................. 11
The Properties......................................... 12
General........................................... 12
Description of Productive Properties.............. 13
Description of the Fee Lands...................... 14
Oil and Gas Sales from the Productive Properties....... 15
Oil Sales......................................... 15
Gas and Liquids Sales............................. 15
Exploration and Development Activities................. 16
Productive Properties............................. 16
Fee Lands......................................... 16
Estimates of Petroleum Engineers....................... 17
September 30, 1998 Estimates...................... 17
Certain Factors Affecting Estimates............... 17
Industry Conditions and Regulation..................... 26
Industry Conditions............................... 26
Regulation -- General............................. 26
Natural Gas Regulation............................ 26
Tax Considerations to Owners of Units.................. 27
Federal Income Tax Considerations................. 27
IDC Recapture Income to the Company on
Distribution...................................... 35
Backup Withholding................................ 35
Information Return Filing Requirements............ 35
State Tax Considerations.......................... 36
Severance Taxes................................... 38
Ad Valorem Taxes.................................. 38
ITEM 2 -- Properties....................................... 38
ITEM 3 -- Legal Proceedings................................ 38
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ITEM 4 -- Submission of Matters to a Vote of Unit
Holders................................................... 38
PART II
ITEM 5 -- Market for the Registrant's Units and Related
Unit Holder Matters....................................... 39
ITEM 6 -- Selected Financial Data.......................... 39
ITEM 7 -- Management's Discussion and Analysis of Financial
Condition and Results
of Operation.................................. 39
ITEM 8 -- Financial Statements and Supplementary Data...... 42
ITEM 9 -- Changes in and Disagreements with Accountants on
Accounting and
Financial Disclosure.......................... 49
PART III
ITEM 10 -- Directors and Executive Officers of the
Registrant................................................ 49
ITEM 11 -- Executive Compensation........................... 49
ITEM 12 -- Unit Ownership of Certain Beneficial Owners and
Management................................................ 49
ITEM 13 -- Certain Relationships and Related Transactions... 49
PART IV
ITEM 14 -- Exhibits, Financial Statement Schedules, and
Reports on Form 8-K....................................... 50
SIGNATURE................................................... 51
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SAFE HARBOR STATEMENT UNDER THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
Statements, other than historical facts, contained in this Annual Report on
Form 10-K, including statements of estimated oil and gas production and
reserves, drilling plans, future cash flows, anticipated capital expenditures
and Working Interest Owner strategies, plans and objectives, are "forward
looking statements" within the meaning of Section 27A of the Securities Act of
1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as
amended. Although the Working Interest Owner has advised the Trust that it
believes that its forward looking statements are based on reasonable
assumptions, it cautions that such statements are subject to a wide range of
risks and uncertainties incident to the exploration for, development and
marketing of oil and gas, and it can give no assurance that its estimates and
expectations will be realized. Important factors that could cause actual results
to differ materially from the forward looking statements include, but are not
limited to, changes in production volumes, worldwide demand, and commodity
prices for petroleum natural resources; the timing and extent of the Working
Interest Owner's success in developing and producing oil and gas reserves; risks
incident to the drilling and operation of oil and gas wells; future production
and development costs; the effect of existing and future laws, governmental
regulations and the political and economic climate of the United States; and
conditions in the capital markets. Other risk factors are discussed elsewhere in
this Form 10-K, including those risk factors described under the heading
"Duration and Termination of the Trust."
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PART I
ITEM 1. BUSINESS
INTRODUCTION
LL&E Royalty Trust (the "Trust") was created under the laws of the State of
Texas on June 28, 1983 pursuant to a Trust Agreement (the "Trust Agreement")
between The Louisiana Land and Exploration Company (the "Company") and First
City National Bank of Houston. Effective February 13, 1993, Chase Bank of Texas,
National Association ("N.A."), formerly Texas Commerce Bank National Association
acquired from the Federal Deposit Insurance Corporation (the "FDIC"), as
receiver for New First City, Texas -- Houston, N.A., substantially all of the
assets of New First City, Texas -- Houston N.A., which previously had acquired
all of the assets of First City, Texas -- Houston, N.A. after that institution
was closed by action of the FDIC on October 30, 1992. Chase Bank of Texas,
National Association now serves as Trustee of the Trust. The Trustee's offices
are located at 712 Main Street, Houston, Texas 77002, and its telephone number
is (713) 216-5447. The Company is also referred to herein as the "Working
Interest Owner" in its capacity as the owner of the working interests in the
Properties referred to below. The term "Working Interest Owner" includes the
successors and assigns of such working interests, although at present, no such
assignments have been made. On October 22, 1997, the shareholders of the Company
approved a definitive agreement to merge with Burlington Resources Inc. ("BR").
Effective on that date, the Company became a wholly-owned subsidiary of BR. The
merger has had no significant effects on the Trust. Upon creation of the Trust,
the Company conveyed to the Trust (a) net overriding royalty interests
(equivalent to net profits interests) (the "Overriding Royalties") in certain
productive oil and gas properties located in Alabama, Florida and Texas and in
federal waters offshore Louisiana (the "Productive Properties") and (b) 3%
royalty interests (the "Fee Lands Royalties") in certain of the Company's then
unleased, undeveloped south Louisiana fee lands (the "Fee Lands"). The
Productive Properties and the Fee Lands are collectively referred to herein as
the "Properties". Title to the Overriding Royalties and the Fee Lands Royalties
(collectively referred to herein as the "Royalties") is held by a partnership
(the "Partnership") of which the Trust and the Company are the only partners,
holding a 99% and a 1% interest, respectively. The Royalties are the only assets
of the Partnership. The term "Royalties" reflects the Partnership interest of
the Trust, and references to specific amounts of Royalties are references to the
Trust's interest in the Overriding Royalties or Fee Lands Royalties held by the
Partnership. The instruments of conveyance which transferred the Royalties to
the Trust and subsequently to the Partnership are collectively referred to
herein as the "Conveyances". The Trust is passive, with the Trustee having only
such powers as are necessary for collection and distribution of the revenues
resulting from the Royalties, the payment of Trust liabilities and the
conservation and protection of the Trust estate.
Units of Beneficial Interest (the "Units") in the Trust were distributed by
the Company to holders of record of its capital stock on June 22, 1983 on the
basis of one Unit for each two shares of capital stock owned on such date. Each
of the Units evidences an undivided interest in the Trust, which owns a 99%
interest in the Partnership, which holds title to the Royalties. The Unit
holders participate in the revenues resulting from the Royalties. See "Tax
Considerations to Owners of Units -- Federal Income Tax Considerations".
The Units are not an interest in or obligation of the Working Interest
Owner or of the other operators of the Properties. However, the ultimate value
of the Royalties will be dependent, in part, upon the ability of the operators
of the Properties to operate them successfully. There is no requirement that the
Working Interest Owner expend any specific amounts with respect to the
Properties. The Working Interest Owner is free to transfer its interest
(burdened by the Royalties) to third parties. In certain limited cases the
Working Interest Owner will be permitted to farm out interests in the Productive
Properties and to reduce the Overriding Royalties proportionately. The Working
Interest Owner does not have any obligation to produce any specific amounts of
oil and gas from any of the Properties. Upon termination or abandonment of any
lease the Overriding Royalties relating thereto will be extinguished. The amount
of revenues attributable to the Overriding Royalties may be affected by
operating agreements, and the amount of revenues attributable to the Royalties
may be affected by unitization and pooling arrangements. The value of the
Royalties is also subject to all the risks associated with oil and gas
operations and to the costs of comprehensive regulation by governmental
authorities. See "Industry Conditions and Regulation".
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The Trustee has no responsibility relating to the operation of the
Productive Properties or Fee Lands. The information in this Annual Report on
Form 10-K relating to the characteristics of and operations on the Productive
Properties and Fee Lands, the calculation of the payments made with respect to
the Royalties and certain other matters has been furnished to the Trustee by the
Working Interest Owner.
TERMS AND OPERATION OF THE TRUST
CREATION AND OPERATION OF THE TRUST
Pursuant to the Conveyances, the Overriding Royalties and Fee Lands
Royalties were conveyed to the Trust and were then immediately assigned to the
Partnership, which was formed to hold the Royalties. See "Terms and Operation of
the Trust -- The Partnership". The Royalties are the only asset of the Trust,
other than cash being held for the payment of expenses and liabilities and for
distribution to the Unit holders. The Trustee of the Trust is Chase Bank of
Texas, N.A.
The Trustee holds the Royalties pursuant to the terms of the Trust
Agreement. The Trust Agreement may be amended by a vote of Unit holders owning a
majority of the Units with concurrence of the Trustee, but no provision of the
Trust Agreement may be amended (unless consented to by 100% of the Unit holders)
in a manner which would (a) permit the Trustee to engage in business or
investment activities on behalf of the Trust, (b) alter the rights of the Unit
holders among themselves, (c) alter the number of Units, (d) reduce or delay the
distribution of the Monthly Income Amounts (defined hereinafter) to Unit
holders, (e) adversely affect the characterization of the Trust as an express
trust under the Texas Trust Code, (f) authorize the distribution to Unit holders
of record of any assets other than cash or other personal property or (g) alter
the voting requirements as provided in the Trust Agreement. In no event may the
Trust Agreement be amended in a manner that would jeopardize the continued
applicability of any Internal Revenue Service ruling letter or any opinion of
counsel described in "Tax Considerations to Owners of Units -- Federal Income
Tax Considerations -- Rulings and Tax Opinion Regarding Distribution".
The Trustee may resign and may be removed by a vote of Unit holders owning
a majority of the Units. If the Trustee resigns, a successor trustee will be
appointed, which must be a national bank meeting certain requirements, including
having capital, surplus and undivided profits of at least $100,000,000.
The Trust has no employees; administrative functions of the Trust are
performed by the Trustee. The Conveyances provide that the Working Interest
Owner will maintain books and records sufficient to determine the amounts
payable under the Royalties.
TERMS OF THE CONVEYANCES
The discussion herein of the Conveyances is intended to be a general
summary of certain of the provisions of the Conveyances, forms of which are on
file with the Securities and Exchange Commission and are incorporated by
reference as exhibits to this Annual Report on Form 10-K. The discussion herein
is qualified in its entirety by reference to the relevant provisions of such
forms of the Conveyances.
The Conveyances impose on the Working Interest Owner no contractual
obligation to drill any wells or to maintain operations or production once
established. However, the Conveyances of Overriding Royalty Interests do
obligate the Working Interest Owner to conduct and carry on the development,
maintenance and operation of the Productive Properties with reasonable and
prudent business judgment and in accordance with good oil and gas field
practices, or, where the Working Interest Owner is not the operator, to use
reasonable efforts to cause the operator to do so. Actual drilling operations
depend on whether geological and geophysical evaluations indicate that drilling
will be prudent. There is no requirement that the Working Interest Owner expend
any specific amounts with respect to the Properties, and it is free to transfer
its interests (burdened by the Royalties) to third parties. The Working Interest
Owner does not have any obligation to produce any specific amounts of oil and
gas from any of the Properties and it has the right to abandon its interest in
any well or lease. Upon termination of any lease, the Overriding Royalties
relating thereto will be extinguished.
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Uncertainties or controversies may arise from time to time with respect to
the correct sales prices that may be charged by the Working Interest Owner for
oil and gas produced from the Properties. The Conveyances provide that amounts
received by the Working Interest Owner that may be subject to any such
uncertainty or controversy and otherwise payable to the Trust may, at the option
of the Working Interest Owner under certain circumstances, be deposited in
escrow with an escrow agent, which may be Chase Bank of Texas, N.A., and will
not be payable with respect to the Royalties until the matter is resolved. The
Working Interest Owner may place other amounts in escrow under certain
circumstances. Amounts owing to the Trust and paid to the Working Interest Owner
by the escrow agent upon final resolution of any such matter will be delivered
to the Trustee on the next succeeding Monthly Record Date (defined below) and
distributed to the record holders of Units as of that Monthly Record Date. The
provisions of the Conveyances that provide for escrow accounts permit the
Working Interest Owner to elect, under certain circumstances, to calculate and
pay amounts attributable to the Royalties, without establishing actual escrow
accounts, in amounts equal to the amounts that would have been paid had actual
escrow accounts been established.
The Conveyances provide that under certain circumstances the Working
Interest Owner may place all or a portion of the revenues which would otherwise
accrue to the Royalties in an escrow account rather than treating such revenues
as Gross Proceeds. In particular, with respect to any Productive Property, if,
at the end of any month, (a) the aggregate estimated future Gross Proceeds (as
defined in the Conveyances), as estimated by independent petroleum engineers in
their most current report, is less than (b) the sum of (i) estimated future
Production Costs (as defined in the Conveyances), as estimated by the Working
Interest Owner, excluding certain costs, and (ii) 400% of the aggregate
estimated future Special Costs (as defined in the Conveyances), the Working
Interest Owner may escrow an amount equal to a certain percentage (the
calculation of which is described below) of the revenues which would otherwise
constitute Gross Proceeds. The phrase "Gross Proceeds", as used in the
Conveyances, and subject to certain exceptions, means, on an accrual accounting
method, the amount recorded as revenues by the Working Interest Owner from the
sale of oil, gas and certain other hydrocarbons from a given Productive
Property. The phrase "Production Costs", as used in the Conveyances, includes
lease operating expenses, overhead and taxes. The phrase "Special Costs", as
used in the Conveyances, includes, among other things: (a) the aggregate
estimated cost of plugging and abandoning wells and dismantling platforms on
such Productive Property, and (b) estimated future capital expenditures. The
amount the Working Interest Owner may place in escrow with respect to any
Productive Property in any month may not exceed Gross Proceeds for that month
multiplied by 250% of the aggregate estimated future Special Costs divided by
the aggregate estimated future Gross Proceeds for that Property. Further, the
total amount so escrowed cannot exceed 125% of the aggregate estimated future
Special Costs for the particular Productive Property.
Based on the escrow provisions described above, the Working Interest Owner
has escrowed $2.3 million of proceeds from the Offshore Louisiana property to
provide for a portion of the estimated costs of dismantling platforms on such
property. At present, the Working Interest Owner is not escrowing additional
proceeds from any of the Productive Properties, however, the Working Interest
Owner has advised the Trustee that based on the September 30, 1998 reserve
report included in this Annual Report, the Working Interest Owner is permitted
to place funds in escrow from the Jay Field, South Pass 89, and Offshore
Louisiana properties. The Working Interest Owner has advised the Trustee that it
intends to continue to monitor all relevant facts and circumstances to evaluate
the necessity of escrowing funds as described above. The Working Interest Owner
is under no obligation to give any advance notice to the Trustee or the Unit
holders in the event it determines that additional funds should be escrowed. If
the Working Interest Owner begins to escrow additional funds, the Royalties paid
to the Trust would be reduced and the reduction could be significant.
In the event that the Working Interest Owner is required to pay any refunds
or interest (including any payment made pursuant to settlements entered into by
the Working Interest Owner in good faith) as a result of overcharges with
respect to which Royalties have already been paid, neither the Trustee nor the
Unit holders are expected to be obligated to return to the Working Interest
Owner any payments previously received. However, the amount of any such refunds
or interest would reduce future payments attributable to the Royalties. Holders
of Units may, as a result of the procedures described above and under
"Liabilities and Contingency Reserves" below, receive distributions of amounts
that otherwise would have been distributed to
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former holders if such amounts had not been held in escrow or reserves, or,
conversely, may have their distributions reduced as a result of controversies
about amounts that may be collected by the Working Interest Owner or as a result
of the establishment of escrow accounts or reserves for contingencies.
THE PARTNERSHIP
Title to the Royalties is held by a partnership of which the Trust and the
Company are the only partners. The Partnership was formed solely for the purpose
of owning the Royalties, and its only functions are the ownership of such
interests and the related receipt of funds, payment of expenses, disbursement of
revenues from the Royalties and preparation of certain reports to the Trustee.
RECEIPTS AND PAYMENTS
The terms of the Trust Agreement, the Conveyances and the partnership
agreement between the Trust and the Company (the "Partnership Agreement")
provide that the Working Interest Owner will use its best efforts to make
payments to the Partnership, the Partnership will make payments to the Trust,
and the Trust and Partnership will use reasonable efforts to pay expenses, only
on the Monthly Record Date (defined as the close of business on the fifth day of
the month unless such fifth day is not a business day, in which case it will be
the next business day following the fifth day) for each Monthly Period (defined
as the period which commences on the day following a Monthly Record Date and
continuing through and including the succeeding Monthly Record Date). For
taxable years beginning on or after January 1, 1987, the Partnership has been
required to use the accrual method of accounting, and thus the portion of the
Trust's income attributable to the Partnership and reported to the Unit holders
is likewise on the accrual basis. Consequently, the Unit holder required to
recognize income and expense for a Monthly Period may not be the Unit holder
entitled to the Monthly Income Amount. See "Tax Considerations to Owners of
Units -- Federal Income Tax Considerations -- Tax Consequences of Owning
Units -- Accounting for Income and Deductions".
LIABILITIES AND CONTINGENCY RESERVES
Because of the passive nature of the Trust assets and the restrictions on
the power of the Trustee to incur obligations, the only liabilities that the
Trust typically incurs are for routine administrative expenses, such as
Trustee's fees and accounting, engineering, legal and other professional fees.
The costs and expenses of the Trust may increase or decrease in future years,
depending on the volume of trading of the Units, the amount of revenues paid to
the Trust and increases or decreases in accounting, engineering, legal and other
professional fees and other factors. Substantial federal income tax liabilities
would result if the Internal Revenue Service were to revoke or change its
position on its ruling that neither the Trust nor the Partnership is taxable as
a corporation and such revocation or change were not judicially reversed. See
"Tax Considerations to Owners of Units -- Federal Income Tax Considerations --
Rulings and Tax Opinion Regarding Distribution".
The Trust Agreement and the Partnership Agreement provide that the Trustee
or the Partnership may establish cash contingency reserves in the event that (a)
either (i) a claim is asserted against or is likely to be asserted against the
Trust or the Partnership, whichever is the case, and the Trustee has received an
opinion of counsel stating that the claim has a reasonable probability of
succeeding or (ii) a claim against the Trust or the Partnership, whichever is
the case, has been successful but is not currently due and payable, and (b) the
amount or probable amount of such claim is such that it cannot be satisfied out
of monthly income from the Royalties. Such reserves will be deposited in
noninterest-bearing accounts, except that such contingency reserves will be
placed in certificates of deposit or United States government securities
maturing on the next Monthly Record Date if the Trustee or the Partnership,
whichever is the case, has received an opinion of counsel to the effect that
such action will not jeopardize the tax treatment of the Trust or Partnership as
a trust or partnership, respectively, and not as an association taxable as a
corporation. Assuming that the Trust is classified for tax purposes as a grantor
trust and the Partnership is classified for tax purposes as a partnership (see
"Tax Considerations to Owners of Units -- Federal Income Tax
Considerations -- Tax Consequences of Owning Units"), if such reserves are
established, the amounts placed in reserve will be taxable to the Unit holders
when received by the Partnership, even though they are not distributed to Unit
holders at that time. If cash contingency reserves are established and placed in
interest-bearing accounts as described above, the
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Trustee will furnish reports annually to all Unit holders of record on the
applicable Monthly Record Dates containing information sufficient to enable Unit
holders to calculate their share of taxable income (on either a cash or accrual
basis) attributable to any interest earned on the reserves.
If at any time the cash available to the Trust or the Partnership is not
sufficient to pay liabilities that have become due, the Trustee or the
Partnership, respectively, may borrow funds on a secured or an unsecured basis
to pay such liabilities. Except for borrowings to purchase Units as described
under "The Units -- Possible Requirement That Units Be Divested", neither the
Trustee nor the Partnership may borrow an amount that at the time of borrowing
exceeds 50% of the estimated revenues of the Trust or the Partnership,
respectively, during the immediately following six Monthly Periods. Generally,
such borrowing must be repaid before any further Trust or Partnership
distributions, whichever is the case, can be made.
The Trust Agreement requires the Trustee to receive all income and proceeds
of the Royalties and to pay all expenses, charges, liabilities and obligations
of the Trust. See "The Units -- Distributions and Income Computations". The
Trustee submits reports to the Unit holders as described under "The
Units -- Periodic Reports". The Trust Agreement gives the Trustee only such
rights and powers as are necessary and proper for the conservation and
protection of the Royalties and prohibits the Trustee from entering into or
engaging in any business or investment activity on behalf of the Trust.
Except as described under "The Units -- Liability of Unit Holders", the
Trustee will be indemnified out of the Trust assets for any liability, expense,
claim, damage or other loss incurred in performing its duties, unless resulting
from its negligence, bad faith or fraud. In no event will the Trustee be deemed
to have acted negligently, fraudulently or in bad faith if it takes action or
suffers action to be taken in good faith in reliance upon and in accordance with
the advice of parties (including its own employees) considered to be qualified
as experts on the matters submitted to them. Neither the Trust, the Trustee, the
Partnership nor the Working Interest Owner will be entitled to indemnification
from the Unit holders. To the extent not inconsistent with the Trust Agreement,
the Trustee has been relieved from certain liabilities otherwise imposed by the
Texas Trust Act, as amended by the Texas Trust Code (the "Texas Trust Code").
DURATION AND TERMINATION OF THE TRUST
Unless sooner terminated, the Trust will continue until such time as its
net revenues (after administrative expenses of the Trust) for each of two
successive years are less than $5,000,000 per year. The Trust may be terminated
at any time by a vote of Unit holders owning a majority of the Units. Upon the
termination of the Trust, the Trustee will sell the assets of the Trust for cash
(unless authorized by the holders of a majority of the Units to sell such assets
for non-cash consideration) upon such terms as the Trustee, in its sole
discretion, deems to be in the best interests of the Unit holders. After paying
or making provision for all liabilities of the Trust, the Trustee will
distribute all cash then held by it in its capacity as Trustee. After the
termination of the Trust, the Trustee will continue to act as Trustee for
purposes of liquidating and winding up the affairs of the Trust.
THE ROYALTIES
The manner of calculating the payments attributable to the Royalties is set
forth in the Conveyances, forms of which are on file with the Securities and
Exchange Commission and are incorporated by reference as exhibits to this Annual
Report on Form 10-K. The description herein of the manner of calculating those
payments is qualified in its entirety by the detailed terms of the Conveyances.
OVERRIDING ROYALTIES
For the purposes of computing Net Proceeds (as defined in the Conveyances),
the Productive Properties have been grouped geographically into four groups of
leases, each of which has been defined as a separate "Property". These groups
are designated herein as the "Jay Field", "South Pass 89", "Offshore Louisiana"
and "Fort Worth Basin". See "The Properties -- Description of Productive
Properties". The Overriding Royalties consist of overriding royalty interests
(equivalent to net profits interests) equal to various
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percentages of the Net Proceeds, as defined, from the production of oil, gas and
other hydrocarbons from the Productive Properties. Net Proceeds are computed on
a Property-by-Property (i.e., lease group) basis and consist of the aggregate
proceeds to the Working Interest Owner from the sale of oil, gas and other
hydrocarbons from each of the Productive Properties ("Gross Proceeds") less
"Production Costs", which include primarily (a) all direct costs, charges and
expenses incurred by the Working Interest Owner in exploration, production,
development and other operations on the Productive Properties (including
secondary and tertiary recovery operations), including abandonment costs; (b)
all applicable taxes, including severance, ad valorem and windfall profit taxes,
but excluding income taxes; (c) all operating charges directly associated with
the Productive Properties; (d) an allowance for costs, computed on a current
basis at a rate equal to Chase Bank of Texas, N.A.'s prime rate plus 1/2% per
annum on the average amounts by which, and for only so long as, costs and
expenses for any Productive Property have exceeded the proceeds of production
from such Productive Property; (e) amounts paid by the Working Interest Owner as
refunds of excess sales prices on previous sales; and (f) applicable charges for
certain overhead expenses. The Working Interest Owner's estimates of total
abandonment costs are $9.6 million for Jay Field, $2.6 million for South Pass 89
and $3.0 million for Offshore Louisiana. The Working Interest Owner has escrowed
$2.3 million from Offshore Louisiana proceeds to pay a portion of the
anticipated costs of abandonment at Offshore Louisiana. No such amount has been
escrowed with respect to Jay Field and South Pass 89.
If operating and other costs exceed net revenues from a Productive Property
for any month, the excess will be recovered by the Working Interest Owner out of
future production from such Productive Property prior to making further payments
attributable to the Royalties with respect to such Productive Property, but
neither the Trust, the Trustee, the Partnership, nor any Unit holder will be
liable for any such costs or liabilities, nor will they be obligated to return
any income from the Royalties received during any prior period. However, any
such excess costs or overpayment of Royalties will reduce future payments of
Royalties.
Although crude oil production from Jay Field has a low sulphur content, gas
production from the field has a high content of sulphur which is removed prior
to processing and marketing such production. Although sulphur removed as a
by-product is sold by the Working Interest Owner, the removal of the sulphur is
essential to the marketing of the gas produced. For the purpose of computing Net
Proceeds, all proceeds to the Working Interest Owner from the sale of sulphur
extracted from Jay Field production and all direct costs and an allocated
portion of other costs associated with such extraction are excluded from the
calculations.
The Trust owns Overriding Royalties expressed as various percentages of Net
Proceeds. The Overriding Royalties with respect to Jay Field and South Pass 89
are equal to 50% of the Net Proceeds attributable to such properties. In years
prior to 1986, the Overriding Royalties were equal to percentages of Net
Proceeds that varied from 20% to 48%. The Overriding Royalties with respect to
Offshore Louisiana and Fort Worth Basin are (and have been since the inception
of the Trust) equal to 90% of the Net Proceeds attributable to such properties.
The amount of revenues attributable to the Overriding Royalties from any
well may be increased or reduced as a result of future pooling and unitization
agreements, extinguished or suspended as a result of "nonconsent" provisions of
present or future operating agreements between the Working Interest Owner and
other working interest owners or extinguished as a result of the expiration of
oil and gas leases. Since the Overriding Royalties were conveyed out of the
Working Interest Owner's working interests, if the Working Interest Owner's
right to revenues is adjusted, extinguished or suspended, the Trust's right to
revenues will also be adjusted, extinguished or suspended.
The Conveyances provide that the Working Interest Owner has the right to
approve unitization and pooling arrangements without the consent of the owners
of Units or the Trustee. Pooling and unitization refer to the joining together
of separate leases, or portions thereof, in a single unit, with the owners of
the interests in each separate lease sharing, depending on their interests, in
the production and costs attributable to the operations of the entire unit.
Since Overriding Royalty revenues are based upon Net Proceeds, determined
after deducting various costs, the amount of such revenues is directly affected
by numerous factors, including governmental regulation, prices received for
production, increases in operating and capital costs and certain taxes and
6
<PAGE> 10
curtailment of purchases by the purchasers of production from the Productive
Properties. In addition, since capital expenditures are deducted for purposes of
computing Net Proceeds, there may be substantial periods during which there will
be no Net Proceeds from a Productive Property because of such capital
expenditures, and therefore no Overriding Royalty revenues from such Productive
Property during such period. The amount of the revenues attributable to the
Overriding Royalties may also decrease materially from time to time as a
consequence of the occurrence of events that are risks incident to the
exploration for and production of oil and gas, including blowouts, cratering,
fires, drilling and production difficulties, environmental pollution problems,
and, with respect to Offshore Louisiana and South Pass 89, risks incident to the
offshore exploration for and production of oil and gas, including those related
to adverse weather and seas. Although any losses or liabilities resulting from
any such events would not require the Trust or Unit holders to repay funds
previously received, they would reduce any amounts payable thereafter with
respect to the Overriding Royalties.
FEE LANDS ROYALTIES
The Fee Lands Royalties consist of royalty interests equal to a 3% interest
in the future gross oil, gas and other hydrocarbon production, if any, from the
Fee Lands, unburdened by the expense of drilling, completion, development,
operating and other costs incident to production. The Fee Lands consist of
approximately 35,000 gross acres in south Louisiana, only approximately 4,509 of
which were leased at December 31, 1998. See "The Properties -- Description of
the Fee Lands" and "Exploration and Development Activities -- Fee Lands".
7
<PAGE> 11
ANALYSIS OF THE WORKING INTEREST OWNER'S CALCULATION OF THE ROYALTIES
The following unaudited schedules summarize the Working Interest Owner's
calculation of the amounts paid to the Trust with respect to the Trust's royalty
interests for (i) the quarter ended December 31, 1998 (applicable to production
from July 1998 through September 1998) and (ii) the year ended December 31, 1998
(applicable to production from October 1997 through September 1998):
QUARTER ENDED DECEMBER 31, 1998
<TABLE>
<CAPTION>
SOUTH OFFSHORE
JAY FIELD PASS 89 LOUISIANA TOTAL
------------ ----------- ----------- ------------
<S> <C> <C> <C> <C>
Revenues:
Liquids............................... $ 3,586,862 $ 1,194,051 $ 172,473 $ 4,953,386
Natural gas........................... 63,221 645,847 609,768 1,318,836
------------ ----------- ----------- ------------
3,650,083 1,839,898 782,241 6,272,222
Production costs and expenses........... (2,429,580) (333,092) (413,817) (3,176,489)
Capital expenditures.................... (740,720) (145,541) (929,512) (1,815,773)
------------ ----------- ----------- ------------
Net Proceeds............................ $ 479,783 $ 1,361,265 $ (561,088) $ 1,279,960
============ =========== =========== ============
Overriding Royalties paid to the
Trust(1).............................. $ 239,891 $ 680,633 $ 0 $ 920,524
============ =========== ===========
Fee Lands Royalties............................................................... 25,172
------------
Royalties paid to the Trust....................................................... $ 945,696
============
</TABLE>
YEAR ENDED DECEMBER 31, 1998
<TABLE>
<CAPTION>
SOUTH OFFSHORE
JAY FIELD PASS 89 LOUISIANA TOTAL
------------ ----------- ----------- ------------
<S> <C> <C> <C> <C>
Revenues:
Liquids............................... $ 17,854,597 $ 5,824,209 $ 973,283 $ 24,652,089
Natural gas........................... 829,430 4,475,107 5,140,446 10,444,983
------------ ----------- ----------- ------------
18,684,027 10,299,316 6,113,729 35,097,072
Production costs and expenses........... (11,050,782) (1,193,526) (1,842,287) (14,086,595)
Capital expenditures.................... (3,911,317) (299,313) (1,070,184) (5,280,814)
------------ ----------- ----------- ------------
Net Proceeds............................ $ 3,721,928 $ 8,806,477 $ 3,201,258 $ 15,729,663
============ =========== =========== ============
Overriding Royalties paid to the
Trust(1).............................. $ 1,860,964 $ 4,403,239 $ 3,528,145 $ 9,792,348
============ =========== ===========
Fee Lands Royalties............................................................... 94,331
------------
Royalties paid to the Trust....................................................... $ 9,886,679
============
</TABLE>
- ------------
(1) As a result of excess production costs being incurred in one monthly
operating period and then being recovered in a subsequent monthly operating
period, the Overriding Royalties paid to the Trust may not agree to the
Trust's royalty interest in Net Proceeds.
8
<PAGE> 12
THE UNITS
DISTRIBUTIONS AND INCOME COMPUTATIONS
Distributions of available revenues to Unit holders are made monthly. Each
payment is made with respect to the preceding Monthly Period of the Trust. The
Trustee determines for each Monthly Period the Monthly Income Amount available
for distribution for such Monthly Period. The Monthly Income Amount for each
Monthly Period is payable to Unit holders of record on the Monthly Record Date
on which such Monthly Period ends and is distributed by the Trustee as soon as
practicable but not later than ten days following such Monthly Record Date (the
"Monthly Payment Date"). Under the terms of the Trust Agreement, the Trustee is
prohibited from investing funds received on each Monthly Record Date pending
disbursement to holders of Units. As a consequence, the Trustee may hold
substantial balances between the Monthly Record Date and the Monthly Payment
Date in each month, and Chase Bank of Texas, N.A. has the use of these balances
during such periods.
Promptly after receipt of the required information, and if practicable
within 90 days of the close of each year, the net taxable income of the Trust
for federal income tax purposes for each Monthly Period ending in such year will
be reported by the Trustee to the Unit holders of record to whom the Monthly
Income Amounts were distributed. The Trustee mailed such reports to Unit holders
in March 1999. If, as anticipated, the Unit holders are owners of interests in a
grantor trust and the Partnership is a partnership for federal income tax
purposes, Unit holders will recognize income for federal income tax purposes in
the Monthly Period when income is recognized by the Partnership. Because the
Partnership has converted to the accrual method of accounting as mandated by the
Tax Reform Act of 1986 (the "1986 Act"), Unit holders are required to recognize
income in certain circumstances prior to receiving cash distributions. See "Tax
Considerations to Owners of Units -- Federal Income Tax
Considerations -- Accounting for Income and Deductions".
TRANSFER OF UNITS
Units are transferable on the records of Chase Bank of Texas, N.A., as
transfer agent and registrar, upon the surrender of any certificate in proper
form for transfer as required by Chase Bank of Texas, N.A. Service charges are
paid as an administrative expense of the Trust, and no service charge is made
directly to Unit holders for any transfer. Until any such transfer, the Trustee
may treat the owner of any Unit as shown by the records of the transfer agent
and registrar as the owner thereof and will not be charged with notice of any
claim or demand respecting such Unit or the interest represented thereby by any
other party. A transfer of a Unit after the Monthly Record Date for any Monthly
Period does not transfer to the transferee the right to the Monthly Income
Amount for such Monthly Period. See "Tax Considerations to Owners of
Units -- Federal Income Tax Considerations -- Tax Consequences of Owning
Units -- Sale of Units" for a discussion of certain federal income tax effects
of the transfer of Units. Texas law governs matters affecting title, ownership,
warranty and transfer of the certificates.
PERIODIC REPORTS
Promptly after receipt of the required information from the Working
Interest Owner, and if practicable within 60 days following the end of each of
the first three fiscal quarters of each year, the Trustee mails to each Unit
holder of record who was such on the last Monthly Record Date in such quarter a
report indicating, among other things, the distributions and revenues
attributable to the Trust for such quarter. Promptly after receipt of the
required information, and if practicable within 90 days after the end of the
Trust's fiscal year (which is the calendar year), the Trustee mails to each Unit
holder who received a Monthly Income Amount for any Monthly Period ending in
such year a report that shows in reasonable detail the receipts and
disbursements, and, for state and federal tax purposes, the income and expenses
of the Trust, as well as sufficient information to permit a calculation of any
depletion deduction for each Monthly Period (or portion thereof, if any) during
the year. Promptly after receipt of the required information, and if practical
within 120 days following the end of each year, the Trustee mails to all Unit
holders of record an annual report containing audited financial statements of
the Trust and a summary oil and gas reserve report with respect to the Trust's
interests in the Properties. The Trustee mails to Unit holders such other
reports and files such
9
<PAGE> 13
returns for federal and state income tax purposes as are required to comply with
applicable laws, to comply with the rules of the New York Stock Exchange and to
permit each Unit holder to calculate his share of the income and deductions of
the Trust. See "Tax Considerations to Owners of Units -- Federal Income Tax
Considerations -- Tax Consequences of Owning Units -- Reports". However, under
the Trust Agreement no duty is imposed on the Trustee to secure, file or
disseminate information to which it is not expressly afforded access under the
terms of the Trust Agreement or the Conveyances or which it is unable to obtain
with reasonable effort and expense.
Under the Trust Agreement, the Trustee has the sole responsibility for
filing all periodic reports and other materials required by law, including the
Securities Exchange Act of 1934 and the rules and regulations thereunder, and by
any securities exchange on which the Units are listed. The cost of preparing and
filing such materials is borne by the Trust.
POSSIBLE REQUIREMENT THAT UNITS BE DIVESTED
The Trust Agreement imposes no restrictions based on nationality or other
status of the persons or other entities which are eligible to hold Units.
However, the Trust Agreement provides that (a) if at any time the Trust or the
Trustee is named a party in any judicial or administrative proceeding that seeks
the cancellation or forfeiture of any property constituting part of the Trust
corpus because of the nationality, or any other status under the laws of the
United States or any political subdivision thereof, of any one or more holders
of Units, or (b) if at any time the Trustee in its reasonable discretion
determines that such a proceeding is threatened or likely to be asserted and the
Trustee has received an opinion of counsel stating that the party asserting or
likely to assert the claim has a reasonable probability of succeeding, the
following procedures will be applicable:
(i) The Trustee may give written notice ("Notice") to each record
owner of Units regarding the existence of such controversy. The Notice will
contain a reasonable summary of such controversy, will include materials
that will permit an owner of Units promptly to confirm or deny to the
Trustee that such owner is a person whose nationality or other status is or
would be an issue in such a proceeding ("Ineligible Holder") and will
constitute a demand to each Ineligible Holder that he dispose of his Units
to a party not of a nationality or other status at issue in the proceeding
described in the Notice within 30 days after the date of the Notice.
(ii) If any Ineligible Holder fails to dispose of his Units, as
required by the Notice, within 30 days after the date of the Notice, the
Trustee will have the right to purchase and will purchase, during the 90
days following the termination of the 30-day period specified in the
Notice, any Unit not so transferred at a cash price equal to the closing
price of the Units on the largest stock exchange on which the Units are
then listed or, in the absence of any such listing, in the over-the-counter
market, on the last business day prior to the expiration of the 30-day
period stated in the Notice. The procedures for any such purchase are more
fully described in the Trust Agreement.
(iii) The Trustee shall cancel any Units acquired in accordance with
the foregoing procedures, thereby increasing the proportionate interest in
the Trust of other holders of Units.
(iv) The Trustee may, in its sole discretion, borrow any amounts
required to purchase Units in accordance with the procedures described
above. Such borrowings would be repaid from revenues to the Trust before
any subsequent distribution to Unit holders would be made.
LIABILITY OF UNIT HOLDERS
The Trust is intended to be an "express trust" created under the Texas
Trust Code. Under Texas law, beneficiaries of an express trust are not
personally liable for the obligations of the Trust, even if the assets of the
Trust are insufficient to discharge its obligations. If the Trust were held not
to constitute an express trust, it is possible that the holders of Units would
be jointly and severally liable for the obligations of the Trust as would
general partners of a partnership. The Trustee may incur liabilities that cannot
be contractually limited, such as tort liability or federal income tax
liability, in the event the Trust is treated as an association taxable as a
corporation. Under current judicial decisions the Federal Energy Regulatory
Commission (the "FERC") is
10
<PAGE> 14
not considered to be empowered to compel refunds from overriding royalty
interest owners with respect to gas price overcharges. However, future laws,
regulations or judicial decisions might permit the FERC or other governmental
agencies to require such refunds by overriding royalty interest owners or to
create filing, reporting or certification obligations for the Trustee or the
Unit holders. Moreover, other parties, such as oil or gas purchasers, may be
able to instigate private lawsuits or other legal action to compel refunds from
overriding royalty interest owners with respect to oil or gas pricing
overcharges. The Working Interest Owner has agreed that it will not seek to
recover from the Unit holders the amount of any refunds it is required to make
except out of future revenues payable to the Trust. See "Terms and Operation of
the Trust -- Terms of the Conveyances" for a description of agreements relating
to the method of handling refunds. The Trustee will be fully liable to the Unit
holders if the Trustee incurs any liability without taking steps reasonably
necessary to ensure that such liability will be satisfiable only out of the
Trust assets (regardless of whether the assets are adequate to satisfy the
liability) and in no event out of amounts distributed to, or other assets owned
by, Unit holders. However, the Trustee will not be liable to the owners of Units
for state or federal income taxes or for refunds, fines, penalties or interest
relating to oil or gas pricing overcharges under state or federal price
controls. The Trustee will be indemnified out of the Trust assets, to the extent
that the Trustee's actions do not constitute negligence, bad faith or fraud, or
are based on good faith reliance upon an expert. In weighing the possible
exposure to liability in the event the Trust were not classified as an "express
trust", each Unit holder should consider (a) the passive nature of the Trust
assets, (b) the restrictions on the power of the Trustee to incur liabilities on
behalf of the Trust and (c) the limited activities to be conducted by the
Trustee.
VOTING BY UNIT HOLDERS
Each Unit is entitled to one vote on any matter submitted to Unit holders.
Meetings of Unit holders may be called at any time by the Trustee and must be
called by the Trustee at the written request of Unit holders owning at least 10%
of the Units. Unit holders may vote in person or by proxy. A majority of Unit
holders is required to constitute a quorum. Except as otherwise provided in the
Trust Agreement, any action by the Unit holders requires the concurrence of the
Trustee and the affirmative vote of Unit holders owning a majority of the Units
represented at the meeting, in person or by proxy. The Trustee and the Working
Interest Owner may solicit and vote proxies.
Although Unit holders possess certain voting rights, their voting rights
are not comparable to those of shareholders of a corporation. For example, there
is no requirement for annual meetings of Unit holders or for annual or other
periodic reelection of the Trustee. To date, no matter has been submitted to a
vote of the Unit holders.
CERTAIN STATE LAW CONSIDERATIONS
It is anticipated that the Units will be treated for certain state law
purposes essentially the same as other securities, that is, as interests in
intangible personal property rather than as interests in real property. However,
there is a possibility that a Unit holder could be treated as owning an interest
in real property. In that event, the tax, probate, devolution of title and
administration laws of Texas, Louisiana, Florida and Alabama applicable to real
property may apply to the Units, even if held by a person who is not a resident
or domiciliary thereof. Application of such laws would make inheritance and
related matters with respect to the Units substantially more onerous than they
would be if the Units are treated as interests in intangible personal property.
In any event the ownership of Units and realization of income from the Royalties
by a Unit holder may subject such Unit holder to state or local income or other
taxation in the state of the Unit holder's residence or domicile. Unit holders
should consult their legal and tax advisors regarding the applicability of these
considerations to their individual circumstances. See "Tax Consideration to
Owners of Units -- State Tax Considerations".
11
<PAGE> 15
THE PROPERTIES
GENERAL
The Trustee has no responsibility relating to the operation of the
Productive Properties or Fee Lands. The information in this Annual Report on
Form 10-K relating to the characteristics of, operations on, and sales from the
Productive Properties and Fee Lands and certain other matters has been furnished
to the Trustee by the Working Interest Owner. The Working Interest Owner is not
the operator of the Jay Field, South Pass 89 or Offshore Louisiana Properties.
On January 31, 1997, the Working Interest Owner sold all of the Fort Worth Basin
Properties with an effective date of October 1, 1996 for $65,000, and the
Trust's interests in such properties terminated on that date.
The Overriding Royalties were carved out of interests (primarily working
interests) owned by the Working Interest Owner at the time of the creation of
the Trust. References herein to "net" wells and acres refer to the interest of
the Working Interest Owner (from which the Royalties were carved) in the "gross"
wells or acres. References to the percentage of the working interest owned by
the Working Interest Owner are references to the working interest out of which
the Overriding Royalties were carved. For example, a reference to a "20% working
interest" in a well or lease that is included in a Productive Property indicates
that the Trust's Overriding Royalties burden 20% of the working interest in the
well or lease. That 20% working interest is also subject to landowners'
royalties and may be subject to other overriding royalty interests and other
burdens that are considered prior to calculation of the amounts payable with
respect to the Overriding Royalties. Since the amounts and nature of such
burdens vary from lease to lease, the information presented herein regarding the
Working Interest Owner's percentage of the working interest in wells or leases
cannot be used to calculate precisely the Trust's interest in any particular
well or lease. In addition, (a) because operating and capital costs are taken
into consideration in calculating the amounts payable with respect to the
Overriding Royalties and because prices for oil and gas may vary from field to
field, information regarding results of well tests or gross quantities of
production from a given well cannot be used to compute the Trust's interest and
(b) because the Productive Properties consist of multiple leases and, in some
cases, multiple fields, the interest of the Working Interest Owner in any given
well or lease may not be indicative of its interest (or the Trust's interest) in
an entire Productive Property.
12
<PAGE> 16
DESCRIPTION OF PRODUCTIVE PROPERTIES
Certain information, as of December 31, 1998, regarding the Productive
Properties is set forth in the table below. The Productive Properties include
leases (or portions thereof) owned by the Working Interest Owner on which
productive formations are located and, in certain cases, adjacent leases (or
portions thereof) owned by the Working Interest Owner which are either included
in pooling arrangements or which are held by delay rentals. The leases were
grouped into four groups, with each constituting a separate "Property" for
purposes of computing the Overriding Royalties under the Conveyances. The
numbers of net acres and net wells in the table below represent amounts net to
the Working Interest Owner as of December 31, 1998.
<TABLE>
<CAPTION>
PRODUCTIVE WELLS(1)
PRODUCTIVE -------------------------------
PROPERTY AND YEAR ACRES OIL GAS
IN WHICH ----------------- -------------- -------------
PRODUCTION COMMENCED LOCATION GROSS NET GROSS NET GROSS NET
-------------------- -------- ------- ------ ----- ----- ----- ----
<S> <C> <C> <C> <C> <C> <C> <C>
Jay Field (1970)(2)......... Onshore 184,472(3) 62,150(3) 65 21.9 -- --
Alabama
and Florida
South Pass 89 (1982)........ Offshore 5,000 1,250 11 2.75 1 .25
Louisiana
Offshore Louisiana
(1968)(4)................... Offshore 26,563 5,646 11(5) 1.3 15(5) 3.0
Louisiana
Fort Worth Basin
(1977)(6)................... Onshore
Texas -- -- -- -- -- --
------- ------ -- ----- --
216,035 69,046 87 25.95 16 3.25
======= ====== == ===== == ====
</TABLE>
- ----------
(1) Represents wells productive or capable of production. Net wells reflect the
Working Interest Owner's working interest ownership. Gross and net wells
exclude injection wells.
(2) Includes interests in 23 leases which are a part of the Jay Field Unit
created by a unit agreement among Exxon Company, U.S.A. (the operator) and
others. The Jay Field is made up of 177 different tracts of land. Portions
of certain leases are located outside of the Jay Field Unit. The Overriding
Royalties from the Jay Field burden only the portions of such leases
included within the Jay Field Unit and owned by the Working Interest Owner
as of June 28, 1983. In addition, certain minor interests of the Company in
the Jay Field are not included in the Jay Field Productive Property. The
information in the table above relates only to the portion of the Jay Field
included in the Jay Field Productive Property.
(3) Gross acres reflects aggregate porosity acre feet in producing formations in
the Jay Field, and net acres reflects the Working Interest Owner's
ownership interest in the producing formations as determined volumetrically
for purposes of the unit agreement relating to the Jay Field.
(4) Includes six federal leases or federal units (as applicable) with
designations, initial production dates and percentage ownership of the
Working Interest Owner as follows:
<TABLE>
<CAPTION>
PERCENTAGE
OF THE WORKING
INTEREST OWNED
DESIGNATION AND INITIAL BY THE WORKING
PRODUCTION DATE INTEREST OWNER
<S> <C>
East Cameron 195 Unit (1971).............................. 33.33%
East Cameron 336, South Addition (1983)................... 20%
Eugene Island 261 (1979).................................. 20%
South Marsh Island 76, South Addition (1968).............. 25%
Vermilion 331, South Addition (1977)...................... 12.5%
</TABLE>
Last year, the Company disclosed an additional 8.33% working interest owned
by the Company in the South Marsh Island 76, South Addition that was not
burdened by the Overriding Royalties. The Company disposed of this interest
in 1998. Eugene Island 261 ownership excludes a 13.33% working
13
<PAGE> 17
interest owned by the Company that is not burdened by the Overriding
Royalties. Vermilion 331, South Addition ownership excludes a 12.5% working
interest owned by a subsidiary of the Company that is not burdened by the
Overriding Royalties. All of Vermilion 267 was assigned to other owners and
the Working Interest Owner withdrew from the lease effective 1/1/97 as it
continued to operate at a cash deficit.
(5) Gross wells at Offshore Louisiana include one dual completion gas well. A
well with multiple completions is counted as one well.
(6) On January 31, 1997, the Working Interest Owner sold all of the Fort Worth
Basin Properties for $65,000. The Trust's interests in the proceeds of the
sale less excess production costs recoverable were distributed to the Trust
in April 1997.
DESCRIPTION OF THE FEE LANDS
The Fee Lands originally subject to the Fee Lands Royalties consisted of
approximately 400,000 acres of undeveloped lands owned in fee by the Working
Interest Owner in south Louisiana that were not subject to oil and gas leases as
of the effective date of the Conveyances with respect to the Fee Lands
Royalties. The Fee Lands constituted a substantial portion of all of the land
owned in fee by the Working Interest Owner in south Louisiana at the time of the
Conveyances but excluded (a) the Working Interest Owner's property subject to
oil and gas leases or productive lands owned by the Working Interest Owner as of
such date, (b) beds and bottoms of navigable waters and (c) certain other minor
parcels of land. The Working Interest Owner has developed very limited portions
of the Fee Lands, and could, but has no obligation to, elect to develop certain
additional portions of the Fee Lands itself.
Under Louisiana law, mineral royalties, in general, will terminate, in the
absence of production, after the lapse of ten consecutive years from the date of
conveyance. However, the production of any mineral included in the Conveyances
(including that obtained through testing a shut-in well proved to be capable of
producing in paying quantities) before the lapse of ten years will, except as
hereinafter provided with respect to production obtained from a unit, maintain
the Royalties in existence for so long as such production continues without
cessation, and for a period of ten years thereafter, as to all of the lands
affected thereby that are contiguous to the land burdened by the Royalties from
which such production is obtained. Tracts of land are rendered noncontiguous by
intervening tracts owned by third parties or not covered by the Conveyances,
including navigable bodies of water, that divide and separate the lands burdened
by the Royalties. Parcels of land that meet only at a corner are likewise
noncontiguous. The Fee Lands contain both contiguous and noncontiguous tracts.
In the case of production from a unit, the Royalties will be maintained with
respect to the whole of the body of land contiguous to the production so long as
such production continues without cessation, and for a period of ten years
thereafter, if the unit well is situated on land burdened by the Royalties; but
if the unit well is on land other than that burdened by the Royalties,
production maintains the Royalties only with respect to that portion of the land
included in the unit. If all or a portion of the tract of land burdened by the
Royalties is included within a unit on which there already exists a shut-in well
capable of producing in paying quantities located on other lands within the
unit, the ten-year period for termination of the Royalties in the absence of
production would begin anew on the effective date of the order or act creating
the unit, and production within the ten-year period would maintain the Royalties
only with respect to the acreage subject to the Royalties included in the unit.
A unit is an area within which all owners of mineral rights share in production
therefrom. It may be created by agreement or by the Louisiana Department of
Conservation. The Trust receives minimal revenues related to production from
wells drilled on Fee Lands acreage as well as from certain units that include
small portions of the lands burdened by the Fee Lands Royalties. Since the
producing wells on unitized acreage are located on property other than that
burdened by the Fee Lands Royalties, such production could serve to maintain the
Fee Lands Royalties beyond the initial ten year period only as to the lands
included within said Units.
Consequently, most of the Fee Lands Royalties in the original Fee Lands
terminated in June 1993. The Trust never received any revenues from the tracts
as to which the Fee Lands Royalties terminated and such termination did not
affect tracts from which the Trust is receiving revenues. However, the Trust
will not be entitled to receive any revenues in the future from the tracts as to
which the Fee Lands Royalties terminated.
14
<PAGE> 18
Subsequent to the June 1993 termination, the Fee Lands consist of approximately
35,000 gross acres, approximately 4,509 acres of which were under lease as of
December 31, 1998.
OIL AND GAS SALES FROM THE PRODUCTIVE PROPERTIES
OIL SALES
In addition to crude oil sold to unaffiliated third parties, crude oil from
South Pass 89 and two of the Offshore Louisiana Productive Properties is sold to
an affiliate, which transports the oil to shore and sells it to unaffiliated
third parties at "spot" prices. For purposes of computing the payments
attributable to the Overriding Royalties, Net Proceeds include the proceeds from
the sales by the affiliate after deduction of applicable transportation costs.
Prior to the sale of the Working Interest Owner's Mobile, Alabama refinery
in July 1996, substantially all of the crude oil from the Jay Field was used as
feedstock for said refinery. The Working Interest Owner treats, for internal and
landowners' royalty purposes, Jay Field crude as sold at the wellhead at the
Exxon posted field price. This treatment is also utilized for purposes of
computing Net Proceeds.
GAS AND LIQUIDS SALES
Natural gas from the Productive Properties is sold to an affiliate, which
transports the offshore Louisiana gas onshore, and sells that gas and the Jay
Field gas to unaffiliated third parties at published "spot" prices under
contracts typical of those prevailing in the industry.
The Working Interest Owner generally retained the right to revenue from
liquids contained in the gas sold offshore Louisiana. Depending upon the prices
prevailing from time to time for natural gas relative to those for gas liquids,
all or a portion of such gas is processed at plants located onshore Louisiana to
remove the liquids. Both these liquids and the liquids available at the tailgate
of the Jay Field processing plant are sold by an affiliate to unaffiliated third
parties, some of which is transported by the affiliate prior to the sale. Some
of the propane and virtually all of the other liquids are sold by the affiliate
at published "spot" prices, while the propane from the Jay Field and some of the
Offshore Louisiana Productive Properties are sold to Dufour Petroleum at a price
based upon Dufour's posted price.
For purposes of computing the payments attributable to the Overriding
Royalties, Net Proceeds include the proceeds from the natural gas and liquids
sales by the affiliate after deduction of applicable transportation and
processing costs.
Due to the state of the gas industry and the marketing strategies used by
different purchasers and producers, it is not uncommon for certain working
interest owners in a property to be overproduced and to have delivered more gas
than such owner was entitled to sell, leaving the other working interest owners
underproduced. As a result, an imbalance may develop between the various working
interest owners regarding the amount of gas to which each is entitled and the
amount each actually takes and sells. The Working Interest Owner uses the
"entitlement" method of recording gas production, which results in revenues
being recognized on the Working Interest Owner's share of production regardless
of which party's purchaser has actually taken and paid for the gas. Because the
Working Interest Owner records revenues and makes distributions to the Trust
based upon its entitled share of production at the relevant contractual prices,
and because the Working Interest Owner's actual receipts depend on the price it
receives when the imbalances are reconciled, adjustments to the Working Interest
Owner's recorded revenues have been made in the past and may be made in the
future. To the extent that any such adjustments decrease the revenues recorded
by the Working Interest Owner because gas prices were lower at the time the
Working Interest Owner's gas was actually delivered than when the revenues were
originally recorded, or for other reasons, future distributions to the Trust
would be reduced.
The laws and regulations governing the prices which the Working Interest
Owner receives from the sale of oil and gas from the Productive Properties and
the taxes paid with respect to the production are complex, often ambiguous and
subject to alteration, often with retroactive effect. If the Working Interest
Owner does
15
<PAGE> 19
not properly interpret the applicable law or regulations in a manner consistent
with later determinations and interpretations of regulatory authorities or of
the courts, the Working Interest Owner may be required to refund to its
customers amounts previously collected plus interest, which may be substantial
if a long period passes between the time of the overcharge and the determination
that a refund is required. See "Terms and Operation of the Trust -- Terms of the
Conveyances" for information regarding the effect of any refunds on Unit
holders.
EXPLORATION AND DEVELOPMENT ACTIVITIES
PRODUCTIVE PROPERTIES
The following is a summary of the Working Interest Owner's net drilling
activities on the Productive Properties for the years ended December 31, 1996,
1997 and 1998:
<TABLE>
<CAPTION>
NET WELLS
-----------------------------
OIL GAS DRY
1996 -------- -------- -----
<S> <C> <C> <C>
Exploratory............................................ -- 0.4 --
Development............................................ -- -- --
1997
Exploratory............................................ 0.3 0.2 --
Development............................................ -- 0.2 --
1998
Exploratory............................................ -- -- 0.125
Development............................................ -- -- --
</TABLE>
At December 31, 1998, no wells were in progress on the Productive
Properties.
The following are the significant activities by the Working Interest Owner
on the Productive Properties during 1998:
Jay Field
Capital expenditures totaled approximately $3.9 million in 1998, $2.9
million of which was for nitrogen injection costs.
South Pass 89
Capital expenditures of approximately $0.3 million were incurred in 1998.
Offshore Louisiana
Capital expenditures of approximately $1.1 million were incurred in 1998
primarily for the drilling of one unsuccessful gas well and the recompletion of
another gas well.
FEE LANDS
Approximately 4,509 acres of the south Louisiana Fee Lands subject to the
Trust's 3% royalty interest were under lease as of December 31, 1998. There were
no wells drilled on the Fee Lands in 1998.
16
<PAGE> 20
ESTIMATES OF PETROLEUM ENGINEERS
SEPTEMBER 30, 1998 ESTIMATES
Estimates of the Properties' proved oil and gas reserves and estimates of
the future net revenues from the proved oil and gas reserves attributable to the
Properties as of September 30, 1998 have been made by Miller and Lents, Ltd.
("Miller and Lents"). Based on such estimates, Miller and Lents has also
calculated the present value of the estimated future net revenues to the Trust
and the imputed reserves attributable to the Trust as of September 30, 1998. A
copy of Miller and Lents' letter, dated February 23, 1999 setting forth such
estimates is reproduced below.
As explained in the letter, the estimates of future net revenues from
proved reserves and the present value of such future net revenues were
calculated based on criteria prescribed by the Securities and Exchange
Commission (the "SEC") and were based upon prices and costs during September
1998; the present value was based on a discount factor of 10% per year.
According to the Miller and Lents letter, the estimated future net revenues
to the Trust from total proved reserves as of September 30, 1998 were
approximately $12.7 million, and the present value of such future net revenues
was approximately $7.5 million. (The estimates as of September 30, 1997,
performed by Gruy Engineering Corp., ("Gruy") were $117.6 million and $58
million, respectively, before giving effect to approximately $9.4 million in
distributions during 1998.)
The estimates of future net revenues as of September 30, 1998 reflect an
87.9% decrease in future net revenues, and an 85.3% decrease in the present
value of future net revenues from those estimated by Gruy as of September 30,
1997, after adjusting those 1997 estimates for distributions related to the
twelve months of production ended September 30, 1998. The decreases resulted
primarily from lower prices as compared with September 30, 1997 estimates;
however approximately 17% of the reduction in present worth of the future net
revenues attributable to the Jay Field is the result of a forecast of oil and
gas production by Miller and Lents that predicts a more moderate rate of
extraction than that forecast by Gruy in the report as of September 30, 1997. In
general, spot domestic natural gas prices increased slightly while crude oil and
gas condensate prices have decreased in late 1998. The decrease in 1998
estimated future net revenues from the 1997 estimates (after adjusting the
estimates for 1998 distributions) was attributable to Jay Field, South Pass 89
and Offshore Louisiana, where those estimates decreased by approximately $91.3
million, increased by $2.1 million and decreased $3.3 million, respectively.
CERTAIN FACTORS AFFECTING ESTIMATES
Because the Royalties on the Properties (other than the Fee Lands) are
"net" overriding royalty interests (often referred to as net profits interests),
estimates of future net revenues to the Trust are affected by a number of
factors in addition to the engineering, well performance and other data taken
into consideration by petroleum engineers in estimating the quantity and nature
of gross oil and gas reserves in the ground. Such other factors include oil and
gas prices (the changes in which have materially affected the estimates of
future net revenues to the Trust in recent years), projections of operating and
capital costs, and the Working Interest Owner's evaluation of the economic
feasibility of conducting additional operations.
As indicated above, estimates of future net revenues attributable to the
Trust are based in part on estimates of quantities of proved oil and gas
reserves in place. It should be emphasized that there can be no assurance that
the quantities of oil and gas classified as proved reserves will ultimately be
recovered. Because estimating proved reserves is not an exact science, the
potential for significant revisions, either upward or downward, in estimates of
proved reserves is high. Such revisions have occurred in the past with respect
to the Productive Properties and, with respect to certain Productive Properties,
have been material in relation to the reserves assigned to such Productive
Properties. Reserve estimates are based on many judgmental factors, and the
accuracy of reserve estimates depends on the quantity and quality of geological
data, production performance data and reservoir engineering data as well as the
skill and judgment of the petroleum engineer in interpreting such data. The
process of estimating reserves involves continual revisions of estimates
(usually on an annual basis) as additional information is made available through
drilling, testing, reservoir studies and
17
<PAGE> 21
acquiring historical pressure and production data. When a new reservoir is
discovered, proved reserves are determined strictly by volumetric analysis,
using limited reservoir data (porosity, net pay thickness, water saturation,
permeability and estimated extent of the productive area) indicated by the
discovery well to estimate reserves over an underground area that may cover many
acres. As a well is produced and the reservoir pressure declines, production
volumes (hydrocarbons and water) and other factors are generally monitored and
recorded so that the proved reserves can be periodically reestimated following
sufficient intervals of production history. In addition, the drilling of
development wells can provide additional reservoir data, including information
regarding the areal extent of the reservoir. As reservoir history is
accumulated, the historical information is incorporated into volumetric
calculations or extrapolated production performance plots to refine the reserve
estimate. Consequently, the accuracy of the reserve estimate generally improves
with additional production history.
Estimates of both the volume of, and future net revenues from, any
specified reserves are of necessity based on assumptions with respect to
anticipated market demand and prices obtainable for production from the
particular reservoir and with respect to the costs and expenses incurred in
developing and producing those reserves. A decline in price will reduce the
estimated future revenues to the Trust. A reduction in volume of sales from
those estimated, as a result of curtailments or otherwise, delays the receipt of
revenues and reduces the present value of future net revenues from the property.
Similarly, changes in the timing and amounts of future capital expenditures can
also affect the revenues and the present value. Consequently, reserve, net
revenue and present value estimates made in the future may differ materially
from those contained herein as a result of conditions in the oil and gas
industry and general economic conditions.
The independent engineers' estimated net revenues have been determined on
the basis of when the oil or gas is estimated to be produced. However, the
payments with respect to the Royalties are received by the Trustee approximately
65 days after the end of the month in which the sales of oil and gas are
recorded as revenues by the Working Interest Owner, and the distribution of
income from the Royalties to holders of Units (net of Trust expenses) occurs
approximately 75 days after the end of such month. The estimated net revenues in
Miller and Lents' letter have not been reduced for costs and expenses of the
Trust, which are expected to be approximately $.6 million for the twelve months
ending September 30, 1999. The costs and expenses of the Trust may increase or
decrease in future years, depending on the amount of revenues from the
Royalties, increases or decreases in accounting, engineering, legal and other
professional fees and other factors.
In estimating future net revenues to the Trust, Miller and Lents has only
considered capital expenditures associated with the production and development
of estimated proved reserves. Based on that assumption, Miller and Lents
estimated that as of September 30, 1998, the Working Interest Owner's capital
expenditures for production and development of only the proved reserves would be
approximately $15.6 million for the period from October 1, 1998 through December
31, 2001. No assurance can be given that the level of capital expenditures
included in this estimate will result in the discovery of additional reserves or
the successful development of reserves now classified as proved undeveloped.
Amounts of future net revenues estimated for any given period do not take into
account the possible effect of current or possible future market conditions
relating to the price of oil and gas and other factors discussed below.
In making its estimates, Miller and Lents used price and cost assumptions
as described in the Miller and Lents letter. These assumptions are assumptions
only, and there can be no assurance that actual prices and costs in the future
will not be materially different from those assumed. Prices of oil and gas and
related costs have varied dramatically in recent years and are impossible to
predict with certainty. As a result, and because of other inherent uncertainties
in estimating oil and gas reserves and in forecasting production levels, prices
and costs, neither the Trustee nor Miller and Lents nor the Working Interest
Owner can predict what actual revenues to the Trust will be. See "Industry
Conditions and Regulation".
Pursuant to Statement of Financial Accounting Standards No. 69 the Trust is
required to include as supplementary information estimates (which are unaudited)
of quantities of proved oil and gas reserves attributable to the Trust. The
Miller and Lents letter includes such estimates, prepared on the basis described
therein. The quantities imputed to the Trust are calculated by multiplying
Miller and Lents' estimated net
18
<PAGE> 22
reserves of the Working Interest Owner (prior to taking into consideration the
Trust's interests) by the ratio of Miller and Lents' estimated future net
revenues to the Trust to Miller and Lents' estimated future gross revenues to
the Working Interest Owner prior to taking into consideration the Trust's
interests. Because the quantities are calculated in this manner, factors other
than gross oil and gas reserves in the ground (such as changes in prices and
costs, excesses of capital expenditures over amounts used in preparing
estimates, as described in the preceding paragraphs, and other factors) will
affect the quantities shown as estimated oil and gas reserves imputed to the
Trust.
19
<PAGE> 23
[MILLER AND LENTS, LTD LETTERHEAD]
[FIFTY YEARS OF SERVICE LOGO]
February 23, 1999
Chase Bank of Texas, National Association, Trustee
LL&E Royalty Trust
600 Travis, 11th Floor
Houston, Texas 77002
Re: LL&E Royalty Trust
00-97-5013
Gentlemen:
In response to your request, we estimated the proved reserves and future
net revenues attributable to certain working and royalty interests owned by
Burlington Resources (the "Company") in certain properties in which the LL&E
Royalty Trust (the "Trust") owns an interest.
The Trust owns, indirectly through a partnership with the Company, (a) net
overriding royalty interests equivalent to net profits interests (the
"Overriding Royalties") in certain productive oil and gas properties located in
Alabama and Florida and federal waters Offshore Louisiana (the "Working Interest
Properties") and (b) a three percent royalty interest (the "Royalties") under
approximately 35,000 acres of the Company's south Louisiana fee lands (the "Fee
Lands"). We calculated the imputed reserves using the formulas and criteria
specified by the Company, as described in following paragraphs, and estimated
future revenues net to the Trust as of September 30, 1998 in accordance with the
definitions contained in the Securities and Exchange Commission Regulation S-X,
Rule 4-10(a) as shown in the Appendix.
The estimated proved imputed reserves and future net revenue, discounted
at 10 percent per year, compounded annually, net to the interests owned by the
Trust as of September 30, 1998 are:
<TABLE>
<CAPTION>
Net Proved
Net Proved Imputed Reserves
--------------------------------------
Crude Oil, Discounted
Condensate, and Natural Future Net Estimated
Natural Gas Liquids Gas, Revenue, Net Revenues,
Reserve Category MBbls. MMcf M$ M$
- ---------------- ------------------- ------- ---------- -------------
<S> <C> <C> <C> <C>
Proved Developed 391 1,869 8,412 4,371
Proved Undeveloped 37 2,162 4,264 3,081
--- ----- ------ -----
Total Proved 428 4,031 12,676 7,452
=== ===== ====== =====
</TABLE>
20
<PAGE> 24
[MILLER AND LENTS, LTD. LETTERHEAD]
Chase Bank of Texas, National Association, Trustee February 23, 1999
LL&E Royalty Trust Page 2
These figures are based on estimates from the Trust economic model that is
attached to this report.
The table below shows summary projections of the estimated undiscounted
net revenues to the Trust:
<TABLE>
<CAPTION>
Estimated Net Revenues to the Trust
-------------------------------------
For Production From Proved From Proved From Total
During the 12 Developed Undeveloped Proved
Months Ended Reserves, Reserves, Reserves,
September 30 M$ M$ M$
-------------- -------- --------- ----------
<S> <C> <C> <C>
1999 2,927 0 2,927
2000 500 0 500
2001 289 1,417 1,705
2002 123 1,699 1,822
2003 23 1,148 1,171
2004 22 0 22
Remainder 4,528 0 4,529
------ ------ -------
Total 8,412 4,264 12,676
====== ====== =======
</TABLE>
The following table sets forth the total estimated undiscounted future net
revenues to be disbursed to the Trust from proved reserves of each Working
Interest Property and the Fee Lands from January 1, 1999:
<TABLE>
<CAPTION>
Last Year of
Estimated Future Estimated
Net Revenues to Economic
The Trust, Life of
Property M$ Reserves
- ------------------- ------------ ------------
<S> <C> <C>
Jay Field 4,203 2036
South Pass 89 5,793 2003
Offshore Louisiana 2,080 2002
Fee Lands 600 2049
----------
Total 12,676
==========
</TABLE>
For the purposes of computing the above net revenues to the Trust, the Working
Interest Properties have been grouped geographically into three groups of
leases designated as the "Jay Field", "South Pass 89", and "Offshore
Louisiana". The "Fort Worth Basin" group was sold prior to September 30, 1997
and is not included in this report. The Company has conveyed Overriding
Royalties to the Trust expresses as various percentages of Net Proceeds from
these Working Interest Properties and has also conveyed to the Trust three
percent royalty interest in the Fee Lands. The table below sets forth the
percentage of Net Proceeds attributable to the Overriding Royalties for each
Working Interest Property:
21
<PAGE> 25
MILLER AND LENTS, LTD.
Chase Bank of Texas, National Association, Trustee February 23, 1999
LL&E Royalty Trust Page 3
<TABLE>
<CAPTION>
Percentage of Net Proceeds
Working Interest Property Attributable to Overriding Royalties
- ------------------------- ------------------------------------
<S> <C>
Jay Field 50
South Pass 89 50
Offshore Louisiana 90
</TABLE>
The Overriding Royalties owned by the Trust are equivalent to net profits
interests of varying percentages, as shown above, of the Net Proceeds from the
sale of production of oil, gas, and other hydrocarbons from the Working Interest
Properties. Net Proceeds have been computed on a property-by-property basis and
consist of the revenues recorded by the Company from the sale of oil, gas, and
other hydrocarbons from each of the Working Interest Properties less (a) all
direct costs, charges, and expenses incurred by the Company in production,
development, and other operations on the Working Interest Properties (including
secondary and tertiary recovery operations), and for dismantlement and
abandonment costs where applicable; (b) all applicable taxes (including
severance and ad valorem) excluding income taxes; (c) all operating charges
directly associated with the Working Interest Properties, (d) applicable charges
for certain overhead expenses, and (e) other charges specified in the Trust
documents. Administrative expenses of the Trust have not been deducted in
determining the net revenues in the foregoing tables. The total future
dismantlement costs to the Company's working interest included in the
calculation of Net Proceeds are $2.6 million for South Pass 89, $9.6 million for
the Jay Field, and $3.0 million for the Offshore Louisiana properties.
Currently, $2.3 million is escrowed for dismantlement for Offshore Louisiana.
Excess production costs will result to the Company's working interest in
the event that the costs, charges, and expenses attributable to a Working
Interest Property exceed the revenues received from the sale of oil, gas, and
other hydrocarbons produced from such property ("Excess Production Costs").
Pursuant to the provisions of the Trust documents, the Company is allowed to
recover such costs from future Net Proceeds. As of December 31, 1998, Excess
Production Costs to the Company's working interest are zero for South Pass 89,
Jay Field, and the Fee Lands properties. Excess production costs for the
Offshore Louisiana properties are $0.769 million.
The estimated net revenues to the Trust from proved reserves of the Working
Interest Properties and Fee Lands have been determined on the basis of when the
oil or gas attributable to the Overriding Royalties or the Royalties is
estimated to be produced. However, the distribution of the Net Proceeds to the
Trust will occur approximately 65 days after the end of the month in which the
sales of oil and gas from the productive properties and the Fee Lands are
recorded as revenues by the Company. Therefore, estimated net revenues to the
Trust from proved reserves for a 12-month period beginning October 1 correspond
to estimated distributions to the Trust during the following calendar year. The
amounts in the tables above reflect those estimates of the disbursements to the
Trust.
The estimates of future net revenues have been calculated using methods
prescribed by the Securities and Exchange Commission by applying the prices for
oil and gas being received by the Company in September 1998 to estimated future
production of oil and gas reserves over the economic
22
<PAGE> 26
MILLER AND LENTS, LTD.
Chase Bank of Texas, National Association, Trustee February 23, 1999
LL&E Royalty Trust Page 4
life of the reserves and assuming continuation of existing economic conditions.
Surface and well equipment salvage values and well plugging and field
abandonment costs have been considered in the projections computing Net Proceeds
for all properties.
The reserve estimates and production rate projections used to forecast
future net revenues and imputed reserves attributable to the Trust are based on
detailed geologic and engineering studies, with corresponding rate projections
made consistent with current producing rates and performance of comparable
wells. Where sufficient data were available, oil and gas reserves were estimated
by extrapolation of established historic performance trends. Reserves for the
remaining properties were estimated by volumetric calculations or by analogy to
similar properties. Estimated reserves for the Jay Field property are based on
comprehensive engineering studies utilizing historic performance trends and
reservoir simulation computer model studies.
Net reserves, as used herein, are reserves net to the Company or imputed
to the Trust after taking into account existing third party interests and
landowners' royalties. Portions of the properties are pooled or unitized, and
the reserve estimates herein are based on existing pooling and unitization
arrangements.
The imputed estimated proved reserves attributable to the Trust were
calculated for each property by multiplying the net proved reserves of the
Company by the ratio of the estimated future net revenues of the Trust to the
estimated future gross revenues of the Company from each of the properties
prior to consideration of the Trust, as follows:
<TABLE>
<S> <C> <C>
Estimated future
Imputed proved reserves net revenues to the Estimated net proved
to the Trust (expressed = Trust x reserves of the Company
in barrels or Mcf) ------------------- (barrels or Mcf)
Estimated future
gross revenues
to the Company(1)
</TABLE>
(1) Prior to subtraction of all costs (including Jay Field fuel and severance
taxes) and the costs attributable to the Trust.
As the imputed estimated reserves of the Trust are calculated using estimated
future revenues, changes in the assumption on which the revenue estimates are
based would result in changes in the Trust's imputed reserves.
The evaluations presented in this report, with the exceptions of those
parameters specified by others, reflect our informed judgments based on
accepted standards of professional investigation but are subject to those
generally recognized uncertainties associated with interpretation of
geological, goephysical, and engineering information. Government policies and
market conditions different from those employed in this study may cause the
total quantity of oil or gas to be recovered, actual production rates, prices
received, or operating and capital costs to vary from those presented in this
report.
23
<PAGE> 27
[MILLER AND LENTS, LTD LETTERHEAD]
Chase Bank of Texas, National Association, Trustee February 23, 1999
LL&E Royalty Trust Page 5
The extent and character of ownership, reversions, product prices, test,
production, and other data which were furnished by the Company have been
accepted as represented. Operating costs and estimated capital expenditures
furnished by the Company were reviewed for reasonableness. No field inspections
or well tests were conducted by personnel in conjunction with this study. We
did not verify or determine the extent, character, obligations, status or
liabilities, if any, arising from any gas imbalances or any current or possible
future environmental liabilities that might be applicable.
Any distribution or publication of this letter or any part thereof must
include this letter in its entirety.
Very truly yours,
MILLER AND LENTS, LTD.
By /s/ LARRY M. GRING
-------------------------------
Larry M. Gring
Senior Vice President
LMG/psh
24
<PAGE> 28
Appendix
PROVED RESERVE DEFINITIONS
IN ACCORDANCE WITH
SECURITIES AND EXCHANGE COMMISSION REGULATION S-X
PROVED OIL AND GAS RESERVES
Proved oil and gas reserves are the estimated quantities of crude oil,
natural gas, and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions, i.e., prices
and costs as of the date the estimate is made. Prices include consideration of
changes in existing prices provided only by contractual arrangements but not on
escalations based upon future conditions.
1. Reservoirs are considered proved if economic producibility is
supported by either actual production or conclusive formation test.
The area of a reservoir considered proved includes (a) that portion
delineated by drilling and defined by gas-oil and/or oil-water
contacts, if any, and (b) the immediately adjoining portions not yet
drilled but which can be reasonably judged as economically productive
on the basis of available geological and engineering data. In the
absence of information on fluid contacts, the lowest known structural
occurrence of hydrocarbons controls the lower proved limit of the
reservoir.
2. Reserves which can be produced economically through application of
improved recovery techniques (such as fluid injection) are included in
the proved classification when successful testing by a pilot project
or the operation of an installed program in the reservoirs provides
support for the engineering analysis on which the project or program
was based.
3. Estimates of proved reserves do not include the following:
a. Oil that may become available from known reservoirs but is
classified separately as indicated additional reserves.
b. Crude oil, natural gas, and natural gas liquids, the recovery of
which is subject to reasonable doubt because of uncertainty as to
geology, reservoir characteristics, or economic factors.
c. Crude oil, natural gas, and natural gas liquids, that may occur
in undrilled prospects.
d. Crude oil, natural gas, and natural gas liquids, that may be
recovered from oil shales, coal, gilsonite, and other such
sources.
Depending upon their status of development, proved reserves are subdivided
into proved developed reserves and proved undeveloped reserves.
PROVED DEVELOPED OIL AND GAS RESERVES
Proved developed oil and gas reserves are reserves that can be expected to
be recovered through existing wells with existing equipment and operating
methods. Additional oil and gas expected to be obtained through the application
of fluid injection or other improved recovery techniques for supplementing the
natural forces and mechanisms of primary recovery should be included as proved
developed reserves only after testing by a pilot project or after the operation
of an installed program has confirmed through production response that increased
recovery will be achieved.
PROVED UNDEVELOPED OIL AND GSA RESERVES
Proved undeveloped oil and gas reserves are reserves that are expected to
be recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion. Reserves on undrilled
acreage shall be limited to those drilling units offsetting productive units
that are reasonably certain of production when drilled. Proved reserves for
other undrilled units can be claimed only where it can be demonstrated with
certainty that there is continuity of production from the existing productive
formation. Under no circumstances should estimates for proved undeveloped
reserves be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated, unless such
techniques have been proved effective by actual tests in the area and in the
same reservoir.
25
<PAGE> 29
INDUSTRY CONDITIONS AND REGULATION
INDUSTRY CONDITIONS
The availability of a ready market for oil and gas depends upon numerous
factors beyond the Working Interest Owner's control, including the production of
crude oil and gas by others, crude oil imports, the marketing of competitive
fuels, the proximity and capacity of oil and gas pipelines, the availability of
treatment facilities, the regulation of allowable production by governmental
authorities and the regulation by the FERC and various state agencies of the
transportation and marketing of natural gas transported or sold in interstate
commerce. Because of the mechanics of the Royalties, changes in Net Proceeds due
to any of the factors above are typically not reflected in the amounts payable
to the Trust until the third month after the oil and gas sales are recorded or
the related costs are incurred.
REGULATION -- GENERAL
The production of oil and gas in the United States is affected by many
state and federal regulations with respect to allowable rates of production,
marketing and environmental matters. Future regulations could change allowable
rates of production or the manner in which oil and gas operations may be
lawfully conducted.
The Working Interest Owner's oil and gas activities on the Productive
Properties are subject to existing federal, state and local laws and regulations
relating to health, safety, environmental quality and pollution control. The
Working Interest Owner has advised the Trustee that it believes that its
operations and facilities are in general compliance with applicable health,
safety, and environmental laws and regulations. However, events in recent years
have heightened environmental concerns about the oil and gas industry generally,
and about offshore operations in particular. Oil and gas operations are subject
to extensive governmental regulation, including regulations that may in certain
circumstances impose absolute liability upon lessees for the cost of cleaning up
pollutants and for pollution damages resulting from their operations, and that
may require lessees to suspend or cease operations in affected areas. Although
the Working Interest Owner has advised the Trustee that current environmental
regulation has not had a material adverse effect on the Working Interest Owner's
method of operations, the effects of changes in environmental law, such as
stricter environmental regulation and enforcement policies, cannot be predicted.
NATURAL GAS REGULATION
In prior years, natural gas prices were subject to regulation by the
Federal Energy Regulatory Commission. On July 26, 1989, the Natural Gas Wellhead
Decontrol Act of 1989 was enacted. This legislation generally removed wellhead
price controls immediately on certain new wells and wells not covered by a gas
contract and provided for the removal of all controls by January 1, 1993. As a
result, all of the Working Interest Owner's natural gas production is currently
free of wellhead price regulation and is priced at competitive market levels.
In the winter of 1993-94, FERC implemented its Order 636 on the
comparability of pipeline services. The order was designed to eliminate certain
competitive advantages interstate pipelines may have had in selling gas and
further move the industry toward a more efficient, competitive market
environment. Among other things, Order 636 required pipelines to unbundle the
various services that they had provided in the past, such as gas supply,
gathering, transmission and storage, and offer these services individually to
their customers.
26
<PAGE> 30
TAX CONSIDERATIONS TO OWNERS OF UNITS
FEDERAL INCOME TAX CONSIDERATIONS
INTRODUCTION
The following summary discusses the federal income tax consequences
attendant to the acquisition, ownership and disposition of Units. However, for
the following reasons, no assurance can be given that the tax treatment
described in this summary will be available. First, administrative and judicial
interpretations of recent changes in the tax law affecting these matters are
nonexistent or insufficient to provide definitive guidance as to the proper tax
treatment of certain items. Second, certain of the tax consequences described
herein are not subject to clear resolution under present law and the existing
administrative and judicial interpretations thereof. Third, the laws or
regulations affecting these matters are subject to new interpretations, by the
Internal Revenue Service (the "Service") or by the courts, which could adversely
affect Unit holders.
Because the federal income tax consequences of the acquisition, ownership
and disposition of Units are highly complex, this discussion is merely a summary
and does not purport to provide detailed tax information to Unit holders or to
function as a substitute for careful tax planning and analysis. All Unit holders
are urged to consult their own tax advisors regarding the effects on their
personal tax situations of acquiring, owning, and disposing of Units.
RULINGS AND TAX OPINION REGARDING DISTRIBUTION
The following information concerning the Company's ruling requests to the
Service regarding the federal income tax consequences of the creation and
distribution of Units to the Company's shareholders (the "Distribution") and the
operation of the Partnership and the Trust has been provided by the Company. The
Company has received the following requested rulings from the Service:
1. The Trust will be classified as a trust and not as an association
taxable as a corporation.
2. The Trust will be characterized as a "grantor" trust as to the Unit
holders and not as a "nongrantor" trust (a "simple" or "complex" trust).
3. The Partnership will be classified as a partnership and not as an
association taxable as a corporation.
4. The transfer of a Unit will be considered to be the transfer of the
proportionate part of the Partnership interest attributable to such Unit.
5. Each Unit holder will be entitled to deduct cost depletion (or
percentage depletion if greater than cost depletion and if otherwise
allowable) with respect to his pro rata interest in the Royalties computed
by reference to such Unit holder's basis in the Units.
6. Each Royalty will be considered an economic interest in oil and gas
in place, and each Royalty will constitute a single property within the
meaning of Section 614(a) of the Internal Revenue Code (the "Code").
7. Each Unit holder will be treated as the producer of crude oil
attributable to his pro rata interest in the Royalties for windfall profit
tax purposes.
8. The steps taken to create the Trust and the Partnership and to
distribute the Units are properly viewed as a distribution of the Royalties
by the Company to its stockholders, followed by the stockholders'
contribution of the Royalties to the Partnership in exchange for interests
therein, which in turn was followed by the contribution by the stockholders
of the interests in the Partnership to the Trust in exchange for Units.
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Although the Company requested these rulings prior to the time of the
Distribution, the rulings were issued after the Distribution occurred.
Therefore, the Service could revoke the rulings if it changes its position on
the matters the rulings address.
These favorable rulings are consistent with a legal opinion the Company
received from tax counsel prior to the Distribution. The opinion of counsel is
not binding on the Service or the courts, and the Service may revoke its
favorable rulings, as mentioned above. If it were to do so, there can be no
assurance that the position of the Service would not be upheld in a judicial
proceeding.
At the same time the Company requested the rulings described above, the
Company requested a ruling to the effect that it would not recognize gain or
loss upon the transfer of the Royalties to the Trust or upon the Distribution.
The Company subsequently withdrew this request. The Service had indicated to the
Company that, if a ruling had been issued with respect to this issue, it would
have been unfavorable. Tax counsel advised the Company prior to the Distribution
that, because of the lack of direct authority, it was unable to express an
opinion on this issue. See "IDC Recapture Income to the Company on
Distribution".
No other rulings with respect to the Distribution of the Units have been
requested from the Service and, except as noted below, no opinion of counsel has
been requested or rendered regarding any other tax consequences discussed
herein.
TAX CONSEQUENCES OF OWNING UNITS
The federal income tax consequences of owning Units depend, in large part,
on (i) the proper classification of the Trust as a trust rather than as an
association taxable as a corporation, (ii) the classification of the Partnership
as a partnership rather than as an association taxable as a corporation, and
(iii) the categorization of the Trust as a "grantor" trust rather than as a
"nongrantor" trust (a "simple" or "complex" trust). For purposes of this summary
it has been assumed that neither the Trust nor the Partnership will be
classified as an association taxable as a corporation and that the Trust is
properly categorized as a grantor trust, positions consistent with the favorable
rulings received by the Company from the Service regarding these issues.
However, as mentioned above, because the rulings were issued after the
Distribution occurred, the Service could revoke its favorable rulings if it
changes its position regarding these matters.
The manner in which Unit holders who received their Units in the
Distribution or who acquired their Units before September 7, 1983 have chosen to
report their receipt of such Units may affect the manner in which they report
the receipt of income distributions from the Trust. This summary of the federal
income tax treatment of income distributions from the Trust is based in part on
the assumption that the Unit holders described above have characterized their
receipt of Units as a receipt of interests in a grantor trust owning cash
payment rights and economic interests in oil and gas properties.
General Features of Grantor Trust Taxation. An entity which is properly
classifiable as a trust for federal income tax purposes may be treated as
falling into one of three categories: (i) a grantor trust, (ii) a simple trust,
or (iii) a complex trust. Because the existence of a grantor trust is generally
disregarded for federal income tax purposes, a grantor trust is not subject to
tax, and its beneficiaries (the owners of Units in the case of the Trust)
generally are considered for tax purposes to own the assets of the trust
directly. Thus, the owners of Units should be treated as owning the Partnership
interest which the Trust holds, and each owner of a Unit should be treated as a
partner (to the extent of such Unit holder's interest in the Trust) in the
Partnership for federal income tax purposes. Treatment of partners for federal
income tax purposes is discussed below. The Trustee has filed, and anticipates
that it will continue to file, federal income tax returns on the basis that the
Trust is a grantor trust.
General Features of Partnership Taxation. An organization which is properly
classifiable as a partnership for federal income tax purposes is not a taxable
entity and incurs no federal income tax liability. Instead, each item of
partnership income, gain, loss, deduction, credit, and tax preference flows
through to the partners, substantially as though the partners had received or
expended such item directly. Each Unit holder is required to take into account
in computing his federal income tax liability his distributive share of all
items of Partnership income, gain, loss, deduction, credit and tax preference
for each taxable year of the Partnership
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ending with or within his taxable year based on the Partnership's method of
accounting, without regard to the Unit holder's method of accounting or whether
the Unit holder received or will receive any cash distributions. Consequently,
it is possible that in any year a Unit holder's share of the taxable income of
the Partnership (and possibly the income tax payable by him with respect to such
taxable income) may exceed the cash, if any, actually distributed in such year.
See "Accounting for Income and Deductions", below.
Special tax rules apply to any "publicly traded partnership", i.e., any
partnership whose capital interests are traded on an established securities
market or are readily tradeable on a secondary market or its substantial
equivalent. Because the transfer of a Unit represents a transfer of an interest
in the Partnership, the Partnership is included in the definition of a publicly
traded partnership. A publicly traded partnership is taxed as a corporation for
federal income tax purposes unless 90% or more of its gross income is from
certain qualified passive sources (which include income from oil and gas
activities). Because all of the Partnership's income is derived from the
Royalties, it should not be taxed as a corporation.
Tax-exempt organizations are subject to tax on their unrelated business
income. Previously, income and deductions from publicly traded partnership
interests acquired by tax-exempt organizations after December 17, 1987 were
automatically treated as unrelated business income and deductions. Effective for
partnership years beginning after 1993, income and deductions from publicly
traded partnerships are no longer automatically treated as unrelated business
income and deductions. As a result, tax-exempt Unit owners should consult their
tax advisors to determine if they are subject to tax on net income attributable
to Units in the Trust.
Depletion Deductions. The owner of an economic interest in producing oil
and gas properties is entitled to deduct, on his federal income tax return, an
allowance for the greater of cost depletion or (if otherwise allowable)
percentage depletion on each such property. Each Unit owner who acquires Units
by purchase should be entitled, by reason of the Partnership's election under
Section 754 of the Internal Revenue Code of 1986, as amended (the "Code"), to
deduct cost depletion (or, if greater and otherwise available, percentage
depletion) with respect to production from each of the Royalties using his basis
in such Royalties. The amount of deductions based on cost depletion cannot
exceed the total adjusted tax basis of the property. Prior to the enactment of
the Revenue Reconciliation Act of 1990 (the "1990 Act"), only cost depletion was
allowed to a Unit holder with respect to production attributable to the
Royalties carved out of properties which become proven prior to this acquisition
of Units. Under the provisions of the 1990 Act, Unit holders acquiring their
Units after October 11, 1990, may be entitled to deduct an allowance for
percentage depletion if such deduction would otherwise exceed the allowable
deduction for cost depletion, regardless of whether the oil and gas interest was
"proven" at the time of its acquisition. However, in order to take percentage
depletion, the Unit holder must qualify for the "independent producer" exemption
contained in Section 613A(c) of the Code; otherwise, such owner will be limited
to cost depletion.
Cost depletion for each productive property is calculated by (i) dividing
the dollars derived from the sale of oil or gas attributable to such productive
property that was actually produced during the taxable year by the sum of this
amount plus the total dollars estimated to be derived in the future from the
sale of the total units of production (barrels of oil and thousand cubic feet
("Mcf") of gas) attributable to the productive property held by the Trust
expected to be recoverable therefrom and (ii) multiplying the result in (i) by
the adjusted tax basis of the productive property.
Section 1254 of the Code provides that for property placed in service by a
taxpayer after December 31, 1986, depletion deductions which reduce the adjusted
basis of such property must be recaptured as ordinary income upon a disposition
of the property. The amount of such recapture is generally limited to the amount
of gain recognized by the taxpayer on such disposition. No oil and gas
properties were placed in service by the Partnership subsequent to 1986.
However, it is unclear whether this recapture provision applies to any portion
of the depletion deduction claimed with respect to the Royalties in the case of
Units acquired after December 31, 1986. The Service has not issued any
regulations or other pronouncements to indicate its interpretation of these
recapture provisions as they affect the transfer of partnership interests.
The foregoing discussion does not purport to be a complete analysis of the
complex legislation and regulations relating to the availability and calculation
of the depletion deduction for oil and gas properties.
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Unit holders who desire further or more specific information with respect to
these matters should consult their own tax advisors.
Trust Administrative Expenses. For individuals, miscellaneous itemized
deductions are deductible only to the extent that, in the aggregate, they exceed
2% of the Unit holder's adjusted gross income. However, Section 62(a)(4) of the
Code provides that deductions attributable to property held for the production
of royalty income may be deducted in arriving at a taxpayer's adjusted gross
income. Trust administrative expenses are incurred by the Trustee on behalf of
Unit holders in connection with the income from the Royalties flowing through
the Partnership and Trust and, therefore, may be deducted in arriving at a Unit
holder's adjusted gross income. Accordingly, such deductions should not be
subject to the 2% floor affecting miscellaneous itemized deductions.
Classification of Trust Income. A taxpayer is limited in his ability to
deduct losses from passive activities against other types of income. As a fixed
investment grantor trust, the Trust is prohibited from engaging in any business
or other investment activity, and it cannot engage in an activity which could be
considered a trade or business activity for passive activity purposes. Temporary
regulations indicate that taxpayers may not treat income from mineral royalties
(other than royalties derived from a trade or business) as earned in the
ordinary course of a trade or business without obtaining a ruling to such effect
from the Service. Therefore, royalty income (such as that generated by the
Trust) which is not attributable to a trade or business is characterized as
"portfolio income" rather than passive activity income under these rules.
Unit holders must include Trust income or loss, net of Trust administrative
expenses and cost depletion deductions, in their calculation of net portfolio
income or loss. Because Trust net income or loss is considered portfolio income
or loss, it may not be used to offset a Unit holder's income or losses from
passive activities. The tax laws relating to the various classifications of
income and the tax consequences of these classifications are complex. Unit
holders should consult their tax advisors to determine the impact of these
provisions on their individual tax situations.
Alternative Minimum Tax for Corporations. For a corporation, alternative
minimum taxable income is equal to (i) regular taxable income of the
corporation, with certain adjustments, plus (ii) items of tax preference. After
a corporation's alternative minimum taxable income is reduced by an exemption
amount, it is then multiplied by 20%, the alternative minimum tax rate, to yield
the tentative alternative minimum tax. The amount by which this tentative
alternative minimum tax (reduced by any alternative minimum tax foreign tax
credit) exceeds the regular tax is the corporation's alternative minimum tax
liability. The corporate alternative minimum tax provisions insure that
corporate taxpayers pay tax equal to at least 20% of their economic income above
the exemption amount. The corporate exemption amount is $40,000, less 25% of the
excess of alternative minimum taxable income over $150,000.
Alternative Minimum Tax for Noncorporate Taxpayers. A noncorporate Unit
holder's alternative minimum taxable income is generally equal to (i) his
regular taxable income, with certain adjustments, plus (ii) items of tax
preference. After a noncorporate taxpayer's alternative minimum taxable income
is reduced by an exemption amount, the tentative alternative minimum tax is
determined by multiplying this amount by 26% for the first $175,000, and 28% of
the excess over $175,000. The amount by which this tentative minimum tax
(reduced by any alternative minimum tax foreign tax credit) exceeds regular tax
is the noncorporate taxpayer's minimum tax liability. The noncorporate
taxpayer's exemption amount is $45,000 in the case of joint returns or surviving
spouses, $33,750 in the case of unmarried individuals who are not surviving
spouses, and $22,500 in the case of married individuals filing separate returns,
estates and trusts. The exemption amounts are reduced by 25% of the amount by
which a taxpayer's alternative minimum taxable income exceeds $150,000 ($112,500
for singles and $75,000 for married taxpayers filing separately, estates and
trusts).
Because of the complexity of the rules and regulations concerning the
application of the alternative minimum tax, Unit holders should consult their
tax advisors to determine its impact on their tax situations.
Abandonment Losses. Unit holders are entitled to claim deductions for
abandonment losses with respect to any Royalties which are determined to be
worthless and are abandoned. Each Unit holder should
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determine the amount of his abandonment losses by reference to that amount of
his adjusted basis for his Units attributable to each Royalty which becomes
worthless. Any deductions for abandonment losses allowed to a Unit holder will
reduce his basis in each Unit for purposes of computing gain or loss on any
subsequent disposition of Units. The Trustee will furnish to Unit holders
information which will permit computation of abandonment loss deductions, if
any. See "Reports", below. No such abandonment losses have been realized since
the creation of the Trust.
Taxation of Nonresident Foreign Unit Holders. Unit holders who are
nonresident alien individuals or foreign corporations (collectively, "Foreign
Taxpayers"), in general, are subject to U.S. tax at the rate of 30% on passive
income such as the gross income produced by the Royalties. In certain
circumstances, the applicable tax rate may be lower as a result of tax treaties.
This tax is applied to the gross income produced by the Royalties, without
taking into account any deductions, such as depletion. The Trustee must withhold
this tax and remit it directly to the United States Treasury.
The U.S. income (including income from the Trust) of a Foreign Taxpayer
engaged in a trade or business in the United States is, in general, taxable at
the graduated rates applicable to individuals or corporations, if the income is
effectively connected with such trade or business. A Foreign Taxpayer may elect
to treat the income from the Royalties as effectively connected with the conduct
of a United States trade or business under Section 871 or Section 882 of the
Code (or pursuant to any similar provisions of applicable tax treaties). A
Foreign Taxpayer whose Royalty income is effectively connected with a United
States trade or business or who elects to treat it as such is entitled to claim
all deductions, including depletion, with respect to such income and is exempt
from the 30% withholding requirement. Such exemption is claimed for a calendar
year by filing, in duplicate, with the Trustee, Form 4224, Exemption from
Withholding Tax on Income Effectively Connected with the Conduct of a Trade or
Business in the United States (or a substitute statement containing the
information required by Income Tax Regulation Section 1.1441-4). The exemption
statement must be received by the Trustee in advance of the royalty payment for
which it is intended to apply. A separate Form 4224 (or substitute statement)
must be filed with the Trustee for each calendar year in order to effect an
exemption from withholding for that year's income. Final regulations issued
under Section 1441, which are effective for payments made beginning January 1,
2000, require that such exemption be claimed on Form W-8, Certificate of Foreign
Status, and would extend the validity period from one to three years. If the
Trustee holds a valid Form 4224 or a substitute statement containing information
as required under regulations, in effect prior to January 1, 2000, such
certificate or statement will be treated as a valid withholding certificate
until its validity expires under those regulations or, if earlier, until
December 31, 2000. Because the application of the Final Withholding Regulations
will vary depending on a holder's particular circumstances, all holders are
urged to consult their own tax advisors regarding the application of the Final
Withholding Regulations to them. Generally, nonresident foreign Unit holders are
subject to a state income tax on income from sources within such state in the
same manner as a citizen or resident of the United States.
A 30% "branch profits tax" is imposed on the after-tax profits of a U.S.
branch of a foreign corporation attributable to its income effectively connected
(or treated as such) with a U.S. trade or business. An income tax treaty between
the U.S. and a foreign country may reduce or eliminate the branch profits tax
only if the foreign corporation is a "qualified resident" of the foreign country
in which it is incorporated.
A withholding tax is imposed on partnerships in an amount equal to the
United States tax on effectively connected taxable income which is properly
allocable to a foreign person under section 704(b) of the Code. The amount of
withholding tax is equal to the highest rate of United States tax to which each
foreign partner is subject. A foreign partner's share of withholding tax paid by
a partnership is treated as distributed to the foreign partner on the earlier of
(i) the date the partnership actually pays the tax to the Service or (ii) the
last day of the partnership's tax year for which the tax is paid. Future
regulations may modify the general rule described above to provide for earlier
deemed distributions and reductions in basis in circumstances such as those
involving mid-year dispositions of partnership interests. The Service is
authorized to impose penalties on a partnership for failure to satisfy
withholding tax liabilities.
Section 6039C of the Code allows the Service to require reporting by
foreign direct owners of United States real property interests. To date no such
reporting requirements have been announced by the Service.
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If a Foreign Taxpayer owns (or has owned during a five-year look-back
period) more than five percent of the outstanding Units, either directly or
through attribution rules under Section 897 of the Code, the Units in the hands
of such a Foreign Taxpayer are treated as United States real property interests.
For such a Foreign Taxpayer, gain or loss from the sale or exchange of Units
will generally be regarded as arising from the sale or exchange of property
effectively connected with the conduct of a United States trade or business.
Therefore, any gain or loss on the sale of Units must be reported to the Service
and appropriate taxes paid.
Section 1445 of the Code generally provides for withholding at the source
when a United States real property interest is acquired from a Foreign Taxpayer
after December 31, 1984. An exemption from withholding applies in the case of
stock regularly traded on an established securities market. Treasury regulations
expand this withholding exemption to include the acquisition of an interest in a
publicly traded partnership or trust. This exemption will also apply in the case
of a Foreign Person transferring a greater than five percent interest if the
transfer is from a single transferor in a single transaction; however, under
such circumstances, the transferor is subject to the substantive FIRPTA tax
liability.
Foreign Taxpayers that received Units in the original distribution on June
28, 1983 must generally compute their basis in such Units by reference to the
adjusted basis of the corresponding individual property interest in the hands of
the distributing corporation (the Company) before the Distribution, increased by
(i) any gain recognized by the distributing corporation on the Distribution and
(ii) certain taxes paid by the distributee on such Distribution. Foreign
Taxpayers purchasing Units after the Distribution should use their cost of
acquisition as the initial tax basis for such Units.
The federal income taxation of nonresident alien individuals and foreign
corporations is a highly complex matter which may be affected by many other
considerations. Therefore, nonresident alien individuals or foreign corporations
should consult their tax advisors as to the effects of their ownership of Units.
Sale of Units. Generally, a Unit holder will realize gain or loss on the
sale or exchange of Units measured by the difference between the amount realized
on the sale or exchange and his adjusted basis for such Unit at the time of the
sale or exchange. Subject to the recapture provisions contained in Code Section
1254, gain or loss on the sale of Units realized by a holder who is not a
"dealer" with respect to such Units and who held them for more than 12 months
will generally be treated as long-term capital gain or loss, provided the
taxpayer held the Units as a capital asset. Gain constituting Code Section 1254
recapture will be characterized as ordinary income. For oil and gas properties
placed in service after December 31, 1986, the Code Section 1254 recapture
amount will include depletion deductions which reduced the Unit holder's basis
in such property. See "Depletion Deductions" above.
The sale of Units should be considered, for tax purposes, as the sale of an
interest in the Partnership. Income allocable to such Units to the date of sale
will be taxable to the selling owner of Units, and the purchaser of Units will
be taxable on income allocable to such Units from the date of purchase forward.
See "Accounting for Income and Deductions", below. Certain information reporting
requirements may apply to the sale of Units. See "Information Return Filing
Requirements", below. The Partnership has made an election under Section 754 of
the Code to allow each subsequent purchaser of Units to take a basis in his
share of the Royalties which reflects his cost basis in the Units (as opposed to
his pro rata share of the Partnership's basis in the Royalties) for purposes of
calculating deductions for depletion and abandonments with respect to such
Royalties.
The Service has ruled that a partner must maintain a single aggregate
adjusted tax basis in partnership interests acquired in multiple transactions.
Upon a sale of a portion of such aggregate interest, such partner would be
required to allocate his aggregate tax basis between the interest sold and the
interest retained by some equitable apportionment method such as the relative
fair market values of such interests on the date of sale. It is unclear whether
the ruling would apply to owners of publicly traded units of beneficial
interests in a trust (such as the Trust) which owns interests in a partnership
(such as the Partnership). If the ruling is applicable to the Units, such
process of aggregating the tax basis of all Units owned by a Unit holder would
effectively prohibit a Unit holder owning Units which were purchased at
different prices from controlling the timing of the recognition of the inherent
gain or loss in his Units by choosing which Units he will sell. A Unit
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holder considering the subsequent purchase of additional Units or the sale of
Units purchased in more than one block should consult his own tax advisor as to
the possible consequences of this ruling.
Reports. The Trustee will furnish to Unit holders of record annual reports
(such as the LL&E Royalty Trust -- 1998 Tax Information package) containing
certain information necessary to permit the computation of federal and state tax
liabilities.
Audit of Partnership and Trust Returns. While no federal income tax is
required to be paid by organizations which are classified as partnerships or
grantor trusts, partnerships and grantor trusts must file informational federal
income tax returns which are subject to examination by the Service.
The Code provides that the tax treatment of "partnership items" is
determined at the partnership level rather than at the partner level. These
rules, which apply to the Partnership, provide in general for partnership level
Service audits and deficiency proceedings or claims for refund in respect of
"partnership items". These rules also provide for the designation of a "tax
matters partner" (the Company, in the case of the Partnership), who has the
power to (i) extend the applicable statute of limitations on assessments of tax
(normally three years) attributable to "partnership items" and (ii) enter into
settlement agreements which will bind other partners unless they specifically
elect not to be bound. Under Treasury regulations, the term "partnership items"
includes, insofar as may be relevant in the case of the Partnership, (i) the
Partnership's aggregate and each partner's distributive share of items of
income, gain, loss, deduction or credit, (ii) items of the Partnership which may
be tax preference items under Section 57(a) of the Code for any partner, (iii)
optional adjustments to the basis of Partnership property pursuant to an
election under Section 754 (including necessary preliminary determinations, such
as the determination of a transferee partner's basis in a Partnership interest)
and (iv) windfall profit tax (for periods when the windfall profit tax was in
effect). Further, a person whose tax is indirectly determined by taking into
account partnership items, such as a Unit holder, is required to notify the
Service if he treats partnership items inconsistently with the treatment on the
partnership return. Failure to notify will allow the Service to assess the
resulting deficiency without further proceedings, and may result in a penalty.
See "Other Possible Penalties". Each Unit holder should consult a tax advisor to
determine the effects of the applicability of these rules to the Partnership.
Accounting for Income and Deductions. Since 1987 the Partnership has
utilized the accrual method of accounting for tax purposes. The accrual method
of accounting requires a taxpayer to recognize income at the earlier of the time
the income is received or all events have occurred which fix the right to
receive such income and the amount thereof can be determined with reasonable
accuracy. Deductions are allowable for the taxable year in which all the events
have occurred which establish the fact of liability giving rise to such
deduction and the amount thereof can be determined with reasonable accuracy.
Because the Trust is treated as a grantor trust with respect to each Unit
holder, the Royalty income of the Trust will be deemed to have been accrued by
each Unit holder on the day the Partnership accrues such income under its method
of accounting and not on the date cash is distributed by the Partnership or the
Trust, regardless of a Unit holder's method of accounting. Income from the Trust
will be taxed to each Unit holder in the taxable year within which the taxable
year of the Partnership ends. Trust administrative expenses are costs incurred
outside of the Partnership and will be recognized by Unit holders consistent
with their method of accounting and without regard to the taxable year and or
accounting method employed by the Partnership or the Trust.
The Trust makes monthly distributions to Unit holders of record on each
Monthly Record Date on which it has revenues to distribute. Because the
Partnership must use the accrual method of accounting for tax purposes, the
Trust cannot match taxable income of the Partnership with cash distributions
from the Trust. Thus, in certain cases a Unit holder may be required to report
taxable income attributable to his Units, but the Unit holder will not receive
the distribution attributable to such income. This will be true to the extent a
cash distribution from the Partnership paid on any Monthly Record Date is
associated with income accrued by the Partnership prior to such Monthly Record
Date.
The Trust Agreement and the Partnership Agreement provide that income and
deductions of the Trust and the Partnership during the period ended on each
Monthly Record Date will be allocated to the Unit
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holders of Record on that Monthly Record Date. The Code generally requires that
items of partnership income and deduction be allocated among transferors and
transferees of partnership interests, as well as among partners whose interests
otherwise vary during a taxable period, on a daily basis. However, the
Conference Committee Report with respect to the applicable Code provision states
that regulations will provide a convention permitting such allocations to be
made on a monthly basis. Furthermore, relevant legislative history indicates
that allocations on a reasonable basis will be permitted pending adoption of
prospective regulations governing the matter. It is uncertain whether the
Service will accept the allocation method used by the Partnership and the Trust
or will require income and deductions of the Partnership or the Trust to be
determined and allocated daily or based on some other method of proration. If
the Service made such a contention, the judicial response would also be
uncertain. The Trustee believes that the allocation method adopted for the Trust
and the Partnership is reasonable and consistent with the purposes of applicable
Code provisions. In the event regulations are proposed which prescribe a
convention which is inconsistent with the method used by the Trust and the
Partnership, the Trustee intends to offer comments on the proposed regulations
and to take other action it deems appropriate in order to attempt to persuade
the Service to adopt a convention which would enable the Trust and the
Partnership to continue to use the allocation method now in use. In the event
such a convention is not provided, the Service may contend that taxable income
or losses should be allocated among Unit holders in a different manner. If any
such contention were sustained, the Unit holders' respective tax liabilities
would be adjusted, and some could be required to pay additional tax. A Unit
holder who transfers or acquires Units should consult with his tax advisor with
regard to the proper reporting of income received and expenses paid by the Trust
or the Partnership during the month in which such Units are acquired or
transferred.
Related Tax Effects on Unit Holders. The ownership of Units may result in
the federal income tax returns of a Unit holder being subject to scrutiny by the
Service. A Unit holder's returns may be examined as a result of an audit of the
Trust or the Partnership, and the Service may make adjustments to such returns
which are unrelated to the Distribution and the ownership of Units.
The tax classification of the Trust and the Partnership directly affects
the reporting by the Unit holders of the Trust's income and distributions. A
Unit holder who treats the Trust as a grantor trust would pay tax attributable
to the Trust's portion of the Partnership's income and income from other sources
received or accrued (depending on his method of accounting) even though no cash
was distributed by the Trust. If a Unit holder reports income attributable to
the Trust in a manner that is inconsistent with the final determination of the
status of the Trust or the Partnership, such Unit holder may be liable for a
deficiency (including interest) or may be required to file timely a claim for
refund in order to obtain any overpayment of taxes. In addition, any tax
deficiency or refund claim arising out of a Unit holder's reporting of Trust
income could increase the likelihood of an audit of such Unit holder's tax
return.
Other Possible Penalties. An owner of a security who receives income in
respect of such interest must report the character and amount of such income,
for federal income tax purposes, in a manner which is consistent with the
federal income tax reports of the entity which was the source of the income. The
consistency requirement is deemed to be waived if the taxpayer files a statement
with the Service identifying the inconsistency. Because of the presence of
"street name" investors and the possible existence of transfer record
inaccuracies, holders of interests which are actively traded in the securities
markets may encounter situations in which it is difficult to comply fully and
accurately with the consistency requirement and other federal tax reporting
requirements. Certain penalties could be assessed against a taxpayer that fails
to comply with such requirements. Because of the complexity of the federal tax
reporting requirements applicable to trusts (such as the Trust) which own
interests in partnerships (such as the Partnership) and because all of the tax
attributes of the Royalties flow through the Partnership and the Trust to the
Unit holders, there is an increased likelihood that Unit holders will violate
the consistency requirement and other reporting requirements regarding their
individual federal income tax returns and the information returns of the Trust
and the Partnership. Any violations of the consistency requirements could lead
to imposition of certain penalties on the Unit holders or other adverse results.
Furthermore, the Trust or the Partnership might be subject to certain penalties
in connection with its furnishing of statements and information to Unit holders
or the government if such statements or information prove to be inaccurate due,
for example, to differences between
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the transfer agent's records and actual ownership data. The Code provides
reporting requirements designed to facilitate the transfer of information
between partnerships and trusts and owners of interests therein held by
nominees. See "Nominee Reporting Requirements".
IDC RECAPTURE INCOME TO THE COMPANY ON DISTRIBUTION
As described in prior reports, at the time of the creation of the Trust, a
legal issue existed as to whether the disposition of a royalty carved out of an
operating interest to which intangible drilling and development costs ("IDC")
have been charged was a disposition of "property" for purposes of Section 1254
of the Code. Section 1254 requires a taxpayer to recapture IDC upon the
disposition of an oil and gas property.
The Company took the position on its tax returns that the distribution of
the Royalties did not trigger Section 1254 recapture. The Service subsequently
audited the Company's federal income tax returns for 1983, the year in which the
Trust was created and in which the Units were distributed, and assessed a
deficiency attributable to the distribution of the Units and recapture of IDC
under Section 1254 of the Code. The Company responded to this formal adjustment
to its tax liability by filing a petition in the United States Tax Court
contesting this deficiency, and in 1989 the Tax Court rendered an opinion
favorable to the Company. The IRS did not appeal the ruling of the Tax Court.
Consequently, the Tax Court's opinion is now final and nonappealable.
BACKUP WITHHOLDING
The Code's backup withholding system applies to all "reportable payments".
The rate of withholding of tax is 31% of all reportable payments. A reportable
payment includes not only reportable interest or dividend payments but also
"other reportable payments". The term "other reportable payment" includes
certain royalty payments. Accordingly, subject to the limitations discussed
below, a Unit holder may be subject to backup withholding with respect to all or
a portion of his distributions from the Trust.
The Code requires a payor to withhold 31% of any reportable payment if the
payee fails to furnish his taxpayer identification number ("TIN") to the payor
in the required manner or to establish an exemption from the requirement or if
the Secretary of the Treasury notifies the payor that the TIN furnished by the
payee is incorrect. Accordingly, a Unit holder may avoid backup withholding by
furnishing his correct TIN to the Trustee of the Trust. Any Unit holder who does
not provide his TIN to the Trustee should consult his tax advisor concerning the
applicability of the backup withholding provisions to his distributions from the
Trust.
Nominee Reporting Requirements. The Code imposes reporting requirements on
nominee owners of interests in an estate or trust. Any person holding an
interest in the Trust as a nominee owner must furnish the Trustee with specified
information about the beneficial owner. In addition, the nominee owner must
forward to the beneficial owner specified information supplied by the Trustee
pertaining to the beneficial owner's interest. Failure to comply with these
requirements may result in the imposition of penalties up to $100,000. Those
persons holding Units for the beneficial ownership of another should consult
with their tax advisors to ensure compliance with the new nominee reporting
requirements.
INFORMATION RETURN FILING REQUIREMENTS
Under the Code, any partner who sells or exchanges (other than through a
broker) an interest in a partnership holding "unrealized receivables" or certain
inventory within the meaning of Section 751 of the Code is required to notify
the partnership of such transaction within 30 days of the transfer (or, if
earlier, January 15 of the calendar year following the calendar year in which
the exchange occurred). Any such partner who fails to so notify the partnership
may be subject to a $50 penalty for each such failure. Furthermore, the
partnership is required to notify the Service of any sale or exchange (of which
it has notice) of a partnership interest, and to report the name and address of
the transferee and the transferor who were parties to such transaction, along
with all other information required by applicable Treasury regulations. The
partnership must also provide the information to the transferor and the
transferee. If the partnership fails to furnish any such notification, it may be
subjected to a penalty of $50 per failure, up to an annual maximum of $100,000.
35
<PAGE> 39
Depletion deductions subject to recapture under Section 1254 of the Code
(see "Depletion Deductions") constitute "unrealized receivables" within the
meaning of Section 751 of the Code. Accordingly, Unit holders disposing of Units
acquired after December 31, 1986 (other than through a broker) may be required
to notify the Trustee in writing of such disposition and provide the Trustee
with the Unit holder's name, address, taxpayer identification number and the
date of the disposition. Failure to so notify the Trustee may subject a Unit
holder, as well as the Trust and the Partnership, to the above-described
penalties. Without notification from Unit holders, the Trust and Partnership
cannot comply with these reporting requirements because they have no other way
of determining which Units disposed of during the year were acquired by the
transferring Unit holder subsequent to December 31, 1986.
STATE TAX CONSIDERATIONS
The Royalties burden properties in Texas, Louisiana, Florida and Alabama,
and the ownership of the Royalties may subject Unit holders to income and other
taxation in such states, require the filing of returns in such states, or both.
A generalized summary of the relevant tax laws of the states in which the
Royalties are located is contained in the following paragraphs.
Texas
Texas does not impose an income tax. Therefore, for all taxpayers, no part
of the income produced from Royalties which burden mineral properties located in
the State of Texas is subject to income tax in the State of Texas.
Texas does impose a franchise tax on all corporations and certain other
entities (such as limited liability companies). The tax is equal to the greater
of an amount determined based on taxable capital or an amount determined based
on earned surplus. The tax is calculated by comparing 0.25 percent of the
taxpayer's net taxable capital to 4.5 percent of the taxpayer's net taxable
earned surplus. The franchise tax is the greater of the two amounts. Net taxable
earned surplus, for Unit holders subject to the Texas franchise tax, is computed
by adjusting taxable income reported for federal income tax purposes. Generally,
net taxable earned surplus is apportioned to Texas based on a taxpayer's
apportionment factor. However, if income from the Royalties represents
nonbusiness income to the taxpayer, such income would be allocated, net of
related expenses.
In computing net taxable earned surplus, a Unit holder's allowable
depletion deduction will be the same as the amount allowed for federal income
tax purposes.
Louisiana
Louisiana imposes an income tax on all income of resident individuals (but
accords a credit for income taxes paid to other states by Louisiana residents)
and on income derived from Louisiana sources by nonresident individuals. Royalty
income earned from property located within Louisiana is considered income
derived from Louisiana sources for this purpose. Therefore, individual Unit
holders who are not residents of Louisiana are subject to Louisiana income tax
on income from the Royalties allocated to Louisiana. Such nonresident
individuals will be allowed certain deductions and exemptions which are
apportioned to Louisiana based upon the ratio of Louisiana income to federal
adjusted gross income. The income tax rates for individuals range from a low of
2 percent to a high of 6 percent.
Louisiana imposes an income tax on all corporations, and other entities
treated as corporations, if they earn or receive income derived from or
attributable to sources within Louisiana. Oil and gas Royalty income, net of
expenses, is generally treated as allocable income in Louisiana (oil and gas
Royalty income is specifically allocated to where the property is located). Gain
or loss on the sale of Units is also considered allocable income and is
allocated to the state in which the Units have business situs (if they have been
so used in connection with the taxpayer's business to acquire a business situs)
or, in the absence of a business situs, to the taxpayer's commercial domicile.
Thus, for an individual who is not a resident of Louisiana, in the absence of a
business situs, gain or loss will be allocated to the nonresident's legal
domicile. The income tax rates for corporations range from a low of 4 percent to
a high of 8 percent.
36
<PAGE> 40
Unit holders are allowed a depletion deduction based on the greater of the
amount determined under the percentage method or cost method. The rate for
computing Louisiana depletion under the percentage method is greater for Unit
holders who are corporations or trusts (22 percent). For individual Unit
holders, allowable depletion will be the same as the amount allowed for federal
income tax purposes.
Louisiana also imposes a franchise tax on corporations based on a
corporation's capital (borrowed or contributed) and undistributed surplus. The
amount subject to Louisiana franchise tax is apportioned where assets are owned
or revenue is earned outside of Louisiana. Thus, a Unit holder subject to
Louisiana franchise tax would apportion its franchise tax base taking into
account only such Unit holder's interest to the extent it is attributable to
property located and revenue generated in Louisiana.
Florida
Florida does not impose an income tax on individuals, partnerships or
private trusts. The Trust has received a Technical Assistance Advisement from
the Florida Department of Revenue indicating that the Trust and the Partnership
are not subject to taxation under the Florida Income Tax Code. However, the
Partnership must file an annual information return disclosing distributive
shares of the Working Interest Owner and the Trust.
Corporations and certain other entities treated as corporations under the
Florida Income Tax Code (such as limited liability companies) are subject to
Florida income tax if they earn or receive income derived from or attributable
to sources within Florida. Both resident and nonresident corporations receiving
income from the Royalties are required to file a Florida corporate return. Such
income may be characterized as either business or nonbusiness income depending
on the taxpayer's circumstances. Business income is apportioned to Florida based
on the corporation's apportionment factor. However, if income from the Royalties
represents nonbusiness income, such income would be allocated, net of related
expenses.
The Florida corporate income tax is imposed at the annual rate of 5.5
percent on adjusted Federal taxable income allocable or apportionable to
Florida. Any entity subject to the Florida income tax is also subject to the
annual Emergency Excise Tax of 2.2 percent on certain accelerated depreciation
deductions taken on the corporation's federal income tax return. This excise tax
will not apply for any assets placed into service after 1986. In addition,
Florida has adopted an alternative minimum tax which may be applicable to
certain Unit holders.
In computing Florida taxable income, a Unit holder's allowable depletion
deduction will be the same as the amount allowed for federal income tax
purposes.
Florida also imposes an intangibles tax, which taxes the value of
receivables and investments at a rate of 0.2 percent.
Alabama
Alabama imposes an income tax on all income of resident individuals (but
accords a credit for income taxes paid to other states by Alabama residents) and
on the income derived from Alabama sources by nonresident individuals. Royalty
income earned from property located within Alabama is considered income derived
from Alabama sources for this purpose. Therefore, individual Unit holders who
are not residents of Alabama are subject to Alabama income tax on income from
the Royalties allocated to Alabama. Such nonresident individuals will be allowed
certain deductions and exemptions which are apportioned to Alabama based upon
the ratio of Alabama income to total gross income. The rates for individuals
range from a low of 2 percent to a high of 5 percent.
Alabama also imposes an income tax on all corporations and other entities
treated as corporations if they earn or receive income derived from or
attributable to sources within Alabama. Both resident and nonresident
corporations receiving income from the Royalties are required to file an Alabama
corporate return. Such income may be characterized as either business or
nonbusiness income depending on the taxpayer's circumstances. Business income is
apportioned to the state based on the corporation's apportionment factor.
37
<PAGE> 41
However, if income from the Royalties represents nonbusiness income, such income
would be allocated, net of related expenses. The income tax rate for
corporations is 5 percent.
Both individual Unit holders and corporate Unit holders are allowed a
depletion deduction based on the greater of the amount determined under the
percentage method or cost method. The rate for computing Alabama depletion under
the percentage method is 27.5 percent.
Alabama imposes a franchise tax on foreign corporations based on the sum of
such corporation's capital, certain indebtedness and undistributed surplus. The
portion of this amount subject to Alabama franchise tax is determined by
applying the corporation's Alabama income tax apportionment factor to the
franchise tax base. For domestic corporations, Alabama franchise tax is solely
based on the par value of its stock.
SEVERANCE TAXES
The Royalties, and consequently the Unit holders, will bear their
proportionate share of severance taxes on the production from the Properties.
Except for a $.03 per barrel conservation tax on oil which was suspended in
1990, there is no severance tax on production from properties in the federal
offshore domain. Louisiana generally imposes a severance tax of 12.5% of the
market value of oil and, beginning July 1, 1990, $.07 per Mcf, as adjusted by a
gas-based rate adjustment, of gas produced in Louisiana. Texas generally imposes
a severance tax of 4.6% of the actual value of oil plus (3)/16 of a cent per
barrel of oil and 7.5% of the market value of gas produced plus 1/30 of a cent
per Mcf of gas produced in Texas. Florida generally imposes a severance or
production tax of 8% of the actual value of oil production and a tax on gas at
the rate of $.171 per Mcf, as adjusted by the gas based rate adjustment, per
fiscal year, beginning July 1, 1990 and thereafter. Alabama generally imposes a
severance tax of 8% and a conservation tax of 2% of the actual value of oil and
gas production.
AD VALOREM TAXES
The Unit holders will bear their proportionate share of ad valorem taxes
assessed on the fair market value of the Royalties in Texas and Alabama. The
Royalties, and consequently the Unit holders, will bear their proportionate
shares of the ad valorem taxes on the fair market value of the Jay Field
properties located in Florida. No ad valorem tax is assessed on royalty owners
with respect to properties in Louisiana or the federal offshore leases. Texas
has numerous taxing jurisdictions which, in addition to the state itself,
include counties, school districts, cities and industrial districts. Any
property located within more than one district may be taxed by each
jurisdiction. Generally, the taxing jurisdictions base their assessments on the
fair market value of the property at a certain point in time. In the case of
mineral interests, the taxing authorities take into consideration the net
present value of the estimated future net revenues to be derived from such
property.
ITEM 2. PROPERTIES
Reference is made to "Item 1. Business" for the information required by
this item.
ITEM 3. LEGAL PROCEEDINGS
None.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF UNIT HOLDERS
None.
38
<PAGE> 42
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S UNITS AND RELATED UNIT HOLDER MATTERS
The Units are traded on the New York Stock Exchange (ticker symbol LRT).
The table below presents the high and low sales prices for each quarterly period
in the years ended December 31, 1998 and 1997.
Since the cash distributions to Unit holders result from royalty and
overriding royalty interests, the timing, duration and amount of future cash
distributions will be dependent on the many and varied factors discussed
throughout Part I hereto, which factors are beyond the control of the Trustee.
The cash distributions to Unit holders for each quarterly period in the years
ended December 31, 1998 and 1997 (applicable to production for October 1997
through September 1998 and October 1996 through September 1997) are also
included in the table below.
<TABLE>
<CAPTION>
1998 QUARTER ENDED 1997 QUARTER ENDED
----------------------------------------- -----------------------------------------
MARCH 31 JUNE 30 SEPT. 30 DEC. 31 MARCH 31 JUNE 30 SEPT. 30 DEC. 31
-------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Units of Beneficial
Interest:
High sales price...... $ 5 3/16 $ 4 15/16 $ 4 9/16 $ 4 1/16 $ 5 3/8 $ 5 5/8 $ 5 1/4 $ 5 1/4
Low sales price....... 4 5/8 4 9/16 3 1/4 2 3/16 4 3/8 4 11/16 4 1/4 4 1/8
Distributions per
Unit.................. $0.2076 $0.1471 $0.0942 $0.0441 $0.1865 $0.2137 $0.1123 $0.1575
The total number of Unit holders of record as of March 19, 1999 was 6,504.
</TABLE>
ITEM 6. SELECTED FINANCIAL DATA
Reference is made to "Item 1. Business -- Estimates of Petroleum Engineers"
of this Annual Report on Form 10-K.
The Trust has not reported estimates of proved imputed oil or gas reserves
to any federal authority or agency other than the Securities and Exchange
Commission.
The following table presents in summary form selected financial information
regarding the Trust.
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-------------------------------------------------------------------
1998 1997 1996 1995 1994
----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C>
Revenues........................ $ 9,886,679 $13,281,125 $16,335,605 $ 7,200,588 $10,358,681
Cash earnings................... 9,360,223 12,729,412 15,811,746 6,619,563 9,687,476
Cash distributions to Unit
holders....................... 9,361,986 12,724,229 15,810,105 6,626,123 9,687,120
Cash distributions per Unit..... $ 0.49300 $ 0.67000 $ 0.83250 $ 0.34890 $ 0.51008
</TABLE>
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
-------------------------------------------------------------------
1998 1997 1996 1995 1994
----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C>
Trust Corpus.................... $ 2,584,963 $ 3,747,726 $ 4,432,543 $ 5,851,902 $ 7,030,462
</TABLE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATION
The unaudited data included in Item 1 and the financial statements and
notes thereto in Item 8 are an integral part of this discussion and analysis and
should be read in conjunction herewith.
LIQUIDITY AND CAPITAL RESOURCES
As stipulated in the Trust Agreement, the Trust is intended to be passive,
and the Trustee's activities are limited to the receipt of revenues attributable
to the Royalties, which revenues are to be distributed currently (after payment
of or provision for Trust expenses and liabilities) to the owners of the Units.
The Trust has no source of liquidity or capital resources other than the
revenue, if any, attributable to the Royalties.
39
<PAGE> 43
INFORMATION SYSTEMS FOR THE YEAR 2000
The Trust is reliant on the performance of third parties for the receipt of
royalty income, payment of expense and disbursement of distributable income. Any
failure by third party suppliers or business partners to successfully address
the year 2000 issue could adversely impact and cause delays in cash
distributions to Unit holders.
Since 1996, BR has been in the process of implementing new financial and
operating computer systems. The first phase of implementation was completed in
the first quarter of 1997 for certain operating areas within BR. The remaining
operating and financial systems are scheduled for implementation in phases, with
project completion scheduled for the second quarter of 1999. These new systems
are year 2000 compliant. Additionally, BR is in the process of identifying
suppliers and business partners who are not prepared to offer assurance that
their systems will be year 2000 compliant. The cost of achieving year 2000
compliance is not expected to have a materially adverse effect on the
distributions or operations of the Trust.
The Trustee has developed and is implementing a program to prepare its
systems and applications for the Year 2000, including those used to render
services to the Trust. In that connection, the Trustee intends to have such
systems and applications capable of processing, on and after January 1, 2000,
date, and date-related data consistent with the functionality of such systems
and applications, without a material adverse effect upon its performance of
services as Trustee.
RESULTS OF OPERATIONS
Revenues are generally received in the third month following the month of
production of oil and gas attributable to the Trust's interest. Both revenues
and Trust expenses are recorded on a cash basis. Accordingly, distributions to
Unit holders for the years ended December 31, 1998, 1997 and 1996 are
attributable to the Working Interest Owner's operations during the twelve-month
periods ended September 30, 1998, 1997 and 1996, respectively.
Distributions to Unit holders for 1998, 1997 and 1996 amounted to
$9,361,986 ($0.49300 per Unit), $12,724,229 ($0.67000 per Unit), and $15,810,105
($0.83250 per Unit), respectively. During these years the Trust received cash of
$9,886,679, $13,281,125, and $16,335,605, respectively, from the Working
Interest Owner with respect to the Royalties from the Properties.
The following unaudited schedule provides a summary of the Working Interest
Owner's calculation of the Net Proceeds from the Properties and the Royalties
paid to the Trust for the respective years.
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
----------------------------------------------
1998 1997 1996
------------ ------------ ------------
<S> <C> <C> <C>
Net Proceeds:
Revenues.................................... $ 35,097,072 $ 53,076,483 $ 53,312,854
Production costs and expenses............... (14,086,595) (15,900,901) (16,692,110)
Capital expenditures........................ (5,280,814) (12,968,988) (7,784,396)
------------ ------------ ------------
Net Proceeds........................ $ 15,729,663 $ 24,206,594 $ 28,836,348
============ ============ ============
Royalties paid to the Trust:
Overriding Royalties........................ $ 9,792,348 $ 13,125,292 $ 16,107,110
Fee Lands Royalties......................... 94,331 155,833 233,445
------------ ------------ ------------
$ 9,886,679 13,281,125 16,340,555
Partnership expenses........................ -- -- (4,950)
------------ ------------ ------------
Royalties paid to the Trust......... $ 9,886,679 $ 13,281,125 $ 16,335,605
============ ============ ============
</TABLE>
Revenues of the Working Interest Owner with respect to the Productive
Properties decreased 34% during the 1998 operating period, following a marginal
decrease in the prior year. The decrease in revenues during the 1998 operating
period is due to declining commodity prices for oil and natural gas liquids and
a decrease in
40
<PAGE> 44
natural gas production. The decrease in natural gas production is primarily the
result of the conversion of a well from gas to oil.
Average crude oil, natural gas liquids and natural gas prices received by
the Working Interest Owner for production attributable to the Productive
Properties decreased in 1998 compared to the 1997 operating period. Average
crude oil prices decreased from $20.64 per barrel for the 1997 operating period
to $14.60 per barrel for the 1998 operating period. Average natural gas liquids
prices decreased from $13.40 per barrel for the 1997 operating period to $11.23
per barrel for the 1998 operating period. Average natural gas prices received by
the Working Interest Owner for production attributable to the Productive
Properties decreased slightly during 1998 from $2.57 per thousand cubic feet for
the 1997 operating period to $2.55 per thousand cubic feet for the 1998
operating period.
Production costs and expenses incurred by Working Interest Owner on the
Productive Properties decreased 11% during the 1998 operating period following a
decrease of 5% during the 1997 operating period. The decrease in the 1998
operating period is due primarily to decreased workover expenses and lower
electrical and fuel costs reported at Jay Field. Production taxes at Jay Field
for the 1998 operating period are down as a result of lower product sales
prices.
Capital expenditures decreased 59% in the 1998 operating period compared to
an increase of 67% in the 1997 operating period. The decrease in 1998 capital
expenditures is attributable to decreased drilling activity at South Pass 89 and
Offshore Louisiana, lower facilities expenditures at South Pass 89 and Jay Field
and lower nitrogen injection costs at Jay Field.
The Trust's Fee Lands Royalties decreased 39% to approximately $94,000 in
1998. The amount of Fee Lands leased as of December 31, 1998 is approximately
4,509 acres.
41
<PAGE> 45
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
LL&E ROYALTY TRUST
STATEMENTS OF CASH EARNINGS AND DISTRIBUTIONS
YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
<TABLE>
<CAPTION>
1998 1997 1996
----------- ----------- -----------
<S> <C> <C> <C>
Royalty revenues...................................... $ 9,886,679 $13,281,125 $16,335,605
Trust administrative expenses......................... (526,456) (551,713) (523,859)
----------- ----------- -----------
Cash earnings......................................... 9,360,223 12,729,412 15,811,746
Changes in undistributed cash......................... 1,763 (5,183) (1,641)
----------- ----------- -----------
Cash distributions.................................... $ 9,361,986 $12,724,229 $15,810,105
=========== =========== ===========
Cash distributions per Unit........................... $ 0.49300 $ 0.67000 $ 0.83250
=========== =========== ===========
Units outstanding..................................... 18,991,304 18,991,304 18,991,304
=========== =========== ===========
</TABLE>
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
DECEMBER 31, 1998 AND 1997
<TABLE>
<CAPTION>
1998 1997
------------ ------------
<S> <C> <C>
ASSETS
Cash........................................................ $ 19,963 $ 21,726
Net overriding royalty interests in productive oil and gas
properties and 3% royalty interests in fee lands (notes 2,
3 and 5).................................................. 76,282,000 76,282,000
Less accumulated amortization (note 3)...................... (73,717,000) (72,556,000)
------------ ------------
Total assets........................................... $ 2,584,963 $ 3,747,726
============ ============
LIABILITIES AND TRUST CORPUS
Trust corpus (18,991,304 Units of Beneficial Interest
authorized, issued and outstanding)....................... $ 2,584,963 $ 3,747,726
Contingencies (note 4)
------------ ------------
Total liabilities and Trust corpus..................... $ 2,584,963 $ 3,747,726
============ ============
</TABLE>
STATEMENTS OF CHANGES IN TRUST CORPUS
YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
<TABLE>
<CAPTION>
1998 1997 1996
------------ ------------ ------------
<S> <C> <C> <C>
Trust corpus, beginning of period (note 3)...... $ 3,747,726 $ 4,432,543 $ 5,851,902
Cash earnings................................... 9,360,223 12,729,412 15,811,746
Cash distributions.............................. (9,361,986) (12,724,229) (15,810,105)
Amortization of royalty interests (note 3)...... (1,161,000) (690,000) (1,421,000)
------------ ------------ ------------
Trust corpus, end of period..................... $ 2,584,963 $ 3,747,726 $ 4,432,543
============ ============ ============
</TABLE>
See accompanying notes to financial statements.
42
<PAGE> 46
LL&E ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
(1) FORMATION OF THE TRUST
On June 28, 1983, The Louisiana Land and Exploration Company (herein
Working Interest Owner or Company) created LL&E Royalty Trust (Trust) and
distributed Units of Beneficial Interest (Units) in the Trust to the holders of
record of capital stock of the Company on the basis of one Unit for each two
shares of capital stock held on June 22, 1983. On October 22, 1997, the
shareholders of the Company approved a definitive agreement to merge with
Burlington Resources Inc. ("BR"). Effective on that date, the Company became a
wholly owned subsidiary of BR. The merger has had no significant effects on the
Trust.
Upon creation of the Trust, the Company conveyed to the Trust (a) net
overriding royalty interests (Overriding Royalties), which are equivalent to net
profits interests, in certain productive oil and gas properties located in
Alabama, Florida, Texas and in federal waters offshore Louisiana (Productive
Properties) and (b) 3% royalty interests (Fee Lands Royalties) in approximately
400,000 acres of the Company's then unleased, undeveloped south Louisiana fee
lands (Fee Lands). The Overriding Royalties and the Fee Lands Royalties are
referred to collectively as the "Royalties." Title to the Royalties is held by a
partnership (Partnership) of which the Trust and the Company are the only
partners, holding 99% and 1% interests, respectively.
The Trust is passive, with Chase Bank of Texas, National Association as
Trustee, having only such powers as are necessary for the collection and
distribution of revenues resulting from the Royalties, the payment of Trust
liabilities and the conservation and protection of the Trust estate. The Units
are listed on the New York Stock Exchange.
(2) NET OVERRIDING ROYALTY INTERESTS AND FEE LANDS ROYALTIES
The instruments conveying the Overriding Royalties generally provide that
the Working Interest Owner or any successor working interest owner will
calculate and pay to the Trust each month an amount equal to various percentages
of the Net Proceeds (as defined) from the Productive Properties. For purposes of
computing Net Proceeds, the Productive Properties have been grouped
geographically into four groups of leases, each of which has been defined as a
separate "Property". Generally, Net Proceeds will be computed on a
Property-by-Property basis and will consist of the aggregate proceeds to the
Working Interest Owner or any successor working interest owner from the sale of
oil, gas and other hydrocarbons from each of the Productive Properties less: (a)
all direct costs, charges, and expenses incurred by the Working Interest Owner
in exploration, production, development and other operations on the Productive
Properties (including secondary and tertiary recovery operations), including
abandonment costs; (b) all applicable taxes, including severance, ad valorem and
windfall profits taxes, but excluding income taxes except as described in note 4
below; (c) all operating charges directly associated with the Productive
Properties; (d) an allowance for costs if costs and expenses for any Productive
Property have exceeded proceeds of production from such Productive Property; and
(e) charges for certain overhead expenses.
The Fee Lands Royalties consist of royalty interests equal to a 3% interest
in the future gross oil, gas, and other hydrocarbon production, if any, from
each of the Fee Lands, unburdened by the expense of drilling, completion,
development, operating and other costs incident to production. In June 1993,
pursuant to applicable law, the Fee Lands Royalties terminated as to all tracts
not then held by production or maintained by production from other tracts.
Consequently, at December 31, 1998, the Fee Lands consisted of approximately
35,000 gross acres.
43
<PAGE> 47
LL&E ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(3) BASIS OF PRESENTATION
The financial statements of the Trust are prepared on the following basis:
(a) Royalties are recorded on a cash basis and are generally received
by the Trustee in the third month following the month of production of oil
and gas attributable to the Trust's interest.
(b) Trust expenses, which include accounting, engineering, legal and
other professional fees, Trustee's fees and out-of-pocket expenses, are
recorded on a cash basis.
(c) Amortization of the net overriding royalty interests in productive
oil and gas properties and the 3% royalty interest in Fee Lands, which is
calculated on a unit-of-production basis, is charged directly to the Trust
corpus since the amount does not affect cash earnings. Amortization
calculated for interim periods is based on the annual reserve study
prepared by independent petroleum engineers as of the end of the preceding
year. Given the volatility of oil prices, amortization recorded in the
fourth quarter, based on the current year reserve study, may include a
significant year-end adjustment that will reflect the impact of price
changes as well as other reserve revisions. Amortization recorded in the
fourth quarter was increased by $0.5 million in 1998, reduced by $.1
million in 1997, and reduced by $.06 million in 1996 as a result of such
adjustments.
(d) The initial carrying value of the Trust's royalty interests in oil
and gas properties represents the Company's cost on a successful efforts
basis (net of accumulated depreciation, depletion and amortization) at June
28, 1983 applicable to the interests in the properties transferred to the
Trust. Information regarding the calculation of the amount of such cost was
supplied by the Company to the Trustee. The initial carrying value and
related accumulated amortization has been reduced by the amounts attributed
to the Fort Worth Basin property which was sold in January 1997. Proceeds
from the sale were included in the cash distribution in April 1997. The
unamortized balance at December 31, 1998 is not indicative of the fair
market value of the interests held by the Trust.
The preparation of the financial statements requires estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenue and expenses during the reporting
period. Actual results could differ from those estimates.
While these statements differ from financial statements prepared in
accordance with generally accepted accounting principles, the cash basis of
reporting revenues and expenses is considered to be the most meaningful because
monthly distributions to the Unit holders are based on net cash receipts.
(4) FEDERAL INCOME TAX MATTERS
In May and June 1983, the Company applied to the Internal Revenue Service
(IRS) for certain rulings, including the following: (a) the Trust will be
classified for federal income tax purposes as a trust and not as an association
taxable as a corporation, (b) the Trust will be characterized as a "grantor"
trust as to the Unit holders and not as a "simple" or "complex" trust (a
"non-grantor" trust), (c) the Partnership will be classified as a partnership
and not as an association taxable as a corporation, (d) the Company will not
recognize gain or loss upon the transfer of the Royalties to the Trust or upon
the distribution of the Units to its stockholders, (e) each Royalty will be
considered an economic interest in oil and gas in place, and each Overriding
Royalty will constitute a single property within the meaning of Section 614(a)
of the Internal Revenue Code (Code), (f) the steps taken to create the Trust and
the Partnership and to distribute the Units would be viewed for federal income
tax purposes as a distribution of the Royalties by the Company to its
stockholders, followed by the contribution of the Royalties by the stockholders
to the Partnership in exchange for interests therein, which in turn was followed
by the contribution by the stockholders of the interests in the Partnership to
the Trust in exchange for Units, and (g) the transfer of a Unit of the Trust
will be considered
44
<PAGE> 48
LL&E ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
for federal income tax purposes to be the transfer of the proportionate part of
the Partnership interest attributable to such Unit.
Subsequent to the distribution of the Units, the IRS ruled favorably on all
requested rulings except (d). Because the Rulings were issued after the
distribution of the Units, however, the rulings could be revoked by the IRS if
it changes its position on the matters they address. If the IRS changed its
position on these issues, challenged the Trust and the Unit holders and was
successful, the result could be adverse.
The Company withdrew its requested ruling (d) that the Company did not
recognize gain or loss upon the transfer of the Royalties to the Trust or upon
distribution of the Units to its stockholders because the IRS proposed to rule
that the transfer and distribution resulted in the recapture of ordinary income
attributable to intangible drilling and development costs under Section 1254 of
the Code (IDC Recapture Income). Counsel for the Company expressed no opinion on
this issue. The Company and the IRS subsequently litigated the issue, and in
1989 the Tax Court rendered an opinion favorable to the Company. The Tax Court
held that the Company's transfer of the Royalties to the Trust and its
distribution of the Units to its stockholders did not constitute a disposition
of "oil, gas, or geothermal property" within the meaning of Section 1254 of the
Code. Consequently the Company was not required to recognize IDC Recapture
Income on the disposition of the Royalties. The opinion of the Tax Court has
become final and nonappealable.
These financial statements are prepared on the basis that the Trust will be
treated as a "grantor" trust and the Partnership will be treated as a
partnership for federal income tax purposes. Accordingly, no income taxes are
provided in the financial statements.
(5) DISMANTLEMENT OF PLATFORMS AT OFFSHORE LOUISIANA
The conveyances creating the Overriding Royalties permit the Company, under
certain circumstances, to establish an escrow for various matters. From the
August 1991 distribution through the August 1992 distribution the Company
escrowed funds from Offshore Louisiana in connection with anticipated platform
dismantlement costs at Offshore Louisiana. The Company ceased escrowing for
dismantlement costs at Offshore Louisiana beginning with the September 1992
distribution because it had fully escrowed the amount estimated to be ultimately
incurred for dismantlement of platforms located on this property. The total
cumulative Offshore Louisiana escrow balance as of December 31, 1998 was
approximately $2,300,000, 90% of which was otherwise distributable to the Trust.
The Company has advised the Trustee that it intends to continue to monitor
its estimates of relevant factors in order to evaluate the necessity of
escrowing funds on an ongoing basis, whether in connection with dismantlement
costs or other matters. The Company is under no obligation to give any advance
notice to the Trustee or the Unit holders in the event it determines that funds
should be escrowed. If the Company decides to escrow additional amounts, the
Royalties paid to the Trust would be reduced, and the reductions could be
significant.
(6) SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED)
Pursuant to Statement of Financial Accounting Standards No. 69, the Trustee
is required to include as supplementary information estimates of quantities of
proved oil and gas reserves and present value of future net revenues
attributable to the Trust. Information regarding estimates of proved oil and gas
reserves imputed to the Trust is based upon reports prepared by Miller and
Lents, Ltd., international oil and gas consultants ("Miller and Lents") as of
September 30, 1998, and by Gruy Engineering Corporation, independent petroleum
engineers ("Gruy") as of September 30, 1997 and 1996. Reserve quantities imputed
to the Trust were calculated by multiplying estimated proved net reserves
(barrels of oil and Mcf of gas) of the Working Interest Owner (prior to taking
into consideration the Trust's interests) by the ratio of estimated future net
revenues to the Trust to estimated future gross revenues to the Working Interest
Owner prior to taking into
45
<PAGE> 49
LL&E ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
consideration the Trust's interests. Estimates of future net revenues were
prepared in accordance with guidelines established by the Securities and
Exchange Commission and thus were based on prices and costs during September
1998, 1997 and 1996.
Accordingly, the table below presents the quantities of estimated proved
reserves imputed to the Trust's interest and the present value of estimated
future net revenues attributed to such proved reserves. The tables below also
present the changes in the estimated proved reserves imputed to the Trust's
interests and the changes in the present value of estimated future net revenues
attributed to the Trust's interests from September 30, 1995 to September 30,
1996, 1997 and 1998 (of which estimates were prepared by Gruy in the periods
ending September 30, 1996 and 1997 and by Miller and Lents in the period ending
September 30, 1998). Imputed proved reserves are stated in thousands of barrels
of liquids and millions of cubic feet of natural gas. The amounts estimated do
not necessarily represent actual dollar amounts to be paid to the Trust by the
Working Interest Owner. In estimating future net revenues, Gruy and Miller and
Lents took into consideration capital expenditures estimated to be necessary to
develop proved reserves only. The Working Interest Owner has informed the
Trustee that it has budgeted additional amounts based on the development of
proved reserves and on other projects designed to find and develop reserves not
included in the Gruy and Miller and Lents reports. In addition, the estimates
should be evaluated in light of the many uncertainties inherent in estimating
oil and gas reserve quantities and in forecasting production levels, prices and
operating costs. See "Item 1. Business -- Estimates of Petroleum Engineers" for
further discussion of the computational aspects of such data and the
uncertainties and other matters which could affect such estimates.
PRESENT VALUE OF ESTIMATED FUTURE NET REVENUES FROM PROVED RESERVES (THOUSANDS
OF DOLLARS)
<TABLE>
<CAPTION>
SEPTEMBER 30,
------------------------------
1998 1997 1996
-------- -------- --------
<S> <C> <C> <C>
Future net revenues........................................ $ 12,676 $117,559 $104,254
10% annual discount for estimated timing of net
revenues................................................. (5,224) (59,584) (47,361)
-------- -------- --------
Present value of future net revenues....................... $ 7,452 $ 57,975 $ 56,893
======== ======== ========
</TABLE>
46
<PAGE> 50
LL&E ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
CHANGES IN IMPUTED PROVED RESERVES AND PRESENT VALUE OF ESTIMATED FUTURE NET
REVENUES
<TABLE>
<CAPTION>
IMPUTED PRESENT VALUE
PROVED RESERVES OF FUTURE
--------------------- NET REVENUES
LIQUIDS GAS (THOUSANDS
(MBBL) (MMCF) OF DOLLARS)
------- -------- -------------
<S> <C> <C> <C>
Estimated at September 30, 1995..................... 2,425 8,472 $ 32,506
Production..................................... (449) (3,097) (16,336)
Revisions of estimates(1)...................... 2,051 2,965 37,472
Accretion of discount.......................... n/a n/a 3,251
------ ------ --------
Estimated at September 30, 1996..................... 4,027 8,340 $ 56,893
Production..................................... (396) (1,884) (13,281)
Revisions of estimates(1)...................... 1,457 2,462 8,674
Accretion of discount.......................... n/a n/a 5,689
------ ------ --------
Estimated at September 30, 1997..................... 5,088 8,918 $ 57,975
Production..................................... (336) (1,947) (9,887)
Revisions of estimates(1)...................... (4,324) (2,940) (46,434)
Accretion of discount.......................... n/a n/a 5,798
------ ------ --------
Estimated at September 30, 1998..................... 428 4,031 $ 7,452
====== ====== ========
</TABLE>
The computation of the present value of future net revenues relating to
proved reserves at September 30, 1998 was based on average natural gas prices of
$1.69 per thousand cubic feet and on crude and condensate prices of
approximately $13.58 per barrel. Prices received in December 1998 approximated
$2.02 per thousand cubic feet for natural gas and $10.14 per barrel of crude oil
and gas condensate. Had these prices been used, the present value of future net
revenues relating to proved reserves would have been reduced.
- ------------
(1) Revisions of estimates are due to the interaction of a number of factors,
including: (i) changes in prices being received; (ii) changes in estimates
of operating and capital costs; (iii) changes in the timing and amounts of
estimated future production; and (iv) changes in the estimated remaining
imputed proved reserves.
47
<PAGE> 51
LL&E ROYALTY TRUST
INDEPENDENT AUDITORS' REPORT
Chase Bank of Texas, National Association, Trustee
and the Unit Holders of LL&E Royalty Trust:
We have audited the accompanying statements of assets, liabilities and
trust corpus of LL&E Royalty Trust (Trust) as of December 31, 1998 and 1997, and
the related statements of cash earnings and distributions and changes in trust
corpus for each of the years in the three-year period ended December 31, 1998.
These financial statements are the responsibility of the Trustee. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by the
Working Interest Owner, 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 3, these financial statements were prepared on the
basis of cash receipts and disbursements as prescribed by the Securities and
Exchange Commission, 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 LL&E
Royalty Trust as of December 31, 1998 and 1997, and the cash earnings and
distributions and changes in trust corpus for each of the years in the
three-year period ended December 31, 1998, on the basis of accounting described
in Note 3.
KPMG LLP
Houston, Texas
March 23, 1999
48
<PAGE> 52
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 Registrant, being a trust, has no directors or executive officers. The
Trustee has only such powers as are necessary for the collection and
distribution of revenues from the Royalties, the payment of Trust liabilities
and the conservation and protection of the Royalties.
ITEM 11. EXECUTIVE COMPENSATION
Not applicable.
ITEM 12. UNIT OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
(a) UNIT OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
Based on filings with the Securities and Exchange Commission and on certain
representations made to the Trustee, the Trustee is not aware of any person
owning beneficially more than five percent of the Units as of March 19, 1999.
(b) UNIT OWNERSHIP OF MANAGEMENT
The Working Interest Owner owns no Units. Chase Bank of Texas, N.A. as
Trustee of the Trust, owns no Units. Chase Bank of Texas, N.A. in its individual
capacity (the "Bank") also owns no Units. As of March 19, 1999, the Trust
Department of the Bank held 3,325 Units in fiduciary accounts. The Trust
Department of the Bank possessed shared voting and investment power regarding
some of such Units. The Bank disclaims beneficial ownership of all such Units.
(c) CHANGE IN CONTROL
The Trustee knows of no arrangements, including the pledge of Units of the
Trust, 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
Chase Bank of Texas, N.A. and the Company and its subsidiaries have a
number of banking and trust relationships.
49
<PAGE> 53
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) FINANCIAL STATEMENTS
The following financial statements of the Trust are included in Part
II, Item 8:
<TABLE>
<CAPTION>
PAGE
NUMBER
------
<S> <C>
Statements of Cash Earnings and Distributions -- Years Ended
December 31, 1998, 1997 and 1996.......................... 42
Statements of Assets, Liabilities and Trust
Corpus -- December 31, 1998
and 1997.................................................. 42
Statements of Changes in Trust Corpus -- Years Ended
December 31, 1998, 1997 and 1996.......................... 42
Notes to Financial Statements............................... 43
Independent Auditors' Report................................ 48
</TABLE>
(b) REPORTS ON FORM 8-K
None.
(c) EXHIBITS
<TABLE>
<S> <C> <C>
4* -- Trust Agreement for LL&E Royalty Trust, dated as of June 1,
1983, between the Company and First City National Bank of
Houston, as Trustee.
27 -- Financial Data Schedule.
28.1* -- Agreement of General Partnership of LL&E Royalty
Partnership.
28.2* -- Form of Conveyance of Overriding Royalty Interests for Fort
Worth Basin Property.
28.3* -- Form of Conveyance of Overriding Royalty Interests for Jay
Field (Alabama) Property.
28.4* -- Form of Conveyance of Overriding Royalty Interests for Jay
Field (Florida) Property.
28.5* -- Form of Conveyance of Overriding Royalty Interests for
Offshore Louisiana Property.
28.6* -- Form of Conveyance of Overriding Royalty Interests for South
Pass 89 Property.
28.7* -- Form of Royalty Deed.
</TABLE>
- ------------
* Incorporated by reference to Exhibits of like designation to Registrant's
Annual Report on Form 10-K for the period ended December 31, 1983 (Commission
File No. 1-8518).
(d) FINANCIAL STATEMENT SCHEDULES
All financial statement schedules have been omitted because the required
information is either inapplicable or the information is set forth in the
financial statements or related notes.
50
<PAGE> 54
SIGNATURE
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.
Date: March 31, 1999
LL&E ROYALTY TRUST
(Registrant)
By: CHASE BANK OF TEXAS,
NATIONAL ASSOCIATION, Trustee
By: /s/ PETE FOSTER
-------------------------------------------------------
Pete Foster
Senior Vice President and Trust Officer
Note: Because the registrant is a trust without officers or employees, only the
signature of an officer of the Trustee is available and has been
provided.
51
<PAGE> 55
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
4* -- Trust Agreement for LL&E Royalty Trust, dated as of June
1, 1983, between the Company and First City National Bank
of Houston, as Trustee.
27 -- Financial Data Schedule.
28.1* -- Agreement of General Partnership of LL&E Royalty
Partnership.
28.2* -- Form of Conveyance of Overriding Royalty Interests for
Fort Worth Basin Property.
28.3* -- Form of Conveyance of Overriding Royalty Interests for
Jay Field (Alabama) Property.
28.4* -- Form of Conveyance of Overriding Royalty Interests for
Jay Field (Florida) Property.
28.5* -- Form of Conveyance of Overriding Royalty Interests for
Offshore Louisiana Property.
28.6* -- Form of Conveyance of Overriding Royalty Interests for
South Pass 89 Property.
28.7* -- Form of Royalty Deed.
</TABLE>
- ---------------
* Incorporated by reference to Exhibits of like designation to Registrant's
Annual Report on Form 10-K for the period ended December 31, 1983 (Commission
File No. 1-8518).
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION FROM LL&E ROYALTY TRUST
1998 ANNUAL REPORT AND FORM 10-K AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE
TO SUCH 1998 ANNUAL REPORT AND FORM 10-K.
</LEGEND>
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1998
<PERIOD-END> DEC-31-1998
<CASH> 19,963
<SECURITIES> 0
<RECEIVABLES> 0
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 19,963
<PP&E> 76,282,000
<DEPRECIATION> (73,717,000)
<TOTAL-ASSETS> 2,584,963
<CURRENT-LIABILITIES> 0
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 2,584,963
<TOTAL-LIABILITY-AND-EQUITY> 2,584,963
<SALES> 9,886,679
<TOTAL-REVENUES> 9,886,679
<CGS> 0
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 526,456
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 9,360,223
<INCOME-TAX> 0
<INCOME-CONTINUING> 9,360,223
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 9,361,986
<EPS-PRIMARY> .493
<EPS-DILUTED> .493
</TABLE>
