SECURITIES AND EXCHANGE
COMMISSION
Washington, D.C.
20549
FORM 10-K
(Mark One)
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ANNUAL REPORT PURSUANT TO
SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF
1934
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For the Fiscal Year ended December 31, 2008
OR
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o
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TRANSITION REPORT PURSUANT TO
SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF
1934
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Commission File
Number: 1-8518
LL&E ROYALTY
TRUST
(Exact name of registrant as
specified in its charter)
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Texas
(State or other jurisdiction
of incorporation or organization)
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76-6007940
(I.R.S. Employer Identification
No.)
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The Bank of New York Mellon Trust Company, N.A., Trustee
Global Corporate Trust
919 Congress Avenue
Austin, Texas
(Address of principal executive
offices)
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78701
(Zip
Code)
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Registrants telephone number, including area code:
1-800-852-1422
Securities registered pursuant to Section 12(b) of the
Act:
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Name of Each Exchange
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Title of Each Class
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On Which Registered
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Units of Beneficial Interest
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New York Stock Exchange
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Securities registered pursuant to Section 12(g) of the
Act: None
Indicate by check mark if the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes
o
No
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Indicate by check mark if the registrant is not required to file
reports pursuant to Section 13 or Section 15(d) of the
Act. Yes
o
No
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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
o
No
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Indicate by check mark whether the registrant has submitted
electronically and posted on its corporate Web site, if any,
every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T during the preceding 12
months (or for such shorter period that the registrant was
required to submit and post such files). Yes
o
No
o
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 registrants 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.
þ
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated
filer, or a smaller reporting company. See the definitions of
large accelerated filer, accelerated
filer and smaller reporting company in Rule
12b-2
of the
Exchange Act. (Check one):
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Large
accelerated
filer
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Accelerated
filer
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Non-accelerated
filer
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Smaller
reporting
company
o
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(Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the
Act). Yes
o
No
þ
As of June 30, 2008, 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 $42,350,608.
As of August 25, 2009, 18,991,304 Units of Beneficial
Interest were outstanding in LL&E Royalty Trust.
Documents
Incorporated by Reference: None
TABLE OF
CONTENTS
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EX-31
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EX-32
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All statements, other than statements of historical fact,
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 Owners or
operators 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 Owners have advised the
Trust that they believe that the forward looking statements are
based on reasonable assumptions, 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
no assurance can be given that the estimates and expectations
will be realized. In addition, all statements regarding future
activities, events or expectations regarding or relating to the
sale of the Trusts assets are forward looking
statements. 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 operators 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 and market for oil and gas royalty assets
similar to those held by the Trust. Other risk factors are
discussed elsewhere in this
Form 10-K,
including the risk factors described under
Item 1A Risk Factors.
PART I
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 (including its successors, as the context
requires, the Company) and First City National Bank
of Houston. Since October 2, 2006, The Bank of New York
Mellon Trust Company, N.A. has served as Trustee. The
Trustees offices are located at 919 Congress Avenue,
Austin, Texas 78701, and its telephone number is
1-800-852-1422.
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(s) includes the successors and assigns of such working
interests, including Quantum Resources Management, LLC, as
assignee of the working interest in the Jay Field Productive
Property (as defined below), which assignment occurred on
December 21, 2006.
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 in federal waters offshore Louisiana (the
Productive Properties) and (b) 3 percent
royalty interests (the Fee Lands Royalties) in
certain of the Companys 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 percent and a
1 percent 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
Trusts 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, protection
and sale 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 percent 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.
In accordance with the Trust Agreement, the Trust is
required to terminate effective as of December 31, 2007,
and is required to sell the Royalties and liquidate the assets
of the Trust. The status of the sale of the Royalties and
liquidation of the Trust are described below. The Trustee will
continue to serve as such until the affairs of the Trust are
completed. See Terms and Operations of the
Trust Termination of the Trust.
The Trustee has no authority or 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 Owners.
As previously disclosed and as described herein, Quantum
Resources Management, LLC, which operates the Jay Field
Productive Property, has temporarily suspended production at the
Jay Field. See Managements Discussion and Analysis
of Financial Condition and Results of Operations
Recent Developments.
1
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. In accordance with the Trust Agreement, the
Trustee intends to sell the Royalties and distribute the net
proceeds, after payment of all expenses and establishing such
reserves as the Trustee deems appropriate. To simplify the
discussion in this
Form 10-K,
the existence of the Partnership is sometimes ignored.
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 Owners will maintain books and records
sufficient to determine the amounts payable under the Royalties.
Termination
of the Trust
The Trust Agreement provides that the Trust will terminate
in the event that the net revenues fall below $5,000,000 for two
successive years (the Termination Threshold). Net
revenues are calculated as royalty revenues after administrative
expenses of the Trust and as if the Trust had received its pro
rata portion of any amounts being withheld by the Working
Interest Owners or the Partnership under escrow arrangements or
to make refund payments pursuant to the Conveyances (the
Trusts pro rata portion of escrowed amounts relating to
the future dismantlement of platforms are included in the net
revenue calculation for this purpose).
Net revenues to the Trust for the years ended December 31,
2007 and 2006 calculated as described above, were $1,634,740 and
$2,094,226, respectively. Consequently, the Trust was required
to terminate effective December 31, 2007, and is required
to sell the Royalties and liquidate the assets of the Trust.
As a result of the termination of the Trust, the Trustee is
required to 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 consisting of personal
property) upon such terms as the Trustee, in its sole
discretion, deems to be in the best interest of the Unit
holders. After paying or making provision for all actual and
contingent liabilities of the Trust, including fees of the
Trustee, the Trustee will distribute all remaining cash as
promptly as practicable. Despite 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 Trustee
does not expect to make any further monthly distributions to
Unit holders in the interim period prior to the distribution of
the proceeds of the sale of the Trusts assets.
The Trustee has retained Stifel, Nicolaus & Company,
Incorporated (Stifel Nicolaus), a nationally
recognized investment banking firm, to market the Trusts
assets. However, as announced by the Trustee on October 22,
2
2008, the Trustee has determined that, in light of market
conditions, it is in the best interests of the Trust unit
holders to postpone the sale of the Trusts assets for an
indefinite period of time. The Trustee reviews market conditions
frequently, and intends to recommence the marketing process as
soon as practicable. If any asset required to be sold has not
been sold by December 31, 2010, the Trustee will cause the
asset to be sold at public auction to the highest cash bidder,
and will mail notice of any such public auction to all Unit
holders at least 30 days prior to any such auction. Except
in connection with any proposed non-cash sale, no approval of
the Unit holders will be required in connection with the sale of
the Trusts assets.
As of December 31, 2008, the Trust had $62 in cash reserved
for Trust expenses and had unpaid invoices of approximately
$279,000. Based on current general and administrative
expenditures, in the absence of Royalty Revenues the Trustee
expects that it will be required to borrow money in accordance
with the Trust Agreement to fund future Trust expenses.
However, no assurance can be given that the Trustee will be able
to borrow money on terms the Trustee considers reasonable or at
all. The Trust Agreement permits, but does not require, The
Bank of New York Mellon Trust Company, N.A. or an affiliate
to lend funds to the Trustee. In the event any loans are made to
the Trust, the Trust Agreement will prohibit the Trustee
from making any distributions to unitholders until those loans
are repaid in full.
During 2008, the Trust did not receive any royalty revenue
associated with the Jay Field or Offshore Louisiana properties.
The Trust received royalty revenue of $37,239 for South Pass 89
in 2008. The Jay Field, South Pass 89 and Offshore Louisiana
properties excess production costs as of December 31, 2008
were approximately $10,930,000, $56,000 and $11,158,000,
respectively. The excess production costs must be recovered by
the Working Interest Owners before any distribution of royalty
revenues will be made to the Trust. In the first quarter 2008,
the Trust received a single payment of approximately $437,000 as
a result of a review conducted by an independent oil and gas
accounting firm retained by the Trustee to review the Working
Interest Owners calculation of amounts relevant to the
determination of the net proceeds properly payable to the Trust
under the Conveyances. The only other royalty revenue the Trust
received in 2008 was $204,741 attributable to the Fee Lands
Royalties.
Timing of
Liquidation
The Trust Agreement provides that the Trust will terminate
if net revenues fall below $5,000,000 (the Termination
Threshold) for two successive years. Net revenues to the
Trust in 2006 and 2007 fell below the Termination Threshold.
Consequently, the Trust is required to terminate and is required
to sell the Royalties and liquidate the assets of the Trust. The
Trustee intends to sell the assets as soon as practicable. If
any asset required to be sold has not been sold by
December 31, 2010, the Trustee will cause the asset to be
sold at public auction to the highest cash bidder.
Assets
and Liabilities in the Process of Liquidation
As a result of the contractual termination of the Trust
effective December 31, 2007, the Trust is in the process of
liquidation. The table below presents the assets of the Trust at
their estimated fair value, based solely on the assessment
described below:
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ASSETS
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December 31, 2008
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Cash
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$
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62
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Net overriding royalty interests in oil and gas properties and
3% royalty interests in fee lands
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1,254,607
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Net assets in process of liquidation
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$
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1,254,669
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The net overriding royalty interest in oil and gas properties at
December 31, 2008 reflect the Trustees estimate of
value (in the absence of third-party appraisals or evaluations),
based on the Trusts share of future net revenues from the
net overriding royalty interest in the properties as of
December 31, 2008. This estimate is based on the
3
Trustees current assessment of the impact of selling
existing assets based on current market conditions, and includes
the following assumptions:
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The Trusts estimated share of oil and gas reserve volumes
at December 31, 2008, were derived from a reserve report
prepared by Miller and Lents dated July 31, 2009, for the
production period ending September 30, 2008, a copy of
which is attached as Appendix A to this Report on
Form 10-K.
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The estimated fair value does not include any amounts related to
the Offshore Louisiana or Jay Field properties. The estimated
share for these properties is not economical.
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Forward strip commodity prices on December 31, 2008.
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Includes approximately $500,000 of future abandonment costs and
approximately $56,000 of excess production costs to be recouped
by the Working Interest Owners, for the South Pass 89 property.
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Discount rate of 10%.
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Future income taxes were not taken into account.
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The actual net proceeds from the sales of oil and gas properties
may vary substantially from these estimates in value due to
changes in current and estimated future oil and gas prices,
subsequent production, estimates of actual abandonment costs and
other factors which may be applied by the buyers. When comparing
fair value based on forward strip commodity prices on
December 31, 2008 to fair value based on forward strip
commodity prices on June 30, 2009, fair value increased
approximately $281,000 to $1.5 million.
For all other assets presented in the above table, the Trustee
believes that historical cost approximates fair market value due
to the short-term nature of such assets. The Trustee will add
any future distributions to previously established reserves to
pay Trust expenses, which will primarily consist of expenses
incurred by the Trustee to liquidate the Trusts assets.
Any funds remaining after all expenses have been paid will be
distributed to the Unit holders.
For more information regarding the estimated remaining life of
each of the Royalty Properties and the estimated future net
revenues of the Royalty Properties based on information provided
by the Working Interest Owners to Miller and Lents, see
pages 17 through 19 of this
Form 10-K
and Note 9 in the Notes to Financial Statements included
elsewhere in this
Form 10-K.
For more information regarding the amounts escrowed by the
Working Interest Owners as of December 31, 2008, see
Terms and Operations of the Trust Terms of the
Conveyances.
Nothing herein should be interpreted as an assurance of the
values of the assets held by the Trust. The actual value, if
any, of such assets will be determined solely by the amount a
buyer is willing to pay for the assets.
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 Owners 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 Owners 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 a 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 Owners expend any specific amounts with respect
to the Properties, and each is free to transfer its interests
(burdened by the Royalties) to third parties. The operators do
not have any obligation to produce any specific amounts of oil
and gas from any of the Properties and each 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.
4
Uncertainties or controversies may arise from time to time with
respect to the correct sales prices that may be charged by the
Working Interest Owners for oil and gas produced from the
Properties. The Conveyances provide that amounts received by the
Working Interest Owners 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 The Bank of New York Mellon Trust Company,
N.A., and will not be payable with respect to the Royalties
until the matter is resolved. The Working Interest Owners may
place other amounts in escrow under certain circumstances.
Amounts owing to the Trust and paid to the Working Interest
Owners 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 Owners 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 Owners 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 percent of the aggregate estimated future Special Costs
divided by the aggregate estimated future Gross Proceeds for
that Property. Further, if the total amount so escrowed exceeds
125 percent of the aggregate estimated future Special Costs
for the particular Productive Property, no additional amounts
may be escrowed until the escrowed funds are less than
125 percent of such amount.
The Working Interest Owners have advised the Trustee that based
on current estimates included in this Annual Report on
Form 10-K,
the Working Interest Owners are permitted to place additional
funds in escrow from each of the properties. Commencing with the
April 2006 monthly distribution, the Working Interest Owner
began escrowing all amounts otherwise distributable to the Trust
from the Offshore Louisiana and South Pass 89 properties. The
Working Interest Owners have advised the Trustee that they
anticipate escrowing all additional funds from the Offshore
Louisiana and South Pass 89 properties.
Based on the escrow provisions described above, the Working
Interest Owner did not escrow any amounts for the Jay Field
during the year ended December 31, 2008, but escrowed
$2,409,707 during the year ended December 31, 2008 for the
South Pass 89 property. The Working Interest Owner escrowed
$9,117,347 during 2008 for the Offshore Louisiana properties.
The amounts withheld during 2008 were in addition to the
balances escrowed as of December 31, 2007 of $4,543,402 for
Jay Field, $4,090,293 for South Pass 89 property and $3,255,080
for the Offshore Louisiana property. During 2008, none of the
escrowed amounts were expended for the Jay Field or South Pass
89 and $3,595,082 were expended for Offshore Louisiana
properties. The remaining escrowed balances at December 31,
2008 were $4,543,402, $6,500,000 and $8,777,345 for Jay Field,
South Pass 89 and Offshore Louisiana property, respectively. As
of December 31, 2008, the Working Interest Owners
estimates of total Special Costs are $14,200,000 for Jay Field,
$7,500,000 for South Pass 89 and $25,500,000 for Offshore
Louisiana. The Working Interest Owner may begin escrowing
balances at Jay Field if production resumes at this property in
2009. As described above, the Conveyances prohibit the Working
Interest Owner from escrowing
5
additional funds for estimated future Special Costs with respect
to a particular Productive Property once the amount escrowed
exceeds 125 percent of the aggregate estimated future
Special Costs for that property. The Conveyances permit the
Working Interest Owner to release funds from any of the Special
Cost escrows at any time if it determines in its sole discretion
that there no longer exists a need for escrowing all or any
portion of such funds. However, the Working Interest Owner is
not required to do so.
In the event that any 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 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.
See Item 7. Managements Discussion and Analysis of
Financial Condition and Results of Operations.
The
Partnership
Title to the Royalties is held by a partnership of which
LL&E Royalty 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 each 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 Trusts income attributable to the Partnership and
reported to the Unit holders is likewise on the accrual basis.
Consequently, the Unit holder that is 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 Trustees fees and
accounting, engineering, legal and other professional fees. The
costs and expenses of the Trust may increase significantly in
connection with the termination and liquidation of the Trust.
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
6
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 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. There can be no assurance that either the
Trustee or the Partnership would be able to borrow funds on
acceptable terms or on any terms at all.
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).
See Item 7 Managements Discussion and
Analysis of Financial Condition and Results of Operations.
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. The following description is qualified in its
entirety by the information under Terms and Operation of
the Trust Termination of the Trust.
Overriding
Royalties
For the purposes of computing Net Proceeds (as defined in the
Conveyances), the Productive Properties have been grouped
geographically into three groups of leases, each of which has
been defined as a separate Property.
7
These groups are designated herein as the Jay Field,
South Pass 89, and Offshore Louisiana.
See The Properties Description of Productive
Properties. The Overriding Royalties consist of overriding
royalty interests (equivalent to net profits interests) equal to
various 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 The Bank of New York Mellon Trust Company,
N.A.s prime rate plus 0.5 percent 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. As of December 31, 2008, the
Working Interest Owners estimates of total Special Costs
are $14,200,000 for Jay Field, $7,500,000 for South Pass 89 and
$25,500,000 for Offshore Louisiana. See Terms
of the Conveyances above for a description of amounts
escrowed to date.
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. See Managements Discussion and Analysis
of Financial Condition and Results of Operations
Recent Developments for additional information regarding
sulphur at Jay Field.
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 percent of the Net Proceeds attributable to such
properties. The Overriding Royalties with respect to Offshore
Louisiana are equal to 90 percent 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 operator and other
operators or extinguished as a result of the expiration of oil
and gas leases. Since the Overriding Royalties were conveyed out
of the Working Interest Owners working interests, if the
Working Interest Owners right to revenues is adjusted,
extinguished or suspended, the Trusts 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
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
8
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.
As part of the termination procedures, the Trustee engaged an
independent joint venture auditor to review payments to the
Trust for a portion of the Trust properties as part of the
termination of the Trust. The joint venture auditor reviewed the
period from January 2004 through December 2007. As a result of
the review, one of the Working Interest Owners made a payment of
approximately $437,000 in March 2008 to the Trust to settle
certain issues identified. In addition, the independent joint
venture auditor has recently completed a review of the working
interest owners calculations relating to the Trusts
interest in the Jay Field for the period July 1, 2007
through December 31, 2008. Although the matters reviewed
have not yet been finalized with the working interest owner, the
Trustee does not expect any significant net adjustment to the
working interest owners calculations relating to the
Trusts interest in the Jay Field for the period
July 1, 2007 through December 31, 2008.
Fee Lands
Royalties
The Fee Lands Royalties consist of royalty interests equal to a
3 percent 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 22,282 gross acres in south Louisiana, only
approximately 1,062 acres of which were leased at
December 31, 2008. See The Properties
Description of the Fee Lands and Exploration and
Development Activities Fee Lands.
Analysis
of the Working Interest Owners Calculation of the
Royalties
The following schedules summarize the Working Interest
Owners calculation of the amounts paid to the Trust with
respect to the Trusts royalty interests for (i) the
quarter ended December 31, 2008 (applicable to production
from July 2008 through September 2008) and (ii) the
year ended December 31, 2008 (applicable to production from
October 2007 through September 2008):
Quarter
ended December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
South
|
|
|
Offshore
|
|
|
|
|
|
|
Jay Field
|
|
|
Pass 89
|
|
|
Louisiana
|
|
|
Total
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liquids
|
|
$
|
10,097,091
|
|
|
$
|
727,410
|
|
|
$
|
848,618
|
|
|
$
|
11,673,119
|
|
Natural gas
|
|
|
919,447
|
|
|
|
18,486
|
|
|
|
1,068,871
|
|
|
|
2,006,804
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
11,016,538
|
|
|
$
|
745,896
|
|
|
$
|
1,917,489
|
|
|
$
|
13,679,923
|
|
Amounts withheld in escrow
|
|
|
|
|
|
|
|
|
|
|
(1,917,489
|
)
|
|
|
(1,917,489
|
)
|
Production costs and expenses(1)
|
|
|
(4,824,366
|
)
|
|
|
(193,720
|
)
|
|
|
(239,774
|
)
|
|
|
(5,257,860
|
)
|
Capital expenditures
|
|
|
(3,556,069
|
)
|
|
|
(45,809
|
)
|
|
|
19,359
|
|
|
|
(3,582,519
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Proceeds
|
|
$
|
2,636,103
|
|
|
$
|
506,367
|
|
|
$
|
(220,415
|
)
|
|
$
|
2,922,055
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Overriding Royalties paid to the Trust(2)
|
|
$
|
|
|
|
$
|
37,239
|
|
|
$
|
|
|
|
$
|
37,239
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fee Lands Royalties(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,021
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalties paid to the Trust (Royalty revenue)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
46,260
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9
Year
ended December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
South
|
|
|
Offshore
|
|
|
|
|
|
|
Jay Field
|
|
|
Pass 89
|
|
|
Louisiana
|
|
|
Total
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liquids
|
|
$
|
35,649,069
|
|
|
$
|
4,647,549
|
|
|
$
|
4,369,826
|
|
|
$
|
44,666,444
|
|
Natural gas
|
|
|
2,637,542
|
|
|
|
400,601
|
|
|
|
4,747,521
|
|
|
|
7,785,664
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
38,286,611
|
|
|
$
|
5,048,150
|
|
|
$
|
9,117,347
|
|
|
$
|
52,452,108
|
|
Amounts withheld in escrow
|
|
|
|
|
|
|
(2,409,707
|
)
|
|
|
(9,117,347
|
)
|
|
|
(11,527,054
|
)
|
Production costs and expenses(1)
|
|
|
(30,708,141
|
)
|
|
|
(553,424
|
)
|
|
|
(1,374,025
|
)
|
|
|
(32,635,590
|
)
|
Capital expenditures
|
|
|
(14,179,789
|
)
|
|
|
(106,429
|
)
|
|
|
(1,635,943
|
)
|
|
|
(15,922,161
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Proceeds
|
|
$
|
(6,601,319
|
)
|
|
$
|
1,978,590
|
|
|
$
|
(3,009,968
|
)
|
|
$
|
(7,632,697
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Overriding Royalties paid to the Trust(2)
|
|
$
|
|
|
|
$
|
37,239
|
|
|
$
|
|
|
|
$
|
37,239
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fee Lands Royalties(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
204,741
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Proceeds Paid to the Trust(4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
436,548
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalties paid to the Trust (Royalty revenue)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
678,528
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Interest earned on funds escrowed for estimated future
dismantlement costs are reported as a reduction of production
costs and expenses. Interest earned on all properties for the
2008 Fourth Quarter and Twelve Months ending December 31,
2008 was $276,340 and $849,044, respectively. Pursuant to the
terms of the Trust Conveyances, interest earned on the escrowed
funds for any month will be calculated at an interest rate equal
to 80% of the median between the Prime Rate at the end of such
month and the Prime Rate at the end of the preceding month.
|
|
|
|
Processing fees earned on the South Pass 89 properties are shown
as a reduction of production costs and expenses. For the 2008
Fourth Quarter, production costs and expenses include processing
fee income of $191,022. For the Twelve Months ending
December 31, 2008, South Pass 89 processing fees earned
were $885,610.
|
|
(2)
|
|
As a result of excess production costs incurred in one monthly
operating period and then recovered in a subsequent monthly
operating period(s), the Overriding Royalties paid to the Trust
may not agree to the Trusts royalty interest in the Net
Proceeds.
|
|
(3)
|
|
As a result of inquiries by the Trustee, the working interest
owner recalculated its computation of the Fee Lands royalties
and determined that the Trust was overpaid $25,165 during the
third quarter 2008. In October and November 2008, royalty income
was reduced by $16,925 and $8,240, respectively, to adjust for
this overpayment.
|
|
(4)
|
|
In the first quarter 2008, the Trust received a single payment
of $436,548 as a result of a review conducted by an independent
oil and gas accounting firm retained by the Trustee to review
the Working Interest Owners calculation of amounts
relevant to the determination of the net proceeds properly
payable to the Trust under the Conveyances.
|
THE
UNITS
Distributions
and Income Computations
Prior to the termination of the Trust effective
December 31, 2007, distributions of available revenues to
Unit holders were made monthly. Each payment was made with
respect to the preceding Monthly Period of the Trust. The
Trustee determined for each Monthly Period the Monthly Income
Amount available for distribution for such Monthly Period. The
Monthly Income Amount for each Monthly Period was payable to
Unit holders of record on the Monthly Record Date on which such
Monthly Period ends and was distributed by the Trustee as soon
as practicable but not later than ten days following such
Monthly Record Date (the Monthly Payment Date).
Under
10
the terms of the Trust Agreement, the Trustee was
prohibited from investing funds received on each Monthly Record
Date pending disbursement to holders of Units. As a consequence,
the Trustee may have held substantial balances between the
Monthly Record Date and the Monthly Payment Date in each month,
and The Bank of New York Mellon Trust Company, N.A. had 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 has been reported by
the Trustee to the Unit holders of record to whom the Monthly
Income Amounts were distributed. The Trustee mailed reports for
2008 to Unit holders in March 2009.
Transfer
of Units
Units are transferable on the records of The Bank of New York
Mellon Trust Company, N.A. as transfer agent and registrar,
upon the surrender of any certificate in proper form for
transfer as required by The Bank of New York Mellon
Trust Company, 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 Units.
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 Trusts 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 Trusts interests in the Properties. The
Trustee mails to Unit holders such other reports and files such
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
11
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 their
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 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 they are 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
Trustees 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
12
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 percent 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
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.
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 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
holders 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.
THE
PROPERTIES
General
The Trustee has no authority or 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 Owners. The following description is qualified in its
entirety by the information under Terms and Operation of
the Trust Termination of the Trust.
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 percent working interest in a well or lease
that is included in a Productive Property indicates that the
Trusts Overriding Royalties burden 20 percent of the
working interest in the well or lease. That 20 percent
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
Owners percentage of the working interest in wells or
leases cannot be used to calculate precisely the Trusts
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 Trusts interest and
(b) because the Productive Properties consist of multiple
13
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 Trusts interest) in an
entire Productive Property.
Description
of Productive Properties
Certain information, as of December 31, 2008, 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 three 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, 2008.
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Productive
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Property and Year
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Productive Wells(1)
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in Which
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Acres
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Oil
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Gas
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Production Commenced
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Location
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Gross
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Net
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Gross
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Net
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Gross
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Net
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Jay Field (1970)(2)
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Onshore
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184,472
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(3)
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62,150
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(3)
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32
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10.78
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1
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.34
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Alabama
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and Florida
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South Pass 89 (1982)
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Offshore
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5,000
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1,250
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2
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0.50
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0.00
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0.00
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Louisiana
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Offshore Louisiana (1968)(4)
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Offshore
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10,000
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1,625
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6
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0.75
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10
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1.55
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Louisiana
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199,472
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65,025
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40
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12.03
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11
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1.89
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(1)
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Represent producing wells and wells capable of production. Net
wells reflect the Working Interest Owners working
interest. Gross and net wells exclude injection wells.
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(2)
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Includes interests in 23 leases which are a part of the Jay
Field Unit created by a unit agreement originally among
ExxonMobil (as 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 were 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. All right, title
and interest of the Company in the Jay Field Productive Property
was assigned to the following entities in the following
undivided percentages on December 21, 2006, effective as of
September 1, 2006:
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Percentage of
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the Working
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Interest Owned
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Designation
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by the Operators
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Black Diamond Resources
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3.9080
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%
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QAB Carried WI, LP
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1.6248
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%
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QAC Carried WI, LP
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2.8844
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%
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Quantum Resources A1, LP
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91.5828
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%
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Quantum Resources Management, LLC (Quantum) manages
the Jay Field working interest on behalf of the above listed
assignees. The Company will continue to account for and report
on the remainder of the Properties other than the Jay Field
Productive Properties.
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(3)
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Gross acres reflect aggregate porosity
acre-feet
in
producing formations in the Jay Field, and net acres reflect the
Working Interest Owners ownership interest in the
producing formations as determined volumetrically for purposes
of the unit agreement relating to the Jay Field.
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(4)
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Includes four federal leases or federal units (as applicable)
with designations, initial production dates and percentage
ownership of the Working Interest Owner as follows:
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Percentage of
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the Working
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Designation and Initial
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Interest Owned
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Production Date
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by the Operators
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East Cameron 195 Unit (1971)
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33.33
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%
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East Cameron 336, South Addition (1983)
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20
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%
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Eugene Island 261 (1979)
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20
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%
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South Marsh Island 76, South Addition (1968)
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25
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%
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Vermilion 331, South Addition (1977)
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12.5
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%
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During the fourth quarter of 2001, the Working Interest Owner
assigned its ownership in any future wells or existing well work
activity at East Cameron 336 to other owners, but retained its
share of the plugging and abandonment liability.
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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 Owners 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 there
from. 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
15
revenues in the future from the tracts as to which the Fee Lands
Royalties terminated. The Fee Lands now consist of approximately
22,282 gross acres, approximately 1,062 acres of which
were under lease as of December 31, 2008.
OIL AND
GAS SALES FROM THE PRODUCTIVE PROPERTIES
The following description is qualified in its entirety by the
information under Terms and Operation of the
Trust Termination of the Trust.
Oil
Sales
In addition to crude oil sold to third parties, crude oil from
South Pass 89 is sold to an affiliate of ConocoPhillips which
sells it to 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.
Gas and
Liquids Sales
Natural gas from certain of the Productive Properties is sold to
an affiliate of ConocoPhillips, which transports the offshore
gas onshore, and sells that gas to third parties at market
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 third parties, some of which
is transported by the affiliate prior to the sale. Propane and
virtually all of the other liquids are sold by the affiliate, of
ConocoPhillips, at published spot prices. Natural
gas is settled by the Working Interest Owner on a percent of
proceeds basis.
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 Owners share of production regardless of which
partys purchaser has actually taken and paid for the gas.
The Working Interest Owner makes distributions to the Trust
based upon its entitled share of production at the relevant
contractual prices. The Working Interest Owners actual
receipts depend on the price received when the imbalances are
reconciled, adjustments to the Working Interest Owners
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 Owners
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 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 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.
16
EXPLORATION
AND DEVELOPMENT ACTIVITIES
Productive
Properties
The following is a summary of the Working Interest Owners
net drilling activities on the Productive Properties for the
years ended December 31, 2006, 2007 and 2008:
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Net Wells
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Oil
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Gas
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Dry
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2006
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Exploratory
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Development
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2007
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Exploratory
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Development
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2008
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Exploratory
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Development
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The following are the significant activities by the Working
Interest Owner on the Productive Properties during 2008:
Jay
Field
Capital and abandonment expenditures of approximately
$14,000,000 were incurred in 2008, primarily for nitrogen
purchases for injections.
South
Pass 89
Capital and abandonment expenditures of approximately $106,000
were incurred in 2008, primarily for capital workovers.
Offshore
Louisiana
Capital and abandonment expenditures of approximately $1,600,000
were incurred in 2008, primarily for capital workovers.
Fee
Lands
Approximately 1,062 acres of the south Louisiana Fee Lands
subject to the Trusts 3 percent royalty interest were
under lease as of December 31, 2008.
ESTIMATES
OF PETROLEUM ENGINEERS
September 30,
2008 Estimates
Estimates of the 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, 2008
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, 2008. A copy of the Miller
and Lents letter, dated July 31, 2009, setting forth such
estimates, is reproduced as Appendix A to this Annual
Report.
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
17
based upon oil, and natural gas prices and costs represented by
the Working Interest Owner to be in effect as of
September 30, 2008. The present value was based on a
discount factor of 10% per year.
The following table sets forth, as of September 30, 2008,
certain estimated imputed proved reserves, estimated future net
revenues and the discounted present value thereof attributable
to the underlying properties and the Royalties, in each case
derived from the Miller and Lents reserve report. A summary of
the reserve report is included as Appendix A to this Report
on
Form 10-K.
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Net Proved Imputed Reserves and Revenues
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Crude Oil,
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Net Revenues
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Condensate, and
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Natural
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Future Net
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Discounted at 10%
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Natural Gas Liquids
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Gas,
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Revenues,
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Per Year,
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Reserve Category
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MBbls.
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MMcf
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M$
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M$
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Proved Developed
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72.1
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120.6
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8,673.7
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6,542.6
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Proved Undeveloped
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62.3
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51.6
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6,901.7
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4,394.7
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Total Proved
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134.4
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172.2
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15,575.4
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10,937.3
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The estimates of future net revenues as of September 30,
2008 reflect a 38% percent decrease in future net revenues, and
a 39% percent decrease in the present value of future net
revenues from those estimated as of September 30, 2007. The
independent engineers have advised the Trustee that most of the
reasons for the decreases relate to the Jay Field. The
independent engineers have advised the Trustee that despite
increased oil and gas prices at September 30, 2008, the Jay
Field estimates at September 30, 2008 decreased primarily
as a result of a decrease in the fields average daily oil
production rate, the cessation of NGL revenues due to the lack
of NGL sales since February 2008, increased operating costs,
increased forecasted capital expenditures, and increased Excess
Production Costs as compared with September 30, 2007.
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 prior years), projections of
operating and capital costs, and the Working Interest
Owners evaluation of the economic feasibility of
conducting additional operations. Decreases in the price
estimates used in the preparation of the Miller and Lents report
would decrease the estimates of the reserves as well as the
estimates of the future net revenues to the Trust and of the
discounted value of those future net revenues, and these
decreases could be significant.
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 to be produced in the
future. Proved 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. Estimating proved
reserves is not an exact science. Significant revisions of the
estimates of proved reserves 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
acquiring historical pressure and production data. When a new
reservoir is discovered, proved reserves are determined
primarily 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,
18
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.
The estimated net revenues have been determined on the basis of
when the oil or gas is estimated to be produced. However,
payments, if any, 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. The Trustee does not expect to
make any quarterly distributions after December 31, 2007.
The estimated net revenues in Miller and Lents letter have
not been reduced for costs and expenses of the Trust.
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, as of September 30, 2008, the Working
Interest Owner has estimated the capital expenditures for
production and development of only the proved reserves would be
approximately $47,200,000 for the period from October 1,
2008 through September 30, 2009. 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 attached
as Appendix A to this report on
Form 10-K.
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. 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 attached as Appendix A includes
such estimates, prepared on the basis described therein. The
quantities imputed to the Trust are calculated by multiplying
Miller and Lents estimated net reserves of the Working
Interest Owner (prior to taking into consideration the
Trusts 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
Trusts 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.
INDUSTRY
CONDITIONS AND REGULATION
Industry
Conditions
The availability of a ready market for oil and gas depends upon
numerous factors beyond the Working Interest Owners
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
19
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
Overriding 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
Oil and gas activities on the 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 the operations and facilities are in general compliance
with applicable health, safety, and environmental laws and
regulations.
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 Companys ruling
requests to the Service regarding the federal income tax
consequences of the creation and distribution of Units to the
Companys 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 holders 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).
20
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.
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
holders 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.
21
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 ending
with or within his taxable year based on the Partnerships
method of accounting, without regard to the Unit holders
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 holders 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 percent or more of its gross income
is from certain qualified passive sources (which include income
from oil and gas activities). Because all of the
Partnerships 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. 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
Partnerships 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 adjusted tax basis of the productive
property by the total number of units of production (barrels of
oil and thousand cubic feet (Mcf) of gas) remaining
attributable to the productive property held by the Trust as of
the taxable year and (ii) multiplying the result in
(i) by the number of units sold during the year.
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.
22
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. 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 two
percent of the Unit holders 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 taxpayers
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 holders adjusted gross income.
Accordingly, such deductions should not be subject to the two
percent 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. 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 holders 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
corporations alternative minimum taxable income is reduced
by an exemption amount, it is then multiplied by
20 percent, 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
corporations alternative minimum tax liability. The
corporate alternative minimum tax provisions insure that
corporate taxpayers pay tax equal to at least 20 percent of
their economic income above the exemption amount. The corporate
exemption amount is $40,000, less 25 percent of the excess
of alternative minimum taxable income over $150,000.
Alternative Minimum Tax for Noncorporate
Taxpayers.
A noncorporate Unit holders
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
taxpayers alternative minimum taxable income is reduced by
an exemption amount, the tentative alternative minimum tax is
generally determined by multiplying this amount by
26 percent for the first $175,000, and 28 percent of
the excess over $175,000. If a noncorporate taxpayers
income includes long term capital gain income, lower rates of
tax are applicable. The amount by which this tentative minimum
tax (reduced by any alternative minimum tax foreign tax credit)
exceeds regular tax is the noncorporate taxpayers minimum
tax liability. For tax years beginning in 2008, the noncorporate
taxpayers exemption amount is $69,950 ($66,250 in
2007) in the case of joint returns or surviving spouses,
$46,200 ($44,350 in 2007) in the case of unmarried
individuals who are not surviving spouses, $34,975 ($33,125 in
2007) in the case of married individuals filing separate
returns, and $22,500 for estates and trusts. For married persons
filing jointly or surviving spouses, the exemption amounts are
reduced by 25 percent of the amount by which their
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.
23
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 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 percent 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 income from real property, such as 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 percent withholding requirement. Such
exemption is claimed for a calendar year by filing, in
duplicate, with the Trustee,
Form W-8ECI,
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 W-
8ECI (or substitute statement) must be filed with the Trustee
every three years in order to effect an exemption from
withholding for that years income. Because the application
of the withholding Regulations will vary depending on a
holders particular circumstances, all holders are urged to
consult their own tax advisors regarding the application of the
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 percent 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.
Under Section 1446 of the Code, 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, which is currently 35 percent
for individuals and 35 percent for corporations. A foreign
partners 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 partnerships 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.
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
24
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.
In general, the amount of withholding is 10 percent of the
amount realized or the disposition by a Foreign Taxpayer. 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 not apply in the case of a Foreign
Person transferring a substantial amount of non-publicly traded
interests in publicly traded partnerships if the transfer is
from a single transferor (or related transferors) in a single
transaction (or separate transactions that occur within three
months).
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 holders 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 Partnerships 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 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.
The treasury regulations provide that a partner selling a
portion of its interest in a publicly traded partnership may use
its actual holding period in the sold interest if, (i) the
ownership interest is divided into identifiable units
25
with ascertainable holding periods, (ii) the selling
partner can identify the portion of its partnership interest
transferred, and (iii) the selling partner makes the
required election.
A Unit holder whose Units are loaned to a short
seller to cover a short sale of Units may be considered as
having disposed of those Units. If so, the Unit holder would no
longer be a partner in the Partnership and would likely
recognize gain or loss from the disposition. As a result the
Partnerships items of income and loss would not be
recognized by the Unit holder, and any cash distributions to the
Unit holder would constitute ordinary income. The IRS has
announced that it is studying tax issues relating to the tax
treatment of short sales of partnership interests.
Reports.
The Trustee will furnish to Unit
holders of record annual reports (such as the LL&E Royalty
Trust 2008 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 Partnerships aggregate and each
partners 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
partners 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 holders 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
26
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 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 holders 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 Trusts
income and distributions. A Unit holder who treats the Trust as
a grantor trust would pay tax attributable to the Trusts
portion of the Partnerships 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 holders reporting of Trust
income could increase the likelihood of an audit of such Unit
holders tax return.
Reporting
Requirements for Widely-Held Fixed Investment Trusts
Under new IRS regulations, effective for the trust tax reporting
requirements after December 31, 2006, the Trust is
classified as a widely-held fixed investment trust (WHFIT).
Effective for the calendar year ended December 31, 2007 the
Trust will no longer be required to file an information return
reporting the items of income, credit or deduction that would be
allocated to the unit holders based on their investment in the
Trust. Effective for 2007 and subsequent years, the regulations
require the sharing of tax information among trustees and
intermediaries that hold a trust interest on behalf of or for
the account of a beneficial owner or any representative or agent
of a trust interest holder of fixed investment trusts that are
classified as widely-held fixed investment trusts. The new
reporting requirements provide for the dissemination of trust
tax information by the Trustee to intermediaries who are
ultimately responsible for reporting the investor-specific
information through Forms 1099 to the investors and the
Internal Revenue Service. Every trustee or intermediary that is
required to file a Form 1099 for a Trust interest holder
must furnish a written tax information statement that is in
support of the amounts as reported on the applicable
Form 1099 to the Trust interest holder. Any generic tax
information provided by the Trustee of LL&E
27
Royalty Trust is intended to only be used to assist Unit holders
in the preparation of their 2008 federal and state income tax
returns.
Available
Trust Tax Information
In compliance with the new reporting requirements for
widely-held fixed investment trusts and the dissemination of
trust tax reporting information, the Trustee provides a generic
tax information reporting booklet which is intended to only be
used to assist Unit holders in the preparation of their 2008
federal and state income tax returns. This tax information
booklet can be obtained at www.businesswire.com/cnn/lrt.htm
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
the transfer agents 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 Companys
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 Courts
opinion is now final and nonappealable.
Backup
Withholding
The Codes backup withholding system applies to all
reportable payments. The rate of withholding of tax
is 28 percent 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 28 percent 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.
28
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, trust or partnership. 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
owners 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 for the
information required to be supplied to the transferor and
transferee, and $250,000 for the information required to be
supplied to the Service.
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 holders 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 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.
Louisiana
Louisiana imposes an income tax on all income of resident
individuals (but provides 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. Relative to individual
income tax, effective for tax years beginning after
January 1, 2003 the excess itemized deduction was repealed
in its entirety. Beginning in 2007, taxpayers are allowed a
deduction in the amount of 57.5 percent (65 percent in
2008) of the excess federal itemized deductions. The income
tax rates for individuals range from a low of 2 percent to
a high of 6 percent.
29
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 direct and indirect expenses, is
generally treated as allocable income in Louisiana (oil and gas
Royalty income is specifically allocated to where the property
is located). For corporations with a tax year beginning before
December 31, 2005, 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 taxpayers business to acquire
a business situs) or, in the absence of a business situs, to the
taxpayers commercial domicile. Thus, for corporations with
a tax year beginning before December 31, 2005, in the
absence of a business situs, gain or loss will be allocated to
the corporations commercial domicile. For corporations
with a tax year beginning after December 31, 2005, gain or
loss on the sale of units is no longer allocable.
Instead, gains/losses not in the ordinary course of business are
apportioned. The gain/loss is included in the apportionable
income tax base but not included in the apportionment factors
(Note that if a corporation uses separate accounting or has a
zero Louisiana income tax apportionment factor, exceptions apply
to this treatment. La. R.S. §287.94(H) contains further
information on the exceptions.) The income tax rates for
corporations range from a low of 4 percent to a high of
8 percent. For an individual who is not a resident of
Louisiana, in the absence of a business situs, gain or loss
shall be allocated to the nonresidents state of legal
domicile.
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 of gross income, but
limited to 50 percent of net income received from the oil
and gas property). 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
the larger of (i) a corporations apportioned capital
(borrowed or contributed) and undistributed surplus or
(ii) the assessed value of all realty and personalty in
Louisiana in the preceding year. A corporations capital is
apportioned based on a ratio of assets (tangible and intangible)
and revenue sourced to Louisiana to total assets (tangible and
intangible) and revenue everywhere. For franchise tax years
beginning after December 31, 2006, corporations in the
business of manufacturing use a single sales factor to apportion
capital.
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 (FDR) 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 taxpayers
circumstances. Business income is apportioned to Florida based
on the corporations 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 corporations 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 holders
allowable depletion deduction will be the same as the amount
allowed for federal income tax purposes.
Florida also imposed an intangibles tax on individuals,
corporations, partnerships, and fiduciary filers. The intangible
base included notes receivable, investments, and accounts
receivable (less a reasonable allowance for
30
uncollectible accounts). Effective January 1, 2007, the
annual tax on intangible personal property such as stocks,
bonds, mutual funds, money market funds, and unsecured notes was
repealed. Beginning January 1, 2007, taxpayers will no
longer file an intangible personal property tax return on these
types of intangible personal property. Not all intangible taxes
have been repealed. The intangible tax on leases of
government-owned real property and the one-time intangible tax
on notes secured by a mortgage on Florida real property are
still in effect.
Alabama
Alabama imposes an income tax on all income of resident
individuals (but allows 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 taxpayers circumstances. Business
income is apportioned to the state based on the
corporations apportionment factor. 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 6.5 percent.
Individual Unit holders and corporate Unit holders are allowed a
depletion deduction based on the greater of the amount of
depletion deducted on their federal tax returns or an amount
equal to 12 percent of gross income from each property
(however such amount shall not exceed 50 percent of the
Unit holders net income).
In addition to the corporate income tax, Alabama imposes a
Business Privilege Tax. The Privilege Tax is imposed on the net
worth of domestic and foreign corporations, limited liability
entities, and disregarded entities. For the Privilege Tax, net
worth is the sum of the corporations outstanding capital
stock and any additional
paid-in-capital,
(but without reduction for treasury stock), and retained
earnings. The portion of the net worth subject to the privilege
tax is determined by applying the corporations Alabama
income tax apportionment factor to the net worth base. The rate
is determined by the entitys federal taxable income in
Alabama. The rate ranges from $.25 to $1.75 for each $1,000 of
net worth in Alabama. Minimum tax is $100 and maximum tax is
$15,000 for all years after 2000. For financial institutions and
insurance companies, the maximum tax is $3,000,000.
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 $0.03 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 percent of the market value of oil. The gas tax is
subject to an annual rate adjustment each July 1, but to
not less than $0.07 per mcf. Florida generally imposes a
severance or production tax of 8 percent of the actual
value of oil production and a tax on gas. The gas tax rate is
the gas base rate of $0.171 per mcf times the gas base rate
adjustment. Beginning July 1, 1987, the gas base rate
adjustment is determined by the FDR annually on July 1.
Alabama generally imposes a privilege tax on gas production or
severance at the rate of 8 percent and a conservation tax
of 2 percent of the actual value of oil and gas production
(the 2 percent rate is reduced to 1 percent for a
period of five years for certain wells for which the initial
permits were obtained between July 1, 1996 and July 1,
2002).
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 Alabama. The Royalties, and consequently the Unit holders,
will bear their proportionate shares of the
31
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.
AVAILABLE
INFORMATION
The Trust makes copies of its reports under the Exchange Act
available at
www.businesswire.com/cnn/lrt.htm
as
promptly as practicable after they are filed with the Securities
and Exchange Commission. The Trusts filings under the
Exchange Act are available electronically from the website
maintained by the SEC at
http:www.sec.gov
. The Trust will
also provide electronic copies of its recent filings free of
charge upon request to the Trustee, and will provide paper
copies of its recent filings for its costs of reproduction upon
request to the Trustee.
Although risk factors are described elsewhere in this
Form 10-K
together with specific Cautionary Statements, the following is a
summary of the principal risks associated with an investment in
units in the Trust.
The
Trust terminated as of December 31, 2007 and is required to
sell its assets and liquidate.
In accordance with the Trust Agreement, the Trust was
required to terminate as of December 31, 2007, and the
Trustee is required to sell the assets of the Trust and to
liquidate the Trust. There can be no assurance that the assets
can be sold for any particular amount. If the Trustee has not
sold the assets by December 31, 2010, the Trustee is
required to sell the assets in a public auction.
The
Trust will incur expenses in connection with the sale of its
assets and liquidation.
The Trust will incur expenses in connection with the sale of its
assets and liquidation, including expenses and costs of a
financial advisor to assist with the sale of the Trusts
assets, and the expenses could be significant.
The
sale of the Trusts assets will take a substantial amount
of time.
The sale of the Trusts assets will take a substantial
amount of time. The Trustee has determined that, in light of
market conditions, it is in the best interests of the Trust unit
holders to postpone the sale of the Trusts assets for an
indefinite period of time. The sale may not be completed by
December 31, 2010.
If the
Trust has not sold its assets by December 31, 2010, the
Trustee is required to sell the assets in a public
auction.
If the Trustee has not sold the assets by December 31,
2010, the Trustee is required to sell the assets in a public
auction. A public auction might not result in as favorable a
price for the Trusts assets as an individually negotiated
transaction.
The
market prices for oil and gas may not increase and may decline
prior to the time the Trust enters into a binding agreement for
the sale of the Trusts assets.
Market prices of,
and/or
market expectations for future, oil, gas and other hydrocarbons
may not increase, and may decrease, before the Trust enters into
a binding agreement for the sale of the Trusts assets.
Natural
gas and oil prices fluctuate due to a number of factors, and
lower prices will reduce the market value of the Trusts
assets.
The Trust does not anticipate making any additional
distributions to Unit holders prior to a final liquidating
distribution. The value of the Trusts assets remains
dependent upon the prices realized from the sale of natural gas
and oil. Natural gas and oil prices can fluctuate widely on a
month-to-month
basis in response to a variety of factors
32
that are beyond the control of the Trust, the Working Interest
Owner and the operators. Factors that contribute to price
fluctuation include, among others:
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U.S. and worldwide economic conditions and expectations
regarding future conditions and supply and demand;
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|
political conditions worldwide, in particular political
disruption, war or other armed conflicts in oil producing
regions;
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weather conditions;
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the supply and price of foreign natural gas and oil;
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the level of consumer demand;
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the price and availability of alternative fuels;
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|
the proximity to, and capacity of, transportation
facilities; and
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|
the effect of worldwide energy conservation measures.
|
Moreover, government regulations, such as regulation of natural
gas transportation and price controls, can affect product prices
in the long term.
Lower natural gas and oil prices may reduce the amount of
natural gas and oil that is economic to produce and may also
reduce the value of the Trusts assets.
The
Shut In of the Jay Field may have a material adverse effect on
the value of the Trusts assets.
As previously announced, in early February 2009 the Trust
received a letter from Quantum Resources Management LLC
addressed to all Jay Field royalty interest owners stating that
Quantum had temporarily suspended production from the Jay Field
on December 22, 2008. The letter stated that Quantums
decision to suspend production resulted from the dramatic
decline in oil prices coupled with high operating expenses. The
shut in of the Jay Field may have a material adverse effect on
the Trusts sale of its interests and on the value the
Trust may be able to obtain for the Jay Field interest.
Damage
from Hurricanes Katrina and Rita has had a material adverse
effect on the value of the Trusts assets.
The damage caused by Hurricanes Katrina and Rita to production
facilities for properties in which the Trust has an interest has
had a material adverse effect on the value of the Trusts
assets. The damage has interrupted production, damaged
production facilities, increased expenses, increased abandonment
costs, and resulted in the decision by the Working Interest
Owner to escrow all funds otherwise distributable to the Trust
from the Offshore Louisiana and South Pass 89 properties.
Additional information regarding the damage to these properties
is included under Managements Discussion and Analysis of
Financial Condition and Results of Operations.
Pending
litigation against the Working Interest Owner could adversely
impact the value of the Trusts assets.
The Trustee has been informed by the Working Interest Owner that
the Working Interest Owner has been named as one of many
defendants in certain lawsuits alleging the underpayment of
royalties on the production of natural gas and natural gas
liquids through the use of below-market prices, improper
deductions, improper measurement techniques and transactions
with affiliated companies. Plaintiffs in some of the lawsuits
allege that the underpayment of royalties, among other things,
resulted in false forms being filed by the relevant Working
Interest Owner with the Minerals Management Service, thereby
violating the civil False Claims Act.
If the plaintiffs are successful in the matters described above,
a judgment or settlement could entitle the Working Interest
Owner to reimbursements for past periods attributable to
properties covered by the Trusts interest, which could
decrease the value of the Trusts assets. The Working
Interest Owner has informed the Trustee that at
33
this time, the Working Interest Owner is not able to reasonably
estimate the amount of any potential loss or settlement
allocable to the Trusts interest.
Increased
production and development costs for the Overriding Royalties
will decrease the value of the Trusts
assets.
Production and development costs attributable to the Overriding
Royalties are deducted in the calculation of the Trusts
share of net proceeds. Accordingly, higher production and
development costs, without concurrent increases in revenues,
directly decrease the amount attributable to the Overriding
Royalties, and thus decrease the value of the Trusts
assets.
Trust
reserve estimates depend on many assumptions that may prove to
be inaccurate, which could cause both estimated reserves and
estimated future revenues to be too high.
The value of the Trusts assets depends upon, among other
things, the amount of reserves attributable to the Overriding
Royalties and the estimated future value of the reserves.
Estimating reserves is inherently uncertain. Ultimately, actual
production, revenues and expenditures for the underlying
properties will vary from estimates and those variations could
be material. Petroleum engineers consider many factors and make
assumptions in estimating reserves. Those factors and
assumptions include:
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historical production from the area compared with production
rates from similar producing areas;
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the assumed effect of governmental regulation; and
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assumptions about future commodity prices, production and
development costs, severance and excise taxes, and capital
expenditures.
|
Changes in these assumptions can materially change reserve
estimates.
The reserve quantities attributable to the Overriding Royalties
and revenues are based on estimates of reserves and revenues for
the underlying properties. The method of allocating a portion of
those reserves to the Trust is complicated because the Trust
holds an interest in the Overriding Royalties and does not own a
specific percentage of any actual reserves.
Operating
risks can adversely affect the value of the Trusts
assets.
The occurrence of drilling, production or transportation
accidents and other natural disasters at any of the properties
will reduce the value of the Trusts assets. These
occurrences include blowouts, cratering, explosives and other
environmental damage that may result in personal injuries,
property damage, damage to productive formations or equipment
and environmental damages. Any uninsured costs would be deducted
as a production cost in calculating net proceeds payable under
the Conveyances. The allocation of insurance proceeds to insured
costs is not within the control of the Trustee, and as a result
of the complexity of allocating insurance proceeds, the
allocation may take a significant amount of time.
Trust Unit
holders and the Trustee have no control or influence over the
operation or development of the Properties.
Neither the Trustee nor the Unit holders can influence or
control the operation or future development of the underlying
properties. The properties are operated by independent third
parties. The Working Interest Owner does not operate any of the
properties except as otherwise described in this Annual Report
on
Form 10-K.
Neither the Trustee nor the Unit holders have any right to
replace an operator. The Working Interest Owner handles receipt
and payment of funds relating to the Properties and payments to
the Trust for the Overriding Royalties.
The
operator may abandon any property, terminating the related
Overriding Royalties.
The operator of any of the properties may abandon any well or
property if it reasonably believes that the well or property can
no longer produce in commercially economic quantities. This
could result in termination of the Overriding Royalties relating
to the abandoned well or property.
34
Unit
holders have limited voting rights.
Voting rights as a Unit holder are more limited than those of
stockholders of most public corporations. For example, there is
no requirement for annual meetings of Unit holders or for an
annual or other periodic re-election of the Trustee. Unlike
corporations which are generally governed by boards of directors
elected by their equity holders, the Trust is administered by a
corporate Trustee in accordance with the Trust Agreement
and other organizational documents. The Trustee has extremely
limited discretion in its administration of the Trust.
Unit
holders have limited ability to enforce the Trusts rights
against the current or future owners of the
Properties.
The Trust Agreement and related trust law permit the
Trustee and the Trust to sue the Working Interest Owner to
compel the Working Interest Owner to fulfill the terms of the
Conveyances of the Overriding Royalties. If the Trustee does not
take appropriate action to enforce provisions of the
Conveyances, the recourse of a Unit holder would likely be
limited to bringing a lawsuit against the Trustee to compel the
Trustee to take specified actions. Unit holders probably would
not be able to sue the Working Interest Owner directly.
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Item 1B.
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Unresolved
Staff Comments
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None.
Reference is made to Item 1. Business for the
information required by this item.
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Item 3.
|
Legal
Proceedings
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None.
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Item 4.
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Submission
of Matters to a Vote of Unit Holders
|
None.
PART II
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Item 5.
|
Market
for the Registrants Common Equity, Related Unit Holder
Matters and Issuer Purchases of Equity Securities
|
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, 2008 and 2007. The cash distributions to Unit
holders for each quarterly period in the years ended
December 31, 2008 and 2007 (applicable to production for
October 2007 through September 2008 and October 2006 through
September 2007) are also included in the table below.
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2008 Quarter Ended
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2007 Quarter Ended
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March 31
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June 30
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Sept. 30
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Dec. 31
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March 31
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June 30
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Sept. 30
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Dec. 31
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Units of Beneficial Interest:
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High sales price
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$
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2.20
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$
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2.60
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$
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2.25
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$
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1.71
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$
|
2.85
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$
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2.14
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$
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1.87
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$
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2.58
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Low sales price
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1.73
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1.88
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1.58
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0.49
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1.95
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1.49
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1.10
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1.40
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Distributions per Unit
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$
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0.0000
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$
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0.0000
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$
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0.0000
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$
|
.0000
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$
|
0.0272
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$
|
0.0000
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$
|
0.0000
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$
|
.0334
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The Trustee does not expect to make any further distributions
prior to a final liquidating distribution upon the sale of the
Trusts assets.
The total number of Unit holders of record as of March 29,
2009 was 3,869.
35
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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.
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Years Ended December 31,
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2008
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2007
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2006
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2005
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2004
|
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Revenues
|
|
$
|
678,528
|
|
|
$
|
1,965,473
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$
|
3,068,638
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|
|
$
|
7,354,827
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|
|
$
|
10,857,596
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Cash earnings
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(331,921
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)
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634,378
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2,094,226
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6,586,512
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10,178,621
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Cash distributions to Unit holders
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1,150,481
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1,831,080
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6,002,945
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10,177,500
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Cash distributions per Unit
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$
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$
|
0.0606
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$
|
0.0964
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$
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0.3161
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$
|
0.5359
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Trust Corpus
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$
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62
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$
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2,037,083
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$
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2,616,186
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$
|
2,393,340
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$
|
1,827,273
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Item 7.
|
Managements
Discussion and Analysis of Financial Condition and Results of
Operations
|
Critical
Accounting Policies
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
Trusts interest.
(b) Trust expenses, which include accounting, engineering,
legal and other professional fees, Trustees 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 percent 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 September 30 of the
preceding year. Amortization calculated in the fourth quarter is
based on the current year reserve study.
(d) The initial carrying value of the Trusts royalty
interests in oil and gas properties represents the
Companys 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. The unamortized balance at
December 31, 2008 is not indicative of the fair market
value of the interests held by the Trust.
This basis for reporting distributable income is considered to
be the most meaningful because distributions to the unitholders
for a month are based on net cash receipts for such month.
However, it will differ from the basis used for financial
statements prepared in accordance with accounting principles
generally accepted in the United States of America because,
under such accounting principles, royalty income for a month
would be based on net proceeds from sales for such month without
regard to when calculated or received and interest income for a
month would be calculated only through the end of such month,
and accounting principles generally accepted in the United
States would require a liquidation basis of accounting.
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.
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.
36
Liquidity
and Capital Resources
As stipulated in the Trust Agreement, the Trust is intended
to be passive, and the Trustees 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.
Recent
Developments
During 2008, the Trust did not receive any royalty revenue
associated with the Jay Field or Offshore Louisiana properties.
The Trust received royalty revenue of $37,239 for South
Pass 89 in 2008. The Jay Field, South Pass 89 and Offshore
Louisiana properties excess production costs as of
December 31, 2008 were approximately $10,930,000, $56,000
and $11,158,000, respectively. The excess production costs must
be recovered by the Working Interest Owners before any
distribution of royalty revenues will be made to the Trust.
As previously announced, in early February 2009 the Trust
received a letter from Quantum Resources Management LLC
addressed to all Jay Field royalty interest owners stating that
Quantum had temporarily suspended production from the Jay Field
on December 22, 2008. The letter stated that Quantums
decision to suspend production resulted from the dramatic
decline in oil prices coupled with high operating expenses. The
letter from Quantum notes that as operator of the Jay Field,
Quantum is facing three major issues: declining production,
increased costs, and significantly lower oil prices. The letter
also states that Quantums long term goal for the Jay Field
is to economically produce the maximum amount of reserves, and
notes that when Quantum temporarily suspended production, it
maintained the capability to reestablish production at a future
date. Quantum noted that to produce and sell the oil, it needs a
combination of higher product prices and lower costs, and
further noted that it is analyzing alternative production
scenarios that might result in improved economics. Quantum also
informed royalty interest owners that Quantum is analyzing all
options to reduce operational costs in the Jay Field, and that,
if its efforts are successful, Quantum expects to be able to
reestablish production from the field. While production from the
field is temporarily suspended, Quantum stated that it will
continue to conduct Unit Operations in the Jay Field in
accordance with the Unit Agreement.
As a result of a review by an independent oil and gas accounting
firm retained by the Trustee to review the Working Interest
Owners calculation of amounts relevant to the
determination of the net proceeds properly payable to the Trust
under the Conveyances, the Trustee and the Working Interest
Owner concluded that the Working Interest Owner had
inadvertently included sulfur extraction processing costs at the
Jay and Little Escambia Creek Field Unit desulfurization plant
in the calculation of Jay Field Gross Proceeds. Because neither
the Trustees oil and gas accounting firm nor the Working
Interest Owner was able to quantify the amount of the sulfur
extraction costs inadvertently included, the Trustee requested
that the Working Interest Owner pay to the Trust royalties on
the revenue generated by the sale of the sulfur in lieu of
refunding the amount charged to the Trusts interest. The
Trustee engaged an independent joint venture auditor to review
payments to the Trust for a portion of the Trust properties as
part of the termination of the Trust. The joint venture auditor
reviewed the period from January 2004 through December 2007. As
a result of the review, one of the Working Interest Owners made
a payment of approximately $437,000 in March 2008 to the Trust
to settle certain issues identified. In addition, the
independent joint venture auditor has recently completed a
review of the working interest owners calculations
relating to the Trusts interest in the Jay Field for the
period July 1, 2007 through December 31, 2008.
Although the matters reviewed have not yet been finalized with
the working interest owner, the Trustee does not expect any
significant net adjustment to the working interest owners
calculations relating to the Trusts interest in the Jay
Field for the period July 1, 2007 through December 31,
2008.
During 2005, Hurricanes Katrina and Rita affected the
operational status of properties included in the Offshore
Louisiana and South Pass 89 groups of properties, and Hurricane
Dennis and Tropical Storm Cindy affected the operational status
of the gas plant at Jay Field. The gas plant at Jay Field
returned to full operating status on April 13, 2006.
However, distributions to the Trust will be reduced
significantly for a period of time as a result of the damage
from these storms to the production facilities for properties in
which the Trust has an interest. As a result of the uncertainty
of future proceeds from these properties, the Trustee as of
December 31, 2008 has reserved $62 that
37
otherwise would have been distributed to the unitholders for the
payment of the Trusts likely expenses in the foreseeable
future. The Trustee intends to hold these funds for use in the
payment of future Trust expenses until it becomes reasonably
clear that they are no longer necessary.
Following is a description of the damage caused by Hurricanes
Katrina and Rita to production facilities for properties in
which the Trust has an interest. This information is based on
assessments of damage the Working Interest Owner has received
regarding damage from Hurricanes Katrina and Rita to the
Offshore Louisiana and South Pass 89 properties. All of the
information in this Report on
Form 10-K
relating to the operational status of the properties provided to
the Working Interest Owner by the various operators of the
properties in which the Trust has an interest, and was provided
to the Trust by the Working Interest Owner. The Working Interest
Owner is not the operator of any of these properties, and relies
on the various operators for information regarding the
operational status of the various properties. Consequently, all
of the information provided herein is based on preliminary and
sometimes informal information provided by the operators of the
Properties. The information provided herein is based on the
respective operators preliminary assessments of the damage
to the production facilities. The Trustee has been informed that
the assessments are ongoing, and that the assessments of
damages, the predictions of the likelihood of repairs and time
necessary to complete such repairs, the decisions to repair or
abandon facilities, and all other estimates are subject to
change.
South
Pass 89
Repairs due to Hurricane Katrina damage (August 2005) were
completed in the fourth quarter of 2006 and the field was
substantially restored to production in December 2006. The
operator, Marathon Oil Company, had provided a cost estimate of
$6,000,000 ($1,500,000 net to the Trust) to repair the
South Pass 89 B platform, however the operator has
indicated the actual cost to date is estimated at $6,500,000
($1,600,000 net to the Trust).
Offshore
Properties:
East
Cameron 336
The Working Interest Owner had previously elected not to
participate in proposed wellwork and remained responsible only
for field abandonment costs. The lease expired in 2007 and the
operator, Apache, informed the Working Interest Owner that it
had abandoned the wells in the first half of 2008. The platform
has not been abandoned yet and no cost estimates or actual costs
have been received to date.
East
Cameron 195
The East Cameron 195 platform was heavily damaged during
Hurricane Rita; however, it was not a significant producer, had
been shut in by the operator, Maritech, and had been approved
for abandonment prior to Hurricane Rita. The operators
early estimate of the wells-only abandonment for East Cameron
195 was $27,000,000 ($9,100,000 net to the Trust), however
costs to date are estimated at $31,000,000 ($10,300,000 net
to the Trust). These costs are for well abandonment only and do
not include platform abandonment and debris removal costs. Well
abandonment work began in February 2006 and was substantially
finished in December 2006 (7 wells were plugged and
abandoned and 3 wells have remaining plugging work that
will be completed as part of the platform and debris removal
process). Platform abandonment and debris removal work has not
commenced and the Working Interest Owner has not received an
estimated cost for such work from the operator.
South
Marsh Island 76
The South Marsh Island 76 platform was heavily damaged during
Hurricane Rita in 2005. The operator, Mariner, abandoned the
wells in 2008 for a cost of $4,485,953 ($403,736 net to the
Trust). No cost estimates have been received for the final
platform debris removal and site clearance.
38
Eugene
Island 261
The Eugene Island 261 platform was damaged during Hurricane Rita
but was repaired and returned to production in November 2005.
The estimated repair cost was $220,000 (resulting in costs
attributable to the Trusts interest of $44,000).
Vermillion
331
The Vermillion 331 platform was damaged during Hurricane Rita.
The operator, Energy Resources Technology, repaired the platform
and returned it to production in November 2006. The estimated
repair cost was $1,200,000 (resulting in costs attributable to
the Trusts interest of approximately $150,000).
Jay
Field
In December 2006, the Working Interest Owner and ExxonMobil, as
the operator of the Jay Field, sold their respective interests
in the field to Quantum Resource Management LLC (Quantum).
Quantum became the operator in April 2007. As described above
under Recent Developments, Quantum suspended
production from the Jay Field on December 22, 2008.
Other
The Working Interest Owner has advised the Trustee that the
Working Interest Owner has completed its analysis of the scope
and applicability of the insurance policies carried by the
Working Interest Owner to the damages that resulted from
Hurricanes Katrina and Rita to properties in which the Trust has
an interest. The Working Interest Owner has advised the Trustee
that, except as noted below, the Working Interest Owner believes
it has received all of the insurance reimbursements it will
receive for damages to the South Pass 89 and Offshore Louisiana
properties, and has reported the amounts (net to the working
interest owners interest) to the Trustee as follows:
|
|
|
|
|
Reimbursements received by the Working Interest Owner due to
lost production (which will be reported as Other Revenue) as
follows:
|
|
|
|
|
Offshore Louisiana Property
|
|
|
|
|
South Marsh Island 76 (Hurricane Rita)
|
|
$
|
1,275,000
|
|
Reimbursements received by the Working Interest Owner for
operating costs (which will be reported as a reduction to lease
operating expense) as follows:
|
|
|
|
|
South Pass 89
|
|
|
|
|
SP 89B (Hurricane Katrina)
|
|
$
|
816,088
|
|
SP 86C (Hurricane Katrina)
|
|
$
|
111,725
|
|
Offshore Louisiana Property
|
|
|
|
|
East Cameron 195 (Hurricane Rita)
|
|
$
|
6,525,937
|
|
South Marsh Island 76 (Hurricane Rita)
|
|
$
|
2,328,915
|
|
Eugene Island 261 (Hurricane Rita)
|
|
$
|
52,160
|
|
Vermillion 331 (Hurricane Rita)
|
|
$
|
206,259
|
|
The figures given above relate to the Working Interest
Owners interest in the properties. The Trusts
interest in these amounts is 50% with respect to South Pass 89
and 90% with respect to Offshore Louisiana. The exception noted
above relates to several making well safe claims for certain
properties which have been denied by the Working Interest
Owners insurers. The Working Interest Owner is evaluating
the denials.
The Working Interest Owner further informed the Trustee that the
insurance proceeds received will be applied, to the extent
permitted by the Trusts governing documents, to offset
existing Excess Production Costs and to fund the Special Cost
Escrows for Offshore Louisiana and South Pass 89.
The Working Interest Owner has further informed the Trustee that
although the work to secure and repair or replace damaged
equipment and restore production at properties the operators
have determined to repair has now
39
been completed, work nevertheless remains ongoing to secure,
plug, abandon and dismantle other properties in which the Trust
has an interest and that the operators have determined to
abandon. In particular, the work and expenses to plug, abandon
and dismantle the facilities at South Marsh Island 76 and East
Cameron 195 are expected to extend into 2009 or longer. The
Working Interest Owner has informed the Trustee that these
ongoing expenses are not insured.
The abandonment and repair costs estimated by the Working
Interest Owner have had and are expected to have a material
adverse effect on royalties payable from the South Pass 89 and
Offshore Louisiana properties to the Trust, and from the Trust
to Unit holders. As previously disclosed, the Working Interest
Owner began escrowing funds otherwise distributable to the Trust
from the South Pass 89 property and Offshore Louisiana
properties, beginning with the April 2006 monthly
distribution. Consequently, distributions from the Trust to the
Unit holders have been eliminated for a period of time. The
Trustee does not expect to make any further distribution prior
to a final liquidating distribution after the sale of the
Trusts interests.
Results
of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Royalty revenues
|
|
$
|
678,528
|
|
|
$
|
1,965,473
|
|
|
$
|
3,068,638
|
|
Trust administrative expenses
|
|
|
(1,010,449
|
)
|
|
|
(1,331,095
|
)
|
|
|
(974,412
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash earnings
|
|
$
|
(331,921
|
)
|
|
$
|
634,378
|
|
|
$
|
2,094,226
|
|
Changes in undistributed cash
|
|
|
331,921
|
|
|
|
516,103
|
|
|
|
(263,146
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash distributions
|
|
$
|
|
|
|
$
|
1,150,481
|
|
|
$
|
1,831,080
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash distributions per unit
|
|
$
|
0.0000
|
|
|
$
|
0.0606
|
|
|
$
|
0.0964
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Units outstanding
|
|
|
18,991,304
|
|
|
|
18,991,304
|
|
|
|
18,991,304
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalty revenues are generally received in the third month
following the month of production of oil and gas attributable to
the Trusts interest. Both revenues and expenses are
recorded on a cash basis. Accordingly, distributions to Unit
holders for the years ended December 31, 2008, 2007 and
2006 are attributable to the Working Interest Owners
operations during the twelve-month periods ended
September 30, 2008, 2007 and 2006, respectively.
Administrative expenses incurred by the Trust decreased $320,646
or 24% for the year ended December 31, 2008 as compared to
the year ended December 31, 2007. The decrease in 2008
administrative expenses was primarily a result of decreases in
accounting and legal fees incurred by the Trust. Administrative
expenses incurred by the Trust increased $356,683 or 37% for the
year ended December 31, 2007 as compared to the year ended
December 31, 2006. The increase in 2007 administrative
expenses was primarily a result of increases in accounting and
legal fees incurred by the Trust.
Distributions to Unit holders for 2008, 2007 and 2006 amounted
to $0 ($0.0000 per Unit), $1,150,481 ($0.0606 per Unit) and
$1,831,080 ($0.0964 per Unit) respectively. During these years,
the Trust received cash of $678,528,
40
$1,965,473 and $3,068,638, 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 Owners calculation of the Net Proceeds
from the Properties and the Royalties paid to the Trust for the
respective years.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Net Proceeds:
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
52,452,108
|
|
|
$
|
29,574,488
|
|
|
$
|
30,199,489
|
|
Amounts withheld in escrow
|
|
|
(11,527,054
|
)
|
|
|
(7,973,453
|
)
|
|
|
(2,096,559
|
)
|
Production costs and expenses
|
|
|
(32,635,590
|
)
|
|
|
(27,468,852
|
)
|
|
|
(19,076,533
|
)
|
Capital expenditures
|
|
|
(15,922,161
|
)
|
|
|
(2,417,881
|
)
|
|
|
(5,042,463
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Proceeds
|
|
$
|
(7,632,697
|
)
|
|
$
|
(8,285,698
|
)
|
|
$
|
3,983,934
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalties paid to the Trust:
|
|
|
|
|
|
|
|
|
|
|
|
|
Overriding Royalties
|
|
$
|
37,239
|
|
|
$
|
1,566,221
|
|
|
$
|
2,726,914
|
|
Fee Lands Royalties
|
|
|
204,741
|
|
|
|
399,252
|
|
|
|
341,724
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Proceeds paid to the Trust
|
|
|
436,548
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalties paid to the Trust (Royalty revenues)
|
|
$
|
678,528
|
|
|
$
|
1,965,473
|
|
|
$
|
3,068,638
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues of the Working Interest Owner with respect to the
Productive Properties increased approximately $22,878,000 or
77 percent during the 2008 operating period compared to the
same operating period in 2007. This was offset by higher
production costs and capital expenditures. Revenues decreased
approximately $625,000 or 2 percent during the 2007
operating period compared to the same operating period in 2006
as a result of the Jay Field trunk line being down from
December 20, 2006 to April 2, 2007, partially offset
by South 89 properties producing in 2007. The following
unaudited schedule provides a summary of the Working Interest
Owners net production attributable to the Trust.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Offshore
|
|
|
|
|
|
|
Jay Field
|
|
|
South Pass 89
|
|
|
Louisiana
|
|
|
Total
|
|
|
Year Ended December 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil & Condensate (MBbls)
|
|
|
23
|
|
|
|
|
|
|
|
|
|
|
|
23
|
|
Gas (Mcf)
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
3
|
|
Year Ended December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil & Condensate (MBbls)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas (Mcf)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average natural gas prices received in 2008 increased to $9.29
per thousand cubic feet (mcf) from $7.12 per mcf in
2007. Average crude oil prices increased to $109.32 per barrel
in 2008 from $65.01 per barrel in 2007 while natural gas liquids
prices decreased to $51.15 per barrel in 2008 from $52.58 in
2007. Average natural gas prices received in 2007 decreased to
$7.12 per thousand cubic feet (mcf) from $8.68 per
mcf in 2006. Average crude oil prices increased to $65.01 per
barrel in 2007 from $63.87 per barrel in 2006 while natural gas
liquids prices increased to $52.58 per barrel in 2007 from
$48.41 in 2006.
In 2008, the Working Interest Owner reserved $11,527,054 in
escrow as a result of uncertainties related to the oil and gas
properties. In 2007, the Working Interest Owner reserved
$7,973,453 in escrow as a result of uncertainties related to the
oil and gas properties. In 2006, the Working Interest Owner
reserved $2,096,559.
Production costs and expenses incurred by the Working Interest
Owner on the Productive Properties increased approximately
$5,200,000, or 19 percent, between the 2008 operating
period and the 2007 operating period. Production costs and
expenses incurred by the Working Interest Owner on the
Productive Properties increased approximately $8,400,000, or
44 percent, between the 2007 operating period and the 2006
operating period. The
41
increase in 2007 was primarily attributed to increased lease
operating expenses, non-operated overhead, and labor costs at
Jay Field and Offshore Louisiana.
Capital expenditures increased approximately $13,500,000, or
559% percent, between 2008 and 2007. The increase in 2008
was primarily the result of plant turnaround and workovers at
Jay Field. Capital expenditures decreased approximately
$2,600,000, or 52 percent, between 2007 and 2006. The
decrease in 2007 was primarily the result of a decrease in
developmental drilling at Jay Field.
The Trusts Fee Lands Royalties decreased approximately
$194,511 or 49 percent in the 2008 operating period
compared to the same period in 2007. The Trusts Fee Lands
Royalties increased approximately $58,000 or 17 percent in
the 2007 operating period compared to the same period in 2006.
The amount of Fee Lands leased as of December 31, 2008 and
December 31, 2007 was approximately 1,062 and
1,015 acres, respectively.
The Trustee has been informed by the Working Interest Owner that
the Working Interest Owner has been named as one of many
defendants in certain lawsuits alleging the underpayment of
royalties on the production of natural gas and natural gas
liquids through the use of below-market prices, improper
deductions, improper measurement techniques and transactions
with affiliated companies. Plaintiffs in some of the lawsuits
allege that the underpayment of royalties, among other things,
resulted in false forms being filed by the Working Interest
Owner with the Minerals Management Service, thereby violating
the civil False Claims Act.
If the plaintiffs are successful in the matters described above,
revenues to the Trust could decrease. A judgment or settlement
could entitle the Working Interest Owner to reimbursements for
past periods attributable to properties covered by the
Trusts interest, which could decrease future royalty
payments to the Trust. The Working Interest Owner has informed
the Trustee that at this time, the Working Interest Owner is not
able to reasonably estimate the amount of any potential loss or
settlement allocable to the Trusts interest.
|
|
Item 7A.
|
Quantitative
and Qualitative Disclosures about Market Risk
|
The Trust does not engage in any operations, and does not
utilize market risk sensitive instruments, either for trading
purposes or for other than trading purposes.
42
|
|
Item 8.
|
Financial
Statements and Supplementary Data
|
LL&E
ROYALTY TRUST
STATEMENTS
OF CASH EARNINGS AND DISTRIBUTIONS
Years Ended December 31, 2008, 2007 and 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Royalty revenues
|
|
$
|
678,528
|
|
|
$
|
1,965,473
|
|
|
$
|
3,068,638
|
|
Trust administrative expenses
|
|
|
(1,010,449
|
)
|
|
|
(1,331,095
|
)
|
|
|
(974,412
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash earnings
|
|
$
|
(331,921
|
)
|
|
$
|
634,378
|
|
|
$
|
2,094,226
|
|
Changes in undistributed cash
|
|
|
331,921
|
|
|
|
516,103
|
|
|
|
(263,146
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash distributions
|
|
$
|
|
|
|
$
|
1,150,481
|
|
|
$
|
1,831,080
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash distributions per unit
|
|
$
|
0.0000
|
|
|
$
|
0.0606
|
|
|
$
|
0.0964
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Units outstanding
|
|
|
18,991,304
|
|
|
|
18,991,304
|
|
|
|
18,991,304
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
STATEMENTS
OF ASSETS, LIABILITIES AND TRUST CORPUS
December 31,
2008 and 2007
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
ASSETS
|
Cash
|
|
$
|
62
|
|
|
$
|
331,983
|
|
Net overriding royalty interests in productive oil and gas
properties and 3% royalty interests in fee lands
|
|
|
76,282,000
|
|
|
|
76,282,000
|
|
Less accumulated amortization
|
|
|
(76,282,000
|
)
|
|
|
(74,576,900
|
)
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
62
|
|
|
$
|
2,037,083
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND TRUST CORPUS
|
Trust corpus (18,991,304 Units of Beneficial Interest
authorized, issued and outstanding)
|
|
$
|
62
|
|
|
$
|
2,037,083
|
|
|
|
|
|
|
|
|
|
|
Contingencies (note 8)
|
|
|
|
|
|
|
|
|
Total liabilities and Trust corpus
|
|
$
|
62
|
|
|
$
|
2,037,083
|
|
|
|
|
|
|
|
|
|
|
STATEMENTS
OF CHANGES IN TRUST CORPUS
Years
Ended December 31, 2008, 2007 and 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Trust corpus, beginning of period
|
|
$
|
2,037,083
|
|
|
$
|
2,616,186
|
|
|
$
|
2,393,340
|
|
Cash earnings
|
|
|
(331,921
|
)
|
|
|
634,378
|
|
|
|
2,094,226
|
|
Cash distributions
|
|
|
|
|
|
|
(1,150,481
|
)
|
|
|
(1,831,080
|
)
|
Amortization of royalty interests
|
|
|
(1,705,100
|
)
|
|
|
(63,000
|
)
|
|
|
(40,300
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Trust corpus, end of period
|
|
$
|
62
|
|
|
$
|
2,037,083
|
|
|
$
|
2,616,186
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to financial statements.
43
LL&E
ROYALTY TRUST
December 31,
2008, 2007 and 2006
|
|
(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. On March 31, 2006, Conoco
Phillips acquired BR via merger into Cello Acquisition Corp., a
wholly owned subsidiary of ConocoPhillips. The surviving entity
of the merger was Cello Acquisition Corp., which changed its
name to Burlington Resources Inc. (New BR) Consequently, New BR
is a wholly owned subsidiary of ConocoPhillips. 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 and in federal waters offshore Louisiana (Productive
Properties) and (b) 3 percent royalty interests (Fee
Lands Royalties) in approximately 400,000 acres of the
Companys 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 percent and 1 percent
interests, respectively.
The Trust is passive, with The Bank of New York Mellon
Trust Company, N.A., (the 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 (NYSE
SYMBOL LRT).
Trust Termination
The Trust Agreement provides that the Trust will terminate
in the event that the net revenues fall below $5,000,000 for two
successive years (the Termination Threshold). Net
revenues are calculated as royalty revenues after administrative
expenses of the Trust and as if the Trust had received its pro
rata portion of any amounts being withheld by the Working
Interest Owners or the Partnership under escrow arrangements or
to make refund payments pursuant to the Conveyances (the
Trusts pro rata portion of escrowed amounts relating to
the future dismantlement of platforms are included in the net
revenue calculation for this purpose).
Net revenues to the Trust for the years ended December 31,
2007 and 2006 calculated as described above, were $1,634,740 and
$2,094,226, respectively. Consequently, the Trust was required
to terminate effective December 31, 2007, and is in the
process of selling the Royalties and liquidating the assets of
the Trust.
As a result of 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 consisting of personal property) upon
such terms as the Trustee, in its sole discretion, deems to be
in the best interest of the Unit holders. After paying or making
provision for all actual and contingent liabilities of the
Trust, including fees of the Trustee, the Trustee will
distribute all remaining cash as promptly as practicable.
Despite 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 Trustee does not expect to make any
further monthly distributions to Unit holders in the interim
period prior to the distribution of the proceeds of the sale of
the Trusts assets.
The Trustee has retained Stifel, Nicolaus & Company,
Incorporated (Stifel Nicolaus) to market the
Trusts assets. However, as announced by the Trustee on
October 22, 2008, the Trustee has determined that, in light
of market conditions, it is in the best interests of the Trust
unit holders to postpone the sale of the Trusts assets for
an
44
LL&E
ROYALTY TRUST
NOTES TO
FINANCIAL STATEMENTS (Continued)
indefinite period of time. The Trustee intends to review market
conditions frequently, and intends to recommence the marketing
process as soon as practicable. If any asset required to be sold
has not been sold within three years after the termination of
the Trust, the Trustee will cause the asset to be sold at public
auction to the highest cash bidder, and will mail notice of any
such public auction to all Unit holders at least 30 days
prior to any such auction. Except in connection with any
proposed non-cash sale, no approval of the Unit holders will be
required in connection with the sale of the Trusts assets.
As of December 31, 2008, the Trust had $62 in cash reserved
for Trust expenses. Based on current general and administrative
expenditures, in the absence of Royalty Revenues the Trustee
expects that it will be required to borrow money in accordance
with the Trust Agreement to fund future Trust expenses.
However, no assurance can be given that the Trustee will be able
to borrow money on terms the Trustee considers reasonable or at
all. The Trust Agreement permits, but does not require, The
Bank of New York Mellon Trust Company, N.A. or an affiliate
to lend funds to the Trustee. In the event any loans are made to
the Trust, the Trust Agreement will prohibit the Trustee
from making any distributions to unitholders until those loans
are repaid in full.
During 2008, the Trust did not receive any royalty revenue
associated with the Jay Field or Offshore Louisiana properties.
The Trust received royalty revenue of $37,239 from South Pass 89
in 2008. The Jay Field, South Pass 89 and Offshore Louisiana
properties excess production costs as of December 31, 2008
were approximately $10,930,000, $56,000 and $11,158,000,
respectively. The excess production costs must be recovered by
the Working Interest Owners before any distribution of royalty
revenues will be made to the Trust. The only other royalty
revenue received by the trust in 2008 was $204,741 attributable
to fee lands.
As a result of a review by an independent oil and gas accounting
firm retained by the Trustee to review the Working Interest
Owners calculation of amounts relevant to the
determination of the net proceeds properly payable to the Trust
under the Conveyances, the Trustee and the Working Interest
Owner concluded that the Working Interest Owner had
inadvertently included sulfur extraction processing costs at the
Jay and Little Escambia Creek Field Unit desulfurization plant
in the calculation of Jay Field Gross Proceeds. Because neither
the Trustees oil and gas accounting firm nor the Working
Interest Owner was able to quantify the amount of the sulfur
extraction costs inadvertently included, the Trustee requested
that the Working Interest Owner pay to the Trust royalties on
the revenue generated by the sale of the sulfur in lieu of
refunding the amount charged to the Trusts interest. The
Working Interest Owner agreed to do so, and made a single
payment of $437,000 to the Trust on March 7, 2008 to settle
all issues relating to the inclusion of the sulfur extraction
costs in the calculation of Jay Field Gross Proceeds.
Recent
Developments
On December 23, 2008, Quantum suspended production from Jay
Field due to deteriorating economic conditions. Quantum
currently has no plans for future well workovers to return wells
to production or to drill additional wells.
In December 2006, the Working Interest Owner and the operator of
the Jay Field, ExxonMobil, sold their respective interests in
the field to Quantum Resource Management, LLC (Quantum). Quantum
became the operator in April 2007.
During 2005, Hurricanes Katrina and Rita affected the
operational status of properties included in the Offshore
Louisiana and South Pass 89 groups of properties, and Hurricane
Dennis and Tropical Storm Cindy affected the operational status
of the gas plant at Jay Field. The gas plant at Jay Field
returned to full operating status on April 13, 2006.
However, distributions to the Trust will be reduced
significantly for a period of time as a result of the damage
from these storms to the production facilities for properties in
which the Trust has an interest. As a result of the uncertainty
of future proceeds from these properties, the Trustee as of
December 31, 2008 has reserved $62 that otherwise would
have been distributed to the unitholders for the payment of the
Trusts likely expenses in the foreseeable future.
45
LL&E
ROYALTY TRUST
NOTES TO
FINANCIAL STATEMENTS (Continued)
Following is a description of the damage caused by Hurricanes
Katrina and Rita to production facilities for properties in
which the Trust has an interest. This information is based on
assessments of damage the Working Interest Owner has received
regarding damage from Hurricanes Katrina and Rita to the
Offshore Louisiana and South Pass 89 properties. All of the
information in this Report on
Form 10-K
relating to the operational status of the properties provided to
the Working Interest Owner by the various operators of the
properties in which the Trust has an interest, and was provided
to the Trust by the Working Interest Owner. The Working Interest
Owner is not the operator of any of these properties, and relies
on the various operators for information regarding the
operational status of the various properties. Consequently, all
of the information provided herein is based on preliminary and
sometimes informal information provided by the operators of the
Properties. The information provided herein is based on the
respective operators preliminary assessments of the damage
to the production facilities. The Trustee has been informed that
the assessments are ongoing, and that the assessments of
damages, the predictions of the likelihood of repairs and time
necessary to complete such repairs, the decisions to repair or
abandon facilities, and all other estimates are subject to
change.
South
Pass 89
Repairs due to Hurricane Katrina damage (August 2005) were
completed in the fourth quarter of 2006 and the field was
substantially restored to production in December 2006. The
operator, Marathon Oil Company, had provided a cost estimate of
$6,000,000 ($1,500,000 net to the Trust) to repair the
South Pass 89 B platform, however the operator has
indicated the actual cost to date is estimated at $6,500,000
($1,600,000 net to the Trust).
Offshore
Properties:
East
Cameron 336
The Working Interest Owner had previously elected not to
participate in proposed wellwork and remained responsible only
for field abandonment costs. The lease expired in 2007 and the
operator, Apache, informed the Working Interest Owner that it
had abandoned the wells in the first half of 2008. The platform
has not been abandoned yet and no cost estimates or actual costs
have been received to date.
East
Cameron 195
The East Cameron 195 platform was heavily damaged during
Hurricane Rita; however, it was not a significant producer, had
been shut in by the operator, Maritech, and had been approved
for abandonment prior to Hurricane Rita. The operators
early estimate of the wells-only abandonment for East Cameron
195 was $27,000,000 ($9,100,000 net to the Trust), however
costs to date are estimated at $31,000,000 ($10,300,000 net
to the Trust). These costs are for well abandonment only and do
not include platform abandonment and debris removal costs. Well
abandonment work began in February 2006 and was substantially
finished in December 2006 (7 wells were plugged and
abandoned and 3 wells have remaining plugging work that
will be completed as part of the platform and debris removal
process). Platform abandonment and debris removal work has not
commenced and the Working Interest Owner has not received an
estimated cost for such work from the operator.
South
Marsh Island 76
The South Marsh Island 76 platform was heavily damaged during
Hurricane Rita in 2005. The operator, Mariner, abandoned the
wells in 2008 for a cost of $4,485,953 ($403,736 net to the
Trust). No cost estimates have been received for the final
platform debris removal and site clearance.
46
LL&E
ROYALTY TRUST
NOTES TO
FINANCIAL STATEMENTS (Continued)
Eugene
Island 261
The Eugene Island 261 platform was damaged during Hurricane Rita
but was repaired and returned to production in November 2005.
The estimated repair cost was $220,000 (resulting in costs
attributable to the Trusts interest of $44,000).
Vermillion
331
The Vermillion 331 platform was damaged during Hurricane Rita.
The operator, Energy Resources Technology, repaired the platform
and returned it to production in November 2006. The estimated
repair cost was $1,200,000 (resulting in costs attributable to
the Trusts interest of approximately $150,000).
Other
The Working Interest Owner has advised the Trustee that the
Working Interest Owner has completed its analysis of the scope
and applicability of the insurance policies carried by the
Working Interest Owner to the damages that resulted from
Hurricanes Katrina and Rita to properties in which the Trust has
an interest. The Working Interest Owner has advised the Trustee
that, except as noted below, the Working Interest Owner believes
it has received all of the insurance reimbursements it will
receive for damages to the South Pass 89 and Offshore Louisiana
properties. The total amount of reinvestments that has been
reported to the Trustee is $10,400,000 for Offshore Louisiana
and $928,000 for South Pass 89 (net to the working interest
owners interest). The Trusts interest in these
amounts is 50% with respect to South Pass 89 and 90% with
respect to Offshore Louisiana. The exception noted above relates
to several making well safe claims for certain properties which
have been denied by the Working Interest Owners insurers.
The Working Interest Owner is evaluating the denials.
The Working Interest Owner further informed the Trustee that the
insurance proceeds received will be applied, to the extent
permitted by the Trusts governing documents, to offset
existing Excess Production Costs and to fund the Special Cost
Escrows for Offshore Louisiana and South Pass 89.
The Working Interest Owner has further informed the Trustee that
although the work to secure and repair or replace damaged
equipment and restore production at properties the operators
have determined to repair has now been completed, work
nevertheless remains ongoing to secure, plug, abandon and
dismantle other properties in which the Trust has an interest
and that the operators have determined to abandon. In
particular, the work and expenses to plug, abandon and dismantle
the facilities at South Marsh Island 76 and East Cameron 195 are
expected to extend into 2009 or longer. The Working Interest
Owner has informed the Trustee that these ongoing expenses are
not insured.
The abandonment and repair costs estimated by the Working
Interest Owner have had and are expected to have a material
adverse effect on royalties payable from the South Pass 89 and
Offshore Louisiana properties to the Trust, and from the Trust
to Unit holders. As previously disclosed, the Working Interest
Owner began escrowing funds otherwise distributable to the Trust
from the South Pass 89 property and Offshore Louisiana
properties, beginning with the April 2006 monthly
distribution. Consequently, distributions from the Trust to the
Unit holders have been eliminated for a period of time. The
Trustee does not expect to make any further distribution prior
to a final liquidating distribution after the sale of the
Trusts interests.
The accompanying financial statements have been prepared
assuming that the Trust will continue as a going concern. As
discussed in Note 1, the Trusts net revenues did not
exceed the $5,000,000 Termination Threshold stipulated by the
Trust Agreement for the second consecutive year, thus
requiring the Trust to termination effective December 31,
2007. The accompanying financial statements do not include any
adjustments as a result of the termination of the Trust.
47
LL&E
ROYALTY TRUST
NOTES TO
FINANCIAL STATEMENTS (Continued)
Additionally, the Trust has $62 in cash reserved for Trust
expenses as of December 31, 2008 and had unpaid invoices of
approximately $279,000. Based on current general and
administrative expenditures, in the absence of Royalty Revenues
the Trustee expects that it will be required to borrow money in
accordance with the Trust Agreement to fund future Trust
expenses. However, no assurance can be given that the Trustee
will be able to borrow money on terms the Trustee considers
reasonable or at all. The Trust Agreement permits, but does
not require, The Bank of New York Mellon Trust Company,
N.A. or an affiliate to lend funds to the Trustee. In the event
any loans are made to the Trust, the Trust Agreement will
prohibit the Trustee from making any distributions to unit
holders until those loans are repaid in full.
|
|
(3)
|
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 three 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 percent 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,
2008, the Fee Lands consisted of approximately 22,282 gross
acres.
The Trustee engaged an independent joint venture auditor to
review payments to the Trust for a portion of the Trust
properties as part of the termination of the Trust. The joint
venture auditor reviewed the period from January 2004 through
December 2007. As a result of the review, one of the Working
Interest Owners made a payment of approximately $437,000 in
March 2008 to the Trust to settle certain issues identified.
|
|
(4)
|
Basis of
Presentation
|
Significant
Accounting Policies
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
Trusts interest.
(b) Trust expenses, which include accounting, engineering,
legal and other professional fees, Trustees 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 percent 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
48
LL&E
ROYALTY TRUST
NOTES TO
FINANCIAL STATEMENTS (Continued)
based on the annual reserve study prepared by independent
petroleum engineers as of September 30 of the preceding year.
Amortization calculated in the fourth quarter is based on the
current year reserve study.
(d) The initial carrying value of the Trusts royalty
interests in oil and gas properties represents the
Companys 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. The unamortized balance at
December 31, 2008 is not indicative of the fair market
value of the interests held by the Trust.
This basis for reporting distributable income is considered to
be the most meaningful because distributions to the unitholders
for a month are based on net cash receipts for such month.
However, it will differ from the basis used for financial
statements prepared in accordance with accounting principles
generally accepted in the United States because, under such
accounting principles, royalty income for a month would be based
on net proceeds from sales for such month without regard to when
calculated or received and interest income for a month would be
calculated only through the end of such month, and accounting
principles generally accepted in the United States would require
a liquidation basis of accounting.
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.
|
|
(5)
|
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 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 Companys 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
49
LL&E
ROYALTY TRUST
NOTES TO
FINANCIAL STATEMENTS (Continued)
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.
Long-lived assets are reviewed for impairment whenever events or
changes in circumstances indicated that the carrying amount may
not be recoverable. For assets held and used, impairment may
occur if projected undiscounted cash flows are not adequate to
cover the carrying value of the assets. In such cases,
additional analysis is conducted to determine the amount of loss
to be recognized. The impairment loss is determined by the
difference between the carrying amount of the asset and the fair
value measured by future discounted cash flows. The analysis
requires estimates of the amount and timing of projected cash
flows and, where applicable, judgments associated with, among
other factors, the appropriate discount rate. Such estimates are
critical in determining whether any impairment charge should be
recorded and the amount of such charge if an impairment loss is
deemed to be necessary. In addition, future events impacting
cash flows for existing assets could render a writedown
necessary that previously required no such writedown.
An impairment related to the Jay Field was recorded in 2008 as a
result of the continuous shut-down of this property by its
operator. The remaining carrying value of the Jay Field property
of $1,705,100 was written off. This resulted in a full write
down of the asset, which was included in the amortization of
royalty interest in the Trust Corpus, as this amount does
not affect cash earnings. There was no impairment recorded for
the year ended December 31, 2007.
During 2006, the Trust recorded an impairment related to the
Offshore Louisiana property as a result of damage incurred
during Hurricane Rita. The remaining carrying value of the
Offshore Louisiana properties of $10,975 was written off. This
resulted in a full write down of the assets, which was included
in the amortization of royalty interest in the
Trust Corpus, as this amount does not affect cash earnings.
According to the September 30, 2008 reserve report,
included in the Trusts Annual Report on
Form 10-K
for the year ended December 31, 2008, the total future
dismantlement costs to the Working Interest Owner are estimated
to be $14,200,000 for the Jay Field property, $7,500,000 for the
South Pass 89 property, and $25,500,000 million for the
Offshore Louisiana property. The Trusts interests in these
properties are equivalent to 50 percent of the net proceeds
from Jay Field and South Pass 89 properties and 90 percent
of the net proceeds from the Offshore Louisiana property. The
Trusts interests in these properties are equivalent to 50%
of the net proceeds from Jay Field and South Pass 89 properties
and 90% of the net proceeds from the Offshore Louisiana property.
The Working Interest Owner, under the terms of the
Trust Conveyances, is permitted to escrow funds from the
Productive Properties for estimated future costs such as
dismantlement costs and capital expenditures. Beginning with the
April 2006 distribution, the Working Interest Owner elected to
escrow funds from the South Pass 89 and Offshore Louisiana
properties due to significant increases in estimated
dismantlement costs for the Offshore Louisiana property and
capital expenditures for the South Pass 89 properties due to
damage caused by Hurricanes Katrina and Rita. During 2008, the
Working Interest Owner has withheld $2,409,707, none of which
would have been otherwise distributable to the Trust, and
$9,117,347, none of which would have otherwise been
distributable to the Trust, in escrow from the South Pass and
Offshore properties, respectively. During the year ended,
December 31, 2008, none of the escrowed amounts were
expended for Jay Field or South Pass 89, and $3,595,082 was
expended for the Offshore Louisiana properties, respectively.
50
LL&E
ROYALTY TRUST
NOTES TO
FINANCIAL STATEMENTS (Continued)
The cumulative escrow balances as of December 31, 2008 were
$4,543,402, $6,500,000, and $8,777,345 for the Jay Field, South
Pass 89 and Offshore Louisiana properties, respectively. The
Conveyances prohibit the Working Interest Owner from escrowing
additional funds for estimated future Special Costs with respect
to a particular Productive Property once the amount escrowed
exceeds 125 percent of the aggregate estimated future
Special Costs for that Property. The Conveyances permit the
Working Interest Owner to release funds from any of the Special
Costs escrows at any time if it determines in its sole
discretion that there no longer exists a need for escrowing all
or any portion of such funds. However, the Working Interest
Owner is not required to do so.
The Working Interest Owner has advised the Trustee that it
intends to continue monitoring its estimates of relevant factors
in order to evaluate the necessity of escrowing funds on an
ongoing basis. 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.
The Working Interest Owner informed the Trustee that the Working
Interest Owner has been named as one of many defendants in
certain lawsuits alleging the underpayment of royalties on the
production of natural gas and natural gas liquids through the
use of below-market prices, improper deductions, improper
measurement techniques and transactions with affiliated
companies. Plaintiffs in some of the lawsuits allege that the
underpayment of royalties, among other things, resulted in false
forms being filed by the Working Interest Owner with the
Minerals Management Service, thereby violating the civil False
Claims Act.
If the plaintiffs are successful in the matters described above,
revenues to the Trust could decrease. A judgment or settlement
could entitle the Working Interest Owner to reimbursements for
past periods attributable to properties covered by the
Trusts interest, which could decrease future royalty
payments to the Trust. The Working Interest Owner has informed
the Trustee that at this time, the Working Interest Owner is not
able to reasonably estimate the amount of any potential loss or
settlement allocable to the Trusts interest.
(9) 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, 2008,
2007 and 2006. Reserve quantities imputed to the Trust were
calculated by multiplying estimated proved net reserves (barrels
of liquids and Mcf of gas) of the Working Interest Owner (prior
to taking into consideration the Trusts 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 consideration the Trusts 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 represented by the
Working Interest Owner to be in effect as of September 30,
2008, 2007 and 2006.
Accordingly, the tables below presents the quantities of
estimated proved reserves imputed to the Trusts 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 Trusts interests and the changes in the present value
of estimated future net revenues attributed to the Trusts
interests for the years ended September 30, 2008, 2007 and
2006 (of which estimates were prepared by Miller and Lents).
Imputed proved reserves are stated in thousands of barrels of
liquids and millions of cubic feet of natural gas. The estimated
future net revenues do not necessarily represent actual dollar
amounts to be paid to the Trust by the Working Interest Owner.
In estimating future net revenues, Miller and Lents took into
consideration capital expenditures estimated by the Working
Interest Owner to be necessary to develop proved reserves only.
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
51
LL&E
ROYALTY TRUST
NOTES TO
FINANCIAL STATEMENTS (Continued)
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
The Trusts proportionate share of future gross proceeds
|
|
$
|
39,136
|
|
|
$
|
42,836
|
|
|
$
|
116,277
|
|
Less the Trusts proportionate share of Future
operating costs
|
|
|
(1,817
|
)
|
|
|
(1,691
|
)
|
|
|
(3,844
|
)
|
Future capital costs
|
|
|
(5,348
|
)
|
|
|
(5,385
|
)
|
|
|
(10,103
|
)
|
Excess production costs
|
|
|
(16,396
|
)
|
|
|
(10,637
|
)
|
|
|
(3,155
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future royalty income
|
|
|
15,575
|
|
|
|
25,123
|
|
|
|
99,175
|
|
Discount at 10% per annum
|
|
|
(4,638
|
)
|
|
|
(7,181
|
)
|
|
|
(49,207
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of future royalty income from proved oil
and gas reserves
|
|
$
|
10,937
|
|
|
$
|
17,942
|
|
|
$
|
49,968
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes
in Imputed Proved Reserves and Present Value of Estimated Future
Net Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Present Value
|
|
|
|
Imputed
|
|
|
of Future Net
|
|
|
|
Proved Reserves
|
|
|
Revenues
|
|
|
|
Liquids
|
|
|
Gas
|
|
|
(Thousands
|
|
|
|
(Mbbl)
|
|
|
(MMcf)
|
|
|
of dollars)
|
|
|
Estimated at September 30, 2005
|
|
|
2,978
|
|
|
|
6,263
|
|
|
$
|
114,368
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
(35
|
)
|
|
|
(37
|
)
|
|
$
|
(3,069
|
)
|
Revisions of estimates(1)
|
|
|
(1,389
|
)
|
|
|
(4,316
|
)
|
|
|
(72,768
|
)
|
Extensions, discoveries and other additions
|
|
|
|
|
|
|
|
|
|
|
|
|
Accretion of discount
|
|
|
na
|
|
|
|
na
|
|
|
|
11,437
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated at September 30, 2006
|
|
|
1,554
|
|
|
|
1,910
|
|
|
$
|
49,968
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
(23
|
)
|
|
|
(3
|
)
|
|
$
|
(1,965
|
)
|
Revisions of estimates(1)
|
|
|
(1,237
|
)
|
|
|
(1,588
|
)
|
|
|
(35,058
|
)
|
Extensions, discoveries and other additions
|
|
|
|
|
|
|
|
|
|
|
|
|
Accretion of discount
|
|
|
na
|
|
|
|
na
|
|
|
|
4,997
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated at September 30, 2007
|
|
|
294
|
|
|
|
319
|
|
|
$
|
17,942
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
|
|
|
|
|
|
|
$
|
(679
|
)
|
Revisions of estimates(1)
|
|
|
(160
|
)
|
|
|
(147
|
)
|
|
|
(8,120
|
)
|
Extensions, discoveries and other additions
|
|
|
|
|
|
|
|
|
|
|
|
|
Accretion of discount
|
|
|
na
|
|
|
|
na
|
|
|
|
1,794
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated at September 30, 2008
|
|
|
134
|
|
|
|
172
|
|
|
$
|
10,937
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The computation of the present value of future net revenues
relating to proved reserves at September 30, 2008 was based
on spot market prices in effect as of September 30, 2008,
of $7.12 per MMBtu for natural gas, of $101.87 per barrel for
crude oil and of $60.92 per barrel for natural gas liquids at
the Jay Field property.
|
|
|
(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, capital and
dismantlement costs; (iii) changes in the timing and
|
52
LL&E
ROYALTY TRUST
NOTES TO
FINANCIAL STATEMENTS (Continued)
|
|
|
|
|
amounts of estimated future production; and (iv) changes in
the estimated remaining imputed proved reserves. The Trust noted
that for the year ended September 30, 2008, base prices
were $101.61 per barrel for oil and $11.10 per MMBtu for gas.
For the year ended September 30, 2007, base prices were
$79.73 per barrel for oil, $6.66 per MMBtu for gas, and $69.81
per barrel for natural gas liquids.
|
Recent
SEC Rule-Making Activity
In December 2008, the SEC announced that it had approved
revisions designed to modernize the oil and gas company reserve
reporting requirements. The most significant amendments to the
requirements include the following:
|
|
|
|
|
commodity prices economic producibility of reserves
and discounted cash flows will be based on a
12-month
average commodity price unless contractual arrangements
designate the price to be used;
|
|
|
|
disclosure of unproved reserves probable and
possible reserves may be disclosed separately on a voluntary
basis;
|
|
|
|
proved undeveloped reserve guidelines reserves may
be classified as proved undeveloped if there is a high degree of
confidence that the quantities will be recovered;
|
|
|
|
reserve estimation using new technologies reserves
may be estimated through the use of reliable technology in
addition to flow tests and production history; and
|
|
|
|
non-traditional resources the definition of oil and
gas producing activities will expand and focus on the marketable
product rather than the method of extraction.
|
The rules are effective for fiscal years ending on or after
December 31, 2009, and early adoption is not permitted. The
Trust is currently evaluating the new rules and assessing the
impact they will have its reported oil and gas reserves. The SEC
is coordinating with the FASB to obtain the revisions necessary
to SFAS No. 19,
Financial Accounting and Reporting
by Oil and Gas Producing Companies,
and SFAS
No. 69,
Disclosures about Oil and Gas Producing
Activities
to provide consistency with the new rules.
In the event that consistency is not achieved in time for
companies to comply with the new rules, the SEC will consider
delaying the compliance date.
Selected
Quarterly Financial Data (Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Summarized Quarterly Results
|
|
|
|
Three Months Ended
|
|
|
|
March 31
|
|
|
June 30
|
|
|
September 30
|
|
|
December 31
|
|
|
2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalty revenues
|
|
$
|
475,750
|
|
|
$
|
73,664
|
|
|
$
|
82,854
|
|
|
$
|
46,260
|
|
Cash distributions
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Cash distribution per unit
|
|
$
|
0.0000
|
|
|
$
|
0.0000
|
|
|
$
|
0.0000
|
|
|
$
|
0.0000
|
|
2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalty revenues
|
|
$
|
673,875
|
|
|
$
|
295,085
|
|
|
$
|
163,563
|
|
|
$
|
832,950
|
|
Cash distributions
|
|
$
|
515,732
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
634,749
|
|
Cash distribution per unit
|
|
$
|
0.0272
|
|
|
$
|
0.0000
|
|
|
$
|
0.0000
|
|
|
$
|
0.0334
|
|
53
Report of
Independent Registered Public Accounting Firm
The Bank of New York Mellon Trust Company, N.A., 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 (the
Trust) as of December 31, 2008 and 2007, 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, 2008. 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 the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
As described in Note 4, 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 accounting
principles generally accepted in the United States of America.
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, 2008 and 2007, and the cash earnings and
distributions and changes in trust corpus for each of the years
in the three-year period ended December 31, 2008, in
conformity with the basis of accounting described in Note 4.
The accompanying financial statements have been prepared
assuming that the Trust will continue as a going concern. As
discussed in Note 1 to the financial statements, net
revenues in 2007 and 2006 fell below the Termination Threshold
prescribed by the Trust Agreement, resulting in the
contractual termination of the Trust effective after
December 31, 2007. In 2008, the Trustee began procedures to
liquidate the Trusts assets. Accordingly, there exists
substantial doubt about the Trusts ability to continue as
a going concern. The Trustee expects that it will be required to
borrow money in accordance with the Trust agreement to fund
future Trust expenses. However, no assurance can be given that
the Trustee will be able to borrow money on terms the Trustee
considers reasonable or at all. The financial statements do not
include any adjustments that might result from the outcome of
this uncertainty.
/s/ KPMG
Houston, Texas
August 26, 2009
54
|
|
Item 9.
|
Changes
in and Disagreements with Accountants on Accounting and
Financial Disclosure
|
None.
|
|
Item 9A.
|
Controls
and Procedures
|
Evaluation of Controls and Procedures.
The
Trust maintains disclosure controls and procedures designed to
ensure that information required to be disclosed by the Trust in
reports that it files or submits under the Securities Exchange
Act of 1934, as amended (the Exchange Act), is
recorded, processed, summarized and reported within the time
periods specified in the SECs rules and regulations.
Disclosure controls and procedures include controls and
procedures designed to ensure that information required to be
disclosed by the Trust is accumulated and communicated by the
Working Interest Owners to the Trustee and its employees who
participate in the preparation of the Trusts periodic
reports as appropriate to allow timely decisions regarding
required disclosure.
As of the end of the period covered by this report, the Trustee
carried out an evaluation of the Trusts disclosure
controls and procedures. Mike Ulrich, as Trust Officer of
the Trustee, has concluded that these controls and procedures
were not effective to allow timely decisions regarding required
disclosure. The Trustee is implementing additional controls and
procedures designed to ensure that information required to be
disclosed by the Trust is accumulated and communicated to the
Trustee on a timely basis.
Due to the contractual arrangements pursuant to which the Trust
was created and the terms of the related Conveyances regarding
information furnished by the Working Interest Owners, the
Trustee relies on (i) information provided by the Working
Interest Owners, including all information relating to the
productive properties burdened by the Royalties, such as
operating data, data regarding operating and capital
expenditures, geological data relating to reserves, information
regarding environmental and other conditions relating to the
productive properties, liabilities and potential liabilities
potentially affecting the revenues to the Trusts interest,
the effects of regulatory changes and of the compliance of the
operators of the productive properties with applicable laws,
rules and regulations, the number of producing wells and
acreage, and plans for future operating and capital
expenditures, and (ii) conclusions of independent reserve
engineers regarding reserves. The conclusions of the independent
reserve engineers are based on information received from the
Working Interest Owners.
Changes in Internal Control over Financial
Reporting.
In connection with the evaluation by
the Trustee of changes in internal control over financial
reporting of the Trust that occurred during the Trusts
last fiscal quarter, no change in the Trusts internal
control over financial reporting was identified that has
materially affected, or is reasonably likely to materially
affect, the Trusts internal control over financial
reporting. The Trustee notes for purposes of clarification that
it has no authority over, has not evaluated and makes no
statement concerning, the internal control over financial
reporting of the Working Interest Owners.
Trustees Report on Internal Control over Financial
Reporting.
The Trustee is responsible for
establishing and maintaining adequate internal control over
financial reporting, as such term is defined in
Rule 13a-15(f)
promulgated under the Securities and Exchange Act of 1934, as
amended. The Trustee conducted an evaluation of the
effectiveness of the Trusts internal control over
financial reporting based on the criteria established in
Internal Control-Integrated Framework
issued
by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO). Based on the Trustees evaluation under
the framework in
Internal Control-Integrated
Framework,
the Trustee concluded that the Trusts
internal control over financial reporting was effective as of
December 31, 2008.
The Trustee does not expect that the Trustees disclosure
controls and procedures relating to the Trust or the
Trustees internal control over financial reporting
relating to the Trust will prevent all errors and all fraud. A
registrants internal control over financial reporting is a
process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with
generally accepted accounting principles. A registrants
internal control over financial reporting includes those
policies and procedures that: (i) pertain to the
maintenance of records that, in reasonable detail, accurately
and fairly reflect the transactions and dispositions of the
assets of the registrant; (ii) provide reasonable assurance
that transactions are recorded as necessary to permit
preparation of financial statements in accordance with the
modified basis of accounting discussed above, and that receipts
and expenditures of the registrant are being made only in
55
accordance with authorizations of management of the registrant;
and (iii) provide reasonable assurance regarding prevention
or timely detection of unauthorized acquisition, use, or
disposition of the registrants assets that could have a
material effect on the financial statements.
Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree
of compliance with the policies or procedures may deteriorate.
Further, the design of disclosure controls and procedures and
internal control over financial reporting must reflect the fact
that there are resource constraints, and the benefits of
controls must be considered relative to their costs. Because of
the inherent limitations in all control systems, no evaluation
of controls can provide absolute assurance that all control
issues and instances of fraud, if any, have been detected.
This annual report does not include an attestation report of the
Trusts registered public accounting firm regarding
internal control over financial reporting. The Trustees
report was not subject to attestation by the Trusts
registered public accounting firm pursuant to temporary rules of
the Securities and Exchange Commission that permit the company
to provide only managements report in this annual report.
|
|
Item 9B.
|
Other
Information
|
None.
PART III
|
|
Item 10.
|
Directors,
Executive Officers of the Registrant and Corporate
Governance
|
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.
The Trust also does not have an audit committee or body serving
a similar function, and does not have an audit committee
financial expert. The Trust has not adopted a code of
ethics, as the Trust has no directors, officers, or employees.
The Trust has not adopted a process by which Unit holders may
communicate with board members, as the Trust has no board
members or persons fulfilling a similar function. Unit holders
may contact the Trustee at the following address: 919 Congress
Avenue, Austin, Texas 78701.
|
|
Item 11.
|
Executive
Compensation
|
Not applicable.
|
|
Item 12.
|
Security
Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters
|
(a) Unit Ownership of Certain Beneficial Owners
Based on filings with the Securities and Exchange Commission,
the Trustee is not aware of any person owning beneficially more
than five percent of the Units as of December 31, 2008
except as set forth below:
|
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
Percentage
|
|
Name
|
|
Units Reported
|
|
|
Reported
|
|
|
Robert E. Robotti(1)
|
|
|
1,074,298
|
|
|
|
5.7
|
%
|
Kleinheinz Capital Partners, Inc.(2)
|
|
|
1,658,582
|
|
|
|
8.73
|
%
|
|
|
|
(1)
|
|
Reference is hereby made to the Schedule 13D/A filed by the
reporting person and others on February 9, 2009 for
additional information regarding the reporting persons
beneficial ownership of such Units.
|
56
|
|
|
(2)
|
|
Reference is hereby made to the Schedule 13D filed by the
reporting person and others on October 17, 2008 for
additional information regarding the reporting persons
beneficial ownership of such Units as of the date of such filing.
|
(b) Unit Ownership of Management
The Working Interest Owner owns no Units. The Bank of New York
Mellon Trust Company, N.A. as Trustee of the Trust, owns no
Units. The Bank of New York Mellon, N.A. in its individual
capacity (the Bank) also owns no Units. As of
March 1, 2009, the Trust Department of the Bank held
no Units in fiduciary accounts.
(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.
(d) Securities Authorized for Issuance Under Equity
Compensation Plans
The Trust has no equity compensation plans.
|
|
Item 13.
|
Certain
Relationships and Related Transactions, and Director
Independence
|
The Bank of New York Mellon and the Company and its subsidiaries
have a number of banking and trust relationships.
|
|
Item 14.
|
Principal
Accounting Fees and Services
|
The following table presents fees for professional audit
services rendered by KPMG LLP for the audit of the LL&E
Trust financial statements for 2008 and 2007 and fees billed for
other services rendered by KPMG LLP.
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
Audit fees(1)
|
|
$
|
351,000
|
|
|
$
|
355,000
|
|
Audit related fees
|
|
|
|
|
|
|
|
|
Tax fees(2)
|
|
|
125,000
|
|
|
|
112,000
|
|
All other fees
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total fees
|
|
$
|
476,000
|
|
|
$
|
467,000
|
|
|
|
|
(1)
|
|
Audit fees consist of fees for the audit of the LL&E Trust
financial statements and reimbursement for travel related
expenses.
|
|
(2)
|
|
Tax fees consist of fees related to the LL&E Trusts
tax information for its unit holders.
|
Pre-Approval
Policies
The Trust does not have an audit committee or body performing a
similar function. Approval of services provided by KPMG LLP and
of fees relating to such services is granted by the Trustee.
57
PART IV
|
|
Item 15.
|
Exhibits,
Financial Statement Schedules
|
(a) Financial Statements
The following financial statements of the Trust are included in
Part II, Item 8:
|
|
|
|
|
|
|
Page
|
|
|
|
Number
|
|
|
|
|
|
43
|
|
|
|
|
43
|
|
|
|
|
43
|
|
|
|
|
44
|
|
|
|
|
55
|
|
(b) Exhibits
|
|
|
|
|
|
|
|
4*
|
|
|
|
|
Agreement for LL&E Royalty Trust, dated as of June 1,
1983, between the Company and First City National Bank of
Houston, as Trustee.
|
|
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.
|
|
31
|
|
|
|
|
Certification pursuant to Section 302 of the Sarbanes-Oxley
Act of 2003.
|
|
32
|
|
|
|
|
Certification pursuant to Section 906 of the Sarbanes-Oxley
Act of 2003.
|
|
|
|
*
|
|
Incorporated by reference to Exhibits of like designation to
Registrants Annual Report on
Form 10-K
for the period ended December 31, 1983 (Commission File
No. 1-8518).
|
(c) 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.
58
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.
LL&E ROYALTY TRUST
(Registrant)
|
|
|
|
By:
|
THE BANK OF NEW YORK MELLON TRUST COMPANY,
N.A.,
Trustee
|
Date: August 26, 2009
Mike Ulrich
Vice President
|
|
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.
|
59
Appendix A
Miller and Lents Report
July 31,
2009
The Bank of New York Mellon Trust Company, N. A.
Trustee, LL&E Royalty Trust
919 Congress Avenue, Suite 500
Austin, TX 78701
|
|
|
|
Re:
|
Estimates of Proved Reserves and
|
Future Net Revenues for the LL&E Royalty Trust
As of September 30, 2008
Gentlemen:
We estimated the proved reserves and the future net revenues
attributable to working and royalty interests owned by
ConocoPhillips and Quantum Resource Management (hereinafter
referred to as the Working Interest Owner) in
certain properties associated with the LL&E Royalty Trust
(the Trust) interest.
The estimated net proved imputed reserves and future net
revenues, discounted at 10 percent per year, owned by the
Trust and without consideration of the Trust Termination
Clause, as of September 30, 2008, are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Proved Imputed Reserves and Revenues(1)(2)
|
|
|
|
Crude Oil,
|
|
|
|
|
|
|
|
|
Net Revenues
|
|
|
|
Condensate, and
|
|
|
Natural
|
|
|
Future Net
|
|
|
Discounted at 10%
|
|
|
|
Natural Gas Liquids,
|
|
|
Gas,
|
|
|
Revenues,
|
|
|
Per Year,
|
|
Reserves Category
|
|
MBbls.
|
|
|
MMcf
|
|
|
M$
|
|
|
M$
|
|
|
Proved Developed
|
|
|
72.1
|
|
|
|
120.6
|
|
|
|
8,673.7
|
|
|
|
6,542.6
|
|
Proved Undeveloped
|
|
|
62.3
|
|
|
|
51.6
|
|
|
|
6,901.7
|
|
|
|
4,394.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Proved
|
|
|
134.4
|
|
|
|
172.2
|
|
|
|
15,575.4
|
|
|
|
10,937.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1)
|
|
As of the effective date of this report, the Trust previously
announced it will terminate effective December 31, 2007
since net revenues to the Trust fell below $5,000,000 for two
successive years the Termination Threshold during
2006 and 2007, even though some of the Trust properties have
remaining productive lives.
|
|
2)
|
|
Total proved reserves and revenues may not equal the sum of the
separate categories due to the manner in which the Trust model
handles the recovery of excess production costs. Timing of the
recoupment of these costs out of total proved production may
vary slightly from the timing associated with the separate
proved reserves categories. Future excess production costs will
be recouped out of total proved production regardless of reserve
category.
|
The above figures are based on estimates from the Trust economic
model attached to this report. The Trust owns, indirectly
through a partnership with the Working Interest Owner,
(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 federal waters Offshore Louisiana (the
Working Interest Properties) and (b) royalty
interests (the Royalties) in certain productive oil
and gas properties located on the Working Interest Owners
South Louisiana fee lands (the Fee Lands) acreage.
We estimated the imputed reserves using the formulas and
criteria specified by the Working Interest Owner, as described
in the following paragraphs, and estimated the future
A-1
|
|
The Bank of
New York Mellon Trust Company, N. A.
|
July 31, 2009
|
|
|
Trustee,
LL&E Royalty Trust
|
Page 2
|
net revenues to the Trust in accordance with the definitions
contained in the Securities and Exchange Commission
Regulation S-X,
Rule 4-10(a)
as shown in the Appendix.
Estimated future net revenues and present value of estimated
future net revenues are not intended and should not be
interpreted to represent fair market value for the estimated
reserves.
Gas volumes for each property are stated at the pressure and
temperature bases appropriate for the sales contract or state
regulatory authority; therefore, some of the aggregated totals
may be stated at a mixed pressure base.
The table below shows summary projections of the estimated
undiscounted future net revenues to the Trust and without
consideration of the Trust Termination Clause:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated Future Net Revenues to the Trust(1)(2)
|
|
For Production
|
|
From Proved
|
|
|
From Proved
|
|
|
From Total
|
|
During the 12
|
|
Developed
|
|
|
Undeveloped
|
|
|
Proved
|
|
Months Ended
|
|
Reserves,
|
|
|
Reserves,
|
|
|
Reserves,
|
|
September 30
|
|
M$
|
|
|
M$
|
|
|
M$
|
|
|
2009
|
|
|
1,399.9
|
|
|
|
0.0
|
|
|
|
1,399.9
|
|
2010
|
|
|
934.8
|
|
|
|
0.0
|
|
|
|
934.8
|
|
2011
|
|
|
1,877.0
|
|
|
|
1,267.4
|
|
|
|
3,144.4
|
|
2012
|
|
|
1,846.9
|
|
|
|
1,326.0
|
|
|
|
3,172.9
|
|
2013
|
|
|
1,262.8
|
|
|
|
1,187.8
|
|
|
|
2,450.6
|
|
2014
|
|
|
830.9
|
|
|
|
1,065.8
|
|
|
|
1,896.7
|
|
Remainder
|
|
|
521.4
|
|
|
|
2,054.7
|
|
|
|
2,576.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
8,673.7
|
|
|
|
6,901.7
|
|
|
|
15,575.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1)
|
|
As of the effective date of this report, the Trust previously
announced it will terminate effective December 31, 2007
since net revenues to the Trust fell below $5,000,000 for two
successive years the Termination Threshold during
2006 and 2007, even though some of the Trust properties have
remaining productive lives.
|
|
2)
|
|
Total proved reserves and revenues may not equal the sum of the
separate categories due to the manner in which the Trust model
handles the recovery of excess production costs. Timing of the
recoupment of these costs out of total proved production may
vary slightly from the timing associated with the separate
proved reserves categories. Future excess production costs will
be recouped out of total proved production regardless of
reserves category.
|
The estimated future net revenues to the Trust from proved
reserves of the Working Interest Properties and Fee Lands have
been determined on the basis of when oil or gas attributable to
the Overriding Royalties or the Royalties is estimated to be
produced. However, the distribution of the Net Proceeds to the
Trust will occur approximately 65 days after the end of the
month in which the sales of oil and gas from the productive
properties and the Fee Lands are recorded as revenues by the
Working Interest Owner. Therefore, the estimated future net
revenues to the Trust from proved reserves for a
12-month
period beginning October 1 correspond to estimated distributions
to the Trust during the following quarter. The amounts in the
table above reflect those estimates of the disbursements to the
Trust and without consideration of the Trust Termination
Clause.
A-2
|
|
The Bank of
New York Mellon Trust Company, N. A.
|
July 31, 2009
|
|
|
Trustee,
LL&E Royalty Trust
|
Page 3
|
The following table sets forth the total estimated undiscounted
future net revenues to be disbursed to the Trust from estimated
proved reserves for each of the Working Interest Properties and
the Fee Lands:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Last Year of
|
|
|
|
Estimated Future
|
|
|
Estimated
|
|
|
|
Net Revenues to
|
|
|
Economic
|
|
|
|
The Trust,
|
|
|
Life of
|
|
Property
|
|
M$(1)(2)
|
|
|
Reserves(3)
|
|
|
Jay Field
|
|
|
12,420.4
|
|
|
|
2017
|
|
South Pass 89
|
|
|
2,233.4
|
|
|
|
2012
|
|
Offshore Louisiana
|
|
|
0.0
|
|
|
|
2015
|
|
Fee Lands
|
|
|
921.6
|
|
|
|
2019
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
15,575.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1)
|
|
As of the effective date of this report, the Trust previously
announced it will terminate effective December 31, 2007
since net revenues to the Trust fell below $5,000,000 for two
successive years the Termination Threshold during
2006 and 2007, even though some of the Trust properties have
remaining productive lives.
|
|
2)
|
|
Total proved reserves and revenues may not equal the sum of the
separate categories due to the manner in which the trust model
handles the recovery of excess production costs. Timing of the
recoupment of these costs out of total proved production may
vary slightly from the timing associated with the separate
proved reserves categories. Future excess production costs will
be recouped out of total proved production regardless of
reserves category.
|
|
3)
|
|
Projected economic life without consideration of estimated
future dismantlement costs.
|
For the purposes of computing the future net revenues to the
Trust, the Working Interest Properties have been combined
geographically into three groups of leases designated as the
Jay Field, South Pass 89, and
Offshore Louisiana. The Working Interest Owner has
conveyed Overriding Royalties to the Trust expressed as various
percentages of Net Proceeds from these Working Interest
Properties and has also conveyed to the Trust a 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:
|
|
|
|
|
|
|
Percentage of Net Proceeds
|
|
Working Interest Property
|
|
Attributable to Overriding Royalties
|
|
|
Jay Field
|
|
|
50
|
|
South Pass 89
|
|
|
50
|
|
Offshore Louisiana
|
|
|
90
|
|
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 estimated revenues to be recorded by
the Working Interest Owner 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
Working Interest Owner 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
current estimates of the future dismantlement costs net of
salvage value to the Working Interest Owners working
interest are approximately $7.5 million for South Pass 89,
$14.2 million for Jay Field, and $25.5 million for the
Offshore Louisiana properties. As of September 30, 2008,
the South Pass 89, Jay Field, and the Offshore Louisiana
properties escrow balances were approximately
$6.5 million,
A-3
|
|
The Bank of
New York Mellon Trust Company, N. A.
|
July 31, 2009
|
|
|
Trustee,
LL&E Royalty Trust
|
Page 4
|
$4.5 million, and $8.7 million, respectively, leaving
an additional $1.0 million, $9.7 million, and
$13.2 million, respectively, attributable to the Working
Interest Owners working interest to be escrowed in the
future.
Excess production costs will result to the Working Interest
Owners 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. Pursuant to
the provisions of the Trust documents, the Working Interest
Owner is allowed to recover such costs from future Net Proceeds.
Excess production costs to the Working Interest Owners
working interest to be recovered from future Net Proceeds as of
September 30, 2008, were $56,497 for South Pass 89,
$10,930,216 for Jay Field, and $11,157,539 for the Offshore
Louisiana properties.
The estimated future net revenues have been calculated, pursuant
to the methods prescribed by the Securities and Exchange
Commission, by applying the product prices for oil, gas,
condensate, and natural gas liquids as of September 30,
2008, to the estimated future production of these products over
the economic life of the reserves and assuming continuation of
current economic conditions.
Well plugging and field abandonment costs were supplied by the
Working Interest Owner and used in the calculation of the Net
Proceeds for the properties. However, the full cost impact of
the 2005 hurricane season beyond that which has already been
provided by the Working Interest Owner, is still not fully known
with regard to potential additional costs for the restoration
and abandonment of certain facilities and wells. Thus, if
additional costs due to the 2005 hurricanes are incurred, this
would have a negative impact to the Trust. Future cost
estimates, if any, for the restoration of producing properties
to satisfy environmental standards were not deducted from future
revenues as such estimates are beyond the scope of this
assignment.
The reserve estimates and production rate projections used to
forecast future net revenues and imputed reserves attributable
to the Trust are based on 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 historical performance
trends. Reserves for the remaining properties were estimated by
volumetric calculations or by analogy to similar properties.
As of the effective date of this report, estimated reserves for
Jay Field were forecasted based on an analysis of historical
production volumes and decline rates. Included in the forecast
are additional production volumes estimated from Quantums
remaining three-well workover program, its planned two-well
horizontal re-entry drilling program, and its remaining future
capital expenditures that are planned to improve well
productivity and field facilities. Potential revenues
attributable to the Trust from Jay Field sulfur sales have not
been included in this report.
Net reserves, as used herein, are reserves net to the Working
Interest Owner or imputed to the Trust after taking into account
existing third party interests and landowner royalties. Portions
of the properties are pooled or unitized, and the reserves
estimates herein are based on existing pooling and unitization
arrangements.
The imputed estimated proved reserves attributable to the Trust
were calculated for each of the three groups of Working Interest
Properties and the Fee Lands by multiplying the respective net
proved reserves of the Working Interest Owner by the ratio of
the estimated future net revenues of the Trust to the estimated
future gross revenues of the Working Interest Owner prior to
consideration of the Trust, as follows:
|
|
|
|
|
|
|
|
|
Imputed proved reserves to the Trust (expressed in Bbls. or Mcf)
|
|
=
|
|
Estimated future net revenues to the Trust
Estimated
future gross revenues to the Working Interest Owner(1)
|
|
x
|
|
Estimated net proved reserves of the Working Interest Owner
(Bbls. or Mcf)
|
|
|
|
1)
|
|
Prior to subtraction of all costs (including Jay Field fuel and
severance taxes) and the costs attributable to the Trust.
|
A-4
|
|
The Bank of
New York Mellon Trust Company, N. A.
|
July 31, 2009
|
|
|
Trustee,
LL&E Royalty Trust
|
Page 5
|
As the imputed estimated proved reserves of the Trust are
calculated using estimated future net revenues, future changes
in the product pricing assumptions on which the revenue
estimates are based would result in corresponding changes in the
Trusts imputed estimated proved reserves, which could be
significant.
As of the effective date of this report, the LL&E Royalty
Trust previously announced the Trust will terminate effective
December 31, 2007 since net revenues to the Trust fell
below $5,000,000 for two successive years the Termination
Threshold during 2006 and 2007, even though some of the
Trust properties have remaining productive lives.
Subsequent to the effective date of this report, Quantum
suspended production from Jay Field on December 23, 2008
due to deteriorating economic conditions. At this time, Quantum
is reviewing all capital expenditures necessary to begin
producing Jay Field in the future and currently has no plans for
future well workovers to return wells to production or injection
or to drill additional wells. The actual startup-date will
depend on options currently under consideration and on improving
economic conditions.
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 the interpretation of geological,
geophysical, 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. Minor precision inconsistencies in subtotals or totals
may arise in the report due to the truncation or rounding of
aggregated values.
The extent and character of ownership, reversions, test,
production, and other data that were furnished by the Working
Interest Owner have been accepted as represented. Operating
costs and estimated capital expenditures furnished by the
Working Interest Owner were reviewed for reasonableness. No
field inspections or well tests were conducted by Miller and
Lents, Ltd. 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.
Miller and Lents, Ltd.
is an independent oil
and gas consulting firm. No director, officer, or key employee
of Miller and Lents, Ltd. has any financial ownership in
ConocoPhillips, Quantum Resource Management, the LL&E
Royalty Trust, or any affiliate. Our compensation for the
required investigations and preparation of this report is not
contingent on the results obtained and reported, and we have not
performed other work that would affect our objectivity.
Preparation of this report was supervised by an officer of the
firm who is a professionally qualified and licensed Professional
Engineer in the State of Texas with more than 25 years of
relevant experience in the estimation, assessment, and
evaluation of oil and gas reserves.
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.
Gary W. Priddy
Consulting Engineer,
P.E.
A-5
|
|
The Bank of
New York Mellon Trust Company, N. A.
|
July 31, 2009
|
|
|
Trustee,
LL&E Royalty Trust
|
Page 6
|
Robert J. Oberst
Senior Vice President,
P.E.
RJO/eb
A-6
INDEX TO
EXHIBITS
|
|
|
|
|
|
|
|
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.
|
|
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.
|
|
31
|
|
|
|
|
Certification pursuant to Section 302 of the Sarbanes-Oxley
Act of 2003.
|
|
32
|
|
|
|
|
Certification pursuant to Section 906 of the Sarbanes-Oxley
Act of 2003.
|
|
|
|
*
|
|
Incorporated by reference to Exhibits of like designation to
Registrants Annual Report on
Form 10-K
for the period ended December 31, 1983 (Commission File
No. 1-8518).
|