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SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)


þ	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 (FEE REQUIRED)

For the Fiscal Year ended December 31, 2006


o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED)

Commission File Number: 1-8518

LL&E ROYALTY TRUST

(Exact name of registrant as specified in its charter)


Texas (State or other jurisdiction of incorporation or organization)		76-6007940 (I.R.S. Employer Identification No.)
The Bank of New York Trust Company, N.A., Trustee
Global Corporate Trust
919 Congress Avenue Austin, Texas		78701
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code: 1-800-852-1422

Securities registered pursuant to Section 12(b) of the Act:


	Name of Each Exchange
Title of Each Class	On Which Registered

Units of Beneficial Interest		New York Stock Exchange

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 þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Act. Yes o No þ

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 þ. 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 registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ.

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer” and “large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o. Accelerated filer þ. Non-accelerated filer o.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o. No þ.

As of June 30, 2006, 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 $51,276,521.

As of March 29, 2007, 18,991,304 Units of Beneficial Interest were outstanding in LL&E Royalty Trust.

Documents Incorporated by Reference: None


	Page
	number

State Tax Considerations		38
Severance Taxes		40
Ad Valorem Taxes		40
Available Information		41
ITEM 1A — Risk Factors		41
ITEM 1B — Unresolved Staff Comments		44
ITEM 2 — Properties		44
ITEM 3 — Legal Proceedings		44
ITEM 4 — Submission of Matters to a Vote of Unit Holders		44

PART II
ITEM 5 — Market for Registrant’s Common Equity, Related Unit Holder Matters and Issuer Purchases of Equity Securities		44
ITEM 6 — Selected Financial Data		45
ITEM 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operation		45
ITEM 7A — Quantitative and Qualitative Disclosures about Market Risk		51
ITEM 8 — Financial Statements and Supplementary Data		52
ITEM 9 — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		64
ITEM 9A — Controls and Procedures		64
ITEM 9B — Other Information		64

PART III
ITEM 10 — Directors Executive Officers and Corporate Governance		65
ITEM 11 — Executive Compensation		65
ITEM 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		65
ITEM 13 — Certain Relationships and Related Transactions, and Director Independence		65
ITEM 14 — Principal Accounting Fees and Services		65

PART IV
ITEM 15 — Exhibits, Financial Statement Schedules		66
SIGNATURE		67
Certification Pursuant to Section 302
Certification Pursuant to Section 906

Statements, other than historical facts, contained in this Annual Report on Form 10-K, including statements of estimated oil and gas production and reserves, drilling plans, future cash flows, anticipated capital expenditures and Working Interest 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 it believes that the forward looking statements are based on reasonable assumptions, it cautions that such statements are subject to a wide range of risks and uncertainties incident to the exploration for, development and marketing of oil and gas, and it can give no assurance that the estimates and expectations will be realized. Important factors that could cause actual results to differ materially from the forward looking statements include, but are not limited to, changes in production volumes, worldwide demand, and commodity prices for petroleum natural resources; the timing and extent of the operators’s success in developing and producing oil and gas reserves; risks incident to the drilling and operation of oil and gas wells; future production and development costs; the effect of existing and future laws, governmental regulations and the political and economic climate of the United States; and conditions in the capital markets. Other risk factors are discussed elsewhere in this Form 10-K, including those risk factors described under the heading “Duration and Termination of the Trust.”

PART I


Item 1.	*Business*

INTRODUCTION

LL&E Royalty Trust (the “Trust”) was created under the laws of the State of Texas on June 28, 1983 pursuant to a Trust Agreement (the “Trust Agreement”) between The Louisiana Land and Exploration Company including its successors, as the context requires, (the “Company”) and First City National Bank of Houston. JPMorgan Chase Bank, N.A., was formerly known as The Chase Manhattan Bank and is the successor by mergers to the original name of the Trustee, First City National Bank of Houston. On April 8, 2006, JPMorgan Chase Bank, N.A. and The Bank of New York announced an agreement pursuant to which The Bank of New York would acquire JPMorgan Chase Bank, N.A.’s corporate trust business. The transaction was effective October 2, 2006, at which time The Bank of New York Trust Company, N.A. succeeded JPMorgan Chase Bank, N.A. as Trustee. The Trustee’s 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 includes the successors and assigns of such working interests, including the assignee of the working interest in the Jay Field Productive Property (as defined below), which assignment occurred on December 21, 2006. 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 December 12, 2005, BR announced the execution of a definitive agreement to be acquired by ConocoPhillips. On March 31, 2006, ConocoPhillips 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 (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 Company’s then unleased, undeveloped south Louisiana fee lands (the “Fee Lands”). The Productive Properties and the Fee Lands are collectively referred to herein as the “Properties”. Title to the Overriding Royalties and the Fee Lands Royalties (collectively referred to herein as the “Royalties”) is held by a partnership (the “Partnership”) of which the Trust and the Company are the only partners, holding a 99 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 Trust’s interest in the Overriding Royalties or Fee Lands Royalties held by the Partnership. The instruments of conveyance which transferred the Royalties to the Trust and subsequently to the Partnership are collectively referred to herein as the “Conveyances”. The Trust is passive, with the Trustee having only such powers as are necessary for collection and distribution of the revenues resulting from the Royalties, the payment of Trust liabilities and the conservation and protection of the Trust estate.

Units of Beneficial Interest (the “Units”) in the Trust were distributed by the Company to holders of record of its capital stock on June 22, 1983 on the basis of one Unit for each two shares of capital stock owned on such date. Each of the Units evidences an undivided interest in the Trust, which owns a 99 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”.

The Units are not an interest in or obligation of the Working Interest Owner or of the operators of the Properties. However, the ultimate value of the Royalties will be dependent, in part, upon the ability of the operators of the Properties to operate them successfully. There is no requirement that the operators or the Working Interest Owner expend any specific amounts with respect to the Properties. The Working Interest Owner is free to transfer its interest (burdened by the Royalties) to third parties. In certain limited cases the Working Interest Owner will be permitted to farm out interests in the Productive Properties and to reduce the Overriding Royalties proportionately. The operators do not have any obligation to produce any specific amounts of oil and gas from any of the Properties.

Upon termination or abandonment of any lease the Overriding Royalties relating thereto will be extinguished. The amount of revenues attributable to the Overriding Royalties may be affected by operating agreements, and the amount of revenues attributable to the Royalties may be affected by unitization and pooling arrangements. The value of the Royalties is also subject to all the risks associated with oil and gas operations and to the costs of comprehensive regulation by governmental authorities. See “Industry Conditions and Regulation”.

The Trustee has no responsibility relating to the operation of the Productive Properties or Fee Lands. The information in this Annual Report on Form 10-K relating to the characteristics of and operations on the Productive Properties and Fee Lands, the calculation of the payments made with respect to the Royalties and certain other matters has been furnished to the Trustee by the Working Interest Owner.

TERMS AND OPERATION OF THE TRUST

Creation and Operation of the Trust

Pursuant to the Conveyances, the Overriding Royalties and Fee Lands Royalties were conveyed to the Trust and were then immediately assigned to the Partnership, which was formed to hold the Royalties. See “Terms and Operation of the Trust — The Partnership”. The Royalties are the only asset of the Trust, other than cash being held for the payment of expenses and liabilities and for distribution to the Unit holders. The Trustee of the Trust is The Bank of New York Trust Company, N.A.

The Trustee holds the Royalties pursuant to the terms of the Trust Agreement. The Trust Agreement may be amended by a vote of Unit holders owning a majority of the Units with concurrence of the Trustee, but no provision of the Trust Agreement may be amended (unless consented to by 100% of the Unit holders) in a manner which would (a) permit the Trustee to engage in business or investment activities on behalf of the Trust, (b) alter the rights of the Unit holders among themselves, (c) alter the number of Units, (d) reduce or delay the distribution of the Monthly Income Amounts (defined hereinafter) to Unit holders, (e) adversely affect the characterization of the Trust as an express trust under the Texas Trust Code, (f) authorize the distribution to Unit holders of record of any assets other than cash or other personal property or (g) alter the voting requirements as provided in the Trust Agreement. In no event may the Trust Agreement be amended in a manner that would jeopardize the continued applicability of any Internal Revenue Service ruling letter or any opinion of counsel described in “Tax Considerations to Owners of Units — Federal Income Tax Considerations — Rulings and Tax Opinion Regarding Distribution”.

The Trustee may resign and may be removed by a vote of Unit holders owning a majority of the Units. If the Trustee resigns, a successor trustee will be appointed, which must be a national bank meeting certain requirements, including having capital, surplus and undivided profits of at least $100,000,000.

The Trust has no employees; administrative functions of the Trust are performed by the Trustee. The Conveyances provide that the Working Interest Owner will maintain books and records sufficient to determine the amounts payable under the Royalties.

Terms of the Conveyances

The discussion herein of the Conveyances is intended to be a general summary of certain of the provisions of the Conveyances, forms of which are on file with the Securities and Exchange Commission and are incorporated by reference as exhibits to this Annual Report on Form 10-K. The discussion herein is qualified in its entirety by reference to the relevant provisions of such forms of the Conveyances.

The Conveyances impose on the Working Interest Owner no contractual obligation to drill any wells or to maintain operations or production once established. However, the Conveyances of Overriding Royalty Interests do obligate the Working Interest Owner to conduct and carry on the development, maintenance and operation of the Productive Properties with reasonable and prudent business judgment and in accordance with good oil and gas field practices, or, where the Working Interest Owner is not the operator, to use reasonable efforts to cause the operator to do so. Actual drilling operations depend on whether geological and geophysical evaluations indicate that drilling will be prudent. There is no requirement that the Working Interest Owner expend any specific amounts with respect

to the Properties, and 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.

Uncertainties or controversies may arise from time to time with respect to the correct sales prices that may be charged by the Working Interest Owner for oil and gas produced from the Properties. The Conveyances provide that amounts received by the Working Interest Owner that may be subject to any such uncertainty or controversy and otherwise payable to the Trust may, at the option of the Working Interest Owner under certain circumstances, be deposited in escrow with an escrow agent, which may be The Bank of New York Trust Company, N.A., and will not be payable with respect to the Royalties until the matter is resolved. The Working Interest Owner may place other amounts in escrow under certain circumstances. Amounts owing to the Trust and paid to the Working Interest Owner by the escrow agent upon final resolution of any such matter will be delivered to the Trustee on the next succeeding Monthly Record Date (defined below) and distributed to the record holders of Units as of that Monthly Record Date. The provisions of the Conveyances that provide for escrow accounts permit the Working Interest Owner to elect, under certain circumstances, to calculate and pay amounts attributable to the Royalties, without establishing actual escrow accounts, in amounts equal to the amounts that would have been paid had actual escrow accounts been established.

The Conveyances provide that under certain circumstances the Working Interest Owner may place all or a portion of the revenues which would otherwise accrue to the Royalties in an escrow account rather than treating such revenues as Gross Proceeds. In particular, with respect to any Productive Property, if, at the end of any month, (a) the aggregate estimated future Gross Proceeds (as defined in the Conveyances), as estimated by independent petroleum engineers in their most current report, is less than (b) the sum of (i) estimated future Production Costs (as defined in the Conveyances), as estimated by the Working Interest Owner, excluding certain costs, and (ii) 400% of the aggregate estimated future Special Costs (as defined in the Conveyances), the Working Interest Owner may escrow an amount equal to a certain percentage (the calculation of which is described below) of the revenues which would otherwise constitute Gross Proceeds. The phrase “Gross Proceeds”, as used in the Conveyances, and subject to certain exceptions, means, on an accrual accounting method, the amount recorded as revenues by the Working Interest Owner from the sale of oil, gas and certain other hydrocarbons from a given Productive Property. The phrase “Production Costs”, as used in the Conveyances, includes lease operating expenses, overhead and taxes. The phrase “Special Costs”, as used in the Conveyances, includes, among other things: (a) the aggregate estimated cost of plugging and abandoning wells and dismantling platforms on such Productive Property, and (b) estimated future capital expenditures. The amount the Working Interest Owner may place in escrow with respect to any Productive Property in any month may not exceed Gross Proceeds for that month multiplied by 250 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.

Based on the escrow provision described above, the Working Interest Owner escrowed $64,609 for the South Pass 89 property, none of which would have been distributable to the Trust based on excess production costs. The Working Interest Owner escrowed $2,031,950 during 2006 for the Offshore Louisiana properties, $945,379 of which would have been distributable to the Trust. There were no amounts escrowed for the Jay Field in 2006. The amounts withheld during 2006 were in addition to the balances escrowed as of December 31, 2005 of $4,543,402 for Jay Field, $2,600,000 for South Pass 89 property and $3,000,000 for Offshore Louisiana properties. During 2006, none of the escrowed amounts were expended for the Jay Field, $1,985,767 were expended for South Pass 89 property and $5,031,950 were expended for Offshore Louisiana properties. The remaining escrowed balance at December 31, 2006 was $4,543,402 and $678,842 for Jay Field and South Pass 89 property, respectively. At December 31, 2006, Offshore Louisiana’s escrow balance was completely utilized. As of December 31, 2006, the Working Interest Owner’s estimates of total Special Costs are $14,200,000 for Jay Field, $5,500,000 for South Pass 89 and $6,900,000 for Offshore Louisiana. See “Status of the Trust” in Item 7 on this Form 10-K. As described above, 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 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.

The Working Interest Owner has advised the Trustee that based on current estimates included in this Annual Report on Form 10-K, the Working Interest Owner is permitted to place additional funds in escrow from each of the properties, and that, 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 Owner has advised the Trustee that it anticipates escrowing additional funds from the Offshore Louisiana and South Pass 89 properties for the foreseeable future.

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. Management’s 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 the Working Interest Owner will use its best efforts to make payments to the Partnership, the Partnership will make payments to the Trust, and the Trust and Partnership will use reasonable efforts to pay expenses, only on the Monthly Record Date (defined as the close of business on the fifth day of the month unless such fifth day is not a business day, in which case it will be the next business day following the fifth day) for each Monthly Period (defined as the period which commences on the day following a Monthly Record Date and continuing through and including the succeeding Monthly Record Date). For taxable years beginning on or after January 1, 1987, the Partnership has been required to use the accrual method of accounting, and thus the portion of the Trust’s income attributable to the Partnership and reported to the Unit holders is likewise on the accrual basis. Consequently, the Unit holder required to recognize income and expense for a Monthly Period may not be the Unit holder entitled to the Monthly Income Amount. See “Tax Considerations to Owners of Units — Federal Income Tax Considerations — Tax Consequences of Owning Units — Accounting for Income and Deductions”.

Liabilities and Contingency Reserves

Because of the passive nature of the Trust assets and the restrictions on the power of the Trustee to incur obligations, the only liabilities that the Trust typically incurs are for routine administrative expenses, such as Trustee’s fees and accounting, engineering, legal and other professional fees. The costs and expenses of the Trust may increase or decrease in future years, depending on the volume of trading of the Units, the amount of revenues paid to the Trust and increases or decreases in accounting, engineering, legal and other professional fees and other factors. Substantial federal income tax liabilities would result if the Internal Revenue Service were to revoke or change its position on its ruling that neither the Trust nor the Partnership is taxable as a corporation and such

revocation or change were not judicially reversed. See “Tax Considerations to Owners of Units — Federal Income Tax Considerations — Rulings and Tax Opinion Regarding Distribution”.

The Trust Agreement and the Partnership Agreement provide that the Trustee or the Partnership may establish cash contingency reserves in the event that (a) either (i) a claim is asserted against or is likely to be asserted against the Trust or the Partnership, whichever is the case, and the Trustee has received an opinion of counsel stating that the claim has a reasonable probability of succeeding or (ii) a claim against the Trust or the Partnership, whichever is the case, has been successful but is not currently due and payable, and (b) the amount or probable amount of such claim is such that it cannot be satisfied out of monthly income from the Royalties. Such reserves will be deposited in noninterest-bearing accounts, except that such contingency reserves will be placed in certificates of deposit or United States government securities maturing on the next Monthly Record Date if the Trustee or the Partnership, whichever is the case, has received an opinion of counsel to the effect that such action will not jeopardize the tax treatment of the Trust or Partnership as a trust or partnership, respectively, and not as an association taxable as a corporation. Assuming that the Trust is classified for tax purposes as a grantor trust and the Partnership is classified for tax purposes as a partnership (see “Tax Considerations to Owners of Units — Federal Income Tax Considerations — Tax Consequences of Owning Units”), if such reserves are established, the amounts placed in reserve will be taxable to the Unit holders when received by the Partnership, even though they are not distributed to Unit holders at that time. If cash contingency reserves are established and placed in interest-bearing accounts as described above, the Trustee will furnish reports annually to all Unit holders of record on the applicable Monthly Record Dates containing information sufficient to enable Unit holders to calculate their share of taxable income (on either a cash or accrual basis) attributable to any interest earned on the reserves.

If at any time the cash available to the Trust or the Partnership is not sufficient to pay liabilities that have become due, the Trustee or the Partnership, respectively, may borrow funds on a secured or an unsecured basis to pay such liabilities. Except for borrowings to purchase Units as described under “The Units — Possible Requirement That Units Be Divested”, neither the Trustee nor the Partnership may borrow an amount that at the time of borrowing exceeds 50% of the estimated revenues of the Trust or the Partnership, respectively, during the immediately following six Monthly Periods. Generally, such borrowing must be repaid before any further Trust or Partnership distributions, whichever is the case, can be made.

The Trust Agreement requires the Trustee to receive all income and proceeds of the Royalties and to pay all expenses, charges, liabilities and obligations of the Trust. See “The Units — Distributions and Income Computations”. The Trustee submits reports to the Unit holders as described under “The Units — Periodic Reports”. The Trust Agreement gives the Trustee only such rights and powers as are necessary and proper for the conservation and protection of the Royalties and prohibits the Trustee from entering into or engaging in any business or investment activity on behalf of the Trust.

Except as described under “The Units — Liability of Unit Holders”, the Trustee will be indemnified out of the Trust assets for any liability, expense, claim, damage or other loss incurred in performing its duties, unless resulting from its negligence, bad faith or fraud. In no event will the Trustee be deemed to have acted negligently, fraudulently or in bad faith if it takes action or suffers action to be taken in good faith in reliance upon and in accordance with the advice of parties (including its own employees) considered to be qualified as experts on the matters submitted to them. Neither the Trust, the Trustee, the Partnership nor the Working Interest Owner will be entitled to indemnification from the Unit holders. To the extent not inconsistent with the Trust Agreement, the Trustee has been relieved from certain liabilities otherwise imposed by the Texas Trust Act, as amended by the Texas Trust Code (the “Texas Trust Code”).

Duration and Termination of the Trust

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 Owner or the Partnership under escrow arrangements or to make refund payments pursuant to the Conveyance (the Trust’s 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 year ended December 31, 2006, calculated as described above, were $2,094,226, thus triggering year one of the Trust’s termination provision. Should the Trust’s net revenues for the year ended December 31, 2007 also fall below the $5,000,000 termination threshold, the Trust would be required to terminate effective December 31, 2007.

The most recent Trust model prepared by Miller and Lents, Ltd., which is based on natural gas and oil prices as of September 30, 2006, projects net revenues to the Trust will be greater than $5,000,000 for the year ended December 31, 2007. However, the damage to the facilities described below, changes in prices, changes in the operator of the Jay Field, and other factors could cause the termination of the Trust. Therefore, the Trustee anticipates that the Trust may terminate on December 31, 2007.

For the first quarter of 2007, the Trust received approximately $600,000 in royalty revenue associated with the Jay Field and no royalty revenue was received from the Offshore Louisiana or South Pass 89 properties. The South Pass 89 and Offshore Louisiana properties excess production costs as of March 31, 2007 totaled $822,000 and $4,612,000, respectively. The excess production costs must be recovered by the Working Interest Owner before any distribution of royalty income will be made to the Trust.

In December 2006, the Working Interest Owner and Exxon Mobil, as the operator of the Jay Field, sold their respective interests in the field to Quantum Resource Management (Quantum). Quantum is expected to become the operator in April 2007 and has informed the Trustee that it plans to undertake a different operating and development strategy for Jay Field than the previous operator. Quantum has informed the Trustee that it plans to reduce costs by terminating the purchase and injection of nitrogen gas, conversion of the nitrogen injection lines to water injection, installation of gas lift on production wells, and the reactivation of the available water supply wells with new electrical submersible pumps to increase the current water injection levels in order to compensate for the cessation of nitrogen injection. While Quantum has informed the Trustee that this program has the potential to reduce costs and increase production, as the timing of Quantum’s succession takes place half-way through the Trust’s production year, it is uncertain whether any potential benefits will be sufficient to affect the Trust’s net revenues or to affect the potential termination of the Trust on December 31, 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, future distributions to the Trust will be reduced significantly for a period of time as a result of other 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, 2006 has reserved $848,086 that otherwise would have been distributed to the unitholders for the payment of the Trust’s 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 was 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 an early 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). The original cost estimate to repair the South Pass 86 “C” platform provided by the operator was $5,500,000 ($600,000 net to the Trust), however the operator has indicated the actual cost to date is estimated at $5,800,000 ($600,000 net to the Trust).

Offshore Properties:

East Cameron 336

The Working Interest Owner had previously elected to not participate in proposed wellwork and remained only responsible for field abandonment costs. The operator, Apache, informed the Working Interest Owner that it has ceased operations and allowed the lease to expire in January, 2007. Abandonment operations for the wells and platform may commence in 2007; no cost estimates have been received.

East Cameron 195

The East Cameron 195 platform was heavily damaged during Hurricane Rita; however, it was not a significant producer, and had been shut in by the operator, Maritech, and had been approved for abandonment prior to Hurricane Rita. The operator’s 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, for which no cost estimates have been received. Well abandonment work began in February, 2006 and was substantially finished in December, 2006.

South Marsh Island 76

The South Marsh Island 76 platform was heavily damaged during Hurricane Rita. The operator, Mariner Corporation, has provided an estimate of $3,600,000 ($900,000 net to the Trust) for diving costs, inspection and removal of the toppled platform deck from the seafloor, and to abandon a floor line. These costs do not include well or facility abandonment costs, for which no cost estimates have been received. Only inspection and diving work has been done to date. The Working Interest Owner has cautioned the Trust that the operator may determine to plug and abandon the property rather than repair the platform and facilities.

Eugene Island 261

The Eugene Island 261 platform was damaged during Hurricane Rita and was repaired and returned to full production in November, 2005. The estimated repair cost was $220,000 (resulting in costs attributable to the Trust’s 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 Trust’s interest of approximately $150,000).

Jay Field

The Jay Field gas plant was damaged by Hurricane Dennis and Tropical Storm Cindy. The damage was repaired by the first week of October 2005. The operator at the time, ExxonMobil, informed the Working Interest Owner that the previously disclosed non-storm problem affecting a trunk line and approximately 25 percent of production from Jay Field was repaired on April 13, 2006.

The Working Interest Owner has advised the Trustee that it is in the process of analyzing the scope and applicability of the insurance policies carried by the Working Interest Owner to the various types of damages that resulted from the storms, and is in the process of discussing these matters with the carrier’s claim adjusters. These discussions are continuing and the Working Interest Owner is continuing to gather documentation to support the claims for the repairs that have been made to the damaged properties, which is difficult as it relates to non-operated properties. Whether the Working Interest Owner will be successful, or to what extent it will be successful, in its attempt to obtain reimbursement for monies spent repairing hurricane damages, is uncertain. Additionally, should the Working Interest Owner be successful in its efforts, the timing of the reimbursement is also uncertain. See “Management’s Discussion and Analysis of Financial Condition and Results of Operation” for additional information regarding the status of discussions regarding potential insurance coverage.

The abandonment and repair costs estimated as described above are expected to have a material adverse effect on royalties payable from the Offshore Louisiana and South Pass 89 properties to the Trust, and from the Trust to Unit holders, for an extended period of time. As previously disclosed, the Working interest Owner began escrowing funds otherwise distributable to the Trust from the Offshore Louisiana properties and South Pass 89 property, beginning with the April 2006 monthly distribution. Consequently, distributions from the Trust to the Unit holders are expected to be reduced significantly or eliminated for an extended period of time.

Whether the Trust’s net revenues for the year ending December 31, 2007 are above the Termination Threshold will depend on the timing of repairs to damaged properties in which the Trust has an interest, oil and natural gas prices for 2007, timing and level of hydrocarbon production, which could vary significantly from the projected production in the reserve report due to the change in the operator of the Jay Field, the level of capital expenditures, and other operational matters as well as administrative expenses of the Trust. Therefore, there can be no assurance that the net revenues of the Trust for the year ended December 31, 2007 may be above the Termination Threshold. For the first quarter of 2007, the Trust received approximately $600,000 in royalty revenue associated with the Jay Field and no royalty revenue was received from the Offshore Louisiana or South Pass 89 properties. Due to the uncertainty from the 2005 storms and the lack of significant royalty revenue received subsequent to December 31, 2006, there is substantial doubt regarding the Trust’s ability to continue as a going concern.

Other Matters Relating to the Termination of the Trust

In addition to the Trust terminating as a result of net revenues to the Trust of less than $5,000,000 for two successive years, the Trust may also be terminated at any time by a vote of Unit holders owning a majority of the Units and the Trust may also be terminated at the expiration of twenty-one (21) years after the death of the last to die of all of the issue living at the date of execution of this Trust Agreement of John D. Rockefeller, Jr., late father of the late former Vice President of the United States, Nelson A. Rockefeller.

Upon the termination of the Trust, the Trustee will sell the assets of the Trust for cash (unless authorized by the holders of a majority of the Units to sell such assets for non-cash consideration 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 provisions for all then existing liabilities of the Trust, including fees of the Trustee, the Trustee will distribute all cash then held by it as promptly as practicable in its capacity as Trustee and, if necessary, will set up reserves in the amounts the Trustee deems appropriate to provide for payment of contingent liabilities. After the termination of the Trust, the Trustee will continue to act as Trustee for purposes of liquidating and winding up the affairs of the Trust.

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. Except in connection with any proposed non-cash sale as described above, no approval of the Unit holders will be required or solicited in connection with the sale of the Trust’s assets after termination of the Trust.

See Item 7 — Management’s 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.

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”. 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 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, 2006, the Working Interest Owner’s estimates of total Special Costs are $14,200,00 for Jay Field, $5,500,000 for South Pass 89 and $6,900,000 for Offshore Louisiana. See “Status of the Trust” in Item 7 on this Form 10-K. As of December 31, 2006, the Working Interest Owner escrowed $64,609 for the South Pass 89 property, none of which would have been distributable to the Trust based on excess production costs. The Working Interest Owner escrowed $2,031,950 during 2006 for the Offshore Louisiana properties, $945,379 of which would have been distributable to the Trust. There were no amounts escrowed for the Jay Field in 2006. The amounts withheld during 2006 were in addition to the balances escrowed as of December 31, 2005 of $4,543,402 for Jay Field, $2,600,000 for South Pass 89 and $3,000,000 for the Offshore Louisiana properties. During 2006 none of the escrowed amounts were expended for the Jay Field, $1,985,767 were expended for South Pass 89 and $5,031,950 were expended for the Offshore Louisiana properties. The remaining escrowed balance at December 31, 2006, was $4,543,402 and $678, 842 for Jay Field and South Pass 89, respectively. At December 31, 2006, Offshore Louisiana’s escrow balance was completely utilized. 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 informed the Trustee that it does not intend to release any of the excess escrowed funds at this time. The Working Interest Owner has advised the Trustee that based on current estimates included in this Annual Report on Form 10-K, the Working Interest Owner is permitted to place additional funds in escrow from each of the properties, and that the Working Interest Owner will continue escrowing all amounts otherwise distributable to the Trust from the Offshore Louisiana and South Pass 89 properties for the foreseeable future.

If operating and other costs exceed net revenues from a Productive Property for any month, the excess will be recovered by the Working Interest Owner out of future production from such Productive Property prior to making further payments attributable to the Royalties with respect to such Productive Property, but neither the Trust, the Trustee, the Partnership, nor any Unit holder will be liable for any such costs or liabilities, nor will they be obligated

to return any income from the Royalties received during any prior period. However, any such excess costs or overpayment of Royalties will reduce future payments of Royalties.

Although crude oil production from Jay Field has a low sulphur content, gas production from the field has a high content of sulphur which is removed prior to processing and marketing such production. Although sulphur removed as a by-product is sold by the Working Interest Owner , the removal of the sulphur is essential to the marketing of the gas produced. For the purpose of computing Net Proceeds, all proceeds to the Working Interest Owner from the sale of sulphur extracted from Jay Field production and all direct costs and an allocated portion of other costs associated with such extraction are excluded from the calculations. The Trustee has held discussions with the Working Interest Owner about whether sulphur sales should be included in Gross Proceeds for the purpose of calculating the Trust’s Overriding Royalty Interest relating to Jay Field. The Working Interest Owner has informed the Trustee that it does not believe that sulphur sales should be included. The Trustee has engaged an independent consultant to review the matter, and the consultant is of the opinion sulphur sales (as well as propane sales) are properly included. However, this opinion is not determinative. The independent consultant has informed the Trustee that the total amount potentially involved appears to be approximately $125,000 per year during the time period reviewed by the consultant. As indicated above however, the Working Interest Owner believes that Gross Proceeds have been calculated properly and does not believe that sulphur sales should be included. The Trustee intends to continue its analysis of these matters and intends to discuss them further with the Working Interest Owner.

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 is (and has been since the inception of the Trust) 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 Owner’s working interests, if the Working Interest Owner’s right to revenues is adjusted, extinguished or suspended, the Trust’s right to revenues will also be adjusted, extinguished or suspended.

The Conveyances provide that the Working Interest Owner has the right to approve unitization and pooling arrangements without the consent of the owners of Units or the Trustee. Pooling and unitization refer to the joining together of separate leases, or portions thereof, in a single unit, with the owners of the interests in each separate lease sharing, depending on their interests, in the production and costs attributable to the operations of the entire unit.

Since Overriding Royalty revenues are based upon Net Proceeds, determined after deducting various costs, the amount of such revenues is directly affected by numerous factors, including governmental regulation, prices received for production, increases in operating and capital costs and certain taxes and curtailment of purchases by the purchasers of production from the Productive Properties. In addition, since capital expenditures are deducted for purposes of computing Net Proceeds, there may be substantial periods during which there will be no Net Proceeds from a Productive Property because of such capital expenditures, and therefore no Overriding Royalty revenues from such Productive Property during such period. The amount of the revenues attributable to the Overriding Royalties may also decrease materially from time to time as a consequence of the occurrence of events that are risks incident to the exploration for and production of oil and gas, including blowouts, cratering, fires, drilling and production difficulties, environmental pollution problems, and, with respect to Offshore Louisiana and South Pass 89, risks incident to the offshore exploration for and production of oil and gas, including those related to adverse weather and seas. Although any losses or liabilities resulting from any such events would not require the Trust or Unit holders to repay funds previously received, they would reduce any amounts payable thereafter with respect to the Overriding Royalties.

Fee Lands Royalties

The Fee Lands Royalties consist of royalty interests equal to a 3 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 22,420 gross

acres in south Louisiana, only approximately 1,015 of which were leased at December 31, 2006. See “The Properties — Description of the Fee Lands” and “Exploration and Development Activities — Fee Lands”.

Analysis of the Working Interest Owner’s Calculation of the Royalties

The following schedules summarize the Working Interest Owner’s calculation of the amounts paid to the Trust with respect to the Trust’s royalty interests for (i) the quarter ended December 31, 2006 (applicable to production from July 2006 through September 2006) and (ii) the year ended December 31, 2006 (applicable to production from October 2005 through September 2006):

Quarter ended December 31, 2006


				South			Offshore
	Jay Field			Pass 89			Louisiana			Total

Revenues:
Liquids	$	7,503,032		$	64,609		$	105,138		$	7,672,779
Natural gas		(903	)		—			378,714			377,811

	$	7,502,129		$	64,609		$	483,852		$	8,050,590
Amounts withheld in escrow		—			(64,609	)		(483,852	)		(548,461	)
Production costs and expenses(1)		(3,938,483	)		(174,883	)		(2,426,733	)		(6,540,099	)
Capital expenditures		(402,299	)		(—	)		(1,738	)		(404,037	)

Net Proceeds	$	3,161,347		$	(174,883	)	$	(2,428,471	)	$	557,993

Overriding Royalties paid to the Trust(2)	$	1,580,674		$	—		$	—		$	1,580,674

Fee Lands Royalties											69,556

Royalties paid to the Trust										$	1,650,230

Year ended December 31, 2006


				South			Offshore
	Jay Field			Pass 89			Louisiana			Total

Revenues:
Liquids	$	27,241,731		$	64,609		$	511,342		$	27,817,682
Natural gas		37,313			—			2,344,494			2,381,807

	$	27,279,044		$	64,609		$	2,855,836		$	30,199,489
Amounts withheld in escrow		—			(64,609	)		(2,031,950	)		(2,096,559	)
Production costs and expenses(1)		(15,735,462	)		(516,976	)		(2,824,095	)		(19,076,533	)
Capital expenditures		(5,024,167	)		(—	)		(18,296	)		(5,042,463	)

Net Proceeds	$	6,519,415		$	(516,976	)	$	(2,018,505	)	$	3,983,934

Overriding Royalties paid to the Trust(2)	$	2,198,850		$	—		$	528,064		$	2,726,914

Fee Lands Royalties											341,724

Royalties paid to the Trust										$	3,068,638


(1)		Interest earned on funds escrowed for future dismantlement costs are reported as a reduction of production costs and expenses. Interest earned for the quarter and year ended December 31, 2006 was approximately $119,791 and $590,632, 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 percent 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 are also shown as a reduction of production costs and expenses. For the year ended December 31, 2006, South Pass 89 property processing fees earned totaled $67,174 and interest on escrow totaled $127,896, while the operating expenses totaled $712,047, netting a production cost of $516,976.

(2)		The 2006 royalty income for the Jay Field and South Pass 89 properties have been reduced by $2,121,713 and $32,905 respectively, as a result of excess production costs arising in 2005. The South Pass 89 and Offshore Louisiana properties have excess production costs of $549,881 and $2,605,242, respectively, as of December 31, 2006.

THE UNITS

Distributions and Income Computations

Distributions of available revenues to Unit holders are made monthly. Each payment is made with respect to the preceding Monthly Period of the Trust. The Trustee determines for each Monthly Period the Monthly Income Amount available for distribution for such Monthly Period. The Monthly Income Amount for each Monthly Period is payable to Unit holders of record on the Monthly Record Date on which such Monthly Period ends and is distributed by the Trustee as soon as practicable but not later than ten days following such Monthly Record Date (the “Monthly Payment Date”). Under the terms of the Trust Agreement, the Trustee is prohibited from investing funds received on each Monthly Record Date pending disbursement to holders of Units. As a consequence, the Trustee may hold substantial balances between the Monthly Record Date and the Monthly Payment Date in each month, and The Bank of New York Trust Company, N.A. has the use of these balances during such periods.

Promptly after receipt of the required information, and if practicable within 90 days of the close of each year, the net taxable income of the Trust for federal income tax purposes for each Monthly Period ending in such year will be reported by the Trustee to the Unit holders of record to whom the Monthly Income Amounts were distributed. The Trustee mailed such reports to Unit holders in March 2007. If, as anticipated, the Unit holders are owners of interests in a grantor trust and the Partnership is a partnership for federal income tax purposes, Unit holders will recognize income for federal income tax purposes in the Monthly Period when income is recognized by the Partnership. Because the Partnership has converted to the accrual method of accounting as mandated by the Tax Reform Act of 1986 (the “1986 Act”), Unit holders are required to recognize income in certain circumstances prior to receiving cash distributions. See “Tax Considerations to Owners of Units — Federal Income Tax Considerations — Accounting for Income and Deductions”.

Transfer of Units

Units are transferable on the records of The Bank of New York 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 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 certificates.

Periodic Reports

Promptly after receipt of the required information from the Working Interest Owner, and if practicable within 60 days following the end of each of the first three fiscal quarters of each year, the Trustee mails to each Unit holder of record who was such on the last Monthly Record Date in such quarter a report indicating, among other things, the distributions and revenues attributable to the Trust for such quarter. Promptly after receipt of the required information, and if practicable within 90 days after the end of the Trust’s fiscal year (which is the calendar year),

the Trustee mails to each Unit holder who received a Monthly Income Amount for any Monthly Period ending in such year a report that shows in reasonable detail the receipts and disbursements, and, for state and federal tax purposes, the income and expenses of the Trust, as well as sufficient information to permit a calculation of any depletion deduction for each Monthly Period (or portion thereof, if any) during the year. Promptly after receipt of the required information, and if practical within 120 days following the end of each year, the Trustee mails to all Unit holders of record an annual report containing audited financial statements of the Trust and a summary oil and gas reserve report with respect to the Trust’s interests in the Properties. The Trustee mails to Unit holders such other reports and files such returns for federal and state income tax purposes as are required to comply with applicable laws, to comply with the rules of the New York Stock Exchange and to permit each Unit holder to calculate his share of the income and deductions of the Trust. See “Tax Considerations to Owners of Units — Federal Income Tax Considerations — Tax Consequences of Owning Units — Reports”. However, under the Trust Agreement no duty is imposed on the Trustee to secure, file or disseminate information to which it is not expressly afforded access under the terms of the Trust Agreement or the Conveyances or which it is unable to obtain with reasonable effort and expense.

Under the Trust Agreement, the Trustee has the sole responsibility for filing all periodic reports and other materials required by law, including the Securities Exchange Act of 1934 and the rules and regulations thereunder, and by any securities exchange on which the Units are listed. The cost of preparing and filing such materials is borne by the Trust.

Possible Requirement That Units Be Divested

The Trust Agreement imposes no restrictions based on nationality or other status of the persons or other entities which are eligible to hold Units. However, the Trust Agreement provides that (a) if at any time the Trust or the Trustee is named a party in any judicial or administrative proceeding that seeks the cancellation or forfeiture of any property constituting part of the Trust corpus because of the nationality, or any other status under the laws of the United States or any political subdivision thereof, of any one or more holders of Units, or (b) if at any time the Trustee in its reasonable discretion determines that such a proceeding is threatened or likely to be asserted and the Trustee has received an opinion of counsel stating that the party asserting or likely to assert the claim has a reasonable probability of succeeding, the following procedures will be applicable:

(i) The Trustee may give written notice (“Notice”) to each record owner of Units regarding the existence of such controversy. The Notice will contain a reasonable summary of such controversy, will include materials that will permit an owner of Units promptly to confirm or deny to the Trustee that such owner is a person whose nationality or other status is or would be an issue in such a proceeding (“Ineligible Holder”) and will constitute a demand to each Ineligible Holder that he dispose of his Units to a party not of a nationality or other status at issue in the proceeding described in the Notice within 30 days after the date of the Notice.

(ii) If any Ineligible Holder fails to dispose of his Units, as required by the Notice, within 30 days after the date of the Notice, the Trustee will have the right to purchase and will purchase, during the 90 days following the termination of the 30-day period specified in the Notice, any Unit not so transferred at a cash price equal to the closing price of the Units on the largest stock exchange on which the Units are then listed or, in the absence of any such listing, in the over-the-counter market, on the last business day prior to the expiration of the 30-day period stated in the Notice. The procedures for any such purchase are more fully described in the Trust Agreement.

(iii) The Trustee shall cancel any Units acquired in accordance with the foregoing procedures, thereby increasing the proportionate interest in the Trust of other holders of Units.

(iv) The Trustee may, in its sole discretion, borrow any amounts required to purchase Units in accordance with the procedures described above. Such borrowings would be repaid from revenues to the Trust before any subsequent distribution to Unit holders would be made.

Liability of Unit Holders

The Trust is intended to be an “express trust” created under the Texas Trust Code. Under Texas law, beneficiaries of an express trust are not personally liable for the obligations of the Trust, even if the assets of the Trust are insufficient to discharge its obligations. If the Trust were held not to constitute an express trust, it is possible that the holders of Units would be jointly and severally liable for the obligations of the Trust as would general partners of a partnership. The Trustee may incur liabilities that cannot be contractually limited, such as tort liability or federal income tax liability, in the event the Trust is treated as an association taxable as a corporation. Under current judicial decisions the Federal Energy Regulatory Commission (the “FERC”) is 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 Trustee’s actions do not constitute negligence, bad faith or fraud, or are based on good faith reliance upon an expert. In weighing the possible exposure to liability in the event the Trust were not classified as an “express trust”, each Unit holder should consider (a) the passive nature of the Trust assets, (b) the restrictions on the power of the Trustee to incur liabilities on behalf of the Trust and (c) the limited activities to be conducted by the Trustee.

Voting by Unit Holders

Each Unit is entitled to one vote on any matter submitted to Unit holders. Meetings of Unit holders may be called at any time by the Trustee and must be called by the Trustee at the written request of Unit holders owning at least 10 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. To date, no matter has been submitted to a vote of the Unit holders.

Certain State Law Considerations

It is anticipated that the Units will be treated for certain state law purposes essentially the same as other securities, that is, as interests in intangible personal property rather than as interests in real property. However, there is a possibility that a Unit holder could be treated as owning an interest in real property. In that event, the tax, probate, devolution of title and administration laws of Louisiana, Florida and Alabama applicable to real property may apply to the Units, even if held by a person who is not a resident or domiciliary thereof. Application of such laws would make inheritance and related matters with respect to the Units substantially more onerous than they would be if the Units are treated as interests in intangible personal property. In any event the ownership of Units and realization of income from the Royalties by a Unit holder may subject such Unit holder to state or local income or other taxation in the state of the Unit holder’s residence or domicile. Unit holders should consult their legal and tax advisors regarding the applicability of these considerations to their individual circumstances. See “Tax Consideration to Owners of Units — State Tax Considerations”.

THE PROPERTIES

General

The Trustee has no responsibility relating to the operation of the Productive Properties or Fee Lands. The information in this Annual Report on Form 10-K relating to the characteristics of, operations on, and sales from the Productive Properties and Fee Lands and certain other matters has been furnished to the Trustee by the Working Interest Owner.

The 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 Trust’s 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 Owner’s percentage of the working interest in wells or leases cannot be used to calculate precisely the Trust’s interest in any particular well or lease. In addition, (a) because operating and capital costs are taken into consideration in calculating the amounts payable with respect to the Overriding Royalties and because prices for oil and gas may vary from field to field, information regarding results of well tests or gross quantities of production from a given well cannot be used to compute the Trust’s interest and (b) because the Productive Properties consist of multiple leases and, in some cases, multiple fields, the interest of the Working Interest Owner in any given well or lease may not be indicative of its interest (or the Trust’s interest) in an entire Productive Property.

Description of Productive Properties

Certain information, as of December 31, 2006, 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, 2006.


Productive
Property and Year								Productive Wells(1)
in Which		Acres						Oil				Acres
Production Commenced	Location	Gross			Net			Gross		Net		Gross		Net

Jay Field (1970)(2)	Onshore		184,472	(3)		62,150	(3)		32		10.78		1		.34
	Alabama and Florida
South Pass 89 (1982)	Offshore		5,000			1,250			2		0.50		2		.50
	Louisiana
Offshore Louisiana (1968)(4)	Offshore		15,000			3,178			17		2.88		29		6.09

	Louisiana		204,472			66,578			51		14.16		32		6.93


(1)		Represent producing wells and wells capable of production. Net wells reflect the Working Interest Owner’s working interest. Gross and net wells exclude injection wells.

(2)		Includes interests in 23 leases which are a part of the Jay Field Unit created by a unit agreement among 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 are not included in the Jay Field Productive Property. The information in the table above relates only to the portion of the Jay Field included in the Jay Field Productive Property. 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;


	Percentage of
	the Working
	Interest Owned
Designation	by the Operators

Black Diamond Resources		3.9080	%
QAB Carried WI, LP		1.6248	%
QAC Carried WI, LP		2.8844	%
Quantum Resources A1, LP		91.5828	%


		Quantum Resources Management, LLC (“Quantum”) will manage the Jay Field working interest on behalf of the above listed assignees after a short post-closing transition period during which the Company will continue to manage the Jay Field working interest. Upon assumption of management responsibilities by Quantum, Quantum will assume the accounting and reporting obligations to the Trust attributable to the Jay Field Productive Property. Quantum has notified the Company that when it takes over the operations of the Jay Field in April 2007, it plans to undertake a different operating and development strategy for Jay Field. Quantum’s basic planned strategy involves attempting to reduce costs and increase production by terminating the purchase and injection of nitrogen gas, conversion of the nitrogen injection lines to water injection, installation of gas lift on production wells, and the reactivation of the available water supply wells with new electrical submersible pumps to increase the current water injection levels in order to compensate for the cessation of nitrogen injection. As of the date of this report, the projected results of these operating and development strategies on the future net revenues of the Trust have not been determined. The Company will continue to account for and report on the remainder of the Properties other than the Jay Field Productive Properties.

(3)		Gross acres reflect aggregate porosity acre-feet in producing formations in the Jay Field, and net acres reflect the Working Interest Owner’s ownership interest in the producing formations as determined volumetrically for purposes of the unit agreement relating to the Jay Field.

(4)		Includes four federal leases or federal units (as applicable) with designations, initial production dates and percentage ownership of the Working Interest Owner as follows:


	Percentage of
	the Working
Designation and Initial	Interest Owned
Production Date	by the Operators

East Cameron 195 Unit (1971)		33.33	%
East Cameron 336, South Addition (1983)		20	%
Eugene Island 261 (1979)		20	%
South Marsh Island 76, South Addition (1968)		25	%
Vermilion 331, South Addition (1977)		12.5	%


		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.

Description of the Fee Lands

The Fee Lands originally subject to the Fee Lands Royalties consisted of approximately 400,000 acres of undeveloped lands owned in fee by the Working Interest Owner in south Louisiana that were not subject to oil and gas leases as of the effective date of the Conveyances with respect to the Fee Lands Royalties. The Fee Lands constituted a substantial portion of all of the land owned in fee by the Working Interest Owner in south Louisiana at the time of the Conveyances but excluded (a) the Working Interest Owner’s property subject to oil and gas leases or productive lands owned by the Working Interest Owner as of such date, (b) beds and bottoms of navigable waters

and (c) certain other minor parcels of land. The Working Interest Owner has developed very limited portions of the Fee Lands, and could, but has no obligation to, elect to develop certain additional portions of the Fee Lands itself.

Under Louisiana law, mineral royalties, in general, will terminate, in the absence of production, after the lapse of ten consecutive years from the date of conveyance. However, the production of any mineral included in the Conveyances (including that obtained through testing a shut-in well proved to be capable of producing in paying quantities) before the lapse of ten years will, except as hereinafter provided with respect to production obtained from a unit, maintain the Royalties in existence for so long as such production continues without cessation, and for a period of ten years thereafter, as to all of the lands affected thereby that are contiguous to the land burdened by the Royalties from which such production is obtained. Tracts of land are rendered noncontiguous by intervening tracts owned by third parties or not covered by the Conveyances, including navigable bodies of water, that divide and separate the lands burdened by the Royalties. Parcels of land that meet only at a corner are likewise noncontiguous. The Fee Lands contain both contiguous and noncontiguous tracts. In the case of production from a unit, the Royalties will be maintained with respect to the whole of the body of land contiguous to the production so long as such production continues without cessation, and for a period of ten years thereafter, if the unit well is situated on land burdened by the Royalties; but if the unit well is on land other than that burdened by the Royalties, production maintains the Royalties only with respect to that portion of the land included in the unit. If all or a portion of the tract of land burdened by the Royalties is included within a unit on which there already exists a shut-in well capable of producing in paying quantities located on other lands within the unit, the ten-year period for termination of the Royalties in the absence of production would begin anew on the effective date of the order or act creating the unit, and production within the ten-year period would maintain the Royalties only with respect to the acreage subject to the Royalties included in the unit. A unit is an area within which all owners of mineral rights share in production 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 revenues in the future from the tracts as to which the Fee Lands Royalties terminated. Subsequent to the June 1993 termination, the Fee Lands consist of approximately 22,420 gross acres, approximately 1,015 acres of which were under lease as of December 31, 2006.

OIL AND GAS SALES FROM THE PRODUCTIVE PROPERTIES

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 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 Owner regarding the amount of gas to which each is entitled and the amount each actually takes and sells. The Working Interest Owner uses the “entitlement” method of recording gas production, which results in revenues being recognized on the Working Interest Owner’s share of production regardless of which party’s purchaser has actually taken and paid for the gas. The Working Interest Owner makes distributions to the Trust based upon its entitled share of production at the relevant contractual prices. The Working Interest Owner’s actual receipts depend on the price received when the imbalances are reconciled, adjustments to the Working Interest Owner’s recorded revenues have been made in the past and may be made in the future. To the extent that any such adjustments decrease the revenues recorded by the Working Interest Owner because gas prices were lower at the time the Working Interest Owner’s gas was actually delivered than when the revenues were originally recorded, or for other reasons, future distributions to the Trust would be reduced.

The laws and regulations governing the prices which the Working Interest Owner receives from the sale of oil and gas from the Productive Properties and the taxes paid with respect to the production are complex, often ambiguous and subject to alteration, often with retroactive effect. If the Working Interest Owner do 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.

EXPLORATION AND DEVELOPMENT ACTIVITIES

Productive Properties

The following is a summary of the Working Interest Owner’s net drilling activities on the Productive Properties for the years ended December 31, 2004, 2005 and 2006:


	Net Wells
	Oil		Gas		Dry

2004
Exploratory		—		—		—
Development		—		—		—
2005
Exploratory		—		—		—
Development		1.000		—		—
2006
Exploratory		—		—		—
Development		—		—		—

The following are the significant activities by the Working Interest Owner on the Productive Properties during 2006:

Jay Field

Capital and abandonment expenditures of approximately $5,000,000 were incurred in 2006, primarily for nitrogen purchases for injections and developmental drilling.

South Pass 89

There were no capital and abandonment expenditures in 2006.

Offshore Louisiana

Capital and abandonment expenditures of approximately $18,000 were incurred in 2006, primarily for capital workovers.

Fee Lands

Approximately 1,015 acres of the south Louisiana Fee Lands subject to the Trust’s 3 percent royalty interest were under lease as of December 31, 2006.

ESTIMATES OF PETROLEUM ENGINEERS

September 30, 2006 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, 2006 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, 2006. A copy of Miller and Lents’ letter, dated March 23, 2007, setting forth such estimates is reproduced below.

As explained in the letter, the estimates of future net revenues from proved reserves and the present value of such future net revenues were calculated based on criteria prescribed by the Securities and Exchange Commission (the “SEC”) and were based upon oil, and natural gas prices and costs represented by the Working Interest Owner to be in effect as of September 30, 2006. The present value was based on a discount factor of 10% per year.

According to the Miller and Lents letter, the estimated future net revenues to the Trust from total proved reserves as of September 30, 2006 were approximately $99,200,000, and the present value of such future net revenues was approximately $49,900,000. (The estimates as of September 30, 2005, were $208,400,000 and $114,400,000, respectively, before giving effect to approximately $3,100,000 in distributions to the Trust during 2006.)

The estimates of future net revenues as of September 30, 2006 reflect a 52 percent decrease in future net revenues, and a 56 percent decrease in the present value of future net revenues from those estimated as of September 30, 2005, after adjusting those 2005 estimates for the estimated distributions related to the twelve months of production ended September 30, 2006.

Certain Factors Affecting Estimates

Because the Royalties on the Properties (other than the Fee Lands) are “net” overriding royalty interests (often referred to as net profits interests), estimates of future net revenues to the Trust are affected by a number of factors in addition to the engineering, well performance and other data taken into consideration by petroleum engineers in estimating the quantity and nature of gross oil and gas reserves in the ground. Such other factors include oil and gas prices (the changes in which have materially affected the estimates of future net revenues to the Trust in recent years), projections of operating and capital costs, and the Working Interest Owner’s evaluation of the economic feasibility of conducting additional operations. 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, production volumes (hydrocarbons and water) and other factors are generally monitored and recorded so that the proved reserves can be periodically reestimated following sufficient intervals of production history. In addition, the drilling of development wells can provide additional reservoir data, including information regarding the areal extent of the reservoir. As reservoir history is accumulated, the historical information is incorporated into volumetric calculations or extrapolated production performance plots to refine the reserve estimate. Consequently, the accuracy of the reserve estimate generally improves with additional production history.

Estimates of both the volume of, and future net revenues from, any specified reserves are of necessity based on assumptions with respect to anticipated market demand and prices obtainable for production from the particular reservoir and with respect to the costs and expenses incurred in developing and producing those reserves. A decline in price will reduce the estimated future revenues to the Trust. A reduction in volume of sales from those estimated, as a result of curtailments or otherwise, delays the receipt of revenues and reduces the present value of future net revenues from the property. Similarly, changes in the timing and amounts of future capital expenditures can also affect the revenues and the present value. Consequently, reserve, net revenue and present value estimates made in the future may differ materially from those contained herein as a result of conditions in the oil and gas industry and general economic conditions.

The independent engineers’ estimated net revenues have been determined on the basis of when the oil or gas is estimated to be produced. However, the payments with respect to the Royalties are received by the Trustee approximately 65 days after the end of the month in which the sales of oil and gas are recorded as revenues by the Working Interest Owner, and the distribution of income from the Royalties to holders of Units (net of Trust expenses) occurs approximately 75 days after the end of such month. The estimated net revenues in Miller and Lents’ letter have not been reduced for costs and expenses of the Trust, which are expected to be approximately $1,100,000 for the twelve months ending September 30, 2007. The costs and expenses of the Trust may increase or decrease in future years, depending on the amount of revenues from the Royalties, increases or decreases in accounting, engineering, legal and other professional fees and other factors.

In estimating future net revenues to the Trust, Miller and Lents has only considered capital expenditures associated with the production and development of estimated proved reserves. Based on that assumption, as of September 30, 2006, the Working Interest Owner has estimated the capital expenditures for production and development of only the proved reserves would be approximately $26,600,000 for the period from October 1, 2006 through September 30, 2007. No assurance can be given that the level of capital expenditures included in this estimate will result in the discovery of additional reserves or the successful development of reserves now classified as proved undeveloped. Amounts of future net revenues estimated for any given period do not take into account the possible effect of current or possible future market conditions relating to the price of oil and gas and other factors discussed below.

In making its estimates, Miller and Lents used price and cost assumptions as described in the Miller and Lents letter. These assumptions are assumptions only, and there can be no assurance that actual prices and costs in the future will not be materially different from those assumed. Prices of oil and gas and related costs have varied dramatically in recent years and are impossible to predict with certainty. As a result, and because of other inherent uncertainties in estimating oil and gas reserves and in forecasting production levels, prices and costs, neither the

Trustee nor Miller and Lents nor the Working Interest Owner can predict what actual revenues to the Trust will be in the future. See “Industry Conditions and Regulation”.

Pursuant to Statement of Financial Accounting Standards No. 69, the Trust is required to include as supplementary information estimates (which are unaudited) of quantities of proved oil and gas reserves attributable to the Trust. The Miller and Lents letter includes such estimates, prepared on the basis described therein. The quantities imputed to the Trust are calculated by multiplying Miller and Lents’ estimated net reserves of the Working Interest Owner (prior to taking into consideration the Trust’s interests) by the ratio of Miller and Lents’ estimated future net revenues to the Trust to Miller and Lents’ estimated future gross revenues to the Working Interest Owner prior to taking into consideration the Trust’s interests. Because the quantities are calculated in this manner, factors other than gross oil and gas reserves in the ground (such as changes in prices and costs, excesses of capital expenditures over amounts used in preparing estimates, as described in the preceding paragraphs, and other factors) will affect the quantities shown as estimated oil and gas reserves imputed to the Trust.

(LETTERHEAD)

March 23, 2007

The Bank of New York

Trustee, LL&E Royalty Trust

221 West 6^th Street, 1^st Floor

Austin, TX 78701-3102


	Re:	Estimates of Proved Reserves and Future Net Revenues for the LL&E Royalty Trust As of September 30, 2006

Gentlemen:

We estimated the proved reserves and the future net revenues attributable to working and royalty interests owned by ConocoPhillips (“the Company”) in certain properties associated with the LL&E Royalty Trust (“the Trust”) interest. The Company acquired the interests as the result of its acquisition of Burlington Resources Inc. in early 2006.

The estimated net proved imputed reserves and future net revenues, discounted at 10 percent per annum, owned by the Trust and without consideration of the Trust Termination Clause, as of September 30, 2006, are as follows:

Net Proved Imputed Reserves and Revenues (1) (2) (3)

Crude Oil,

Net Revenues

Condensate, and

Natural

Future Net

Discounted at 10%

Natural Gas Liquids

Gas,

Revenues,

Per Year,

Reserve Category

MBbls.

MMcf

Proved Developed

1,553.8

1,910.3

99,175.4

49,968.6

Proved Undeveloped

0.0

Total Proved

1,553.8

1,910.3

99,175.4

49,968.6


(1)		The Trust will terminate in the event the total amount of net revenues received by the Trust falls below $5,000,000 for two successive years (“the Termination Threshold”). According to recent press announcements issued by the Trust, net revenues to the Trust during 2006 were below “the Termination Threshold”. There can be no assurance that the net revenues to the Trust during 2007 will be above “the Termination Threshold”. Accordingly, it is possible for the Trust to terminate even though some of the Trust properties have remaining productive lives. See “Duration and Termination of the Trust” in this document on Form 10-K.

(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 reserve

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LL&E Royalty Trust	Page 2

categories. Future excess production costs will be recouped out of total proved production regardless of reserve category.

(3) Proved Undeveloped Reserves associated with the Eugene Island Block 261 well A-6ST were uneconomic under current economic conditions.

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 Company, (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 Company’s South Louisiana fee lands (the “Fee Lands”) acreage. We estimated the imputed reserves using the formulas and criteria specified by the Company, as described in the following paragraphs, and estimated the future 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)(3)
For Production	From Proved		From Proved		From Total
During the 12	Developed		Undeveloped		Proved
Months Ended	Reserves,		Reserves,		Reserves,
September 30	M$		M$		M$

2007		7,105.2		0.0		7,105.2
2008		4,965.5		0.0		4,965.5
2009		5,402.5		0.0		5,402.5
2010		5,690.2		0.0		5,690.2
2011		7,689.1		0.0		7,689.1
2012		8,049.5		0.0		8,049.5
Remainder		60,273.4		0.0		60,273.4

Total		99,175.4		0.0		99,175.4


⁽¹⁾		The Trust will terminate in the event the total amount of net revenues received by the Trust falls below $5,000,000 for two successive years (“the Termination Threshold”). According to recent press announcements issued by the Trust, net revenues to the Trust during 2006 were below “the Termination Threshold”. There can be no assurance that the net revenues to the Trust during 2007 will be above “the Termination Threshold”, thus it is possible for the Trust to terminate even though some of the Trust properties have remaining productive lives. See “Duration and Termination of the Trust” in this document on Form 10-K.

⁽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

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LL&E Royalty Trust	Page 3

production may vary slightly from the timing associated with the separate proved reserve categories. Future excess production costs will be recouped out of total proved production regardless of reserve category.

⁽³⁾ Proved Undeveloped Reserves associated with the Eugene Island Block 261 well A-6ST were uneconomic under current economic conditions.

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 Company. 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 calendar year. The amounts in the table above reflect those estimates of the disbursements to the Trust.

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		98,751.4		2031
South Pass 89		0.0		2010
Offshore Louisiana		0.0		2012
Fee Lands		424.0		2012

Total		99,175.4


(1)		The Trust will terminate in the event the total amount of net revenues received by the Trust falls below $5,000,000 for two successive years (“the Termination Threshold”). According to recent press announcements issued by the Trust, net revenues to the Trust during 2006 were below “the Termination Threshold”. There can be no assurance that the net revenues to the Trust during 2007 will be above “the Termination Threshold”, thus it is possible for the Trust to terminate even though some of the Trust properties have remaining productive lives. See “Duration and Termination of the Trust” in this document on Form 10-K.

(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 reserve categories. Future excess production costs will be recouped out of total proved production regardless of reserve category. Based on information provided by the Company, it is estimated that the future dismantlement costs in excess of the amounts currently held in escrow, will exceed the estimated future net revenues for the South Pass 89 and Offshore Louisiana properties and will result in zero future net revenues to the Trust.

(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 Company 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

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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 Company from the sale of oil, gas, and other hydrocarbons from each of the Working Interest Properties less (a) all direct costs, charges, and expenses incurred by the Company in production, development, and other operations on the Working Interest Properties (including secondary and tertiary recovery operations), and for dismantlement and abandonment costs where applicable; (b) all applicable taxes (including severance and ad valorem) excluding income taxes; (c) all operating charges directly associated with the Working Interest Properties; (d) applicable charges for certain overhead expenses; and (e) other charges specified in the Trust documents. Administrative expenses of the Trust have not been deducted in determining the net revenues in the foregoing tables. The current estimates of the future dismantlement costs net of salvage value to the Company’s working interest are approximately $5.5 million for South Pass 89, $14.2 million for Jay Field, and $6.9 million for the Offshore Louisiana properties. As of September 30, 2006, the South Pass 89, Jay Field, and the Offshore Louisiana properties’ escrow balances were approximately $0.7 million, 4.5 million, and $0.0 million, respectively, leaving an additional $4.8 million, 9.7 million, and $6.9 million, respectively, attributable to the Company’s working interest to be escrowed in the future.

Excess production costs will result to the Company’s working interest in the event that the costs, charges, and expenses attributable to a Working Interest Property exceed the revenues received from the sale of oil, gas, and other hydrocarbons produced from such property (“Excess Production Costs”). Pursuant to the provisions of the Trust documents, the Company is allowed to recover such costs from future Net Proceeds. Excess production costs to the Company’s working interest to be recovered from future Net Proceeds as of September 30, 2006, were $549,881 for South Pass 89 and $2,605,242 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, 2006, 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 Company 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 Company, 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 could 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

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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.

Estimated reserves for the Jay Field property were forecasted based on an analysis of historical production volumes and current decline rates. During 2006, the production volumes decreased due to increasing decline rates. Additional production volumes from the planned 14 well workover program were included in the current forecast but revised downward based on the latest field performance data. Information provided by the Company indicated that as of the effective date of this report, the operator of Jay Field had not yet performed a discretionary uplift workover during 2006. Also included in the forecast of future net revenues are additional capital expenditures which the Company previously indicated were likely to be spent to improve tangible and intangible field facilities to support the current production.

Net reserves, as used herein, are reserves net to the Company or imputed to the Trust after taking into account existing third party interests and landowner royalties. Portions of the properties are pooled or unitized, and the reserve estimates herein are based on existing pooling and unitization arrangements.

The imputed estimated proved reserves attributable to the Trust were calculated for each of the three groups of Working Interest Properties and the Fee Lands by multiplying the respective net proved reserves of the Company by the ratio of the estimated future net revenues of the Trust to the estimated future gross revenues of the Company 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 Company⁽¹⁾	×	Estimated net proved reserves of the Company (Bbls or Mcf)


⁽¹⁾		Prior to subtraction of all costs (including Jay Field fuel and severance taxes) and the costs attributable to the Trust.

As the imputed estimated 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 Trust’s imputed estimated proved reserves, which could be significant.

Subsequent to the effective date of this report, the Company informed us of certain events described below which may result in the actual estimates of future imputed proved reserves and future net revenues to be different than those contained within this report.


	•	The Company and the operator of Jay Field, sold its’ respective working interests in the field to Quantum Resource Management (Quantum) in December 2007. Based on discussions with Quantum, it expects to become operator in April 2007 and will undertake a different operating and development strategy for Jay Field than what has been considered in this report. Quantum’s basic planned strategy involves attempting to reduce costs and increase production by terminating the purchase and injection of nitrogen gas, conversion of the nitrogen injection lines to water injection, installation of gas lift on production wells, and the reactivation of the available water supply wells with new electrical submersible pumps to increase the current water injection levels in order to compensate for the cessation of nitrogen injection. Quantum’s strategy and potential results have not been considered in this report.

	•	The Vermillion Block 331 A-25 well bore is no longer useable for two future planned behind-pipe recompletions. Consequently, additional costs will be incurred in order to drill two new sidetracks which will be required in order to produce the estimated reserves.

(LOGO)


The Bank of New York, Trustee	March 23, 2007


LL&E Royalty Trust	Page 6

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 which were furnished by the Company have been accepted as represented. Operating costs and estimated capital expenditures furnished by the Company were reviewed for reasonableness. No field inspections or well tests were conducted by 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, 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 20 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.


	By	/s/ Gary W. Priddy

Gary W. Priddy

Engineer, P.E.


	By	/s/ Robert J. Oberst

Robert J. Oberst

Senior Vice President, P.E.


	By	/s/ Carl D. Richard

Carl D. Richard

Senior Vice President, P.E.

RJO/sg

Appendix

Proved Reserves Definitions
In Accordance With
Securities and Exchange Commission Regulation S-X

Proved Oil and Gas Reserves

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e, prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements but not on escalations based upon future conditions.

1. Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by gas-oil andor oil-water contacts, if any, and (b) the immediately adjoining portions not yet drilled but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

2. Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the proved classification when successful testing by a pilot project or the operation of an installed program in the reservoirs provides support for the engineering analysis on which the project or program was based.

3. Estimates of proved reserves do not include the following:

a. Oil that may become available from known reservoirs but is classified separately as indicated additional reserves.

b. Crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors.

c. Crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects.

d. Crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite, and other such sources.

Depending upon their status of development, proved reserves are subdivided into proved developed reserves and proved undeveloped reserves.

Proved Developed Oil and Gas Reserves

Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as proved developed reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved Undeveloped Oil and Gas Reserves

Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

INDUSTRY CONDITIONS AND REGULATION

Industry Conditions

The availability of a ready market for oil and gas depends upon numerous factors beyond the Working Interest Owner’s control, including the production of crude oil and gas by others, crude oil imports, the marketing of competitive fuels, the proximity and capacity of oil and gas pipelines, the availability of treatment facilities, the regulation of allowable production by governmental authorities and the regulation by the FERC and various state agencies of the transportation and marketing of natural gas transported or sold in interstate commerce. Because of the mechanics of the 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

The production of oil and gas in the United States is affected by many state and federal regulations with respect to allowable rates of production, marketing and environmental matters. Future regulations could change allowable rates of production or the manner in which oil and gas operations may be lawfully conducted.

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. However, events in recent years have heightened environmental concerns about the oil and gas industry generally, and about offshore operations in particular. Oil and gas operations are subject to extensive governmental regulation, including regulations that may in certain circumstances impose absolute liability upon lessees for the cost of cleaning up pollutants and for pollution damages resulting from their operations, and that may require lessees to suspend or cease operations in affected areas. Although the Working Interest Owner has advised the Trustee that current environmental regulation has not had a material adverse effect on operations, the effects of changes in environmental law, such as stricter environmental regulation and enforcement policies, cannot be predicted.

TAX CONSIDERATIONS TO OWNERS OF UNITS

Federal Income Tax Considerations

Introduction

The following summary discusses the federal income tax consequences attendant to the acquisition, ownership and disposition of Units. However, for the following reasons, no assurance can be given that the tax treatment described in this summary will be available. First, administrative and judicial interpretations of recent changes in the tax law affecting these matters are nonexistent or insufficient to provide definitive guidance as to the proper tax treatment of certain items. Second, certain of the tax consequences described herein are not subject to clear resolution under present law and the existing administrative and judicial interpretations thereof. Third, the laws or regulations affecting these matters are subject to new interpretations, by the Internal Revenue Service (the “Service”) or by the courts, which could adversely affect Unit holders.

Because the federal income tax consequences of the acquisition, ownership and disposition of Units are highly complex, this discussion is merely a summary and does not purport to provide detailed tax information to Unit holders or to function as a substitute for careful tax planning and analysis. All Unit holders are urged to consult their own tax advisors regarding the effects on their personal tax situations of acquiring, owning, and disposing of Units.

Rulings and Tax Opinion Regarding Distribution

The following information concerning the Company’s ruling requests to the Service regarding the federal income tax consequences of the creation and distribution of Units to the Company’s shareholders (the

“Distribution”) and the operation of the Partnership and the Trust has been provided by the Company. The Company has received the following requested rulings from the Service:

1. The Trust will be classified as a trust and not as an association taxable as a corporation.

2. The Trust will be characterized as a “grantor” trust as to the Unit holders and not as a “nongrantor” trust (a “simple” or “complex” trust).

3. The Partnership will be classified as a partnership and not as an association taxable as a corporation.

4. The transfer of a Unit will be considered to be the transfer of the proportionate part of the Partnership interest attributable to such Unit.

5. Each Unit holder will be entitled to deduct cost depletion (or percentage depletion if greater than cost depletion and if otherwise allowable) with respect to his pro rata interest in the Royalties computed by reference to such Unit holder’s basis in the Units.

6. Each Royalty will be considered an economic interest in oil and gas in place, and each Royalty will constitute a single property within the meaning of Section 614(a) of the Internal Revenue Code (the “Code”).

7. Each Unit holder will be treated as the producer of crude oil attributable to his pro rata interest in the Royalties for windfall profit tax purposes.

8. The steps taken to create the Trust and the Partnership and to distribute the Units are properly viewed as a distribution of the Royalties by the Company to its stockholders, followed by the stockholders’ contribution of the Royalties to the Partnership in exchange for interests therein, which in turn was followed by the contribution by the stockholders of the interests in the Partnership to the Trust in exchange for Units.

Although the Company requested these rulings prior to the time of the Distribution, the rulings were issued after the Distribution occurred. Therefore, the Service could revoke the rulings if it changes its position on the matters the rulings address.

These favorable rulings are consistent with a legal opinion the Company received from tax counsel prior to the Distribution. The opinion of counsel is not binding on the Service or the courts, and the Service may revoke its favorable rulings, as mentioned above. If it were to do so, there can be no assurance that the position of the Service would not be upheld in a judicial proceeding.

At the same time the Company requested the rulings described above, the Company requested a ruling to the effect that it would not recognize gain or loss upon the transfer of the Royalties to the Trust or upon the Distribution. The Company subsequently withdrew this request. The Service had indicated to the Company that, if a ruling had been issued with respect to this issue, it would have been unfavorable. Tax counsel advised the Company prior to the Distribution that, because of the lack of direct authority, it was unable to express an opinion on this issue. See “IDC Recapture Income to the Company on Distribution”.

No other rulings with respect to the Distribution of the Units have been requested from the Service and, except as noted below, no opinion of counsel has been requested or rendered regarding any other tax consequences discussed herein.

Tax Consequences of Owning Units

The federal income tax consequences of owning Units depend, in large part, on (i) the proper classification of the Trust as a trust rather than as an association taxable as a corporation, (ii) the classification of the Partnership as a partnership rather than as an association taxable as a corporation, and (iii) the categorization of the Trust as a “grantor” trust rather than as a “nongrantor” trust (a “simple” or “complex” trust). For purposes of this summary it has been assumed that neither the Trust nor the Partnership will be classified as an association taxable as a corporation and that the Trust is properly categorized as a grantor trust, positions consistent with the favorable rulings received by the Company from the Service regarding these issues. However, as mentioned above, because the rulings were issued after the Distribution occurred, the Service could revoke its favorable rulings if it changes its position regarding these matters.

The manner in which Unit holders who received their Units in the Distribution or who acquired their Units before September 7, 1983 have chosen to report their receipt of such Units may affect the manner in which they report the receipt of income distributions from the Trust. This summary of the federal income tax treatment of income distributions from the Trust is based in part on the assumption that the Unit holders described above have characterized their receipt of Units as a receipt of interests in a grantor trust owning cash payment rights and economic interests in oil and gas properties.

General Features of Grantor Trust Taxation. An entity which is properly classifiable as a trust for federal income tax purposes may be treated as falling into one of three categories: (i) a grantor trust, (ii) a simple trust, or (iii) a complex trust. Because the existence of a grantor trust is generally disregarded for federal income tax purposes, a grantor trust is not subject to tax, and its beneficiaries (the owners of Units in the case of the Trust) generally are considered for tax purposes to own the assets of the trust directly. Thus, the owners of Units should be treated as owning the Partnership interest which the Trust holds, and each owner of a Unit should be treated as a partner (to the extent of such Unit holder’s interest in the Trust) in the Partnership for federal income tax purposes. Treatment of partners for federal income tax purposes is discussed below. The Trustee has filed, and anticipates that it will continue to file, federal income tax returns on the basis that the Trust is a grantor trust.

General Features of Partnership Taxation. An organization which is properly classifiable as a partnership for federal income tax purposes is not a taxable entity and incurs no federal income tax liability. Instead, each item of partnership income, gain, loss, deduction, credit, and tax preference flows through to the partners, substantially as though the partners had received or expended such item directly. Each Unit holder is required to take into account in computing his federal income tax liability his distributive share of all items of Partnership income, gain, loss, deduction, credit and tax preference for each taxable year of the Partnership ending with or within his taxable year based on the Partnership’s method of accounting, without regard to the Unit holder’s method of accounting or whether the Unit holder received or will receive any cash distributions. Consequently, it is possible that in any year a Unit holder’s share of the taxable income of the Partnership (and possibly the income tax payable by him with respect to such taxable income) may exceed the cash, if any, actually distributed in such year. See “Accounting for Income and Deductions”, below.

Special tax rules apply to any “publicly traded partnership”, i.e., any partnership whose capital interests are traded on an established securities market or are readily tradeable on a secondary market or its substantial equivalent. Because the transfer of a Unit represents a transfer of an interest in the Partnership, the Partnership is included in the definition of a publicly traded partnership. A publicly traded partnership is taxed as a corporation for federal income tax purposes unless 90 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 Partnership’s income is derived from the Royalties, it should not be taxed as a corporation.

Tax-exempt organizations are subject to tax on their unrelated business income. Tax-exempt Unit owners should consult their tax advisors to determine if they are subject to tax on net income attributable to Units in the Trust.

Depletion Deductions. The owner of an economic interest in producing oil and gas properties is entitled to deduct, on his federal income tax return, an allowance for the greater of cost depletion or (if otherwise allowable) percentage depletion on each such property. Each Unit owner who acquires Units by purchase should be entitled, by reason of the Partnership’s election under Section 754 of the Internal Revenue Code of 1986, as amended (the “Code”), to deduct cost depletion (or, if greater and otherwise available, percentage depletion) with respect to production from each of the Royalties using his basis in such Royalties. The amount of deductions based on cost depletion cannot exceed the total adjusted tax basis of the property. Prior to the enactment of the Revenue Reconciliation Act of 1990 (the “1990 Act”), only cost depletion was allowed to a Unit holder with respect to production attributable to the Royalties carved out of properties which become proven prior to this acquisition of Units. Under the provisions of the 1990 Act, Unit holders acquiring their Units after October 11, 1990, may be entitled to deduct an allowance for percentage depletion if such deduction would otherwise exceed the allowable deduction for cost depletion, regardless of whether the oil and gas interest was “proven” at the time of its acquisition. However, in order to take percentage depletion, the Unit holder must qualify for the “independent

producer” exemption contained in Section 613A(c) of the Code; otherwise, such owner will be limited to cost depletion.

Cost depletion for each productive property is calculated by (i) dividing the 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.

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 holder’s adjusted gross income. However, Section 62(a)(4) of the Code provides that deductions attributable to property held for the production of royalty income may be deducted in arriving at a taxpayer’s adjusted gross income. Trust administrative expenses are incurred by the Trustee on behalf of Unit holders in connection with the income from the Royalties flowing through the Partnership and Trust and, therefore, may be deducted in arriving at a Unit holder’s adjusted gross income. Accordingly, such deductions should not be subject to the 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 holder’s income or losses from passive activities. The tax laws relating to the various classifications of income and the tax consequences of these classifications are complex. Unit holders should consult their tax advisors to determine the impact of these provisions on their individual tax situations.

Alternative Minimum Tax for Corporations. For a corporation, alternative minimum taxable income is equal to (i) regular taxable income of the corporation, with certain adjustments, plus (ii) items of tax preference. After a corporation’s alternative minimum taxable income is reduced by an exemption amount, it is then multiplied by 20 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 corporation’s 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 holder’s alternative minimum taxable income is generally equal to (i) his regular taxable income, with certain adjustments, plus (ii) items of tax

preference. After a noncorporate taxpayer’s alternative minimum taxable income is reduced by an exemption amount, the tentative alternative minimum tax is 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 taxpayer’s 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 taxpayer’s minimum tax liability. For tax years beginning in 2006, the noncorporate taxpayer’s exemption amount is $62,550 ($58,000 in 2005) in the case of joint returns or surviving spouses, $42,500 ($40,250 in 2005) in the case of unmarried individuals who are not surviving spouses, $31,275 ($29,000 in 2005) 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.

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 year’s income. Because the application of the withholding Regulations will vary depending on a holder’s particular circumstances, all holders are urged to consult their own tax advisors regarding the application of the 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 partner’s share of withholding tax paid by a partnership is treated as distributed to the foreign partner on the earlier of (i) the date the partnership actually pays the tax to the Service or (ii) the last day of the partnership’s tax year for which the tax is paid. Future regulations may modify the general rule described above to provide for earlier deemed distributions and reductions in basis in circumstances such as those involving mid-year dispositions of partnership interests. The Service is authorized to impose penalties on a partnership for failure to satisfy withholding tax liabilities.

Section 6039C of the Code allows the Service to require reporting by foreign direct owners of United States real property interests. To date no such reporting requirements have been announced by the Service.

If a Foreign Taxpayer owns (or has owned during a five-year look-back period) more than five percent of the outstanding Units, either directly or through attribution rules under Section 897 of the Code, the Units in the hands of such a Foreign Taxpayer are treated as United States real property interests. For such a Foreign Taxpayer, gain or loss from the sale or exchange of Units will generally be regarded as arising from the sale or exchange of property effectively connected with the conduct of a United States trade or business. Therefore, any gain or loss on the sale of Units must be reported to the Service and appropriate taxes paid.

Section 1445 of the Code generally provides for withholding at the source when a United States real property interest is acquired from a Foreign Taxpayer after December 31, 1984. 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 holder’s basis in such property. See “Depletion Deductions” above.

The sale of Units should be considered, for tax purposes, as the sale of an interest in the Partnership. Income allocable to such Units to the date of sale will be taxable to the selling owner of Units, and the purchaser of Units will be taxable on income allocable to such Units from the date of purchase forward. See “Accounting for Income and Deductions”, below. Certain information reporting requirements may apply to the sale of Units. See “Information Return Filing Requirements”, below. The Partnership has made an election under Section 754 of the Code to allow each subsequent purchaser of Units to take a basis in his share of the Royalties which reflects his cost basis in the Units (as opposed to his pro rata share of the Partnership’s basis in the Royalties) for purposes of calculating deductions for depletion and abandonments with respect to such Royalties.

The Service has ruled that a partner must maintain a single aggregate adjusted tax basis in partnership interests acquired in multiple transactions. Upon a sale of a portion of such aggregate interest, such partner would be required to allocate his aggregate tax basis between the interest sold and the interest retained by some equitable apportionment method such as the relative fair market values of such interests on the date of sale. It is unclear whether the ruling would apply to owners of publicly traded units of beneficial interests in a trust (such as the Trust) which owns interests in a partnership (such as the Partnership). If the ruling is applicable to the Units, such process of aggregating the tax basis of all Units owned by a Unit holder would effectively prohibit a Unit holder owning Units which were purchased at different prices from controlling the timing of the recognition of the inherent gain or loss in his Units by choosing which Units he will sell. A Unit 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 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 Partnership’s 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 — 2006 Tax Information package) containing certain information necessary to permit the computation of federal and state tax liabilities.

Audit of Partnership and Trust Returns. While no federal income tax is required to be paid by organizations which are classified as partnerships or grantor trusts, partnerships and grantor trusts must file informational federal income tax returns which are subject to examination by the Service.

The Code provides that the tax treatment of “partnership items” is determined at the partnership level rather than at the partner level. These rules, which apply to the Partnership, provide in general for partnership level Service audits and deficiency proceedings or claims for refund in respect of “partnership items”. These rules also provide for the designation of a “tax matters partner” (the Company, in the case of the Partnership), who has the power to (i) extend the applicable statute of limitations on assessments of tax (normally three years) attributable to “partnership items” and (ii) enter into settlement agreements which will bind other partners unless they specifically elect not to be bound. Under Treasury regulations, the term “partnership items” includes, insofar as may be relevant in the case of the Partnership, (i) the Partnership’s aggregate and each partner’s distributive share of items of income, gain, loss, deduction or credit, (ii) items of the Partnership which may be tax preference items under Section 57(a) of the Code for any partner, (iii) optional adjustments to the basis of Partnership property pursuant to an election under Section 754 (including necessary preliminary determinations, such as the determination of a transferee partner’s basis in a Partnership interest) and (iv) windfall profit tax (for periods when the windfall profit tax was in effect). Further, a person whose tax is indirectly determined by taking into account partnership items, such as a Unit holder, is required to notify the Service if he treats partnership items inconsistently with the treatment on the partnership return. Failure to notify will allow the Service to assess the resulting deficiency without further proceedings, and may result in a penalty. See “Other Possible Penalties”. Each Unit holder should consult a tax advisor to determine the effects of the applicability of these rules to the Partnership.

Accounting for Income and Deductions. Since 1987 the Partnership has utilized the accrual method of accounting for tax purposes. The accrual method of accounting requires a taxpayer to recognize income at the earlier of the time the income is received or all events have occurred which fix the right to receive such income and the amount thereof can be determined with reasonable accuracy. Deductions are allowable for the taxable year in which all the events have occurred which establish the fact of liability giving rise to such deduction and the amount thereof can be determined with reasonable accuracy.

Because the Trust is treated as a grantor trust with respect to each Unit holder, the Royalty income of the Trust will be deemed to have been accrued by each Unit holder on the day the Partnership accrues such income under its method of accounting and not on the date cash is distributed by the Partnership or the Trust, regardless of a Unit holder’s method of accounting. Income from the Trust will be taxed to each Unit holder in the taxable year within which the taxable year of the Partnership ends. Trust administrative expenses are costs incurred outside of the Partnership and will be recognized by Unit holders consistent with their method of accounting and without regard to the taxable year and or accounting method employed by the Partnership or the Trust.

The Trust makes monthly distributions to Unit holders of record on each Monthly Record Date on which it has revenues to distribute. Because the Partnership must use the accrual method of accounting for tax purposes, the Trust cannot match taxable income of the Partnership with cash distributions from the Trust. Thus, in certain cases a Unit holder may be required to report taxable income attributable to his Units, but the Unit holder will not receive the distribution attributable to such income. This will be true to the extent a cash distribution from the Partnership paid on any Monthly Record Date is associated with income accrued by the Partnership prior to such Monthly Record Date.

The Trust Agreement and the Partnership Agreement provide that income and deductions of the Trust and the Partnership during the period ended on each Monthly Record Date will be allocated to the Unit holders of Record on that Monthly Record Date. The Code generally requires that items of partnership income and deduction be allocated among transferors and transferees of partnership interests, as well as among partners whose interests otherwise vary during a taxable period, on a daily basis. However, the Conference Committee Report with respect to the applicable Code provision states that regulations will provide a convention permitting such allocations to be made on a monthly basis. Furthermore, relevant legislative history indicates that allocations on a reasonable basis will be permitted pending adoption of prospective regulations governing the matter. It is uncertain whether the Service will accept the allocation method used by the Partnership and the Trust or will require income and deductions of the Partnership or the Trust to be determined and allocated daily or based on some other method of proration. If the Service made such a contention, the judicial response would also be uncertain. The Trustee believes that the allocation method adopted for the Trust and the Partnership is reasonable and consistent with the purposes of applicable Code provisions. In the event regulations are proposed which prescribe a convention which is inconsistent with the method used by the Trust and the Partnership, the Trustee intends to offer comments on the proposed regulations and to take other action it deems appropriate in order to attempt to persuade the Service to adopt a convention which would enable the Trust and the Partnership to continue to use the allocation method now in use. In the event such a convention is not provided, the Service may contend that taxable income or losses should be allocated among Unit holders in a different manner. If any such contention were sustained, the Unit holders’ respective tax liabilities would be adjusted, and some could be required to pay additional tax. A Unit holder who transfers or acquires Units should consult with his tax advisor with regard to the proper reporting of income received and expenses paid by the Trust or the Partnership during the month in which such Units are acquired or transferred.

Related Tax Effects on Unit Holders. The ownership of Units may result in the federal income tax returns of a Unit holder being subject to scrutiny by the Service. A Unit holder’s returns may be examined as a result of an audit of the Trust or the Partnership, and the Service may make adjustments to such returns which are unrelated to the Distribution and the ownership of Units.

The tax classification of the Trust and the Partnership directly affects the reporting by the Unit holders of the Trust’s income and distributions. A Unit holder who treats the Trust as a grantor trust would pay tax attributable to the Trust’s portion of the Partnership’s income and income from other sources received or accrued (depending on his method of accounting) even though no cash was distributed by the Trust. If a Unit holder reports income attributable to the Trust in a manner that is inconsistent with the final determination of the status of the Trust or the Partnership, such Unit holder may be liable for a deficiency (including interest) or may be required to file timely a claim for refund in order to obtain any overpayment of taxes. In addition, any tax deficiency or refund claim arising out of a Unit holder’s reporting of Trust income could increase the likelihood of an audit of such Unit holder’s tax return.

Other Possible Penalties. An owner of a security who receives income in respect of such interest must report the character and amount of such income, for federal income tax purposes, in a manner which is consistent with the federal income tax reports of the entity which was the source of the income. The consistency requirement is deemed

to be waived if the taxpayer files a statement with the Service identifying the inconsistency. Because of the presence of “street name” investors and the possible existence of transfer record inaccuracies, holders of interests which are actively traded in the securities markets may encounter situations in which it is difficult to comply fully and accurately with the consistency requirement and other federal tax reporting requirements. Certain penalties could be assessed against a taxpayer that fails to comply with such requirements. Because of the complexity of the federal tax reporting requirements applicable to trusts (such as the Trust) which own interests in partnerships (such as the Partnership) and because all of the tax attributes of the Royalties flow through the Partnership and the Trust to the Unit holders, there is an increased likelihood that Unit holders will violate the consistency requirement and other reporting requirements regarding their individual federal income tax returns and the information returns of the Trust and the Partnership. Any violations of the consistency requirements could lead to imposition of certain penalties on the Unit holders or other adverse results. Furthermore, the Trust or the Partnership might be subject to certain penalties in connection with its furnishing of statements and information to Unit holders or the government if such statements or information prove to be inaccurate due, for example, to differences between the transfer agent’s records and actual ownership data. The Code provides reporting requirements designed to facilitate the transfer of information between partnerships and trusts and owners of interests therein held by nominees. See “Nominee Reporting Requirements”.

IDC Recapture Income to the Company on Distribution

As described in prior reports, at the time of the creation of the Trust, a legal issue existed as to whether the disposition of a royalty carved out of an operating interest to which intangible drilling and development costs (“IDC”) have been charged was a disposition of “property” for purposes of Section 1254 of the Code. Section 1254 requires a taxpayer to recapture IDC upon the disposition of an oil and gas property.

The Company took the position on its tax returns that the distribution of the Royalties did not trigger Section 1254 recapture. The Service subsequently audited the Company’s federal income tax returns for 1983, the year in which the Trust was created and in which the Units were distributed, and assessed a deficiency attributable to the distribution of the Units and recapture of IDC under Section 1254 of the Code. The Company responded to this formal adjustment to its tax liability by filing a petition in the United States Tax Court contesting this deficiency, and in 1989 the Tax Court rendered an opinion favorable to the Company. The IRS did not appeal the ruling of the Tax Court. Consequently, the Tax Court’s opinion is now final and nonappealable.

Backup Withholding

The Code’s backup withholding system applies to all “reportable payments”. The rate of withholding of tax is 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. 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 owner’s interest. Failure to comply with these requirements may result in the imposition of penalties up to $100,000. Those persons holding Units for the beneficial ownership of another should consult with their tax advisors to ensure compliance with the new nominee reporting requirements.

Information Return Filing Requirements

Under the Code, any partner who sells or exchanges (other than through a broker) an interest in a partnership holding “unrealized receivables” or certain inventory within the meaning of Section 751 of the Code is required to notify the partnership of such transaction within 30 days of the transfer (or, if earlier, January 15 of the calendar year following the calendar year in which the exchange occurred). Any such partner who fails to so notify the partnership may be subject to a $50 penalty for each such failure. Furthermore, the partnership is required to notify the Service of any sale or exchange (of which it has notice) of a partnership interest, and to report the name and address of the transferee and the transferor who were parties to such transaction, along with all other information required by applicable Treasury regulations. The partnership must also provide the information to the transferor and the transferee. If the partnership fails to furnish any such notification, it may be subjected to a penalty of $50 per failure, up to an annual maximum of $100,000 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 holder’s name, address, taxpayer identification number and the date of the disposition. Failure to so notify the Trustee may subject a Unit holder, as well as the Trust and the Partnership, to the above-described penalties. Without notification from Unit holders, the Trust and Partnership cannot comply with these reporting requirements because they have no other way of determining which Units disposed of during the year were acquired by the transferring Unit holder subsequent to December 31, 1986.

State Tax Considerations

The Royalties burden properties in 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 is repealed in its entirety. The income tax rates for individuals range from a low of 2 percent to a high of 6 percent.

Louisiana imposes an income tax on all corporations, and other entities treated as corporations, if they earn or receive income derived from or attributable to sources within Louisiana. Oil and gas Royalty income, net of 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 taxpayer’s business to acquire a business situs) or, in the absence of a business situs, to the taxpayer’s 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 corporation’s 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 nonresident’s 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 corporation’s 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 corporation’s 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 taxpayer’s circumstances. Business income is apportioned to Florida based on the corporation’s apportionment factor. However, if income from the Royalties represents nonbusiness income, such income would be allocated, net of related expenses.

The Florida corporate income tax is imposed at the annual rate of 5.5 percent on adjusted Federal taxable income allocable or apportionable to Florida. Any entity subject to the Florida income tax is also subject to the annual Emergency Excise Tax of 2.2 percent on certain accelerated depreciation deductions taken on the corporation’s federal income tax return. This excise tax will not apply for any assets placed into service after 1986. In addition, Florida has adopted an alternative minimum tax which may be applicable to certain Unit holders.

In computing Florida taxable income, a Unit holder’s allowable depletion deduction will be the same as the amount allowed for federal income tax purposes.

Florida also imposes an intangibles tax on individuals, corporations, partnerships, and fiduciary filers. The intangible base includes notes receivable, investments, and accounts receivable (less a reasonable allowance for uncollectible accounts). For individual and corporate intangible tax returns, the first $250,000 of the taxable intangible base is exempt. The exemption is $500,000 for married filing jointly. The rate for individuals, corporations, partnerships, and fiduciary filers is .0005. The rate is applied to the intangible base to determine the intangible tax liability.

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 taxpayer’s circumstances. Business income is apportioned to the state based on the corporation’s apportionment factor. However, if income from the Royalties represents nonbusiness income, such income would be allocated, net of related expenses. The 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 corporation’s 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 corporation’s Alabama income tax apportionment factor to the net worth base. The rate is determined by the entity’s 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, 2003).

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 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 does not maintain an internet address or a website, and therefore does not make copies of its reports under the Exchange Act available in that manner. The Trust’s filings under the Exchange Act are available electronically from the website maintained by the Securities and Exchange Commission 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.


Item 1A.	*Risk Factors*

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.

Natural gas and oil prices fluctuate due to a number of factors, and lower prices will reduce net proceeds available to the Trust and distributions to Trust Unit holders.

The Trust’s distributions are highly 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 that are beyond the control of the Trust, the Working Interest Owner and the operators. Factors that contribute to price fluctuation include, among others:


	•	political conditions worldwide, in particular political disruption, war or other armed conflicts in oil producing regions;

	•	worldwide economic conditions;

	•	weather conditions;

	•	the supply and price of foreign natural gas and oil;

	•	the level of consumer demand;

	•	the price and availability of alternative fuels;

	•	the proximity to, and capacity of, transportation facilities; and

	•	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 reduce net profits available to the Trust. The volatility of energy prices reduces the predictability of future cash distributions to unitholders. Substantially all of the natural gas, oil and natural gas liquids produced from the properties are being sold under short-term or multi-month contracts at market clearing prices or on the spot market.

Damage from Hurricanes Katrina and Rita will have a material adverse effect on distributions from the Trust for the forseeable future.

The damage caused by Hurricanes Katrina and Rita, to production facilities for properties in which the Trust has an interest, is expected to have a material adverse effect on distributions from the Trust for the forseeable future. While the information available remains preliminary and subject to change, the damage has interrupted production, damaged production facilities, increased expenses, increased abandonment costs, and resulted in the decision by the Working Interest Owner to begin escrowing all funds otherwise distributable to the Trust from the Offshore Louisiana and South Pass 89 properties, as well as the decision by the Trustee to escrow all of the amounts otherwise distributable to Unitholders in November 2005 and January — July 2006. Additional information regarding the damage to these properties is included under Management’s Discussion and Analysis.

Pending Litigation Against the Working Interest Owner Could Adversely Impact Cash Distributions

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, 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 Trust’s 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 Trust’s interest.

Increased production and development costs for the Overriding Royalties will result in decreased Trust distributions.

Production and development costs attributable to the Overriding Royalties are deducted in the calculation of the Trust’s share of net proceeds. Accordingly, higher or lower production and development costs, without concurrent increases in revenues, directly decrease or increase the amount received by the Trust for the Overriding Royalties.

If development and production costs of the Overriding Royalties exceed the proceeds of production from the properties, the Trust will not receive net proceeds for those properties until future proceeds from production exceed the total of the excess costs plus accrued interest during the deficit period. Development activities may not generate sufficient additional revenue to repay the costs.

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 units of beneficial interest of the Trust 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:


	•	historical production from the area compared with production rates from similar producing areas;

	•	the assumed effect of governmental regulation; and

	•	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 the natural gas reserves.

Operating risks can adversely affect Trust distributions.

The occurrence of drilling, production or transportation accidents and other natural disasters at any of the properties will reduce Trust distributions by the amount of uninsured costs. 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 to the Trust.

The operators of the properties are subject to extensive governmental regulation.

Oil and gas operations have been, and in the future will be, affected by federal, state and local laws and regulations and other political developments, such as price or gathering rate controls and environmental protection regulations.

Trust Unit holders and the Trustee have no control over the operation or development of the Royalty Properties and have little influence over operation or development.

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 owner of any Properties may abandon any property, terminating the related Overriding Royalties.

The operators of the properties may abandon any well or property if they reasonably believe 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.

The Trust can be terminated and may terminate in 2007.

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. Unless sooner terminated, the Trust will continue until such time as its net revenues (cash earnings) for each of two successive years are less than $5,000,000 per year. 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 Owner or the Partnership under escrow arrangements relating to future dismantlement of platforms or to make refund payments pursuant to the Conveyance. The Trust may be terminated at any time by a vote of Unit holders owning a majority of the Units. The Trust may also be terminated at the expiration of twenty-one (21) years after the death of the last to die of all of the issue living at the date of execution of this Trust Agreement of John D. Rockefeller, Jr., late father of the late former Vice President of the United States, Nelson A. Rockefeller.

Trust assets are depleting assets and, if the operators of the properties do not perform additional development projects, the assets may deplete faster than expected.

The net proceeds payable to the Trust are derived from the sale of depleting assets. Accordingly, the portion of the distributions to Unit holders attributable to depletion may be considered a return of capital. The reduction in proved reserve quantities is a common measure of depletion. Future maintenance and development projects on the properties will affect the quantity of proved reserves. The timing and size of these projects will depend on the market prices of natural gas. If operators of the Properties do not implement additional maintenance and development projects, the future rate of production decline of proved reserves may be higher than the rate currently expected by the Trust. For federal income tax purposes, depletion is reflected as a deduction, which is dependent upon the purchase price of a unit. Please see the section entitled “— Tax Considerations to Owners of Units — Federal Income Tax Considerations” under Item 1 of this Form 10-K.

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 Trust’s 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 them 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.


Item 1B.	*Unresolved Staff Comments*

None.


Item 2.	*Properties*

Reference is made to “Item 1. Business” for the information required by this item.


Item 3.	*Legal Proceedings*

None.


Item 4.	*Submission of Matters to a Vote of Unit Holders*

None.

PART II


Item 5.	*Market for the Registrant’s 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, 2006 and 2005.

Since the cash distributions to Unit holders result from royalty and overriding royalty interests, the timing, duration and amount of future cash distributions will be dependent on the many and varied factors discussed throughout Part I hereto, which factors are beyond the control of the Trustee. The cash distributions to Unit holders for each quarterly period in the years ended December 31, 2006 and 2005 (applicable to production for October 2005 through September 2006 and October 2004 through September 2005) are also included in the table below.


	2006 Quarter Ended								2005 Quarter Ended
	March 31		June 30		Sept. 30		Dec. 31		March 31		June 30		Sept. 30		Dec. 31

Units of Beneficial Interest:
High sales price	$	3.40	$	3.79	$	3.40	$	3.41	$	8.29	$	7.75	$	6.52	$	4.75
Low sales price		2.01		2.16		2.40		2.59		6.04		4.91		4.30		1.90
Distributions per Unit	$	0.0000	$	0.0000	$	0.0202	$	0.0762	$	0.0789	$	0.1056	$	0.0835	$	0.0481

The total number of Unit holders of record as of March 28, 2007 was 3,869.


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.


	Years Ended December 31,
	2006		2005		2004		2003		2002

Revenues	$	3,068,638	$	7,354,827	$	10,857,596	$	8,496,041	$	2,616,241
Cash earnings		2,094,226		6,586,512		10,178,621		7,869,942		2,055,121
Cash distributions to Unit holders		1,831,080		6,002,945		10,177,500		7,882,218		2,076,828
Cash distributions per Unit	$	0.0964	$	0.3161	$	0.5359	$	0.4150	$	0.1094
Trust Corpus	$	2,616,186	$	2,393,340	$	1,827,273	$	1,909,252	$	2,046,528


Item 7.	*Management’s 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 Trust’s interest.

(b) Trust expenses, which include accounting, engineering, legal and other professional fees, Trustee’s fees and out-of-pocket expenses, are recorded on a cash basis.

(c) Amortization of the net overriding royalty interests in productive oil and gas properties and the 3 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 Trust’s royalty interests in oil and gas properties represents the Company’s cost on a successful efforts basis (net of accumulated depreciation, depletion and amortization) at June 28, 1983 applicable to the interests in the properties transferred to the Trust. The unamortized balance at December 31, 2006 is not indicative of the fair market value of the interests held by the Trust.

The preparation of the financial statements requires estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates.

While these statements differ from financial statements prepared in accordance with accounting principles generally accepted in the United States of America, the cash basis of reporting revenues and expenses is considered to be the most meaningful because monthly distributions to the Unit holders are based on net cash receipts.

The unaudited data included in Item 1 and the financial statements and notes thereto in Item 8 are an integral part of this discussion and analysis and should be read in conjunction herewith.

Liquidity and Capital Resources

As stipulated in the Trust Agreement, the Trust is intended to be passive, and the Trustee’s activities are limited to the receipt of revenues attributable to the Royalties, which revenues are to be distributed currently (after payment of or provision for Trust expenses and liabilities) to the owners of the Units. The Trust has no source of liquidity or capital resources other than the revenue, if any, attributable to the Royalties.

Status of the Trust

Net revenues to the Trust for the year ended December 31, 2006, calculated as described above, were $2,094,226, thus triggering year one of the Trust’s termination provision. Should the Trust’s net revenues for the year ended December 31, 2007 also fall below the $5,000,000 termination threshold; the Trust will be required to terminate effective December 31, 2007.

As discussed above, 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 (Quantum). Quantum is expected to become the operator in April 2007 and plans to undertake a different operating and development strategy for Jay Field than the previous operator. Quantum has informed the Trustee that it plans to reduce costs by terminating the purchase and injection of nitrogen gas, conversion of the nitrogen injection lines to water injection, installation of gas lift on production wells, and the reactivation of the available water supply wells with new electrical submersible pumps to increase the current water injection levels in order to compensate for the cessation of nitrogen injection. While this program has the potential to reduce costs and increase production, as the timing of Quantum’s succession takes place half-way through the Trust’s production year, it is uncertain whether the potential benefits will be sufficient to affect the Trust’s net revenues or to affect the potential termination of the Trust on December 31, 2007.

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

Offshore Properties:

East Cameron 336

East Cameron 195

The East Cameron 195 platform was heavily damaged during Hurricane Rita; however, it was not a significant producer, and had been shut in by the operator, Maritech, and had been approved for abandonment prior to Hurricane Rita. The operator’s 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, for which no cost estimates have been received. Well abandonment work began in February, 2006 and was substantially finished in December, 2006.

South Marsh Island 76

The South Marsh Island 76 platform was heavily damaged during Hurricane Rita. The operator, Mariner Corporation, has provided an estimate of $3,600,000 ($900,000 net to the Trust) for diving costs, inspection and removal of the toppled platform deck from the seafloor, and to abandon a floor line. These costs do not include well or facility abandonment costs, for which no cost estimates, have been received. Only inspection and diving work has been done to date. The Working Interest Owner has cautioned the Trust that the operator may determine to plug and abandon the property rather than repair the platform and facilities.

Eugene Island 261

Vermillion 331

Jay Field

The Working Interest Owner has advised the Trustee that it is in the process of analyzing the scope and applicability of the insurance policies carried by the Working Interest Owner to the various types of damages that resulted from the storms, and is in the process of discussing these matters with the carrier’s claim adjusters. These discussions are continuing and the Working Interest Owner is continuing to gather documentation to support the claims for the repairs that have been made to the damaged properties, which is challenging especially as it relates to non-operated properties. Whether the Working Interest Owner will be successful, or to what extent it will be successful, in its attempt to obtain reimbursement for monies spent repairing hurricane damages, is uncertain. Additionally, should it be successful in its efforts, the timing of the reimbursement is also uncertain. Further, even if the Working Interest Owner receives reimbursements for expenses it has incurred, those reimbursements may not have any effect on amounts, if any, payable to the Trust.

The abandonment and repair costs estimated as described above are expected to have a material adverse effect on royalties payable from the Offshore Louisiana and South Pass 89 properties to the Trust, and from the Trust to Unit holders, for an extended period of time. As previously disclosed, the Working interest Owner began escrowing funds otherwise distributable to the Trust from the Offshore Louisiana and South Pass 89 property, beginning with the April 2006 monthly distribution. Consequently, distributions from the Trust to the Unit holders are expected to be reduced significantly or eliminated for an extended period of time.

Whether the Trust’s net revenues for the year ending December 31, 2007 are above the Termination Threshold will depend on the timing of repairs to damaged properties in which the Trust has an interest, oil and natural gas prices for 2007, timing and level of hydrocarbon production, which could vary significantly from the projected production in the reserve report due to the change in the operator of the Jay Field, the level of capital expenditures, and other operational matters as well as administrative expenses of the Trust. Therefore, there can be no assurance that the net revenues of the Trust for the year ended December 31, 2007 may be above the Termination Threshold. For the first quarter of 2007, the Trust received approximately $600,000 in royalty revenue associated with the Jay Field and no royalty income was received from the Offshore Louisiana or South Pass 89 properties. Due to the uncertainty from the 2005 storms and the lack of significant royalty revenue received subsequent to December 31, 2006, there is substantial doubt regarding the Trust’s ability to continue as a going concern.

Other Matters Relating to the Termination of the Trust

In addition to the Trust terminating as a result of net revenues to the Trust of less than $5,000,000 for two successive years, the Trust may also be terminated at any time by a vote of Unit holders owning a majority of the Units and Trust may also be terminated at the expiration of twenty-one (21) years after the death of the last to die of all of the issue living at the date of execution of this Trust Agreement of John D. Rockefeller, Jr., late father of the late former Vice President of the United States, Nelson A. Rockefeller.

Upon the termination of the Trust, the Trustee will sell the assets of the Trust for cash (unless authorized by the holders of a majority of the Units to sell such assets for non-cash consideration 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 provisions for all then existing liabilities of the Trust, including fees of the Trustee, the Trustee will distribute all cash then held by it as promptly as practicable in its capacity as Trustee an, if necessary, will set up reserves in the amounts the Trustee deems appropriate to provide for payment of contingent liabilities. After the termination of the Trust, the Trustee will continue to act as Trustee for purposes of liquidating and winding up the affairs of the Trust.

proposed non-cash sale as described above, no approval of the Unit holders will be required or solicited in connection with the sale of the Trust’s assets after termination of the Trust.

See Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Results of Operations


	Years Ended December 31,
	2006			2005			2004

Royalty Revenues	$	3,068,638		$	7,354,827		$	10,857,596
Trust administrative expenses		(974,412	)		(768,315	)		(678,975	)

Cash earnings	$	2,094,226		$	6,586,512		$	10,178,621
Changes in undistributed cash		(263,146	)		(583,567	)		(1,121	)

Cash distributions	$	1,831,080		$	6,002,945		$	10,177,500

Cash distributions per unit	$	0.0964		$	0.3161		$	0.5359

Units outstanding		18,991,304			18,991,304			18,991,304

Revenues are generally received in the third month following the month of production of oil and gas attributable to the Trust’s interest. Both revenues and expenses are recorded on a cash basis. Accordingly, distributions to Unit holders for the years ended December 31, 2006, 2005 and 2004 are attributable to the Working Interest Owner’s operations during the twelve-month periods ended September 30, 2006, 2005 and 2004, respectively.

Administrative expenses incurred by the Trust increased approximately $206,000 or 27 percent for the year ended December 31, 2006 as compared to the year ended December 31, 2005. The increase in 2006 administrative expenses was primarily a result of increases in accounting and printing fees incurred by the Trust.

Distributions to Unit holders for 2006, 2005 and 2004 amounted to $1,831,080 ($0.0964 per Unit), $6,002,945 ($0.3161 per Unit) and $10,177,500 ($0.5359 per Unit) respectively. During these years, the Trust received cash of $3,068,638, $7,354,827 and $10,857,596, respectively, from the Working Interest Owner with respect to the Royalties from the Properties.

The following unaudited schedule provides a summary of the Working Interest Owner’s calculation of the Net Proceeds from the Properties and the Royalties paid to the Trust for the respective years.


	Years Ended December 31,
	2006			2005			2004

Net Proceeds:
Revenues	$	30,199,489		$	35,882,309		$	33,137,067
Amounts withheld in escrow		(2,096,559	)		—			—
Production costs and expenses		(19,076,533	)		(18,101,873	)		(14,849,569	)
Capital expenditures		(5,042,463	)		(8,367,167	)		(7,903,159	)

Net Proceeds	$	3,983,934		$	9,413,269		$	10,384,339

Royalties paid to the Trust:
Overriding Royalties	$	2,726,914		$	6,996,298		$	10,128,734
Fee Lands Royalties		341,724			358,529			728,862

Royalties paid to the Trust	$	3,068,638		$	7,354,827		$	10,857,596

Revenues of the Working Interest Owner with respect to the Productive Properties decreased approximately $5,700,000 or 16 percent during the 2006 operating period compared to the same operating period in 2005. The decrease in revenues is primarily a result of a decrease in natural gas and crude oil production volumes in 2006 as

compared to 2005 due to operational problems, primarily as a result of Hurricanes Rita and Katrina, as well as, the natural production decline of the fields. The decrease in revenues caused by lower production volumes was partially offset by an increase in natural gas, natural gas liquid, and crude oil prices. Revenues increased approximately $2,700,000 in 2005 as compared to the same period in 2004 primarily due to an increase in natural gas, natural gas liquid and crude oil prices in 2005 as compared to 2004 partially offset by higher natural gas prices. The increase in revenues due to higher prices was partially offset by a decline in produced volumes primarily related to operational problems resulting from hurricanes and tropical storms at the Jay Field and natural production decline of the Offshore Louisiana property, South Marsh Island in 2005.

Average natural gas prices received in 2006 increased to $8.68 per thousand cubic feet (“mcf”) from $7.31 per mcf in 2005. Average crude oil prices increased to $63.87 per barrel in 2006 from $50.60 per barrel in 2005 while natural gas liquids prices increased to $48.41 per barrel in 2006 from $35.39 in 2005. Average natural gas prices increased in 2005 to $7.31 per mcf from $5.66 per mcf in 2004. Average crude oil prices increased to $50.60 per barrel in 2005 from $35.28 per barrel in 2004 and natural gas liquids prices increased to $35.39 per barrel in 2005 from $29.69 in 2004.

In 2006, the Working Interest Owner reserved $2,096,559 in escrow as a result of uncertainties related to the oil and gas properties. No amounts were reserved in 2005 and 2004.

Production costs and expenses incurred by the Working Interest Owner on the Productive Properties increased approximately $1,000,000, or 5 percent, between the 2006 operating period and the 2005 operating period. The increase in 2006 was primarily attributed to the repair of damages caused by Hurricane Rita, at Offshore Louisiana locations. Additionally, lease operating expenses increased at South Pass 89, as a result of increased non-operated workover costs, increased overhead expenses, increased insurance costs, and decreased outside processing credits. Production costs and expenses increased approximately $3,300,000, or 22 percent, during the 2005 operating period compared to the same period in 2004. The increase in 2005 was primarily due to higher non-operated labor costs and increased workover and repair expenses at the Jay Field.

Production costs recorded by the Working Interest Owner in 2006 include injected nitrogen expenses. In 2005, the previous Working Interest Owner, Burlington Resources, included injected nitrogen expenses in capital expenditures. The change resulted in a $2,700,000 increase in production costs, but no effect on royalties paid to the Trust. This increase was offset due to a reduction in workover and overhead expenses.

Capital expenditures decreased approximately $3,300,000, or 40 percent, between 2006 and 2005. The decrease in 2006 was primarily the result of the Working Interest Owner’s accounting reclassification for nitrogen injection charges, resulting in a $2,700,000 reduction of capital expenses at the Jay Field as described above. Capital expenditures increased $464,008 or 6 percent in 2005 as compared to 2004. The increase in capital expenditures in 2005 was primarily due to an increase in developmental drilling costs at Jay Field, resulting in three new wells being drilled.

The Trust’s Fee Lands Royalties did not change significantly in the 2006 operating period compared to the same period in 2005. The Trust’s Fee Lands Royalties decreased approximately $370,000 or 51 percent in the 2005 operating period compared to the same period in 2004. The Fee Lands Royalties for 2004 included a one-time, lump-sum payment of approximately $357,000 for royalties related to the Bayou Sauvier Field. This payment represents earnings from a royalty interest in Bayou Sauvier for approximately 18 months of production. The amount of Fee Lands leased as of December 31, 2006 and December 31, 2005 was approximately 1,015 acres.

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.

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 Trust’s 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. As described in detail elsewhere herein, the Trust’s monthly distributions are highly dependent upon the prices realized from the sale of oil and natural gas. Oil and natural gas prices can fluctuate widely on a month-to-month basis in response to a variety of factors that are beyond the control of the Trust and the Working Interest Owner. Factors that contribute to price fluctuation include, among others:


	•	political conditions worldwide, in particular political disruption, war or other armed conflicts in oil producing regions;

	•	worldwide economic conditions;

	•	weather conditions;

	•	the supply and price of foreign natural gas;

	•	the level of consumer demand;

	•	the price and availability of alternative fuels;

	•	the proximity to, and capacity of, transportation facilities; and

	•	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.


Item 8.	*Financial Statements and Supplementary Data*

LL&E ROYALTY TRUST

STATEMENTS OF CASH EARNINGS AND DISTRIBUTIONS
Years Ended December 31, 2006, 2005 and 2004


	2006			2005			2004

Royalty revenues	$	3,068,638		$	7,354,827		$	10,857,596
Trust administrative expenses		(974,412	)		(768,315	)		(678,975	)

Cash earnings	$	2,094,226		$	6,586,512		$	10,178,621
Changes in undistributed cash		(263,146	)		(583,567	)		(1,121	)

Cash distributions	$	1,831,080		$	6,002,945		$	10,177,500

Cash distributions per unit	$	0.0964		$	0.3161		$	0.5359

Units outstanding		18,991,304			18,991,304			18,991,304

STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS

December 31, 2006 and 2005


	2006			2005

ASSETS
Cash	$	848,086		$	584,940
Net overriding royalty interests in productive oil and gas properties and 3% royalty interests in fee lands (notes 3, 4, 6 and 7)		76,282,000			76,282,000
Less accumulated amortization (notes 4 and 6)		(74,513,900	)		(74,473,600	)

Total assets	$	2,616,186		$	2,393,340


LIABILITIES AND TRUST CORPUS
Trust corpus (18,991,304 Units of Beneficial Interest authorized, issued and outstanding)	$	2,616,186		$	2,393,340

Contingencies (notes 5, 7, 8 and 9)
Total liabilities and Trust corpus	$	2,616,186		$	2,393,340

STATEMENTS OF CHANGES IN TRUST CORPUS

Years Ended December 31, 2006, 2005 and 2004


	2006			2005			2004

Trust corpus, beginning of period (note 4)	$	2,393,340		$	1,827,273		$	1,909,252
Cash earnings		2,094,226			6,586,512			10,178,621
Cash distributions		(1,831,080	)		(6,002,945	)		(10,177,500	)
Amortization of royalty interests (notes 4 and 6)		(40,300	)		(17,500	)		(83,100	)

Trust corpus, end of period	$	2,616,186		$	2,393,340		$	1,827,273

See accompanying notes to financial statements.

LL&E ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS

December 31, 2006, 2005 and 2004

(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 Company’s then unleased, undeveloped south Louisiana fee lands (Fee Lands). The Overriding Royalties and the Fee Lands Royalties are referred to collectively as the “Royalties.” Title to the Royalties is held by a partnership (Partnership) of which the Trust and the Company are the only partners, holding 99 percent and 1 percent interests, respectively.

The Trust is passive, with The Bank of New York 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. On April 8, 2006, JPMorgan Chase and The Bank of New York Trust Company, N.A. announced an agreement pursuant to which The Bank of New York Trust Company, N.A. would acquire JPMorgan Chase’s corporate trust business. The transaction was effective October 2, 2006, The Bank of New York Trust Company, N.A. succeeded JPMorgan Chase Bank, N.A. as Trustee. The Units are listed on the New York Stock Exchange (NYSE SYMBOL — LRT).

Status 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 (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 Owner or the Partnership under escrow arrangements or to make refund payments pursuant to the Conveyance (the Trust’s 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 year ended December 31, 2006, as calculated above, were $2,094,226, thus triggering year one of the Trust’s termination provision. Should the Trust’s net revenues for the year ended December 31, 2007 also fall below the $5,000,000 termination threshold; the Trust will be required to terminate effective December 31, 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. Certain of the Offshore Louisiana and South Pass 89 properties sustained substantial damage. As a result of the damage to these two properties, the Working Interest Owner began escrowing all funds otherwise distributable from the Offshore Louisiana and South Pass 89 properties beginning with the April 2006 distribution. Distributions to the Trust from these properties are expected to be eliminated for an extended period of time. Also during 2005, Hurricane Dennis and Tropical Storm Cindy affected the operational status of the gas plant at Jay Field until the damage was repaired in April 2006. As a result of the uncertainty of future proceeds from these properties, the Trustee reserved $848,086 that otherwise would have been distributed to

LL&E ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS — (Continued)

the unitholders for the payment of the Trust’s 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 relating to the operational status of the properties was 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

Offshore Properties:

East Cameron 336

East Cameron 195

South Marsh Island 76

LL&E ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS — (Continued)

or facility abandonment costs, for which no cost estimates have been received. Only inspection and diving work has been done to date. The Working Interest Owner has cautioned the Trust that the operator may determine to plug and abandon the property rather than repair the platform and facilities.

Eugene Island 261

Vermillion 331

Jay Field

The most recent Trust model prepared by Miller and Lents, Ltd., which is based on natural gas and oil prices as of September 30, 2006, projects net revenues to the Trust will be greater than $5,000,000 for the year ended December 31, 2007. However, the damage to the facilities described above, changes in prices, changes in the operator of the Jay Field, and other factors could cause the termination of the Trust on December 31, 2007.

In addition to the Trust terminating as a result of net revenues to the Trust of less than $5,000,000 for two successive years, the Trust may also be terminated at any time by a vote of Unit holders owning a majority of the Units and Trust may also be terminated at the expiration of twenty-one (21) years after the death of the last to die of all of the issue living at the date of execution of this Trust Agreement of John D. Rockefeller, Jr., late father of the late former Vice President of the United States, Nelson A. Rockefeller.

Upon the termination of the Trust, the Trustee will sell the assets of the Trust for cash (unless authorized by the holders of a majority of the Units to sell such assets for non-cash consideration 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 provisions for all then existing liabilities of the Trust, including fees of the Trustee, the Trustee will distribute all cash then held by it as promptly as practicable in its capacity as Trustee an, if necessary, will set up reserves in the amounts the Trustee deems appropriate to provide for payment of contingent liabilities. After the termination of the Trust, the Trustee will continue to act as Trustee for purposes of liquidating and winding up the affairs of the Trust.

LL&E ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS — (Continued)

proposed non-cash sale as described above, no approval of the Unit holders will be required or solicited in connection with the sale of the Trust’s assets after termination of the Trust.

(2) Going Concern

The accompanying financial statements have been prepared assuming that the Trust will continue as a going concern. As discussed in Note 1, the Trust’s net revenues did not exceed the $5,000,000 Termination Threshold stipulated by the Trust Agreement, thus triggering year one of the termination provision. In the event that the Trust’s net revenues for the year ended December 31, 2007 do not exceed $5,000,000, the Trust will terminate effective December 31, 2007.

Whether the Trust’s net revenues for the year ending December 31, 2007 exceed the Termination Threshold will depend on the timing of repairs to damaged properties in which the Trust has an interest, oil and natural gas prices for 2007, timing and level of hydrocarbon production, which could vary significantly from the projected production in the reserve report due to the change in the operator of the Jay Field, the level of capital expenditures, and other operational matters as well as administrative expenses of the Trust. Therefore, there can be no assurance that the net revenues of the Trust for the year ended December 31, 2007 may be above the Termination Threshold.

For the first quarter of 2007, the Trust received approximately $600,000 in royalty revenue associated with the Jay Field and no royalty income was received from the Offshore Louisiana or South Pass 89 properties. The South Pass 89 and Offshore Louisiana properties excess production costs as of March 31, 2007 totaled $822,000 and $4,612,000, respectively. The excess production costs must be recovered by the Working Interest Owner before any distribution of royalty revenue to the Trust. Due to the uncertainty from the 2005 storms and the lack of significant royalty revenue received subsequent to December 31, 2006, there is substantial doubt regarding the Trust’s ability to continue as a going concern. The accompanying financial statements do not include any adjustments that might result from the outcome of this uncertainty.

(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 5 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, 2006, the Fee Lands consisted of approximately 22,420 gross acres.

LL&E ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS — (Continued)

(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 Trust’s interest.

(b) Trust expenses, which include accounting, engineering, legal and other professional fees, Trustee’s fees and out-of-pocket expenses, are recorded on a cash basis.

(c) Amortization of the net overriding royalty interests in productive oil and gas properties and the 3% royalty interest in Fee Lands, which is calculated on a unit-of-production basis, is charged directly to the Trust corpus since the amount does not affect cash earnings. Amortization calculated for interim periods is based on the annual reserve study prepared by independent petroleum engineers as of September 30 of the preceding year. Amortization calculated in the fourth quarter is based on the current year reserve study.

(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.

LL&E ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS — (Continued)

The Company withdrew its requested ruling (d) that the Company did not recognize gain or loss upon the transfer of the Royalties to the Trust or upon distribution of the Units to its stockholders because the IRS proposed to rule that the transfer and distribution resulted in the recapture of ordinary income attributable to intangible drilling and development costs under Section 1254 of the Code (IDC Recapture Income). Counsel for the Company expressed no opinion on this issue. The Company and the IRS subsequently litigated the issue, and in 1989 the Tax Court rendered an opinion favorable to the Company. The Tax Court held that the Company’s transfer of the Royalties to the Trust and its distribution of the Units to its stockholders did not constitute a disposition of “oil, gas, or geothermal property” within the meaning of Section 1254 of the Code. Consequently the Company was not required to recognize IDC Recapture Income on the disposition of the Royalties. The opinion of the Tax Court has become final and nonappealable.

These financial statements are prepared on the basis that the Trust will be treated as a “grantor” trust and the Partnership will be treated as a partnership for federal income tax purposes. Accordingly, no income taxes are provided in the financial statements.

(6) Impairment

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.

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. There was no impairment recorded for the year ended December 31, 2005 or 2004.

(7) Dismantlement Costs

According to the September 30, 2006 reserve report, included in the Trust’s Annual Report on Form 10-K for the year ended December 31, 2006, the total future dismantlement costs to the Working Interest Owner are estimated to be $14,200,000 for the Jay Field property, $5,500,000 for the South Pass 89 property, and $6,900,000 million for the Offshore Louisiana property. The Trust’s 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 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 2006, the Working Interest Owner has withheld $2,031,950 and $64,609 in escrow from the Offshore Louisiana and South Pass properties. All costs withheld were expended in 2006.

LL&E ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS — (Continued)

The cumulative escrow balance as of December 31, 2006 was $4,543,402 for the Jay Field property and $678,842 for the South Pass 89 property, 50 percent of which would otherwise have been distributable to the Trust. At December 31, 2006, there was no cumulative escrow balance for the Offshore Louisiana property. 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.

(8) Contingencies

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.

(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, 2006, 2005 and 2004. 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 Trust’s interests) by the ratio of estimated future net revenues to the Trust to estimated future gross revenues to the Working Interest Owner prior to taking into consideration the Trust’s interests. Estimates of future net revenues were prepared in accordance with guidelines established by the Securities and Exchange Commission and thus were based on prices and costs represented by the Working Interest Owner to be in effect as of September 30, 2006, 2005 and 2004.

Accordingly, the tables below presents the quantities of estimated proved reserves imputed to the Trust’s interest and the present value of estimated future net revenues attributed to such proved reserves. The tables below also present the changes in the estimated proved reserves imputed to the Trust’s interests and the changes in the present value of estimated future net revenues attributed to the Trust’s interests for the years ended September 30, 2006, 2005 and 2004 (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. The Working Interest Owner has informed the Trustee that it has budgeted additional amounts based on the development of proved reserves and on other projects designed to find and develop reserves not included in the Miller and Lents reports. In addition, the estimates should be evaluated in light of the many uncertainties inherent in estimating oil and gas reserve quantities and in forecasting production

LL&E ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS — (Continued)

levels, prices and operating costs. See “Item 1. Business — Estimates of Petroleum Engineers” for further discussion of the computational aspects of such data and the uncertainties and other matters which could affect such estimates.

Present Value of Estimated Future Net Revenues from Proved Reserves


	September 30,
	2006			2005			2004
	(In thousands)

The Trust’s proportionate share of future gross proceeds	$	116,277		$	225,089		$	230,204
Less the Trust’s proportionate share of — Future operating costs		(3,844	)		(3,859	)		(4,430	)
Future capital costs		(10,103	)		(10,638	)		(12,083	)
Excess production costs		(3,155	)		(2,155	)		(2,486	)

Future royalty income		99,175			208,437			211,205
Discount at 10% per annum		(49,206	)		(94,069	)		(115,843	)

Standardized measure of future royalty income from proved oil and gas reserves	$	49,969		$	114,368		$	95,362

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, 2003		2,501			4,753		$	38,811
Production		(88	)		(1,287	)	$	(10,858	)
Revisions of estimates(1)		1,870			1,869			63,528
Extensions, discoveries and other additions		—			—			—
Accretion of discount		na			na			3,881

Estimated at September 30, 2004		4,283			5,335		$	95,362

Production		(56	)		(602	)	$	(7,355	)
Revisions of estimates(1)		(1,249	)		1,530			16,825
Extensions, discoveries and other additions		—			—			—
Accretion of discount		na			na			9,536

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

LL&E ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS — (Continued)

The computation of the present value of future net revenues relating to proved reserves at September 30, 2006 was based on spot market prices in effect as of September 30, 2006, of $4.175 per MMBtu for natural gas, of $61.04 per barrel for crude oil and of $49.56 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 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, 2006, base prices were $62.92 per barrel for oil, $3.66 per MMBtu for gas, and $ per barrel for natural gas liquids. For the year ended September 30, 2005, base prices were $65.00 per barrel for oil, $15.00 per MMBtu for gas, and $49.56 per barrel for natural gas liquids.

(10) Selected Quarterly Financial Data (Unaudited)


	Summarized Quarterly Results
	Three Months Ended
	March 31		June 30		September 30		December 31

2006:
Royalty revenues	$	432,197	$	297,042	$	689,169	$	1,650,230
Cash distributions	$	—	$	—	$	383,018	$	1,448,062
Cash distribution unit	$	0.0000	$	0.0000	$	0.0202	$	0.0762
2005:
Royalty revenues	$	1,710,710	$	2,253,155	$	1,708,845	$	1,682,117
Cash distributions	$	1,497,987	$	2,005,536	$	1,586,650	$	912,772
Cash distribution unit	$	0.0789	$	0.1056	$	0.0835	$	0.0481

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Bank of New York 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, 2006 and 2005, 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, 2006. 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, 2006 and 2005, and the cash earnings and distributions and changes in trust corpus for each of the years in the three-year period ended December 31, 2006, 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 described in Note 2 to the financial statements, net revenues in 2006 fell below the Termination Threshold stipulated by the Trust Agreement. The Trustee currently expects net revenues in 2007 will also fall below the Termination Threshold. Accordingly, the Trustee anticipates that the Trust will be required to terminate under the provisions of the Trust Agreement effective December 31, 2007 and there exists substantial doubt about the Trust’s ability to continue as a going concern. The 2006 financial statements do not include any adjustments that might result from the outcome of this uncertainty.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of LL&E Royalty Trust’s internal control over financial reporting as of December 31, 2006, based on criteria established in “Internal Control — Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated April 2, 2007 expressed an unqualified opinion on the Trustee’s assessment of, and the effective operation of, internal control over financial reporting.

KPMG LLP

Houston, Texas

April 2, 2007

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Bank of New York Trust Company, N.A., Trustee
and the Unit Holders of LL&E Royalty Trust:

We have audited the Trustee’s assessment, included in the accompanying report, the Trustee’s Report on Internal Control over Financial Reporting, that LL&E Royalty Trust (the “Trust”) maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in “Internal Control — Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Trustee is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on the Trustee’s assessment and an opinion on the effectiveness of the Trust’s internal control over financial reporting based on our audit.

We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating the Trustee’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s 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 company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s 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.

In our opinion, the Trustee’s assessment that LL&E Royalty Trust maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on criteria established in “Internal Control — Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, LL&E Royalty Trust maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria established in “Internal Control — Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the accompanying statements of assets, liabilities and trust corpus of LL&E Royalty Trust as of December 31, 2006 and 2005, 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, 2006, and our report dated April 2, 2007 expressed an unqualified opinion on those financial statements.

KPMG, LLP

Houston, Texas

April 2, 2007


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 SEC’s 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 Owner to the Trustee and its employees who participate in the preparation of the Trust’s 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 Trustee’s disclosure controls and procedures. Mike Ulrich, as Trust Officer of the Trustee, has concluded that these controls and procedures are effective.

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 Owner, the Trustee relies on (i) information provided by the Working Interest Owner, 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 Trust’s 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 Owner.

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 Trust’s last fiscal quarter, no change in the Trust’s internal control over financial reporting was identified that has materially affected, or is reasonably likely to materially affect, the Trust’s 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 Owner.

The Trustee does not intend to expand its responsibilities beyond those permitted or required by the Trust Agreement and those required by applicable law.

Trustee’s 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 Trust’s 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 Trustee’s evaluation under the framework in “Internal Control-Integrated Framework,” the Trustee concluded that the Trust’s internal control over financial reporting was effective as of December 31, 2006. The Trustee’s assessment of the effectiveness of the Trust’s internal control over financial reporting as of December 31, 2006 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report which is included herein.

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 March 1, 2007 except that Adam Usdan and Trellus Management Company, LLC, 712 Main Street, Houston, Texas 77002, have filed a Schedule 13G with the Securities and Exchange Commission reporting beneficial ownership of 1,119,000 Units (5.89%) as of December 31, 2006.

(b) Unit Ownership of Management

The Working Interest Owner owns no Units. The Bank of New York Trust Company, N.A. as Trustee of the Trust, owns no Units. The Bank of New York, N.A. in its individual capacity (the “Bank”) also owns no Units. As of March 1, 2007, 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 Trust Company, N.A. 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 2006 and 2005 and fees billed for other services rendered by KPMG LLP.


	2006		2005

Audit fees(1)	$	275,000	$	205,000
Audit related fees		—		—
Tax fees(2)		179,000		100,000
All other fees		—		—

Total fees	$	454,000	$	305,000


(1)		Audit fees consist of fees for the audit of the LL&E Trust financial statements, internal control over financial reporting (in 2006) and reimbursement for travel related expenses.


(2)		Tax fees consist of fees related to the LL&E Trust’s 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.

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

Statements of Cash Earnings and Distributions — Years Ended December 31, 2006, 2005 and 2004		52
Statements of Assets, Liabilities and Trust Corpus — December 31, 2006 and 2005		52
Statements of Changes in Trust Corpus — Years Ended December 31, 2006, 2005 and 2004		52
Notes to Financial Statements		53
Report of Independent Registered Public Accounting Firm		61
Report of Independent Registered Public Accounting Firm		62


	(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 Registrant’s 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.

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 Registrant’s Annual Report on Form 10-K for the period ended December 31, 1983 (Commission File No. 1-8518).


	Page
	number

PART I
ITEM 1 — Business		1
Introduction		1
Terms and Operation of the Trust		2
Creation and Operation of the Trust		2
Terms of the Conveyances		2
The Partnership		4
Receipts and Payments		4
Liabilities and Contingency Reserves		4
Duration and Termination of the Trust		5
Other Matters Relating to the Termination of the Trust		8
The Royalties		9
Overriding Royalties		9
Fee Lands Royalties		10
Analysis of the Working Interest Owner’s Calculation of the Royalties		11
The Units		12
Distributions and Income Computations		12
Transfer of Units		12
Periodic Reports		12
Possible Requirement That Units Be Divested		13
Liability of Unit Holders		14
Voting by Unit Holders		14
Certain State Law Considerations		14
The Properties		15
General		15
Description of Productive Properties		15
Description of the Fee Lands		16
Oil and Gas Sales from the Productive Properties		17
Oil Sales		17
Gas and Liquids Sales		17
Exploration and Development Activities		18
Productive Properties		18
Fee Lands		19
Estimates of Petroleum Engineers		19
September 30, 2006 Estimates		19
Certain Factors Affecting Estimates		19
Industry Conditions and Regulation		29
Industry Conditions		29
Regulation		29
Tax Considerations to Owners of Units		29
Federal Income Tax Considerations		29
IDC Recapture Income to the Company on Distribution		37
Backup Withholding		37
Information Return Filing Requirements		38


		categories. Future excess production costs will be recouped out of total proved production regardless of reserve category.

(3)		Proved Undeveloped Reserves associated with the Eugene Island Block 261 well A-6ST were uneconomic under current economic conditions.


		production may vary slightly from the timing associated with the separate proved reserve categories. Future excess production costs will be recouped out of total proved production regardless of reserve category.

⁽³⁾		Proved Undeveloped Reserves associated with the Eugene Island Block 261 well A-6ST were uneconomic under current economic conditions.


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.


RE:	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002