SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

 

 

FORM 10-K

 

 

 

 

(Mark One)

 

For the Fiscal Year ended December 31, 2009

 

OR

 

 

Commission File Number: 1-8518

LL&E ROYALTY TRUST

(Exact name of registrant as specified in its charter)

 

 

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

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

 

 

Securities registered pursuant to Section 12(g) of the Act: Units of Beneficial Interest

 

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 Section 15(d) of the 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 o     No þ

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes o     No o

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of 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, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

(Do not check if a smaller reporting company)

 

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

 

As of June 30, 2009, 18,991,304 Units of Beneficial Interest were outstanding, and the aggregate market value of Units (based upon the closing price of the Units as reported on Yahoo! Finance) held by nonaffiliates was approximately $10,445,217.

 

As of August 1, 2011, 18,991,304 Units of Beneficial Interest were outstanding in LL&E Royalty Trust.

 

Documents Incorporated by Reference: None

 

 

TABLE OF CONTENTS

 

 

All statements, other than statements of historical fact, contained in this Annual Report on Form 10-K, including statements of estimated oil and gas production and reserves, drilling plans, future cash flows, anticipated capital expenditures and Working Interest Owners’ or operators’ strategies, plans and objectives, are “forward looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Although the Working Interest Owners have advised the Trust that they believe that the forward looking statements are based on reasonable assumptions, such statements are subject to a wide range of risks and uncertainties incident to the exploration for, development and marketing of oil and gas, and no assurance can be given that the estimates and expectations will be realized. In addition, all statements regarding future activities, events or expectations regarding or relating to the sale of the Trust’s assets are “forward looking statements.” Important factors that could cause actual results to differ materially from the forward looking statements include, but are not limited to, changes in production volumes, worldwide demand and commodity prices for petroleum natural resources; the timing and extent of the operators’ success in developing and producing oil and gas reserves; risks incident to the drilling and operation of oil and gas wells; future production and development costs; the effect of existing and future laws, governmental regulations and the political and economic climate of the United States; and conditions in the capital markets and market for oil and gas royalty assets similar to those held by the Trust. Other risk factors are discussed elsewhere in this Form 10-K, including the risk factors described under Item 1A — Risk Factors.

Special Note

 

Along with this report on Form 10-K for the year ended December 31, 2009, LL&E Royalty Trust is filing its quarterly reports on Form 10-Q for the first, second and third quarters of 2009 and 2010 and its annual report on Form 10-K for the year ended December 31, 2010 (collectively, the “Delayed Filings”). These reports were delayed due to the previously reported difficulties the Trust encountered with the calculation of the Jay Field royalties furnished to the Trust by Quantum Resources Management LLC (“Quantum”), which is the operator of the Jay Field and the owner of the working interest owner from which the Trust’s royalty interest was created. You should review all of the Delayed Filings concurrently, and should not rely on any of the Delayed Filings without having reviewed the most recent filings made by the Trust.

 

As previously disclosed, the Trustee engaged an independent joint interest auditing firm (the “Consultant”), to review Quantum’s computation of the amounts payable to the Trust with respect to its interest in the Jay Field from the time of the sale by The Louisiana Land and Exploration Company (“LL&E”) of its working interest to Quantum Resources Management LLC in 2007 through August 2008 (the “First Review Period”). Also as previously disclosed, the Consultant completed its review of the First Review Period, and Quantum and the Trustee reached agreement on the issues the Consultant had raised relating to the computation of expenses properly chargeable in the calculation of amounts payable to the Trust for the First Review Period.

 

Also as previously disclosed, the Trustee subsequently engaged the Consultant to review the computation of the amounts payable to the Trust with respect to its interest in the Jay Field for the production months September 2008 through March 2010 (the “Second Review Period”). The Consultant concluded its review of the Second Review Period, and Quantum and the Trustee resolved all material issues raised by the Consultant. The Trustee determined that it was able to prepare the Trust’s financial statements for the year ended December 31, 2009, which are included in this report.

 

As disclosed in the Trust’s filings for several years, the Trust is now required by the terms of the Trust Agreement to sell its assets and to liquidate. As previously disclosed, the Trustee engaged Stifel, Nicolaus & Company, Incorporated, a nationally-recognized investment banking firm (the “Financial Advisor”) to market the Trust’s assets in anticipation of a sale in accordance with the terms of the Trust Agreement. The Financial Advisor marketed the Trust’s assets and had received preliminary indications of interest in late 2010, and the Trustee intended to sell the assets in accordance with the terms of the Trust Agreement. However, as previously announced, in November 2010, the Trust and Trustee were named as defendants in a Complaint for Legal and Equitable Relief (the “Complaint”) filed by Jeff Beckett in the United States District Court for the Eastern District of Michigan. Mr. Beckett’s Complaint seeks a judicial modification of the terms of the Trust Agreement governing the Trust, a judgment declaring that the termination provisions of the Trust Agreement do not apply and an order preventing the sale of the Trust’s assets. The Complaint also makes a number of other allegations and seeks removal of the Trustee and other relief.

 

As a result of Mr. Beckett’s lawsuit, certain bidders who had submitted preliminary indications of interest to the Financial Advisor indicated that they were unwilling to proceed with the purchase of the Jay Field interest from the Trust until the Beckett lawsuit was resolved. Consequently, as previously disclosed, the Trustee suspended the sale process pending resolution of the lawsuit.

 

The Trustee has been requested by a holder of more than 10% of the Units to call a meeting of the Unitholders for the purpose of voting to remove The Bank of New York Mellon Trust Company, N.A. as Trustee and to appoint a successor trustee of the Trust. The Trustee called the meeting and filed definitive proxy materials with the SEC. On August 9, 2011 the proposed successor informed the Trustee that it was no longer willing to serve as successor trustee. The meeting was convened as scheduled on August 12, 2011, but was adjourned until August 24, 2011 as a result of the withdrawal of the successor. In connection with the calling of the meeting, the parties to the Beckett lawsuit entered into a settlement agreement as described in this report.

 

Additional information regarding the status of the Beckett lawsuit, the status of the sale of the Trust’s assets, the computation of the Jay Field Royalties and related matters is included in this report.

 

 

LL&E Royalty Trust (the “Trust”) was created under the laws of the State of Texas on June 28, 1983 pursuant to a Trust Agreement (the “Trust Agreement”) between The Louisiana Land and Exploration Company (including its successors, as the context requires, the “Company”) and First City National Bank of Houston. Since October 2, 2006, The Bank of New York Mellon Trust Company, N.A. has served as Trustee. The 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(s) includes the successors and assigns of such working interests, including Quantum Resources Management, LLC, as assignee of the working interest in the Jay Field Productive Property (as defined below), which assignment occurred on December 21, 2006.

 

Upon creation of the Trust, the Company conveyed to the Trust (a) net overriding royalty interests (equivalent to net profits interests) (the “Overriding Royalties”) in certain productive oil and gas properties located in Alabama, Florida and in federal waters offshore Louisiana (the “Productive Properties”) and (b) 3 percent royalty interests (the “Fee Lands Royalties”) in certain of the 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, protection and sale of the Trust estate.

 

Units of Beneficial Interest (the “Units”) in the Trust were distributed by the Company to holders of record of its capital stock on June 22, 1983 on the basis of one Unit for each two shares of capital stock owned on such date. Each of the Units evidences an undivided interest in the Trust, which owns a 99 percent interest in the Partnership, which holds title to the Royalties. The Unit holders participate in the revenues resulting from the Royalties. See “Tax Considerations to Owners of Units — Federal Income Tax Considerations”.

 

In accordance with the Trust Agreement, the Trust is required to terminate, sell the Royalties and liquidate the assets of the Trust. On November 11, 2009, the Trust sold its interest in the Fee Lands. The sale resulted in cash proceeds to the Trust of approximately $500,000. However, the sale of the rest of the Royalties has been delayed as a result of the lawsuit described in this report. The status of the sale of the Royalties, the liquidation of the Trust, the Beckett lawsuit and related matters are described below. The Trustee intends to continue to serve as such until the affairs of the Trust are wound up or until a successor trustee is appointed. See Item 1 — “Terms and Operations of the Trust”.

 

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

 

As previously disclosed and as described herein, during 2009, Quantum Resources Management, LLC, which operates the Jay Field Productive Property, temporarily suspended production at the Jay Field.

 

Pursuant to the Conveyances, the Overriding Royalties and Fee Lands Royalties were conveyed to the Trust and were then immediately assigned to the Partnership, which was formed to hold the Royalties. See “Terms and Operation of the Trust — The Partnership”. The Royalties are the only asset of the Trust, other than cash being held for the payment of expenses and liabilities and for distribution to the Unit holders. In accordance with the Trust Agreement, the Trustee intends to sell the Royalties and distribute the net proceeds, after payment of all expenses and establishing such reserves as the Trustee deems appropriate. See Item 1 — “Terms and Operations of the Trust — “Termination of the Trust”, — “Timing of Liquidation”, — “Status of Sale Efforts and Litigation” and — “Assets and Liabilities in the Process of Liquidation”. To simplify the discussion in this Form 10-K, the existence of the Partnership is sometimes ignored.

 

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

 

The Trustee may be removed and replaced 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 foregoing requirements do not apply to a successor appointed by the Unit holders.

 

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

 

The Trust Agreement provides that the Trust will terminate in the event that the net revenues fall below $5,000,000 for two successive years (“the Termination Threshold”). Net revenues are calculated as royalty revenues after administrative expenses of the Trust and as if the Trust had received its pro rata portion of any amounts being withheld by the Working Interest Owners or the Partnership under escrow arrangements or to make refund payments pursuant to the Conveyances (the Trust’s pro rata portion of escrowed amounts relating to the future abandonment of wells and dismantlement of platforms are included in the net revenue calculation for this purpose).

 

Net revenues to the Trust for the years ended December 31, 2007 and 2006 calculated as described above, were $1,634,740 and $2,094,226, respectively. Consequently, the Trust is required to terminate and is required to sell the assets of the Trust.

 

As a result of the termination of the Trust, the Trustee is required to sell the assets for cash in a public auction. See Item 1 — “Terms and Operation of the Trust — Status of Sale Efforts and Litigation” and “Management’s Discussion and Analysis”. After paying or making provision for all actual and contingent liabilities of the Trust, including fees of the Trustee, the Trustee will distribute any remaining cash as promptly as practicable. Despite the termination of the Trust, the Trustee is continuing to act as Trustee for purposes of liquidating and winding up the affairs of the Trust. The Trustee does not expect to make any further monthly distributions to Unit holders in the interim period prior to any distribution resulting from the sale of the Trust’s assets. See “Management’s Discussion and Analysis.”

The Trustee has retained Stifel, Nicolaus & Company, Incorporated, a nationally recognized investment banking firm (the “Financial Advisor”), to market the Trust’s assets. However, as announced by the Trustee on October 22, 2008, the Trustee previously determined that, in light of market conditions at that time, it was in the best interests of the Trust Unit holders to postpone the sale of the Trust’s assets for an indefinite period of time. The Trustee recommenced the marketing efforts in 2010. The Financial Advisor marketed the Trust’s assets and had received preliminary indications of interest in late 2010, and the Trustee intended to sell the assets in accordance with the terms of the Trust Agreement. However, as previously announced, in November 2010 the Trust and Trustee were named as defendants in a Complaint for Legal and Equitable Relief (the “Complaint”) filed by Jeff Beckett in the United States District Court for the Eastern District of Michigan. Mr. Beckett’s Complaint seeks a judicial modification of the terms of the Trust Agreement governing the Trust, a judgment declaring that the termination provisions of the Trust Agreement do not apply and an order preventing the sale of the Trust’s assets. The Complaint also makes a number of other allegations and seeks removal of the Trustee and other relief. On July 7, 2011, Mr. Beckett and the Trust entered into a settlement agreement pursuant to which Mr. Beckett agreed to dismiss his lawsuit with prejudice within ten days after the Trust holds a meeting of the Unit holders for the purpose of voting on a proposal to remove the Trustee and to appoint a successor trustee of the Trust, provided that notice of the meeting is mailed by August 1, 2011 and the meeting occurs by September 1, 2011. Notice of the meeting was mailed prior to August 1, 2011 and the meeting was convened on August 12, 2011. Because the proposed successor trustee withdrew its consent to serve shortly prior to the meeting, the meeting has been adjourned until August 24, 2011.

 

See Item 1 — “Terms and Operation of the Trust — Status of Sale Efforts and Litigation” and “Management’s Discussion and Analysis”.

 

The Trust Agreement provides that if any asset required to be sold has not been sold by December 31, 2010, the Trustee is to cause the asset to be sold at public auction to the highest cash bidder. Consequently, except to the extent that the Trustee is prevented from doing so by a court order, or is removed as Trustee, the Trustee intends to auction the Trust’s assets. In connection with the auction, the Trustee will mail notice of a public auction to all Unit holders at least 30 days prior to any such auction. See Item 1 — “Terms and Operation of the Trust — Status of Sale Efforts and Litigation” and “Management’s Discussion and Analysis”. No approval of the Unit holders will be required in connection with the sale of the Trust’s assets.

 

As of December 31, 2009, the Trust had only $3,741 in cash. At December 31, 2009, the Trust was holding unpaid invoices for administrative services totaling $393,577.

 

As of August 19, 2011, the Trust had no cash except for the cash advanced to the Trust by BNY Mellon, as affiliate of the Trustee, as an interest-free advance to enable the Trust to pay administrative expenses. As of August 19, 2011, the total amount advanced to the Trust (the “Bank Advance”) by the Bank was $2,255,520, of which $161,217 remained available to pay expenses at August 19, 2011. However, at August 19, 2011, in addition to the amount owed to the Bank, the Trust was also holding unpaid invoices for administrative services totaling $443,492. See Management’s Discussion and Analysis. The entire amount of the Bank Advance and all other liabilities and expenses of the Trust must be repaid before any distributions can be made to Unit holders.

 

If the Trust is unable to sell its assets and liquidate promptly, the Trust may attempt to borrow additional funds in accordance with the Trust Agreement to fund Trust expenses. However, the Trust will be prohibited from borrowing funds unless the Trustee determines that the total amount the Trust would then have borrowed is less than 50% of the amount of revenues the Trustee estimates will be received by the Trust during the immediately following six months. Consequently, unless the Trustee determines that the Trust’s assets will be sold within six months, no borrowings appear possible. Even if the Trust is able to proceed with the sale of its assets, the Trust may not be able to borrow funds. The Trust Agreement permits, but does not require, The Bank of New York Mellon Trust Company, N.A. or an affiliate to lend funds to the Trustee. The Trust Agreement prohibits the Trustee from making any distributions to Unit holders until the advances and any loans are repaid in full. If the Trust is unable to sell its assets or borrow additional funds, the Trust might have to be liquidated in bankruptcy.

 

During 2010 the Trust did not receive any royalty revenue except for $10,064 from the Fee Lands (which were sold in November 2009) and $223,910 received in 2010 as an adjustment resulting from a review conducted by an independent oil and gas accounting firm retained by the Trustee to review the Working Interest Owner’s calculation of the net proceeds properly payable to the Trust with respect to the Jay Field Property. The adjustment related to the

Working Interest Owner’s calculation of the net proceeds from the acquisition of the Jay Field working interest by Quantum Resources Management, LLC in 2007 through August 2008. The portion of the adjustment related to 2007, even if received in 2007, would not have affected the termination of the Trust in accordance with the terms of the Trust Agreement.

 

During 2009, the only royalty revenue the Trust received was $737,199 with respect to the South Pass 89 property and $70,905 from the Fee Lands. In addition, on November 11, 2009, the Trust sold its interest in the south Louisiana acreage described in the Trust’s public filings as the “Fee Lands”. The sale resulted in cash proceeds to the Trust, net of fees of $24,828 paid to the auction company that conducted the sale, of approximately $500,000.

 

During 2008, the Trust received a single payment of approximately $437,000 as a result of a review conducted by an independent oil and gas accounting firm retained by the Trustee to review the Working Interest Owner’s calculation of amounts relevant to the determination of the net proceeds properly payable to the Trust with respect to the Working Interest Owner’s inadvertent inclusion of sulfur extraction processing costs at the Jay and Little Escambia Creek Field Unit desulfurization plant in the calculation of Jay Field Gross Proceeds. The only other royalty revenue the Trust received in 2008 was $204,741 attributable to the Fee Lands Royalties and $37,239 attributable to South Pass 89.

 

During 2007, the Trust received a payment of approximately $1,566,000 with respect to Jay Field property and approximately $399,000 with respect to the Fee Land property. The Trust did not receive any royalty income from South Pass 89 or Offshore Louisiana properties.

 

The Jay Field, South Pass 89 and Offshore Louisiana properties excess production costs as of December 31, 2010 were approximately $13,588,000, $868,000 and $2,171,000, respectively. For the year ended December 31, 2009, they were $12,889,000, $373,000 and $3,227,000, respectively. For the year ended December 31, 2008, they were $10,930,000, $56,000 and $11,158,000, respectively. The excess production costs relating to each property must be recovered by the Working Interest Owners before any the Working Interest Owners are required to pay any royalty revenues to the Trust with respect to the particular property.

 

As previously described in the Trust’s filings, in addition to the Working Interest Owners’ rights to recover Excess Production Costs prior to making payments to the Trust, the Working Interest Owners have the right under the Conveyances to escrow or withhold amounts for certain anticipated future expenses, and the Working Interest Owners have done so and expect to continue doing so in the future. See Item 1 — “Terms and Operations of the Trust — Terms of the Conveyances”.

 

The Trust Agreement provides that the Trust must sell its assets and terminate if net revenues fall below $5,000,000 (the “Termination Threshold”) for two successive years. Net revenues to the Trust in 2006 and 2007 fell below the Termination Threshold.. The Trust Agreement provides that if any asset required to be sold has not been sold by December 31, 2010, the Trustee will cause the asset to be sold at public auction to the highest cash bidder. The Trustee intends to comply with the Trust Agreement unless it is removed or prevented from doing so by a court order. See Item 1 — “Terms and Operation of the Trust — Status of Sale Efforts and Litigation” and “Management’s Discussion and Analysis”.

 

Status of Sale Efforts and Litigation

 

As previously disclosed, the Trustee engaged the Financial Advisor to market the Trust’s assets in anticipation of a sale in accordance with the terms of the Trust Agreement. The Financial Advisor marketed the Trust’s interest in the Jay Field and had received preliminary indications of interest in late 2010, and the Trustee intended to sell the Jay Field interest in accordance with the terms of the Trust Agreement. However, also as previously announced, in November 2010 the Trust and Trustee were named as defendants in a Complaint for Legal and Equitable Relief (the “Complaint”) filed by Jeff Beckett in the United States District Court for the Eastern District of Michigan (the “Court”). Mr. Beckett’s Complaint seeks a judicial modification of the terms of the Trust Agreement governing the Trust, a judgment declaring that the termination provisions of the Trust Agreement do not apply and an order

preventing the sale of the Trust’s assets. The Complaint also makes a number of other allegations and seeks removal of the Trustee and other relief.

 

As a result of Mr. Beckett’s lawsuit, certain bidders who had submitted preliminary indications of interest to the Financial Advisor indicated that they were unwilling to proceed with the purchase of the Jay Field interest from the Trust until the Beckett lawsuit was resolved. Consequently, as previously disclosed, the Trustee suspended the sale process pending resolution of the lawsuit. On March 4 , 2011 the Court entered a stipulated order in which the Trust voluntarily agreed that the Trust would not sell any assets of the Trust until at least such time as the Court entered an order dismissing or transferring the case or preliminarily enjoining the sale of the assets. The Trustee filed a Motion to Dismiss for Failure to Join Required Parties, or, in the Alternative, to Transfer Venue with the Court seeking dismissal of the suit and/or transfer of the suit to the United States District Court for the Western District of Texas. However, on July 7, 2011, Mr. Beckett and the Trust entered into a settlement agreement pursuant to which Mr. Beckett agreed to dismiss his lawsuit with prejudice within ten days after the Trust holds a meeting of the Unit holders for the purpose of voting on a proposal to remove the Trustee and to appoint a successor trustee of the Trust, provided that notice of the meeting is mailed by August 1, 2011 and the meeting occurs by September 1, 2011. Notice of the meeting was mailed prior to August 1, 2011, and the meeting was convened on August 12, 2011. Because the proposed successor trustee withdrew its consent to serve shortly prior to the meeting, the meeting has been adjourned until August 24, 2011.

 

The Trustee intends to comply with the terms of the Trust Agreement to the extent possible. Consequently, unless removed, the Trustee currently intends to arrange for the auction of the Trust’s assets in accordance with the terms of the Trust Agreement as soon as is reasonably practicable. The Trustee will mail notice of any such auction of the Trust’s assets to all Unit holders of record in accordance with the terms of the Trust Agreement. The Trustee will also notify all persons who had submitted preliminary indications of interest in purchasing some or all of the Trust’s assets of any such auction, and will endeavor to provide notice to other potential bidders as well.

 

As a result of the Beckett lawsuit, the Trust was unable to complete the sale of its interest in the Jay Field prior to December 31, 2010, and is now required by the terms of the Trust Agreement to sell all of it assets by means of a public auction. The Trustee is unable to predict whether the persons who had submitted preliminary indications of interest in acquiring the Trust’s Jay Field interest in 2010 will be interested in bidding for the interest in a public auction, or, if they are willing to bid, whether they will bid more or less than the amounts they indicated they would consider on a preliminary basis. The preliminary indications of interest the Financial Advisor received when it marketed the Jay Field interest in 2010 ranged from $500,000 to $3,500,000. None of the preliminary indications of interest were firm offers, and all of them remained subject to further review.

 

Unit holders should review the reserve report as of September 30, 2009 included with this annual report, as well as the more recent report as of September 30, 2010 included with the 2010 10-K, but should note, as previously disclosed in the Trust’s filings, that a reserve report is not necessarily indicative of the market value of the interests, and the value of the Trust’s assets will be determined solely by the amount a buyer is willing to pay for the assets. The September 30, 2009 reserve report, dated May 24, 2011, estimates the standardized measure of the Trust’s interest in future net revenues discounted at 10% annually in accordance with SEC guidelines to be approximately $202,000 as of September 30, 2009. Of this amount, the report estimates $202,000 of future net revenues discounted at 10% annually in accordance with SEC guidelines to be attributable to the Trust’s interest in the Jay Field.

 

In preparing, the reserve report, dated May 24, 2011, the reserve engineer considered the Trust’s interests in the South Pass 89 and Offshore Louisiana properties and estimated future revenues value to be zero, the Trust had previously announced that the engineers did not expect that a reserve report addressing the Trust’s interests in South Pass 89 and Offshore Louisiana would attribute any imputed reserves to the Trust’s interests in either of those properties or any estimated future net revenues attributable to the interests held by the Trust in either of those properties.

 

As previously disclosed, the administrative expenses of the Trust are approximately $1,000,000 annually, but have increased as a result of the Beckett Lawsuit. As described above, the Trust’s unpaid invoices at August 19, 2011 were approximately $443,492, and the Trust owed an additional $2,255,520 to the Bank, of which $161,217 remained available to pay expenses. All additional expenses, including expenses incurred by the Trust but for which no invoices had been received at August 19, 2011, and including fees that will become payable to the Financial Advisor upon the sale of the assets and all other fees the Trust incurs, whether as a result of the delays caused by the Beckett lawsuit, or otherwise, must be paid prior to any distribution to Unit holders. It is increasingly likely that the

sale of the Trust’s assets will not generate sufficient proceeds to pay the Trust’s liabilities. If the sale of the Trust’s assets does not generate sufficient proceeds to pay the Trust’s liabilities, there will be no further distributions to Trust Unit holders. As noted above, however, if the Trustee is able to auction the Trust’s assets, all Trust Unit holders will be mailed a notice of the public auction of the Trust’s assets, and any Unit holder who believes that the Trust’s assets are attractive will be welcome to submit a bid for some or all of the assets.

 

Trust Agreement Requirement to Publicly Auction Trust Assets

 

As described in this report, the Trust Agreement requires the Trust to hold a public auction of the Trust’s assets that remained unsold at December 31, 2010. Consequently, unless removed, the Trustee intends to arrange for the auction of the Trust’s assets in accordance with the terms of the Trust Agreement as soon as is reasonably practicable. The Trustee will mail notice of any such auction of the Trust’s assets to all Unit holders of record in accordance with the terms of the Trust Agreement. The Trustee will also notify all persons who had submitted preliminary indications of interest in purchasing some or all of the Trust’s assets of any such auction, and will endeavor to provide notice to other potential bidders as well.

 

The Trustee believes that a public auction of the Trust’s assets as required by the Trust Agreement as soon as possible would maximize the Trust’s likelihood of being able to pay its expenses and make a final distribution to the Unit holders. The auction would be open to all bidders. See Item 1 — “Terms and Operation of the Trust — Status of Sale Efforts and Litigation”

 

Terms of Bank Advance

 

The Bank Advance is interest-free. No Trust distributions can be made until the Bank Advance has been repaid.

 

Potential Replacement of Trustee

 

As previously disclosed and as described above, the Beckett Complaint seeks, among other things, the removal of the Trustee. However, on July 7, 2011, Mr. Beckett and the Trust entered into a settlement agreement pursuant to which Mr. Beckett agreed to dismiss his lawsuit with prejudice within ten days after the Trust holds a meeting of the Unit holders for the purpose of voting on a proposal to remove the Trustee and to appoint a successor trustee of the Trust, provided that notice of the meeting is mailed by August 1, 2011 and the meeting occurs by September 1, 2011. Notice of the meeting was mailed prior to August 1, 2011, and the meeting was convened on August 12, 2011. Because the proposed successor trustee withdrew its consent to serve shortly prior to the meeting, the meeting has been adjourned until August 24, 2011.

 

Status of Review of Jay Field Royalty Computations

 

As described in the Trust’s prior filings, the Trustee engaged an independent joint interest auditing firm (the “Consultant”), to review the computation of the amounts payable to the Trust with respect to its interest in the Jay Field from the time of the sale by The Louisiana Land and Exploration Company (“LL&E”) of its working interest to Quantum Resources Management LLC in 2007 through August 2008 (the “First Review Period”). Also as previously reported, the Consultant completed its review of the First Review Period, Quantum and the Trustee reached agreement on the issues the Consultant had raised relating to the computation of expenses properly chargeable in the calculation of amounts payable to the Trust for the First Review Period. As a result of the review, Quantum revised its computations of the amounts payable to the Trust with respect to the Trust’s interest in the Jay Field for the First Review Period. In addition, as a result of the revisions, Quantum paid the Trust an additional $223,909 in June 2010 relating to the First Review Period, which amount included interest on the amount due to the Trust for the First Review Period.

 

As further described in the Trust’s prior filings, the Trustee subsequently engaged the Consultant to review the computation of the amounts payable to the Trust with respect to its interest in the Jay Field for the production months September 2008 through March 2010 (the “Second Review Period”). Quantum and the Trustee have reached agreement on all material issues raised by the Consultant with respect to the Second Review Period. The Trustee determined that it was able to prepare the Trust’s financial statements for the year ended December 31, 2009, which are included in this report.

The errors noted during the First Review Period and Second Review Period as discussed above were corrected during 2009 and are included in the “Revisions of Estimates” line in the information disclosed in footnote 9.

 

As a result of the contractual termination of the Trust effective December 31, 2007, the Trust is in the process of liquidation. The tables below presents the assets of the Trust at their estimated fair value as of December 31, 2009, based solely on the assessments described below:

 

 

The net overriding royalty interest in oil and gas properties at December 31, 2009 reflect the Trustee’s estimate of value (in the absence of third-party appraisals or evaluations), based on the Trust’s share of future net revenues from the net overriding royalty interest in the properties as of December 31, 2009. This estimate is based on the Trustee’s current assessment of the impact of selling existing assets based on then current market conditions, and includes the following assumptions:

 

 

The actual net proceeds from the sales of oil and gas properties may vary substantially from these estimates in value due to changes in current and estimated future oil and gas prices, subsequent production, estimates of actual abandonment costs and other factors which may be applied by the buyers.

 

For all other assets presented in the above table, the Trustee believes that historical cost approximates fair market value due to the short-term nature of such assets. The Trustee will add any future distributions to previously established reserves to pay Trust expenses, which will primarily consist of expenses incurred by the Trustee to liquidate the Trust’s assets. Any funds remaining after all expenses have been paid will be distributed to the Unit holders.

 

For more information regarding the estimated remaining life of each of the Royalty Properties and the estimated future net revenues of the Royalty Properties based on information provided by the Working Interest Owners to Miller and Lents, see the reserve reports as of September 30, 2009 and 2010 included or filed with the respective Form 10-K’s and Note 9 in the Notes to Financial Statements included elsewhere in the respective Form 10-K’s. For more information regarding the amounts escrowed or withheld by the Working Interest Owners as of December 31, 2009, see “Terms and Operations of the Trust — Terms of the Conveyances”.

 

Nothing herein should be interpreted as an assurance of the values of the assets held by the Trust. The actual value, if any, of such assets will be determined solely by the amount a buyer is willing to pay for the assets. See Item 1 — “Business — Terms and Operation of the Trust — Status of Sale Efforts and Litigation.”

 

Delisting of Trust Units

 

As previously disclosed, on November 16, 2009 the Trust was notified by NYSE Regulation, Inc. (“NYSE Regulation”) that NYSE Regulation had determined that trading in the Trust’s Units on the New York Stock Exchange (“NYSE”) should be suspended prior to the opening on Friday, November 20, 2009. The notification

stated that the decision to delist the Trust was reached in view of the fact that the Trust’s units had fallen below the NYSE’s continued listing standard for average closing price of less than $1.00 over a consecutive 30 trading day period. Also as previously disclosed, on November 19, 2009 arrangements for the transition of trading in the Units from the New York Stock Exchange to the Over-The-Counter market on Pink Sheets were completed. The Trust Units have been traded under the ticker symbol “LRTR” since November 20, 2009.

 

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

 

The Conveyances impose on the Working Interest Owners no contractual obligation to drill any wells or to maintain operations or production once established. However, the Conveyances of Overriding Royalty Interests do obligate the Working Interest Owners to conduct and carry on the development, maintenance and operation of the Productive Properties with reasonable and prudent business judgment and in accordance with good oil and gas field practices, or, where a Working Interest Owner is not the operator, to use reasonable efforts to cause the operator to do so. Actual drilling operations depend on whether geological and geophysical evaluations indicate that drilling will be prudent. There is no requirement that the Working Interest Owners expend any specific amounts with respect to the Properties, and each is free to transfer its interests (burdened by the Royalties) to third parties. The operators do not have any obligation to produce any specific amounts of oil and gas from any of the Properties and each has the right to abandon its interest in any well or lease. Upon termination of any lease, the Overriding Royalties relating thereto will be extinguished.

 

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

 

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

estimated future Special Costs divided by the aggregate estimated future Gross Proceeds for that Property. Further, if the total amount so escrowed exceeds 125 percent of the aggregate estimated future Special Costs for the particular Productive Property, no additional amounts may be escrowed until the escrowed funds are less than 125 percent of such amount.

 

The Working Interest Owners have advised the Trustee that based on current estimates included in this Annual Report on Form 10-K, the Working Interest Owners are permitted to place additional funds in escrow from each of the properties. Commencing with the April 2006 monthly distribution, the Working Interest Owners began escrowing all amounts otherwise distributable to the Trust from the Offshore Louisiana and South Pass 89 properties. The Working Interest Owners have advised the Trustee that they anticipate escrowing all additional funds from all the properties.

 

Based on the escrow provisions described above, the Working Interest Owner did not escrow any amounts for the Jay Field during the year ended December 31, 2009, but escrowed $805,683 during the year ended December 31, 2009 for the South Pass 89 property. The Working Interest Owner escrowed $3,239,055 during 2009 for the Offshore Louisiana properties. During 2009, none of the escrowed amounts were expended for the South Pass 89 or Jay Field properties, while $3,398,812 was expended for the Offshore Louisiana property. The escrow balances remaining at December 31, 2009 were $4,543,402 for Jay Field, $8,936,923 for the South Pass 89 property and $8,812,616 for the Offshore Louisiana property. As of December 31, 2009, the Working Interest Owners’ estimates of total Special Costs for abandonment are $14.2 million for Jay Field, $7.5 million for South Pass 89 and $25.5for Offshore Louisiana. The Working Interest Owners may begin escrowing balances at Jay Field. As described above, the Conveyances prohibit the Working Interest Owners 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 Owners to release funds from any of the Special Cost escrows at any time if either of them 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 Owners are not required to do so.

 

As previously described in the Trust’s filings, in addition to the Working Interest Owners’ rights to recover Excess Production Costs prior to making payments to the Trust, the Working Interest Owners have the right under the Conveyances to escrow or withhold amounts for certain anticipated future expenses, and the Working Interest Owners have done so and expect to continue doing so in the future. The Working Interest Owners are not required to fund actual escrow accounts, and neither has done so. However, they must calculate the royalties as though they had done so.

 

In the event that any Working Interest Owner is required to pay any refunds or interest (including any payment made pursuant to settlements entered into by the Working Interest Owner in good faith) as a result of overcharges with respect to which Royalties have already been paid, neither the Trustee nor the Unit holders are expected to be obligated to return to the Working Interest Owner any payments previously received. However, the amount of any such refunds or interest would reduce future payments attributable to the Royalties. Holders of Units may, as a result of the procedures described above and under “Liabilities and Contingency Reserves” below, receive distributions of amounts that otherwise would have been distributed to former holders if such amounts had not been held in escrow or reserves, or, conversely, may have their distributions reduced as a result of controversies about amounts that may be collected by the Working Interest Owner or as a result of the establishment of escrow accounts or reserves for contingencies.

 

See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 1 — “Terms and Operations of the Trust — Termination of the Trust”.

 

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.

 

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

 

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. As previously disclosed, the costs and expenses of the Trust may increase significantly in connection with the termination and liquidation of the Trust and the Beckett lawsuit. See Item 1 — “Terms and Operations of the Trust — Termination of the Trust” and — “Status of Sale Efforts and Litigation”.

 

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. There can be no assurance that either the Trustee or the Partnership would be able to borrow

additional funds on acceptable terms or on any terms at all. See Item 1 — “Terms and Operations of the Trust — Termination of the Trust”.

 

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

 

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

 

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

 

The manner of calculating the payments attributable to the Royalties is set forth in the Conveyances, forms of which are on file with the Securities and Exchange Commission and are incorporated by reference as exhibits to this Annual Report on Form 10-K. The description herein of the manner of calculating those payments is qualified in its entirety by the detailed terms of the Conveyances. The following description is qualified in its entirety by the information under “Terms and Operation of the Trust — Termination of the Trust.”

 

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 Mellon Trust Company, N.A.’s prime rate plus 0.5 percent per annum on the average amounts by which, and for only so long as, costs and expenses for any Productive Property have exceeded the proceeds of production from such Productive Property; (e) amounts paid by the Working Interest Owner as refunds of excess sales prices on previous sales; and (f) applicable charges for certain overhead expenses. As of December 31, 2009, the Working Interest Owner’s estimates of total Special Costs were $14.2 million for Jay Field, $7.5 million for South Pass 89 and $25.5 million for Offshore Louisiana. See “— Terms of the Conveyances” above for a description of amounts escrowed to date.

 

If operating and other costs exceed net revenues from a Productive Property for any month, the excess will be recovered by the Working Interest Owner out of future production from such Productive Property prior to making

further payments attributable to the Royalties with respect to such Productive Property, but neither the Trust, the Trustee, the Partnership, nor any Unit holder will be liable for any such costs or liabilities, nor will they be obligated to return any income from the Royalties received during any prior period. However, any such excess costs or overpayment of Royalties will reduce future payments of Royalties.

 

Although crude oil production from Jay Field has a low sulphur content, gas production from the field has a high content of sulphur which is removed prior to processing and marketing such production. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Recent Developments” for additional information regarding sulphur at Jay Field.

 

The Trust owns Overriding Royalties expressed as various percentages of Net Proceeds. The Overriding Royalties with respect to Jay Field and South Pass 89 are equal to 50 percent of the Net Proceeds attributable to such properties. The Overriding Royalties with respect to Offshore Louisiana are equal to 90 percent of the Net Proceeds attributable to such properties.

 

The amount of revenues attributable to the Overriding Royalties from any well may be increased or reduced as a result of future pooling and unitization agreements extinguished or suspended as a result of “nonconsent” provisions of present or future operating agreements between the operator and other operators or extinguished as a result of the expiration of oil and gas leases. Since the Overriding Royalties were conveyed out of the Working Interest 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.

 

As part of the termination procedures, the Trustee engaged an independent joint venture auditor to review payments to the Trust for a portion of the Trust properties as part of the termination of the Trust. The joint venture auditor reviewed the period from January 2004 through December 2007. As a result of the review, one of the Working Interest Owners made a payment of approximately $437,000 in March 2008 to the Trust to settle certain issues identified. More recently, the independent joint interest auditor completed a review of the working interest owner’s calculations relating to the Trust’s interest in the Jay Field for the period July 1, 2007 through December 31, 2008, which resulted in an additional payment of $223,910 to the Trust. The independent joint venture auditor has also reviewed the working interest owner’s calculations relating to the Trust’s interest in the Jay Field through March 2010. All material matters issues raised by the independent joint venture auditor with respect to the most recent period have been resolved with the working interest owner.

 

On November 11, 2009, in accordance with the terms of the Trust Agreement requiring the sale of the Trust’s assets, the Trust sold a portion of its assets consisting of its royalty interests in the south Louisiana acreage described elsewhere herein and in the Trust’s prior public filings as the “Fee Lands”. The sale resulted in cash proceeds to the Trust, net of $24,828 in fees to the auction company that conducted the sale, of approximately $500,000. The purchaser was ETROA Resources, LLC. The proceeds were used to reduce the Trust’s accounts payable.

 

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, 2009 (applicable to production from July 2009 through September 2009) and (ii) the year ended December 31, 2009 (applicable to production from October 2008 through September 2009):

 

Quarter ended December 31, 2009

 

Year ended December 31, 2009

 

 

 

 

Prior to the termination of the Trust effective December 31, 2007, distributions of available revenues to Unit holders were made monthly. Each payment was made with respect to the preceding Monthly Period of the Trust. The Trustee determined for each Monthly Period the Monthly Income Amount available for distribution for such Monthly Period. The Monthly Income Amount for each Monthly Period was payable to Unit holders of record on the Monthly Record Date on which such Monthly Period ends and was distributed by the Trustee as soon as practicable but not later than ten days following such Monthly Record Date (the “Monthly Payment Date”). Under the terms of the Trust Agreement, the Trustee was prohibited from investing funds received on each Monthly Record Date pending disbursement to holders of Units. As a consequence, the Trustee may have held substantial

balances between the Monthly Record Date and the Monthly Payment Date in each month, and The Bank of New York Mellon Trust Company, N.A. had the use of these balances during such periods.

 

Promptly after receipt of the required information, and if practicable within 90 days of the close of each year, the net taxable income of the Trust for federal income tax purposes for each Monthly Period ending in such year has been reported by the Trustee to the Unit holders of record to whom the Monthly Income Amounts were distributed. The Trustee mailed reports for 2009 to Unit holders in March 2010.

 

Units are transferable on the records of The Bank of New York Mellon Trust Company, N.A. as transfer agent and registrar, upon the surrender of any certificate in proper form for transfer as required by The Bank of New York Mellon Trust Company, N.A. Service charges are paid as an administrative expense of the Trust, and no service charge is made directly to Unit holders for any transfer. Until any such transfer, the Trustee may treat the owner of any Unit as shown by the records of the transfer agent and registrar as the owner thereof and will not be charged with notice of any claim or demand respecting such Unit or the interest represented thereby by any other party. A transfer of a Unit after the Monthly Record Date for any Monthly Period does not transfer to the transferee the right to the Monthly Income Amount for such Monthly Period. See “Tax Considerations to Owners of Units — Federal Income Tax Considerations — Tax Consequences of Owning Units — Sale of Units” for a discussion of certain federal income tax effects of the transfer of Units. Texas law governs matters affecting title, ownership, warranty and transfer of the Units.

 

Promptly after receipt of the required information from the Working Interest Owners, 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. The Trustee has been unable to provide such quarterly reports during 2009 and 2010 as a result of issues regarding the computation of the Jay Field Royalties. 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 was unable to provide an annual report for the year ended December 31, 2009 and 2010 on a timely basis as a result of issues regarding the computation of the Jay Field Royalties. 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”. 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.

 

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

 

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

 

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

 

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.

 

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. However, see Item 1 — “Terms and Operations of the Trust — Potential Requested Meeting of Unit holders to Replace Trustee and Amend Trust Agreement”.

 

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 Trustee has no authority or responsibility relating to the operation of the Productive Properties or Fee Lands. The information in this Annual Report on Form 10-K relating to the characteristics of, operations on, and sales from the Productive Properties and Fee Lands and certain other matters has been furnished to the Trustee by the Working Interest Owners. The following description is qualified in its entirety by the information under “Terms and Operation of the Trust — Termination of the Trust.”

 

The Overriding Royalties were carved out of interests (primarily working interests) owned by the Working Interest Owner at the time of the creation of the Trust. References herein to “net” wells and acres refer to the interest of the Working Interest Owner (from which the Royalties were carved) in the “gross” wells or acres. References to the percentage of the working interest owned by the Working Interest Owner are references to the working interest out of which the Overriding Royalties were carved. For example, a reference to a “20 percent working interest” in a well or lease that is included in a Productive Property indicates that the 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.

 

Certain information, as of December 31, 2009, 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, 2009.

 

 

 

 

 

 

 

 

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.

 

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. Most of the Fee Lands Royalties in the original Fee Lands terminated in June 1993 pursuant to Louisiana law. On November 11, 2009, the Trust sold its remaining interest in the Fee Lands. The sale resulted in cash proceeds to the Trust, net of fees of $24,828 paid to the auction company that conducted the sale, of approximately $500,000.

 

The following description is qualified in its entirety by the information under “Terms and Operation of the Trust — Termination of the Trust.”

 

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.

 

Natural gas from certain of the Productive Properties is sold to an affiliate of ConocoPhillips, which transports the offshore gas onshore, and sells that gas to third parties at market prices under contracts typical of those prevailing in the industry.

 

The Working Interest Owner generally retained the right to revenue from liquids contained in the gas sold offshore Louisiana. Depending upon the prices prevailing from time to time for natural gas relative to those for gas liquids, all or a portion of such gas is processed at plants located onshore Louisiana to remove the liquids. Both these liquids and the liquids available at the tailgate of the Jay Field processing plant are sold by an affiliate to third parties, some of which is transported by the affiliate prior to the sale. Propane and virtually all of the other liquids are sold by the affiliate, of ConocoPhillips, at published “spot” prices. Natural gas is settled by the Working Interest Owner on a percent of proceeds basis.

 

For purposes of computing the payments attributable to the Overriding Royalties, Net Proceeds include the proceeds from the natural gas and liquids sales by the affiliate after deduction of applicable transportation and processing costs.

Due to the state of the gas industry and the marketing strategies used by different purchasers and producers, it is not uncommon for certain working interest owners in a property to be overproduced and to have delivered more gas than such owner was entitled to sell, leaving the other working interest owners underproduced. As a result, an imbalance may develop between the various Working Interest Owners regarding the amount of gas to which each is entitled and the amount each actually takes and sells. The Working Interest Owner uses the “entitlement” method of recording gas production, which results in revenues being recognized on the Working Interest 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 does not properly interpret the applicable law or regulations in a manner consistent with later determinations and interpretations of regulatory authorities or of the courts, the Working Interest Owner may be required to refund amounts previously collected plus interest, which may be substantial if a long period passes between the time of the overcharge and the determination that a refund is required. See “Terms and Operation of the Trust — Terms of the Conveyances” for information regarding the effect of any refunds on Unit holders.

 

The following is a summary of the Working Interest Owner’s net drilling activities on the Productive Properties for the years ended December 31, 2007, 2008 and 2009:

 

 

The following are the significant activities by the Working Interest Owner on the Productive Properties during 2009:

 

Jay Field

 

Capital and abandonment expenditures of approximately $4,601,000 were incurred in 2009.

 

South Pass 89

 

Capital and abandonment expenditures of approximately $8,000 were incurred in 2009, primarily for capital workovers.

Offshore Louisiana

 

Capital and abandonment expenditures of approximately $247,000 were incurred in 2009.

 

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, 2009 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, 2009. A copy of the Miller and Lents letter, dated May 24, 2011, setting forth such estimates, is reproduced as Appendix A to this Annual Report. A copy of a more recent letter from Miller and Lents, dated June 8, 2011 and as of September 30, 2010, is reproduced as Appendix B to this Annual Report.

 

The following table sets forth, as of September 30, 2009, certain estimated imputed proved reserves, estimated future net revenues and the discounted present value thereof attributable to the underlying properties and the Royalties, in each case derived from the Miller and Lents reserve report. A summary of the 2009 reserve report is included as Appendix A “to this Annual Report”.

 

 

As previously disclosed, the Working Interest Owners have advised the engineers that they plan to escrow or otherwise withhold up to 125 percent of the estimated Future Special Costs in accordance with the provisions of the original Conveyance to the Trust, and the September 30, 2009 and September 30, 2010 reports both reflect that fact.

 

Because the Royalties on the Properties (other than the Fee Lands) are “net” overriding royalty interests (often referred to as net profits interests), estimates of future net revenues to the Trust are affected by a number of factors in addition to the engineering, well performance and other data taken into consideration by petroleum engineers in estimating the quantity and nature of gross oil and gas reserves in the ground. Such other factors include oil and gas prices (the changes in which have materially affected the estimates of future net revenues to the Trust in prior years), projections of operating and capital costs, and the Working Interest 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.

 

The estimated net revenues have been determined on the basis of when the oil or gas is estimated to be produced. However, payments, if any, with respect to the Royalties are received by the Trustee approximately 65 days after the end of the month in which the sales of oil and gas are recorded as revenues by the Working Interest Owner. The Trustee does not expect to make any further quarterly distributions. The estimated net revenues in Miller and Lents’ letter have not been reduced for costs and expenses of the Trust.

 

In making its estimates, Miller and Lents used price and cost assumptions as described in the Miller and Lents letter attached as Appendix A to this report on Form 10-K. These assumptions are assumptions only, and there can be no assurance that actual prices and costs in the future will not be materially different from those assumed. Prices of oil and gas and related costs have varied dramatically in recent years and are impossible to predict with certainty. See “Industry Conditions and Regulation”.

 

Pursuant to Financial Accounting Standards Board (FASB) in Accounting Standards Codification 932 — Extraction Activities — Oil and Gas (formerly known as Statement of Financial Accounting Standards No. 69), the Trust is required to include as supplementary information estimates (which are unaudited) of quantities of proved oil and gas reserves attributable to the Trust. The Miller and Lents letter attached as Appendix A includes such estimates, prepared on the basis described therein. The quantities imputed to the Trust are calculated by multiplying Miller and Lents’ estimated net reserves of the Working Interest Owner (prior to taking into consideration the 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.

 

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.

 

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 Owners have advised the Trustee that they believe that their respective operations and facilities are in general compliance with applicable health, safety, and environmental laws and regulations.

 

Introduction

 

The following summary discusses the federal income tax consequences attendant to the acquisition, ownership and disposition of Units. This summary is based upon current provisions of the Internal Revenue Code of 1986, as amended, which we refer to as the “Code,” existing and proposed Treasury regulations thereunder and current administrative rulings and court decisions, all of which are subject to changes that may or may not be retroactively applied. No attempt has been made in the following summary to comment on all federal income tax matters affecting the Trust or 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 Internal Revenue Service, which we refer to as 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 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 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 Unit holder’s allocated share of 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. The total amount of deductions based on cost depletion cannot exceed the Unit holder’s total adjusted tax basis in the property.

 

Section 1254 of the Code provides that for property placed in service by a taxpayer after December 31, 1986, depletion deductions which reduce the adjusted basis of such property must be recaptured as ordinary income upon a disposition of the property. The amount of such recapture is generally limited to the amount of gain recognized by the taxpayer on such disposition. No oil and gas properties were placed in service by the Partnership subsequent to 1986. However, it is unclear whether this recapture provision applies to any portion of the depletion deduction claimed with respect to the Royalties in the case of Units acquired after December 31, 1986. The Service has not issued any Treasury 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 Treasury 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 Treasury 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 2009, the noncorporate taxpayer’s exemption amount is $70,950 in the case of joint returns or surviving spouses, $46,700 in the case of unmarried individuals who are not surviving spouses, $35,475 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 Treasury 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 Treasury 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 Treasury 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 income effectively connected with a U.S. trade or business 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 Treasury 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 Code Section 751 and 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 attributable to 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 — 2009 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 Treasury 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 Treasury 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 Treasury 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.

 

Some Units are held by middlemen, as such term is broadly defined in the Treasury regulations (and includes custodians, nominees, certain joint owners and brokers holding an interest for a custodian street name, collectively referred to herein as “middlemen”). Therefore, the Trustee considers the Trust to be a non-mortgage widely held fixed investment trust (“WHFIT”) for federal income tax purposes. The Bank of New York Mellon Trust Company, N.A., 919 Congress Avenue, Austin, Texas 78701, telephone number 1-800-852-1422, is the representative of the Trust that will provide the tax information in accordance with applicable Treasury regulations governing the information reporting requirements of the Trust as a WHFIT. Notwithstanding the foregoing, the middlemen holding Units on behalf of Unit holders, and not the Trustee of the Trust, are solely responsible for complying with the information reporting requirements under the Treasury regulations with respect to such Units, including the issuance of Internal Revenue Service Forms 1099 and certain written tax statements. Unit holders whose Units are held by middlemen should consult with such middlemen regarding the information that will be reported to them by the middlemen with respect to the Units. Any generic tax information provided by the Trustee of the Trust is intended to be used only to assist Unit holders in the preparation of their federal and state income tax returns.

 

In compliance with the Treasury regulations reporting requirements for non-mortgage widely-held fixed investment trusts and the dissemination of trust tax reporting information, the Trustee provides a generic tax information reporting booklet which is intended to only be used to assist Unit holders in the preparation of their

2009 federal and state income tax returns. This tax information booklet can be obtained at www.businesswire.com/cnn/lrt.htm

 

Other Possible Penalties.  An owner of a security who receives income in respect of such interest must report the character and amount of such income, for federal income tax purposes, in a manner which is consistent with the federal income tax reports of the entity which was the source of the income. The consistency requirement is deemed to be waived if the taxpayer files a statement with the Service identifying the inconsistency. Because of the presence of “street name” investors and the possible existence of transfer record inaccuracies, holders of interests which are actively traded in the securities markets may encounter situations in which it is difficult to comply fully and accurately with the consistency requirement and other federal tax reporting requirements. Certain penalties could be assessed against a taxpayer that fails to comply with such requirements. Because of the complexity of the federal tax reporting requirements applicable to trusts (such as the Trust) which own interests in partnerships (such as the Partnership) and because all of the tax attributes of the Royalties flow through the Partnership and the Trust to the Unit holders, there is an increased likelihood that Unit holders will violate the consistency requirement and other reporting requirements regarding their individual federal income tax returns and the information returns of the Trust and the Partnership. Any violations of the consistency requirements could lead to imposition of certain penalties on the Unit holders or other adverse results. Furthermore, the Trust or the Partnership might be subject to certain penalties in connection with its furnishing of statements and information to Unit holders or the government if such statements or information prove to be inaccurate due, for example, to differences between the transfer 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”.

 

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.

 

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. 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.

 

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 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 per failure, up to an annual maximum.

 

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. Beginning in 2009, taxpayers are allowed a deduction in the amount of 100 percent (65 percent in 2008) of the excess federal itemized deductions. The income tax rates for individuals range from a low of 2 percent to a high of 6 percent.

 

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 imposed an intangibles tax on individuals, corporations, partnerships, and fiduciary filers. The intangible base included notes receivable, investments, and accounts receivable (less a reasonable allowance for uncollectible accounts). Effective January 1, 2007, the annual tax on intangible personal property such as stocks, bonds, mutual funds, money market funds, and unsecured notes was repealed. Beginning January 1, 2007, taxpayers will no longer file an intangible personal property tax return on these types of intangible personal property. Not all intangible taxes have been repealed. The intangible tax on leases of government-owned real property and the one-time intangible tax on notes secured by a mortgage on Florida real property are still in effect.

Alabama

 

Alabama imposes an income tax on all income of resident individuals (but allows a credit for income taxes paid to other states by Alabama residents) and on the income derived from Alabama sources by nonresident individuals. Royalty income earned from property located within Alabama is considered income derived from Alabama sources for this purpose. Therefore, individual Unit holders who are not residents of Alabama are subject to Alabama income tax on income from the Royalties allocated to Alabama. Such nonresident individuals will be allowed certain deductions and exemptions which are apportioned to Alabama based upon the ratio of Alabama income to total gross income. The rates for individuals range from a low of 2 percent to a high of 5 percent.

 

Alabama also imposes an income tax on all corporations and other entities treated as corporations if they earn or receive income derived from or attributable to sources within Alabama. Both resident and nonresident corporations receiving income from the Royalties are required to file an Alabama corporate return. Such income may be characterized as either business or nonbusiness income depending on the 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.

 

The Royalties, and consequently the Unit holders, will bear their proportionate share of severance taxes on the production from the Properties. Except for a $0.03 per barrel conservation tax on oil which was suspended in 1990, there is no severance tax on production from properties in the federal offshore domain. Louisiana generally imposes a severance tax of 12.5 percent of the market value of oil. The gas tax is subject to an annual rate adjustment each July 1, but to not less than $0.07 per mcf. Florida generally imposes a severance or production tax of 8 percent of the actual value of oil production and a tax on gas. The gas tax rate is the gas base rate of $0.171 per mcf times the gas base rate adjustment. Beginning July 1, 1987, the gas base rate adjustment is determined by the FDR annually on July 1. Alabama generally imposes a privilege tax on gas production or severance at the rate of 8 percent and a conservation tax of 2 percent of the actual value of oil and gas production (the 2 percent rate is reduced to 1 percent for a period of five years for certain wells for which the initial permits were obtained between July 1, 1996 and July 1, 2002).

 

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.

 

The Trust makes copies of its reports under the Exchange Act available at www.businesswire.com/cnn/lrt.htm as promptly as practicable after they are filed with the Securities and Exchange Commission. The Trust’s filings

under the Exchange Act are available electronically from the website maintained by the SEC at http:www.sec.gov. The Trust will also provide electronic copies of its recent filings free of charge upon request to the Trustee, and will provide paper copies of its recent filings for its costs of reproduction upon request to the Trustee.

 

 

Although risk factors are described elsewhere in this Form 10-K together with specific Cautionary Statements, the following is a summary of the principal risks associated with an investment in units in the Trust.

 

The Trust terminated as of December 31, 2007 and is required to sell its assets and liquidate.

 

In accordance with the Trust Agreement, the Trust was required to terminate as of December 31, 2007, and the Trustee is required to sell the assets of the Trust and to liquidate the Trust. There can be no assurance that the assets can be sold for any particular amount. As a result of the Beckett lawsuit described in this report, the Trustee was unable to sell the assets, other than the Fee Lands, by December 31, 2010. Consequently, the Trustee is required to sell the assets in a public auction.

 

The amount the Trust may receive for the sale of the Trust’s assets may be substantially decreased if the Beckett lawsuit is not dismissed.

 

On July 7, 2011, Mr. Beckett and the Trust entered into a settlement agreement pursuant to which Mr. Beckett agreed to dismiss his lawsuit with prejudice within ten days after the Trust holds a meeting of the Unit holders for the purpose of voting on a proposal to remove the Trustee and to appoint a successor trustee of the Trust, provided that notice of the meeting is mailed by August 1, 2011 and the meeting occurs by September 1, 2011. Notice of the meeting was mailed prior to August 1, 2011, and the meeting was convened on August 12, 2011. Because the proposed successor trustee withdrew its consent to serve shortly prior to the meeting, the meeting has been adjourned until August 24, 2011. If the Beckett lawsuit is not dismissed, the Trust may be unable to sell its assets.

 

If the Trust is able to sell its assets despite the existence of the Beckett lawsuit, the existence of the litigation could have an adverse effect on the price the Trust might receive for the assets.

 

The Beckett lawsuit may prevent the sale of the Trust’s assets.

 

If the Beckett lawsuit is not dismissed as described above, the Trust may be unable to sell its assets. If the court enters an order prohibiting the sale of the Trust’s assets, the Trustee will be unable to sell the Trust’s assets until the order expires or is modified or overruled.

 

Any further delays caused by the Beckett lawsuit will continue to increase the Trust’s administrative expenses and decrease or eliminate any possible distributions to Unit holders.

 

The Beckett lawsuit has delayed the sale of the Trust’s assets, which was intended to be completed in December 2010. Although Mr. Beckett and the Trust have entered into a settlement agreement as described above, the Trust’s administrative expenses, which include the expenses of the Beckett lawsuit, continue to accrue. All of the Trust’s expenses must be paid before any distributions can be made to Unit holders.

 

The Trust may be liquidated in an insolvency proceeding.

 

If the Trust is unable to sell its assets or borrow additional funds, the Trust would probably have to be liquidated in an insolvency proceeding. If the Trust is liquidated in an insolvency proceeding, it would incur additional expenses, and Unit holders would be unlikely to receive any distribution.

 

Because the Trust did not sell its assets by December 31, 2010, the Trustee is required to sell the assets in a public auction.

 

Because the Trust was unable to sell its assets by December 31, 2010, the Trust Agreement requires the Trustee to sell the assets in a public auction. A public auction may not result in as favorable a price for the Trust’s assets as an individually negotiated transaction.

The Trust will incur expenses in connection with the sale of its assets and liquidation.

 

The Trust will incur expenses in connection with the sale of its assets and liquidation, including expenses and costs of a financial advisor to assist with the sale of the Trust’s assets, and the expenses will be significant, particularly as a percentage of the Trust’s declining net worth.

 

The market prices for oil and gas may not increase and may decline prior to the time the Trust is able to sell its assets.

 

Market prices of, and/or market expectations for future, oil, gas and other hydrocarbons may not increase, and may decrease, before the Trust is able to sell its assets.

 

Natural gas and oil prices fluctuate due to a number of factors, and lower prices will reduce the market value of the Trust’s assets.

 

The Trust does not anticipate making any additional distributions to Unit holders unless it is able to sell its assets for an amount sufficient to pay all of its liabilities and make a final liquidating distribution of any remaining funds. The value of the Trust’s assets remains dependent upon the prices realized from the sale of natural gas and oil. Natural gas and oil prices can fluctuate widely on a month-to-month basis in response to a variety of factors that are beyond the control of the Trust, the Working Interest Owners and the operators. Factors that contribute to price fluctuation include, among others:

 

 

Moreover, government regulations, such as regulation of natural gas transportation and price controls, can affect product prices in the long term.

 

Lower natural gas and oil prices may reduce the amount of natural gas and oil that is economic to produce and may also reduce the value of the Trust’s assets.

 

The effects of the Working Interest Owner’s substantial work in the Jay Field may have a material effect on the value of the Trust’s interest in the Jay Field.

 

Quantum Resources Management LLC, which is the Jay Field Working Interest Owner, is also the operator of the Jay Field. Quantum has undertaken a substantial upgrade of the Jay Field production facilities. Although Quantum expects the upgrade to have a substantial beneficial effect on the Jay Field’s production, the upgrade has been expensive, and although it may increase the value of the Trust’s interest to a prospective bidder, the accumulated Excess Production Costs that remain to be paid from amounts that might otherwise have been distributable to the Trust are significant, and may have an adverse effect on the amount bidders may offer for the Trust’s interest.

Damage from Hurricanes Katrina and Rita has had a material adverse effect on the value of the Trust’s assets.

 

As previously disclosed, the damage caused by Hurricanes Katrina and Rita to production facilities for properties in which the Trust has an interest has had a material adverse effect on the value of the Trust’s assets at South Pass 89 and Offshore Louisiana. The damage interrupted production, damaged production facilities, increased expenses, increased abandonment costs, and resulted in the decision by the Working Interest Owner to escrow all funds otherwise distributable to the Trust from the Offshore Louisiana and South Pass 89 properties. Additional information regarding the damage to these properties is included under Management’s Discussion and Analysis of Financial Condition and Results of Operations.

 

Pending litigation against the Working Interest Owner could adversely impact the value of the Trust’s assets.

 

The Trustee has been informed by the Working Interest Owner that the Working Interest Owner has been named as one of many defendants in certain lawsuits alleging the underpayment of royalties on the production of natural gas and natural gas liquids through the use of below-market prices, improper deductions, improper measurement techniques and transactions with affiliated companies. Plaintiffs in some of the lawsuits allege that the underpayment of royalties, among other things, resulted in false forms being filed by the relevant Working Interest Owner with the Minerals Management Service, thereby violating the civil False Claims Act.

 

If the plaintiffs are successful in the matters described above, a judgment or settlement could entitle the Working Interest Owner to reimbursements for past periods attributable to properties covered by the Trust’s interest, which could decrease the value of the Trust’s assets. 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 decrease the value of the Trust’s assets.

 

Production and development costs attributable to the Overriding Royalties are deducted in the calculation of the Trust’s share of net proceeds. Accordingly, higher production and development costs, without concurrent increases in revenues, directly decrease the amount attributable to the Overriding Royalties, and thus decrease the value of the Trust’s assets.

 

Trust reserve estimates depend on many assumptions that may prove to be inaccurate, which could cause both estimated reserves and estimated future revenues to be too high.

 

The value of the Trust’s assets depends upon, among other things, the amount of reserves attributable to the Overriding Royalties and the estimated future value of the reserves. Estimating reserves is inherently uncertain. Ultimately, actual production, revenues and expenditures for the underlying properties will vary from estimates and those variations could be material. Petroleum engineers consider many factors and make assumptions in estimating reserves. Those factors and assumptions include:

 

 

Changes in these assumptions can materially change reserve estimates.

 

The reserve quantities attributable to the Overriding Royalties and revenues are based on estimates of reserves and revenues for the underlying properties. The method of allocating a portion of those reserves to the Trust is complicated because the Trust holds an interest in the Overriding Royalties and does not own a specific percentage of any actual reserves.

Operating risks can adversely affect the value of the Trust’s assets.

 

The occurrence of drilling, production or transportation accidents and other natural disasters at any of the properties will reduce the value of the Trust’s assets. These occurrences include blowouts, cratering, explosives and other environmental damage that may result in personal injuries, property damage, damage to productive formations or equipment and environmental damages. Any uninsured costs would be deducted as a production cost in calculating net proceeds payable under the Conveyances. The allocation of insurance proceeds to insured costs is not within the control of the Trustee, and as a result of the complexity of allocating insurance proceeds, the allocation may take a significant amount of time.

 

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

 

Neither the Trustee nor the Unit holders can influence or control the operation or future development of the underlying properties. The properties are operated by independent third parties. The Working Interest Owner does not operate the South Pass 89 or Offshore Louisiana properties. Neither the Trustee nor the Unit holders have any right to replace an operator. The Working Interest Owners handle the receipt and payment of funds relating to the Properties and payments to the Trust for the Overriding Royalties.

 

The Trust is dependent upon the Working Interest Owners to calculate the Royalties payable to the Trust.

 

As described elsewhere herein and previously disclosed, the calculation of the Royalties is complex, and numerous interpretive issues have arisen in the past regarding the proper calculation of the Royalties. The Working Interest Owners control all of the information necessary to calculate the Royalties, and the Trust is dependent upon the Working Interest Owners for calculations. Although the Trustee has engaged a joint interest auditing firm to review the computations from time to time, and has had substantial success in its negotiations with each of the Working Interest Owners over the amounts properly payable to the Trust under the Conveyances, the Trust is nevertheless largely dependent on the Working Interest Owners. Further, in instances in which the joint interest auditing firm retained by the Trustee to review the computations has been unable to reach agreement with the relevant Working Interest Owner over the proper interpretation of the Conveyances, the Trustee may ultimately determine that is would be imprudent to expend additional Trust funds in order to litigate the issues in order to reach a final determination.

 

The operator may abandon any property, terminating the related Overriding Royalties.

 

The operator of any of the properties may abandon any well or property if it reasonably believes that the well or property can no longer produce in commercially economic quantities. This could result in termination of the Overriding Royalties relating to the abandoned well or property.

 

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 the Working Interest Owner to fulfill the terms of the Conveyances of the Overriding Royalties. If the Trustee does not take appropriate action to enforce provisions of the Conveyances, the recourse of a Unit holder would likely be limited to bringing a lawsuit against the Trustee to compel the Trustee to take specified actions. Unit holders probably would not be able to sue the Working Interest Owner directly.

 

None.

 

 

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

 

 

On November 23, 2010 the Trust and Trustee were named as defendants in a Complaint for Legal and Equitable Relief (the “Complaint”) filed by Jeff Beckett in the United States District Court for the Eastern District of Michigan (the “Court”). Mr. Beckett’s Complaint sought a judicial modification of the terms of the Trust Agreement governing the Trust, a judgment declaring that the termination provisions of the Trust Agreement do not apply and an order preventing the sale of the Trust’s assets. The Complaint also made a number of other allegations and sought removal of the Trustee and other relief. On March 4, 2011 the Court entered a stipulated order in which the Trust agreed that the Trust would not sell any assets of the Trust until at least such time as the Court entered an order dismissing or transferring the case or preliminarily enjoining the sale of the assets. The Trustee filed a Motion to Dismiss for Failure to Join Required Parties, or, in the Alternative, to Transfer Venue with the Court seeking dismissal of the suit and/or transfer of the suit to the United States District Court for the Western District of Texas. However, on July 7, 2011, Mr. Beckett and the Trust entered into a settlement agreement pursuant to which Mr. Beckett agreed to dismiss his lawsuit with prejudice within ten days after the Trust holds a meeting of the Unit holders for the purpose of voting on a proposal to remove the Trustee and to appoint a successor trustee of the Trust, provided that notice of the meeting is mailed by August 1, 2011 and the meeting occurs by September 1, 2011. Notice of the meeting was mailed prior to August 1, 2011, and the meeting was convened on August 12, 2011. Because the proposed successor trustee withdrew its consent to serve shortly prior to the meeting, the meeting has been adjourned until August 24, 2011.

 

 

 

Since November 20, 2009 the Units have been traded in the over-the-counter market on Pink Sheets (ticker symbol LRTR). Pink Sheets is a centralized quotation system that collects and publishes quotes for over the counter securities. The table below presents the high and low sales prices for each quarterly period in the years ended December 31, 2009 and 2008. There were no cash distributions to Unit holders in any quarterly period in the years ended December 31, 2009 and 2008.

 

 

The Trustee does not expect to make any distributions prior to a possible final liquidating distribution upon the sale of the Trust’s assets. There is no assurance that the Trust will be able to make any distribution.

 

The total number of Unit holders of record as of June 24, 2011 was 3,343.

 

 

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.

 

 

 

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) The carrying value of the Trust’s royalty interests at December 31, 2009 is not necessarily indicative of the fair market value of the interests held by the Trust.

 

This basis for reporting distributable income is considered to be the most meaningful because distributions to the Unit holders for a month are based on net cash receipts for such month. However, it will differ from the basis used for financial statements prepared in accordance with accounting principles generally accepted in the United States of America because, under such accounting principles, royalty income for a month would be based on net proceeds from sales for such month without regard to when calculated or received and interest income for a month would be calculated only through the end of such month, and accounting principles generally accepted in the United States would require a liquidation basis of accounting.

 

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

 

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

 

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. Except for the bank advance described in this report, the Trust has no source of liquidity or capital resources other than the revenue, if any, attributable to the Royalties.

 

The Working Interest Owners, under the terms of the Trust Conveyances, are permitted to escrow funds (or to calculate the royalties as though they had done so) from the Productive Properties for estimated future costs such as dismantlement costs and capital expenditures. According to the reserve report as of September 30, 2010, dated June 8, 2011, included in the Trust’s Annual Report on Form 10-K for the year ended December 31, 2010, the total future dismantlement costs to the Working Interest Owners are estimated to be $16,100,000 for the Jay Field property, $11,300,000 for the South Pass 89 property, and $10,600,000 for the Offshore Louisiana property. These

estimates are provided to the independent engineers by the Working Interest Owners. The Trust’s interests in these properties are equivalent to 50% of the net proceeds from Jay Field and South Pass 89 properties and 90% of the net proceeds from the Offshore Louisiana property. Please see the reserve report as of September 30, 2010 filed as an exhibit to this Form 10-Q for more recent information. The Trust’s interests in these properties are equivalent to 50% of the net proceeds from Jay Field and South Pass 89 properties and 90% of the net proceeds from the Offshore Louisiana property.

 

The cumulative Offshore Louisiana escrow balance (which is held by the Working Interest Owner and is not segregated) as of December 31, 2009 was $8,812,616. The Offshore Louisiana Working Interest Owner expects to utilize all such amount in payment of a portion of the Trust’s share of Offshore Louisiana dismantlement costs. Under the conveyances, the Offshore Louisiana Working Interest Owner was and remains entitled to escrow or otherwise set aside substantially more than it has for Offshore Louisiana dismantlement costs. If the amounts escrowed or otherwise set aside are inadequate to pay the Trust’s share of the dismantlement costs, the Trust is not liable for the additional amounts. Assuming that the Offshore Louisiana Working Interest Owner has recovered all excess production costs, then, after the payment of the dismantlement costs, 90 percent of any funds remaining in “escrow” would be distributable to the Trust. However, the estimated Offshore Louisiana dismantlement costs exceed the escrowed amounts substantially, and no such distributions are likely.

 

The cumulative escrow balance (which is held by the Working Interest Owner and is not segregated) as of December 31, 2009 was $4,543,402 for the Jay Field property. The Jay Field Working Interest Owner expects to utilize all such amount in payment of a portion of the Trust’s share of Jay Field dismantlement costs. Under the conveyances, the Jay Field Working Interest Owner was and remains entitled to escrow or otherwise set aside substantially more than it has for Jay Field dismantlement costs. If the amounts escrowed or otherwise set aside are inadequate to pay the Trust’s share of the dismantlement costs, the Trust is not liable for the additional amounts. Assuming that the Jay Field Working Interest Owner has recovered all excess production costs, then, after the payment of the dismantlement costs, 50 percent of any funds remaining in “escrow” would be distributable to the Trust. However, the estimated Jay Field dismantlement costs exceed the escrowed amounts substantially, and no such distributions are likely.

 

The cumulative escrow balance (which is held by the Working Interest Owner and is not segregated) as of December 31, 2009 was $8,936,923 for the South Pass 89 property. The South Pass 89 Working Interest Owner expects to utilize all such amount in payment of a portion of the Trust’s share of South Pass 89 dismantlement costs. Under the conveyances, the South Pass 89 Working Interest Owner was and remains entitled to escrow or otherwise set aside substantially more than it has for South Pass 89 dismantlement costs. If the amounts escrowed or otherwise set aside are inadequate to pay the Trust’s share of the dismantlement costs, the Trust is not liable for the additional amounts. Assuming that the South Pass 89 Working Interest Owner has recovered all excess production costs, then, after the payment of the dismantlement costs, 50 percent of any funds remaining in “escrow” would be distributable to the Trust. However, the estimated South Pass 89 dismantlement costs exceed the escrowed amounts substantially, and no such distributions are likely.

 

The conveyances do not require the Working Interest Owners to place the “escrowed” funds into an actual escrow account or to segregate funds in any other manner, and neither of the working interest owners has done so. However, under the conveyances, each Working Interest Owner (or any successor owner of the working interest) is required to calculate Gross Proceeds as though such funds had been escrowed and then subsequently utilized for purposes of paying actual abandonment and related costs. Quantum began withholding additional funds under these provisions in the Trust’s accounting month of December 2010. Information furnished by Quantum to the Trust for production month April 2011 and Trust accounting month July 2011 indicates that 125% of Quantum’s current estimate of these costs is approximately $26,500,000 and that the amount withheld in escrow is $8,900,000.

 

The Working Interest Owners have advised the Trustee that they intend to escrow any amounts otherwise distributable to the Trust to the extent permitted to do so by the conveyances.

 

As of December 31, 2009 the Trust had $3,741 in cash. As of December 31, 2009, the Trust was holding unpaid invoices for administrative services totaling $393,577.

As of August 19, 2011, the total amount of the Bank Advance was $2,255,520, of which $161,217 remained available to pay expenses at August 19, 2011. However, at August 19, 2011, in addition to the amount owed to the Bank, the Trust was also holding unpaid invoices for administrative services totaling $443,492.

 

The Bank Advance is interest-free. No Trust distributions can be made until the Bank Advance has been repaid.

 

The entire amount of the Bank Advance and all other liabilities and expenses of the Trust must be repaid before any distributions can be made to Unit holders.

 

If the Trust is unable to sell its assets and liquidate promptly, the Trust may attempt to borrow funds in accordance with the Trust Agreement to fund Trust expenses. However, the Trust will be prohibited from borrowing funds unless the Trustee determines that the total amount the Trust would then have borrowed is less than 50% of the amount of revenues the Trustee estimates will be received by the Trust during the immediately following six months. Consequently, unless the Trustee determines that the Trust’s assets will be sold within six months, no borrowings appear reasonably possible. Even if the Trust is able to proceed with the sale of its assets, the Trust may not be able to borrow funds. The Trust Agreement permits, but does not require, The Bank of New York Mellon Trust Company, N.A. or an affiliate to lend funds to the Trustee. The Trust Agreement prohibits the Trustee from making any distributions to Unit holders until all loans and all advances are repaid in full. If the Trust is unable to sell its assets or borrow funds, the Trust would probably have to be liquidated in bankruptcy.

 

Recent Developments

 

Termination of the Trust

 

A meeting of the unit holders has been called by the Trustee at the request of a unit holder. The purpose of the meeting is to vote on the unit holder’s proposal to remove The Bank of New York Mellon Trust Company, N.A. as Trustee and to appoint a successor trustee of the Trust. The meeting was convened on August 12, 2011. Because the proposed successor trustee withdrew its consent to serve shortly prior to the meeting, the meeting has been adjourned until August 24, 2011. All statements in this report regarding the intentions or future actions of the Trustee depend on the Trustee remaining the trustee of the Trust. However, the Trustee may be replaced at the meeting.

 

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 to the Trust for the years ended December 31, 2007 and 2006 calculated in accordance with the Trust Agreement were $1,634,740 and $2,094,226, respectively. Consequently, the Trust is required to terminate and is now required to sell the assets of the Trust for cash in a public auction. After paying or making provision for all actual and contingent liabilities of the Trust, including fees of the Trustee, the Trustee will distribute any remaining cash as promptly as practicable. Despite the termination of the Trust, the Trustee is continuing to act as Trustee for purposes of liquidating and winding up the affairs of the Trust. The Trustee does not expect to make any further monthly distributions to Unit holders in the interim period prior to any distribution resulting from the sale of the Trust’s assets.

 

The Trustee has retained Stifel, Nicolaus & Company, Incorporated, a nationally recognized investment banking firm, (the “Financial Advisor”), to market the Trust’s assets. However, as announced by the Trustee on October 22, 2008, the Trustee previously determined that, in light of market conditions at that time, it was in the best interests of the Trust Unit holders to postpone the sale of the Trust’s assets for an indefinite period of time. The Trustee recommenced the marketing efforts in 2010. The Financial Advisor marketed the Trust’s assets and had received preliminary indications of interest in late 2010, and the Trustee intended to sell the assets in accordance with the terms of the Trust Agreement. However, as previously announced, in November 2010 the Trust and Trustee were named as defendants in a Complaint for Legal and Equitable Relief (the “Complaint”) filed by Jeff Beckett in the United States District Court for the Eastern District of Michigan. Mr. Beckett’s Complaint sought a judicial modification of the terms of the Trust Agreement governing the Trust, a judgment declaring that the termination provisions of the Trust Agreement do not apply and an order preventing the sale of the Trust’s assets. The Complaint also made a number of other allegations and seeks removal of the Trustee and other relief. On July 7, 2011, Mr. Beckett and the Trust entered into a settlement agreement pursuant to which Mr. Beckett agreed to dismiss his lawsuit with prejudice within ten days after the Trust holds a meeting of the Unit holders for the purpose of voting on

a proposal to remove the Trustee and to appoint a successor trustee of the Trust, provided that notice of the meeting is mailed by August 1, 2011 and the meeting occurs by September 1, 2011. Notice of the meeting was mailed prior to August 1, 2011, and the meeting was convened on August 12, 2011. Because the proposed successor trustee withdrew its consent to serve shortly prior to the meeting, the meeting has been adjourned until August 24, 2011.

 

The Trust Agreement provides that if any asset required to be sold has not been sold by December 31, 2010, the Trustee is to cause the asset to be sold at public auction to the highest cash bidder. Consequently, unless removed or prevented from doing so by a court order, the Trustee will auction the Trust’s assets. In connection with the auction, the Trustee will mail notice of a public auction to all Unit holders at least 30 days prior to any such auction. No approval of the Unit holders will be required in connection with the sale of the Trust’s assets.

 

As of December 31, 2009, the Trust had $3,741 in cash and was holding unpaid invoices for administrative services totaling approximately $393,577. See Management’s Discussion and Analysis”.

 

As of August 19, 2011, the Trust had no cash except for the cash advanced to the Trust by BNY Mellon, as affiliate of the Trustee, as an interest-free advance to enable the Trust to pay administrative expenses. As of August 19, 2011, the total amount advanced to the Trust (the “Bank Advance”) by the Bank was $2,255,520, of which $161,217 remained available to pay expenses at August 19, 2011. However, at August 19, 2011, in addition to the amount owed to the Bank, the Trust was also holding unpaid invoices for administrative services totaling $443,492. See Management’s Discussion and Analysis. The entire amount of the Bank Advance and all other liabilities and expenses of the Trust must be repaid before any distributions can be made to Unit holders.

 

The entire amount of the Bank Advance and all other liabilities and expenses of the Trust must be repaid before any distributions can be made to Unit holders.

 

During 2010 the Trust did not receive any royalty revenue except for $10,064 from the Fee Lands (which were sold in November 2009) and for $223,910 received in 2010 as an adjustment resulting from a review conducted by an independent oil and gas accounting firm retained by the Trustee to review the Working Interest Owner’s calculation of the net proceeds properly payable to the Trust with respect to the Jay Field Property. The adjustment related to the Working Interest Owner’s calculation of the net proceeds from the acquisition of the Jay Field working interest by Quantum Resources Management, LLC in 2007 through August 2008. The portion of the adjustment related to 2007, even if received in 2007, would not have affected the termination of the Trust in accordance with the terms of the Trust Agreement.

 

During 2009, the only royalty revenue the Trust received was $737,199 with respect to the South Pass 89 property and $70,905 from the Fee Lands. In addition, on November 11, 2009, the Trust sold its interest in the south Louisiana acreage described in the Trust’s public filings as the “Fee Lands”. The sale resulted in cash proceeds to the Trust, net of fees of $24,828 paid to the auction company that conducted the sale, of approximately $500,000.

 

During 2008, the Trust received a single payment of approximately $437,000 as a result of a review conducted by an independent oil and gas accounting firm retained by the Trustee to review the Working Interest Owner’s calculation of amounts relevant to the determination of the net proceeds properly payable to the Trust with respect to the inadvertent inclusion of sulfur extraction processing costs at the Jay and Little Escambia Creek Field Unit desulfurization plant in the calculation of Jay Field Gross Proceeds. The only other royalty revenue the Trust received in 2008 was $204,741 attributable to the Fee Lands Royalties and $37,239 attributable to South Pass 89.

 

During 2007, the Trust received a payment of approximately $1,566,000 with respect to Jay Field property and approximately $399,000 with respect to the Fee Land property. The Trust did not receive any royalty income from South Pass 89 or Offshore Louisiana properties.

 

The Jay Field, South Pass 89 and Offshore Louisiana properties excess production costs as of December 31, 2010 were approximately $13,588,000, $868,000, and $2,171,000, respectively. The excess production costs as of December 31, 2009 were $12,889,000, $373,000, and $3,227,000, respectively. For the year ended December 31, 2008, they were $10,930,000, $56,000 and $11,158,000, respectively. The excess production costs relating to each property must be recovered by the Working Interest Owners before any the Working Interest Owners are required to pay any royalty revenues to the Trust with respect to the particular property.

As previously described in the Trust’s filings, in addition to the Working Interest Owners’ rights to recover Excess Production Costs prior to making payments to the Trust, the Working Interest Owners have the right under the Conveyances to escrow or withhold amounts for certain anticipated future expenses, and the Working Interest Owners have done so and expect to continue doing so in the future. Under the Conveyance, the Working Interest Owners may compute the Royalties without establishing actual third party escrows of withheld funds.

 

Timing of Liquidation

 

The Trust Agreement provides that the Trust must sell its assets and terminate if net revenues fall below $5,000,000 (the “Termination Threshold”) for two successive years. Net revenues to the Trust in 2006 and 2007 fell below the Termination Threshold.. The Trust Agreement provides that if any asset required to be sold has not been sold by December 31, 2010, the Trustee will cause the asset to be sold at public auction to the highest cash bidder. The Trustee intends to comply with the Trust Agreement unless prevented from doing so by a court order.

 

Status of Sale Efforts and Litigation

 

As previously disclosed, the Trustee engaged the Financial Advisor to market the Trust’s assets in anticipation of a sale in accordance with the terms of the Trust Agreement. The Financial Advisor marketed the Trust’s assets and had received preliminary indications of interest in late 2010, and the Trustee intended to sell the assets in accordance with the terms of the Trust Agreement. However, also as previously announced, in November 2010 the Trust and Trustee were named as defendants in a Complaint for Legal and Equitable Relief (the “Complaint”) filed by Jeff Beckett in the United States District Court for the Eastern District of Michigan (the “Court”). Mr. Beckett’s Complaint sought a judicial modification of the terms of the Trust Agreement governing the Trust, a judgment declaring that the termination provisions of the Trust Agreement do not apply and an order preventing the sale of the Trust’s assets. The Complaint also made a number of other allegations and sought removal of the Trustee and other relief.

 

As a result of Mr. Beckett’s lawsuit, certain bidders who had submitted preliminary indications of interest to the Financial Advisor indicated that they were unwilling to proceed with the purchase of the Jay Field interest from the Trust until the Beckett lawsuit was resolved. Consequently, as previously disclosed, the Trustee suspended the sale process pending resolution of the lawsuit. On March 4, 2011 the Court entered a stipulated order in which the Trust voluntarily agreed that the Trust would not sell any assets of the Trust until at least such time as the Court entered an order dismissing or transferring the case or preliminarily enjoining the sale of the assets. The Trustee filed a Motion to Dismiss for Failure to Join Required Parties, or, in the Alternative, to Transfer Venue with the Court seeking dismissal of the suit and/or transfer of the suit to the United States District Court for the Western District of Texas. However, on July 7, 2011, Mr. Beckett and the Trust entered into a settlement agreement pursuant to which Mr. Beckett agreed to dismiss his lawsuit with prejudice within ten days after the Trust holds a meeting of the Unit holders for the purpose of voting on a proposal to remove the Trustee and to appoint a successor trustee of the Trust, provided that notice of the meeting is mailed by August 1, 2011 and the meeting occurs by September 1, 2011. Notice of the meeting was mailed prior to August 1, 2011, and the meeting was convened on August 12, 2011. Because the proposed successor trustee withdrew its consent to serve shortly prior to the meeting, the meeting has been adjourned until August 24, 2011. If the suit is not dismissed, the pending suit could adversely affect the price the Trust might receive in any sale that may be possible.

 

The Trustee intends to comply with the terms of the Trust Agreement unless prevented from doing so by a court order. Consequently, unless removed, the Trustee intends to arrange for the auction of the Trust’s assets in accordance with the terms of the Trust Agreement. The Trustee will mail notice of any such auction of the Trust’s assets to all Unit holders of record in accordance with the terms of the Trust Agreement. The Trustee will also notify all persons who had submitted preliminary indications of interest in purchasing some or all of the Trust’s assets of any such auction, and will endeavor to provide notice to other potential bidders as well.

 

As a result of the Beckett lawsuit, the Trust was unable to complete the sale of its assets prior to December 31, 2010, and is now required by the terms of the Trust Agreement to sell the assets by means of a public auction. The Trustee is unable to predict whether the persons who had submitted preliminary indications of interest in acquiring the Trust’s assets in 2010 will be interested in bidding for them in a public auction, or, if they are willing to bid, whether they will bid more or less than the amounts they indicated they would consider on a preliminary basis. The

preliminary indications of interest the Financial Advisor received when it marketed the Jay Field interest in 2010 ranged from $500,000 to $3,500,000. None of the preliminary indications of interest were firm offers, and all of them remained subject to further review.

 

Unit holders should review the reserve reports as of September 30, 2009 included with this annual report, as well as the more recent report as of September 30, 2010 included with the 2010 10-K, but should note, as previously disclosed in the Trust’s filings, that a reserve report is not necessarily indicative of the market value of the interests, and the value of the Trust’s assets will be determined solely by the amount a buyer is willing to pay for the assets. The September 30, 2009 reserve report, dated May 24, 2011, estimates the standardized measure of the Trust’s interest in future net revenues discounted at 10% annually in accordance with SEC guidelines to be approximately $202,000 as of September 30, 2009. Of this amount, the report estimates $202,000 of future net revenues discounted at 10% annually in accordance with SEC guidelines to be attributable to the Trust’s interest in the Jay Field.

 

In the reserve report, dated May 24, 2011, the reserve engineer considered the Trust’s interests in the South Pass 89 and Offshore Louisiana properties and estimated future revenues value to be zero. The Trust had previously announced that the engineers did not expect that a reserve report addressing the Trust’s interests in South Pass 89 and Offshore Louisiana would attribute any imputed reserves to the Trust’s interests in either of those properties or any estimated future net revenues attributable to the interests held by the Trust in either of those properties.

 

As previously disclosed, the administrative expenses of the Trust are approximately $1,000,000 annually, but have increased as a result of the Beckett lawsuit. As described above, the Trust’s unpaid invoices at August 19, 2011 were approximately $443,492, and the Trust owed an additional $2,255,520 to the Bank, of which $161,217 remained available to pay expenses. All additional expenses, including expenses incurred by the Trust but for which no invoices had been received at August 19, 2011, and including fees that will become payable to the Financial Advisor upon the sale of the assets and all other fees the Trust incurs, whether as a result of the delays caused by the Beckett lawsuit, or otherwise, must be paid prior to any distribution to Unit holders. It is increasingly likely that the sale of the Trust’s assets will not generate sufficient proceeds to pay the Trust’s liabilities. If the sale of the Trust’s assets does not generate sufficient proceeds to pay the Trust’s liabilities, there will be no further distributions to Trust Unit holders. As noted above, however, if the Trustee is able to auction the Trust’s assets, all Trust Unit holders will be mailed a notice of the public auction of the Trust’s assets, and any Unit holder who desires to do so may submit a bid for some or all of the assets.

 

Trust Agreement Requirement to Publicly Auction Trust Assets

 

As described in this report, the Trust Agreement requires the Trust to hold a public auction of the Trust’s assets that remained unsold at December 31, 2010. Consequently, unless removed, the Trustee intends to arrange for the auction of the Trust’s remaining assets in accordance with the terms of the Trust Agreement as soon as is reasonably practicable. The Trustee will mail notice of any such auction of the Trust’s assets to all Unit holders of record in accordance with the terms of the Trust Agreement. The Trustee would also notify all persons who had submitted preliminary indications of interest in purchasing some or all of the Trust’s assets of any such auction, and will endeavor to provide notice to other potential bidders as well.

 

The Trustee believes that a public auction of the Trust’s assets as required by the Trust Agreement as soon as possible would maximize the Trust’s likelihood of being able to pay its expenses and make a final distribution to the Unit holders. The auction will be open to all bidders.

 

Terms of Bank Advance

 

The Bank Advance is interest-free. No Trust distributions can be made until the Bank Advance has been repaid.

 

Status of Review of Jay Field Royalty Computations

 

As described in the Trust’s prior filings, the Trustee engaged an independent joint interest auditing firm (the “Consultant”), to review the computation of the amounts payable to the Trust with respect to its interest in the Jay Field from the time of the sale by The Louisiana Land and Exploration Company (“LL&E”) of its working interest to Quantum Resources Management LLC in 2007 through August 2008 (the “First Review Period”). Also as

previously reported, the Consultant completed its review of the First Review Period, Quantum and the Trustee reached agreement on the issues the Consultant had raised relating to the computation of expenses properly chargeable in the calculation of amounts payable to the Trust for the First Review Period, and Quantum paid the Trust an additional $223,910 in 2010 as an adjustment relating to the First Review Period.

 

As further described in the Trust’s prior filings, the Trustee subsequently engaged the Consultant to review the computation of the amounts payable to the Trust with respect to its interest in the Jay Field for the production months September 2008 through March 2010 (the “Second Review Period”). Quantum and the Trustee have reached agreement on all significant matters raised by the Consultant with respect to the Second Review Period. The Trustee determined that it was able to prepare the Trust’s financial statements for the year ended December 31, 2009, which are included in this report.

 

The errors noted during the First Review Period and Second Review Period as discussed above were corrected during 2009 and are included in the “Revisions of Estimates” line in the information disclosed in footnote 9.

 

Quantum Decision to Escrow or Otherwise Withhold Funds for Estimated Future Abandonment and Related Costs

 

As previously disclosed, and as permitted by the conveyances creating the Trust’s interest in the Jay Field net profits interest, Quantum has informed the Trust’s independent petroleum engineers that Quantum has determined to escrow (or otherwise deduct from any payments otherwise due to the Trust) 125% of the estimated abandonment and related costs it expects to incur in connection with the working interest from which the Trust’s interest was created.

 

At December 31, 2009 Quantum’s estimate of the abandonment and related costs it expects to incur in connection with the working interest was approximately $14.2 million, of which approximately $4.5 million had previously been withheld by the working interest owner for estimated abandonment and related costs (the Trust’s interests in each of these figures is 50%). At December 31, 2010, of Quantum’s estimate of abandonment and related costs it expects to incur in connection with the Jay Field working interest was approximately $16.1 million, of which approximately $4.5 million had been withheld by the working interest owner (the Trust’s interests in each of these figures is 50%)

 

As previously disclosed, Quantum has recently indicated that it intends to withhold 125% of the estimated abandonment and related costs it expects to incur in connection with the working interest before making additional distributions to the Trust’s interest. Subject to the payment of the Excess Production Costs, the holder of the Trust’s interest would be entitled to 50% of the escrowed (or unpaid) amount remaining in excess of actual abandonment and related costs (whether the actual costs are more or less than the estimates). As previously disclosed, the conveyances do not require Quantum to place the “escrowed” funds into an actual escrow account or to segregate funds in any other manner, and neither Quantum nor the prior working interest owner has done so. However, under the conveyances, Quantum (or any successor owner of the working interest) is required to calculate Gross Proceeds as though such funds had been escrowed and then subsequently utilized for purposes of paying actual abandonment and related costs.

 

As previously disclosed, the Working Interest Owner of the Trust’s interests in South Pass 89 and Offshore Louisiana also has been escrowing funds (or otherwise deducting from any payments otherwise due to the Trust) funds for the estimated abandonment and related costs it expects to incur in connection with the working interest from which the Trust’s interest was created relating to those properties.

 

Hurricane Damages

 

During 2005, Hurricanes Katrina and Rita affected the operational status of properties included in the Offshore Louisiana and South Pass 89 groups of properties, and Hurricane Dennis and Tropical Storm Cindy affected the operational status of the gas plant at Jay Field. The gas plant at Jay Field returned to full operating status on April 13, 2006. However, distributions to the Trust have been reduced significantly as a result of the damage from these storms to the production facilities for properties in which the Trust has an interest.

Following is a description of the damage caused by Hurricanes Katrina and Rita to production facilities for properties in which the Trust has an interest. This information is based on assessments of damage the Working Interest Owner has received regarding damage from Hurricanes Katrina and Rita to the Offshore Louisiana and South Pass 89 properties. All of the information in this Report on Form 10-K relating to the operational status of the properties provided to the Working Interest Owner by the various operators of the properties in which the Trust has an interest, and was provided to the Trust by the Working Interest Owner. The Working Interest Owner is not the operator of any of these properties, and relies on the various operators for information regarding the operational status of the various properties. The information provided herein is based on the respective operators’ assessments of the damage to the production facilities.

 

South Pass 89

 

Repairs due to Hurricane Katrina damage (August 2005) were completed in the fourth quarter of 2006 and the field was substantially restored to production in December 2006. The operator, Marathon Oil Company, had provided a cost estimate of $6,000,000 ($1,500,000 net to the Trust) to repair the South Pass 89 “B” platform, however the operator has indicated the actual cost to date is estimated at $6,500,000 ($1,600,000 net to the Trust).

 

Offshore Louisiana Properties:

 

East Cameron 336

 

The Working Interest Owner had previously elected not to participate in proposed well work and remained responsible only for field abandonment costs. The lease expired in 2007 and the operator, Apache, informed the Working Interest Owner that it had abandoned the wells in the first half of 2008. The platform has not been abandoned yet due to a 3^rd party production pipeline located on the platform that requires abandonment prior to removal. It is estimated the platform removal and abandonment will cost an additional $4,000,000 ($800,000 net to the trust).

 

East Cameron 195

 

The East Cameron 195 platform was heavily damaged during Hurricane Rita; however, it was not a significant producer, had been shut in by the operator, Maritech, and had been approved for abandonment prior to Hurricane Rita. The 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 $55,400,000 ($18,400,000 net to the Trust). These costs are for well abandonment and platform abandonment. Well abandonment work began in February 2006 and was substantially finished in December 2006 (7 wells were plugged and abandoned and 3 wells had remaining plugging work that was to be completed as part of the platform and debris removal process). Significant difficulty was observed during the abandonment of these final three wells in 2009 and 2010 as a result of the damage from Hurricane Rita and completing final plug and abandon well work and platform abandonment proved costly. To complete final site clearance and debris removal an additional $2,100,000 ($709,000 net to the trust) is estimated to be required.

 

South Marsh Island 76

 

The South Marsh Island 76 platform was heavily damaged during Hurricane Rita in 2005. The operator, Mariner, abandoned the wells in 2008 for a cost of $13,343,824 ($3,335,956 net to the Trust). It is estimated an additional $4,500,000 ($1,100,000 net to the trust) will be required for final platform abandonment, debris removal and site clearance. Reefing the platform in place is being evaluated.

 

Eugene Island 261

 

The Eugene Island 261 platform was damaged during Hurricane Rita but was repaired and returned to production in November 2005. The estimated repair cost was $220,000 (resulting in costs attributable to the 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

 

In December 2006, the Working Interest Owner and ExxonMobil, as the operator of the Jay Field, sold their respective interests in the field to Quantum Resource Management LLC (Quantum). Quantum became the operator in April 2007. As described above under “Recent Developments”, Quantum suspended production from the Jay Field on December 22, 2008. Production resumed in December 2009.

 

Other

 

The Working Interest Owner has advised the Trustee that the Working Interest Owner has completed its analysis of the scope and applicability of the insurance policies carried by the Working Interest Owner to the damages that resulted from Hurricanes Katrina and Rita to properties in which the Trust has an interest. The Working Interest Owner has advised the Trustee that the Working Interest Owner believes it has received all of the insurance reimbursements it will receive for damages to the South Pass 89 and Offshore Louisiana properties, and has applied the amounts to the respective properties in which the Trust has an interest, to the extent permitted by the Trust’s governing documents, to offset existing Excess Production Costs and to fund the Special Cost Escrows for Offshore Louisiana and South Pass 89.

 

The Working Interest Owner has further informed the Trustee that although the work to secure and repair or replace damaged equipment and restore production at properties the operators have determined to repair has now been completed, work nevertheless remains ongoing to secure, plug, abandon and dismantle other properties in which the Trust has an interest and that the operators have determined to abandon. In particular, the work and expenses to plug, abandon and dismantle the facilities at South Marsh Island 76 and East Cameron 195 are expected to continue. The Working Interest Owner has informed the Trustee that these ongoing expenses are not insured.

 

The abandonment and repair costs have had a material adverse effect on royalties payable from the South Pass 89 and Offshore Louisiana properties to the Trust, and from the Trust to Unit holders. As previously disclosed, the Working Interest Owner began escrowing funds (or calculating the royalties as though it had done so) otherwise distributable to the Trust from the South Pass 89 property and Offshore Louisiana properties, beginning with the April 2006 monthly distributions. In addition, the Jay Field Working Interest Owner has begun or intends to begin escrowing funds, if any, not utilized to pay Excess Production Costs. Consequently, distributions from the Trust to the Unit holders have been eliminated for a period of time. The Trustee does not expect to make any further distribution prior to a final liquidating distribution after the sale of the Trust’s interests. As described herein and in prior filings by the Trust, the Working Interest Owners are not required to fund actual escrow accounts, and neither has done so.

Results of Operations

 

 

Royalty 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, 2009, 2008 and 2007 are attributable to the Working Interest Owner’s operations during the twelve-month periods ended September 30, 2009, 2008 and 2007, respectively.

 

Administrative expenses incurred by the Trust increased $294,148 or 29% for the year ended December 31, 2009 as compared to the year ended December 31, 2008. The increase in 2009 administrative expenses was primarily a result of increases in accounting and legal fees incurred by the Trust. Administrative expenses incurred by the Trust decreased $320,646 or 24% for the year ended December 31, 2008 as compared to the year ended December 31, 2007. The decrease in 2008 administrative expenses was primarily a result of decreases in accounting and legal fees incurred by the Trust.

 

Distributions to Unit holders for 2009, 2008 and 2007 amounted to $0 ($0.0000 per Unit), $0 ($0.0000 per Unit) and $1,150,481 ($0.0606 per Unit) respectively. During these years, the Trust received cash of $808,104, $678,528 and $1,965,473, respectively, from the Working Interest Owner with respect to the Royalties from the Properties. During 2009, the Trust also received $500,172 in proceeds from the sale of Royalty 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.

 

Revenues of the Working Interest Owner with respect to the Productive Properties decreased approximately $40,905,000 or 79 percent during the 2009 operating period compared to the same operating period in 2008. This was offset by lower production costs and capital expenditures and the receipt of $10,041,086 of insurance recovery proceeds. Revenues of the Working Interest Owner with respect to the Productive Properties increased approximately $22,878,000 or 77 percent during the 2008 operating period compared to the same operating period in 2007. This was offset by higher production costs and capital expenditures. The following unaudited schedule provides a summary of the Working Interest Owner’s net production attributable to the Trust.

 

 

Average natural gas prices received in 2009 decreased to $3.75 per thousand cubic feet (“mcf”) from $9.29 per mcf in 2008. Average crude oil prices decreased to $67.93 per barrel in 2009 from $109.32 per barrel in 2008 while natural gas liquids prices decreased to $19.31 per barrel in 2009 from $51.15 in 2008. Average natural gas prices received in 2008 increased to $9.29 per thousand cubic feet (“mcf”) from $7.12 per mcf in 2007. Average crude oil prices increased to $109.32 per barrel in 2008 from $65.01 per barrel in 2007 while natural gas liquids prices decreased to $51.15 per barrel in 2008 from $52.58 in 2007.

 

In 2009, the Working Interest Owner reserved $4,044,739 in escrow as a result of uncertainties related to the oil and gas properties. In 2008, the Working Interest Owner reserved $11,527,054 in escrow as a result of uncertainties related to the oil and gas properties. In 2007, the Working Interest Owner reserved $7,973,453 in escrow as a result of uncertainties related to the oil and gas properties.

 

Production costs and expenses incurred by the Working Interest Owner on the Productive Properties decreased approximately $21,517,000, or 66 percent, between the 2009 operating period and the 2008 operating period. Production costs and expenses incurred by the Working Interest Owner on the Productive Properties increased approximately $5,200,000, or 19 percent, between the 2008 operating period and the 2007 operating period. The increase in 2007 was primarily attributed to increased lease operating expenses, non-operated overhead, and labor costs at Jay Field and Offshore Louisiana.

 

Capital expenditures decreased approximately $11,066,000, or 69% percent, between 2009 and 2008. The decrease in 2009 was primarily the result of plant turnaround and workovers at Jay Field. Capital expenditures increased approximately $13,500,000, or 559% percent, between 2008 and 2007. The increase in 2008 was primarily the result of plant turnaround and workovers at Jay Field. -

 

The Trust’s Fee Lands Royalties decreased approximately $133,836 or 65 percent in the 2009 operating period compared to the same period in 2008. The Trust’s Fee Lands Royalties decreased approximately $194,511 or 49 percent in the 2008 operating period compared to the same period in 2007. The amount of Fee Lands leased as of December 31, 2009 and December 31, 2008 was approximately 0 and 1,062 acres, respectively.

 

The Trustee has been informed by the Working Interest Owner that the Working Interest Owner has been named as one of many defendants in certain lawsuits alleging the underpayment of royalties on the production of natural gas and natural gas liquids through the use of below-market prices, improper deductions, improper measurement techniques and transactions with affiliated companies. Plaintiffs in some of the lawsuits allege that the underpayment of royalties, among other things, resulted in false forms being filed by the Working Interest Owner with the Minerals Management Service, thereby violating the civil False Claims Act.

 

If the plaintiffs are successful in the matters described above, revenues to the Trust could decrease. A judgment or settlement could entitle the Working Interest Owner to reimbursements for past periods attributable to properties covered by the 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.

 

 

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 natural gas. 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 Owners. Factors that contribute to price fluctuation include, among others:

 

 

Moreover, government regulations, such as regulation of natural gas transportation and price controls, can affect product prices in the long term.

 

LL&E ROYALTY TRUST

STATEMENTS OF CASH EARNINGS AND DISTRIBUTIONS
Years Ended December 31, 2009, 2008 and 2007

 

 

December 31, 2009 and 2008

 

 

Years Ended December 31, 2009, 2008 and 2007

 

 

See accompanying notes to financial statements.

LL&E ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS

December 31, 2009, 2008 and 2007

 

 

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, 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 (including the Company) is a wholly owned subsidiary of ConocoPhillips. The merger has had no significant effects on the Trust. In December 2006, the Company, as working interest owner, and ExxonMobil, as the operator of the Jay Field, sold their respective interests in the Jay Field properties located in Florida and Alabama to Quantum Resource Management LLC (“Quantum”). Quantum began operating the Jay Field properties in April 2007. As used in this report, the terms “Working Interest Owner” and “Working Interest Owners” refer to The Louisiana Land and Exploration Company for the South Pass 89 and Offshore Louisiana properties and, after its December 2006 acquisition of the Jay Field interest, Quantum, for the Jay Field properties.

 

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 Mellon Trust Company, N.A., (the Trustee), having only such powers as are necessary for the collection and distribution of revenues resulting from the Royalties, the payment of Trust liabilities and the conservation and protection of the Trust estate. The Units were listed on the New York Stock Exchange (NYSE SYMBOL — LRT) through November 19, 2009 and are now traded over the counter.

 

Trust Termination

 

The Trust Agreement provides that the Trust will terminate in the event that the net revenues fall below $5,000,000 for two successive years (the “Termination Threshold”). Net revenues are calculated as royalty revenues after administrative expenses of the Trust and as if the Trust had received its pro rata portion of any amounts being withheld by the Working Interest Owners or the Partnership under escrow arrangements or to make refund payments pursuant to the Conveyances (the 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 years ended December 31, 2007 and 2006 calculated as described above, were $1,634,740 and $2,094,226, respectively. Consequently, the Trust is required to terminate and is required to sell the assets of the Trust for cash by means of a public auction. After paying or making provision for all actual and contingent liabilities of the Trust, including fees of the Trustee, the Trustee will distribute any remaining cash as promptly as practicable. Despite the termination of the Trust, the Trustee is continuing to act as Trustee for purposes of liquidating and winding up the affairs of the Trust. The Trustee does not expect to make any further monthly distributions to Unit holders in the interim period prior to any distribution resulting from the sale of the Trust’s assets. See “Management’s Discussion and Analysis.”

 

The Trustee has retained Stifel, Nicolaus & Company, Incorporated (the “Financial Advisor”), a nationally recognized investment banking firm, to market the Trust’s assets. However, as announced by the Trustee on

LL&E ROYALTY TRUST

 

NOTES TO FINANCIAL STATEMENTS — (Continued)

 

October 22, 2008, the Trustee previously determined that, in light of market conditions at that time, it was in the best interests of the Trust unit holders to postpone the sale of the Trust’s assets for an indefinite period of time. The Trustee recommenced the marketing efforts in 2010. The Financial Advisor marketed the Trust’s assets and had received preliminary indications of interest in late 2010, and the Trustee intended to sell the assets in accordance with the terms of the Trust Agreement. However, as previously announced, in November 2010 the Trust and Trustee were named as defendants in a Complaint for Legal and Equitable Relief (the “Complaint”) filed by Jeff Beckett in the United States District Court for the Eastern District of Michigan. Mr. Beckett’s Complaint seeks a judicial modification of the terms of the Trust Agreement governing the Trust, a judgment declaring that the termination provisions of the Trust Agreement do not apply and an order preventing the sale of the Trust’s assets. The Complaint also makes a number of other allegations and seeks removal of the Trustee and other relief. See Item 1 — “Terms and Operation of the Trust — Status of Sale Efforts and Litigation” and “Management’s Discussion and Analysis”.

 

On July 7, 2011, Mr. Beckett and the Trust entered into a settlement agreement pursuant to which Mr. Beckett agreed to dismiss his lawsuit with prejudice within ten days after the Trust holds a meeting of the Unit holders for the purpose of voting on a proposal to remove the Trustee and to appoint a successor trustee of the Trust, provided that notice of the meeting is mailed by August 1, 2011 and the meeting occurs by September 1, 2011. Notice of the meeting was mailed prior to August 1, 2011, and the meeting was convened on August 12, 2011. Because the proposed successor trustee withdrew its consent to serve shortly prior to the meeting, the meeting has been adjourned until August 24, 2011.

 

The Trust Agreement provides that if any asset required to be sold has not been sold by December 31, 2010, the Trustee is to cause the asset to be sold at public auction to the highest cash bidder. Consequently, unless replaced or prevented from doing so by the Beckett lawsuit or otherwise, the Trustee will mail notice of a public auction to all Unit holders at least 30 days prior to an such auction in accordance with the Trust Agreement. No approval of the Unit holders will be required in connection with the sale of the Trust’s assets.

 

As of December 31, 2009, the Trust had $3,741 in cash reserved for Trust expenses and unpaid invoices of approximately $393,000. Based on current general and administrative expenditures, in the absence of Royalty Revenues the Trustee expects that it will be required to borrow money in accordance with the Trust Agreement to fund future Trust expenses. However, no assurance can be given that the Trustee will be able to borrow money on terms the Trustee considers reasonable or at all. The Trust Agreement permits, but does not require, The Bank of New York Mellon Trust Company, N.A. or an affiliate to lend funds to the Trustee. In the event any loans are made to the Trust, the Trust Agreement will prohibit the Trustee from making any distributions to unitholders until those loans are repaid in full.

 

During 2009, the Trust did not receive any royalty revenue associated with the Jay Field or Offshore Louisiana properties. The Trust received $737,199 of royalty revenue from the South Pass 89 property and $70,905 of royalty revenue from the Fee Lands property in 2009. Excess production costs must be recovered by the Working Interest Owners before any distribution of royalty revenues will be made to the Trust.

 

Recent Developments

 

A meeting of the unit holders has been called by the Trustee at the request of a unit holder. The purpose of the meeting is to vote on the unit holder’s proposal to remove The Bank of New York Mellon Trust Company, N.A. as Trustee and to appoint a successor trustee of the Trust. The meeting was convened on August 12, 2011. Because the proposed successor trustee withdrew its consent to serve shortly prior to the meeting, the meeting has been adjourned until August 24, 2011. All statements in this report regarding the intentions or future actions of the Trustee depend on the Trustee remaining the trustee of the Trust. However, the Trustee may be replaced at the meeting.

 

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 to the Trust for the years ended

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NOTES TO FINANCIAL STATEMENTS — (Continued)

 

December 31, 2007 and 2006 calculated in accordance with the Trust Agreement were $1,634,740 and $2,094,226, respectively. Consequently, the Trust is required to terminate and is now required to sell the assets of the Trust for cash in a public auction. After paying or making provision for all actual and contingent liabilities of the Trust, including fees of the Trustee, the Trustee will distribute any remaining cash as promptly as practicable. Despite the termination of the Trust, the Trustee is continuing to act as Trustee for purposes of liquidating and winding up the affairs of the Trust. The Trustee does not expect to make any further monthly distributions to Unit holders in the interim period prior to any distribution resulting from the sale of the Trust’s assets.

 

The Trustee has retained the Financial Advisor to market the Trust’s assets. However, as announced by the Trustee on October 22, 2008, the Trustee previously determined that, in light of market conditions at that time, it was in the best interests of the Trust Unit holders to postpone the sale of the Trust’s assets for an indefinite period of time. The Trustee recommenced the marketing efforts in 2010. The Financial Advisor marketed the Trust’s assets and had received preliminary indications of interest in late 2010, and the Trustee intended to sell the assets in accordance with the terms of the Trust Agreement. However, as previously announced, in November 2010 the Trust and Trustee were named as defendants in a Complaint for Legal and Equitable Relief (the “Complaint”) filed by Jeff Beckett in the United States District Court for the Eastern District of Michigan. Mr. Beckett’s Complaint seeks a judicial modification of the terms of the Trust Agreement governing the Trust, a judgment declaring that the termination provisions of the Trust Agreement do not apply and an order preventing the sale of the Trust’s assets. The Complaint also makes a number of other allegations and seeks removal of the Trustee and other relief.

 

As a result of Mr. Beckett’s lawsuit, certain bidders who had submitted preliminary indications of interest to the Financial Advisor indicated that they were unwilling to proceed with the purchase of the Jay Field interest from the Trust until the Beckett lawsuit was resolved. Consequently, as previously disclosed, the Trustee suspended the sale process pending resolution of the lawsuit. On March 4, 2011 the Court entered a stipulated order in which the Trust voluntarily agreed that the Trust would not sell any assets of the Trust until at least such time as the Court entered an order dismissing or transferring the case or preliminarily enjoining the sale of the assets. The Trustee filed a Motion to Dismiss for Failure to Join Required Parties, or, in the Alternative, to Transfer Venue with the Court seeking dismissal of the suit and/or transfer of the suit to the United States District Court for the Western District of Texas. However, on July 7, 2011, Mr. Beckett and the Trust entered into a settlement agreement pursuant to which Mr. Beckett agreed to dismiss his lawsuit with prejudice within ten days after the Trust holds a meeting of the Unit holders for the purpose of voting on a proposal to remove the Trustee and to appoint a successor trustee of the Trust, provided that notice of the meeting is mailed by August 1, 2011 and the meeting occurs by September 1, 2011. Notice of the meeting was mailed prior to August 1, 2011 and the meeting was convened on August 12, 2011. Because the proposed successor trustee withdrew its consent to serve shortly prior to the meeting, the meeting has been adjourned until August 24, 2011. If the suit is not dismissed, the pending suit could adversely affect the price the Trust might receive in any sale that may be possible.

 

As a result of the Beckett lawsuit, the Trust was unable to complete the sale of its assets prior to December 31, 2010, and is now required by the terms of the Trust Agreement to sell the assets by means of a public auction. The Trustee is unable to predict whether the persons who had submitted preliminary indications of interest in acquiring the Trust’s assets in 2010 will be interested in bidding for them in a public auction, or, if they are willing to bid, whether they will bid more or less than the amounts they indicated they would consider on a preliminary basis. The preliminary indications of interest the Financial Advisor received when it marketed the Jay Field interest in 2010 ranged from $500,000 to $3,500,000. None of the preliminary indications of interest were firm offers, and all of them remained subject to further review.

 

The Trust Agreement provides that if any asset required to be sold has not been sold by December 31, 2010, the Trustee is to cause the asset to be sold at public auction to the highest cash bidder. Consequently, unless removed or prevented from doing so by a court order, the Trustee intends to auction the Trust’s assets. In connection with the auction, the Trustee will mail notice of a public auction to all Unit holders at least 30 days prior to any such auction. No approval of the Unit holders will be required in connection with the sale of the Trust’s assets.

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NOTES TO FINANCIAL STATEMENTS — (Continued)

 

As of December 31, 2009, the Trust had $3,741 of cash. At December 31, 2009, the Trust was also holding unpaid invoices for administrative services totaling $393,577.

 

Subsequent to the year ended December 31, 2009 and during 2010, the Trust was required to borrow money to pay its operating expenses. As of December 31, 2010, the Trust had no cash except for cash advanced to the Trust by BNY Mellon, an affiliate of the Trustee, as an interest-free advance to enable the Trust to pay administrative expenses. As of December 31, 2010, the total amount advanced to the Trust (the “Bank Advance”) by the Bank was $1,144,310, of which $564,477 remained available to pay expenses at December 31, 2010. See Management’s Discussion and Analysis”. However, at December 31, 2010, in addition to the amount owed to the Bank, the Trust was also holding unpaid invoices for administrative services totaling $702,151.

 

As of August 19, 2011, the total amount of the Bank Advance remained at $2,255,520, of which $161,217 remained available to pay expenses at August 19, 2011. However, at August 19, 2011, in addition to the amount owed to the Bank, the Trust was also holding unpaid invoices for administrative services totaling $443,492. See Management’s Discussion and Analysis. The entire amount of the Bank Advance and all other liabilities and expenses of the Trust must be repaid before any distributions can be made to Unit holders.

 

If the Trust is unable to sell its assets and liquidate promptly, the Trust may attempt to borrow additional funds in accordance with the Trust Agreement to fund Trust expenses. However, the Trust will be prohibited from borrowing additional funds unless the Trustee determines that the total amount the Trust would then have borrowed is less than 50% of the amount of revenues the Trustee estimates will be received by the Trust during the immediately following six months. Consequently, unless the Trustee determines that the Trust’s assets will be sold within six months, no further borrowings appear reasonably possible. Even if the Trust is able to proceed with the sale of its assets, the Trust may not be able to borrow funds. The Trust Agreement permits, but does not require, The Bank of New York Mellon Trust Company, N.A. or an affiliate to lend funds to the Trustee. In the event any loans are made to the Trust, the Trust Agreement will prohibit the Trustee from making any distributions to Unit holders until those loans are repaid in full. If the Trust is unable to sell its assets or borrow additional funds, the Trust would probably have to be liquidated in bankruptcy.

 

During 2010 the Trust did not receive any royalty revenue except for $10,064 from the Fee Lands (which were sold in November 2009) and for $223,910 received in 2010 as an adjustment resulting from a review conducted by an independent oil and gas accounting firm retained by the Trustee to review the Working Interest Owner’s calculation of the net proceeds properly payable to the Trust with respect to the Jay Field Property. The adjustment related to the Working Interest Owner’s calculation of the net proceeds from the acquisition of the Jay Field working interest by Quantum Resources Management, LLC in 2007 through August 2008. The portion of the adjustment related to 2007, even if received in 2007, would not have affected the termination of the Trust in accordance with the terms of the Trust Agreement.

 

During 2009, the only royalty revenue the Trust received was $737,199 with respect to the South Pass 89 property and $70,905 from the Fee Lands. In addition, on November 11, 2009, the Trust sold its interest in the south Louisiana acreage described in the Trust’s public filings as the “Fee Lands”. The sale resulted in cash proceeds to the Trust, net of fees of $24,828 paid to the auction company that conducted the sale, of approximately $500,000.

 

During 2008, the Trust received a single payment of approximately $437,000 as a result of a review conducted by an independent oil and gas accounting firm retained by the Trustee to review the Working Interest Owner’s calculation of amounts relevant to the determination of the net proceeds properly payable to the Trust with respect to the inadvertent inclusion of sulfur extraction processing costs at the Jay and Little Escambia Creek Field Unit desulfurization plant in the calculation of Jay Field Gross Proceeds. The only other royalty revenue the Trust received in 2008 was $204,741 attributable to the Fee Lands Royalties and $37,239 attributable to South Pass 89.

 

During 2007, the Trust received a payment of approximately $1,566,000 with respect to Jay Field property and approximately $399,000 with respect to the Fee Land property. The Trust did not receive any royalty income from South Pass 89 or Offshore Louisiana properties.

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NOTES TO FINANCIAL STATEMENTS — (Continued)

 

Unit holders should review the reserve report as of September 30, 2009 included with this annual report, as well as the more recent report as of September 30, 2010 included with the 2010 10-K, but should note, as previously disclosed in the Trust’s filings, that a reserve report is not necessarily indicative of the market value of the interests, and the value of the Trust’s assets will be determined solely by the amount a buyer is willing to pay for the assets. The September 30, 2009 reserve report, dated May 24, 2011, estimates the standardized measure of the Trust’s interest in future net revenues discounted at 10% annually in accordance with SEC guidelines to be approximately $202,000 as of September 30, 2009. Of this amount, the report estimates $202,000 of future net revenues discounted at 10% annually in accordance with SEC guidelines to be attributable to the Trust’s interest in the Jay Field.

 

In preparing, the reserve report, dated May 24, 2011, the reserve engineer considered the Trust’s interests in the South Pass 89 and Offshore Louisiana properties and estimated future revenues value to be zero, the Trust had previously announced that the engineers did not expect that a reserve report addressing the Trust’s interests in South Pass 89 and Offshore Louisiana would attribute any imputed reserves to the Trust’s interests in either of those properties or any estimated future net revenues attributable to the interests held by the Trust in either of those properties.

 

As previously disclosed, the administrative expenses of the Trust are approximately $1,000,000 annually, but have increased as a result of the Beckett lawsuit. As described above, the Trust’s unpaid invoices at August 19, 2011were approximately $443,492, and the Trust owed an additional $2,255,520 to the Bank, of which $161,217 remained available to pay expenses. All additional expenses, including expenses incurred by the Trust but for which no invoices had been received at August 19, 2011, and including fees that will become payable to the Financial Advisor upon the sale of the assets and all other fees the Trust incurs, whether as a result of the delays caused by the Beckett lawsuit, must be paid prior to any distribution to Unit holders. It is increasingly likely that the sale of the Trust’s assets will not generate sufficient proceeds to pay the Trust’s liabilities. If the sale of the Trust’s assets does not generate sufficient proceeds to pay the Trust’s liabilities, there will be no further distributions to Trust Unit holders. As noted above, however, if the Trustee is able to auction the Trust’s assets, all Trust Unit holders will be mailed a notice of the public auction of the Trust’s assets, and any Unit holder who desires to do so may submit a bid for some or all of the assets.

 

As described in the Trust’s prior filings, the Trustee engaged an independent joint interest auditing firm (the “Consultant”), to review the computation of the amounts payable to the Trust with respect to its interest in the Jay Field from the time of the sale by The Louisiana Land and Exploration Company (“LL&E”) of its working interest to Quantum Resources Management LLC in 2007 through August 2008 (the “First Review Period”). Also as previously reported, the Consultant completed its review of the First Review Period, Quantum and the Trustee reached agreement on the issues the Consultant had raised relating to the computation of expenses properly chargeable in the calculation of amounts payable to the Trust for the First Review Period, and Quantum paid the Trust an additional $223,910 in 2010 as an adjustment relating to the First Review Period.

 

As further described in the Trust’s prior filings, the Trustee subsequently engaged the Consultant to review the computation of the amounts payable to the Trust with respect to its interest in the Jay Field for the production months September 2008 through March 2010 (the “Second Review Period”). Quantum and the Trustee have reached agreement on all but two of the issues raised by the Consultant with respect to the Second Review Period. As the remaining issues are immaterial to the amount of the Excess Production Costs at Jay Field at December 31, 2010, the Trustee determined that it was able to prepare the Trust’s financial statements for the year ended December 31, 2010, which are included in this report.

 

The errors noted during the First Review Period and Second Review Period as discussed above were corrected during 2009 and are included in the “Revisions of Estimates” line in the information disclosed in footnote 9.

 

As previously disclosed, and as permitted by the conveyances creating the Trust’s interest in the Jay Field net profits interest, Quantum has informed the Trust’s independent petroleum engineers that Quantum has determined to escrow (or otherwise deduct from any payments otherwise due to the Trust) 125% of the estimated abandonment

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NOTES TO FINANCIAL STATEMENTS — (Continued)

 

and related costs it expects to incur in connection with the working interest from which the Trust’s interest was created. At December 31, 2010 Quantum’s estimate of the abandonment and related costs it expects to incur in connection with the working interest was approximately $16.1 million, of which approximately $4.5 million had previously been withheld by the working interest owner for estimated abandonment and related costs (the Trust’s interests in each of these figures is 50%). As previously disclosed, Quantum has recently indicated that it intends to withhold 125% of the estimated abandonment and related costs it expects to incur in connection with the working interest before making additional distributions to the Trust’s interest. Subject to the payment of the Excess Production Costs, the holder of the Trust’s interest would be entitled to 50% of the escrowed (or unpaid) amount remaining in excess of actual abandonment and related costs (whether the actual costs are more or less than the estimates). As previously disclosed, the conveyances do not require Quantum to place the “escrowed” funds into an actual escrow account or to segregate funds in any other manner, and neither Quantum nor the prior working interest owner has done so. However, under the conveyances, Quantum (or any successor owner of the working interest) is required to calculate Gross Proceeds as though such funds had been escrowed and then subsequently utilized for purposes of paying actual abandonment and related costs.

 

As previously disclosed, the Working Interest Owner of the Trust’s interests in South Pass 89 and Offshore Louisiana also has been escrowing funds (or otherwise deducting from any payments otherwise due to the Trust) funds for the estimated abandonment and related costs it expects to incur in connection with the working interest from which the Trust’s interest was created relating to those properties.

 

During 2005, Hurricanes Katrina and Rita affected the operational status of properties included in the Offshore Louisiana and South Pass 89 groups of properties, and Hurricane Dennis and Tropical Storm Cindy affected the operational status of the gas plant at Jay Field. The gas plant at Jay Field returned to full operating status on April 13, 2006. However, distributions to the Trust will be reduced significantly for a period of time as a result of the damage from these storms to the production facilities for properties in which the Trust has an interest. As a result of the uncertainty of future proceeds from these properties, the Trustee as of December 31, 2010 has reserved $564,477 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 provided to the Working Interest Owner by the various operators of the properties in which the Trust has an interest, and was provided to the Trust by the Working Interest Owner. The working Interest Owner is not the operator of any of these properties, and relies on the various operators for information regarding the operational status of the various properties. Consequently, all of the information provided herein is based on preliminary and sometimes informal information provided by the operators of the Properties. The Information provided herein is based on the respective operators’ preliminary assessments of the damage to the production facilities. The Trustee has been informed that the assessments are ongoing, and that the assessments of damages, the predictions of the likelihood of repairs and time necessary to complete such repairs, the decisions to repair or abandon facilities, and all other estimates are subject to change.

 

South Pass 89

 

Repairs due to Hurricane Katrina damage (August 2005) were completed in the fourth quarter of 2006 and the field was substantially restored to production in December 2006. The operator, Marathon Oil Company, had provided a cost estimate of $6,000,000 ($1,500,000 net to the Trust) to repair the South Pass 89 “B” platform, however the operator has indicated the actual cost to date is estimated at $6,500,000 ($1,600,000 net to the Trust).

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NOTES TO FINANCIAL STATEMENTS — (Continued)

 

Offshore Properties:

 

East Cameron 336

 

The Working Interest Owner had previously elected not to participate in proposed well work and remained responsible only for field abandonment costs. The lease expired in 2007 and the operator, Apache, informed the Working Interest Owner that it had abandoned the wells in the first half of 2008. The platform has not been abandoned yet due to a 3^rd party production pipeline located on the platform that requires abandonment prior to removal. It is estimated the platform removal and abandonment will cost an additional $4,000,000 ($800,000 net to the trust).

 

East Cameron 195

 

The East Cameron 195 platform was heavily damaged during Hurricane Rita; however, it was not a significant producer, had been shut in by the operator, Maritech, and had been approved for abandonment prior to Hurricane Rita. The 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 $55,400,000 ($18,400,000 net to the Trust). These costs are for well abandonment and platform abandonment. Well abandonment work began in February 2006 and was substantially finished in December 2006 (7 wells were plugged and abandoned and 3 wells had remaining plugging work that was to be completed as part of the platform and debris removal process). Significant difficulty was observed during the abandonment of these final three wells in 2009 and 2010 as a result of the damage from Hurricane Rita and completing final plug and abandon well work and platform abandonment proved costly. To complete final site clearance and debris removal an additional $2,100,000 ($709,000 net to the trust) is estimated to be required.

 

South Marsh Island 76

 

The South Marsh Island 76 platform was heavily damaged during Hurricane Rita in 2005. The operator, Mariner, abandoned the wells in 2008 for a cost of $13,343,824 ($3,335,956 net to the Trust). It is estimated an additional $4,500,000 ($1,100,000 net to the trust) will be required for final platform abandonment, debris removal and site clearance. Reefing the platform in place is being evaluated.

 

Eugene Island 261

 

The Eugene Island 261 platform was damaged during Hurricane Rita but was repaired and returned to production in November 2005. The estimated repair cost was $220,000 (resulting in costs attributable to the 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

 

In December 2006, the Working Interest Owner and ExxonMobil, as the operator of the Jay Field, sold their respective interests in the field to Quantum Resource Management LLC (Quantum). Quantum became the operator in April 2007. As described above under “Recent Developments”, Quantum suspended production from the Jay Field on December 22, 2008. Production resumed in December 2009.

 

Other

 

The Working Interest Owner has advised the Trustee that the Working Interest Owner has completed its analysis of the scope and applicability of the insurance policies carried by the Working Interest Owner to the

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NOTES TO FINANCIAL STATEMENTS — (Continued)

 

damages that resulted from Hurricanes Katrina and Rita to properties in which the Trust has an interest. The Working Interest Owner has advised the Trustee that, the Working Interest Owner believes it has received all of the insurance reimbursements it will receive for damages to the South Pass 89 and Offshore Louisiana properties, and has applied the amounts to the propertiesto the extent permitted by the Trust’s governing documents, to offset existing Excess Production Costs and to fund the Special Cost Escrows for Offshore Louisiana and South Pass 89.

 

The Working Interest Owner has further informed the Trustee that although the work to secure and repair or replace damaged equipment and restore production at properties the operators have determined to repair has now been completed, work nevertheless remains ongoing to secure, plug, abandon and dismantle other properties in which the Trust has an interest and that the operators have determined to abandon. In particular, the work and expenses to plug, abandon and dismantle the facilities at South Marsh Island 76 and East Cameron 195 are expected to extend into 2010 or longer. The Working Interest Owner has informed the Trustee that these ongoing expenses are not insured.

 

The abandonment and repair costs estimated by the Working Interest Owner have had and are expected to have a material adverse effect on royalties payable from the South Pass 89 and Offshore Louisiana properties to the Trust, and from the Trust to Unit holders. As previously disclosed, the Working Interest Owner began escrowing funds otherwise distributable to the Trust from the South Pass 89 property and Offshore Louisiana properties, beginning with the April 2006 monthly distribution. Consequently, distributions from the Trust to the Unit holders have been eliminated for a period of time. The Trustee does not expect to make any further distribution prior to a final liquidating distribution after the sale of the Trust’s interests. As described herein, the Working Interest Owners are not required to fund actual escrows accounts, and neither have done so.

 

 

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 for the second consecutive year, thus requiring the Trust to termination effective December 31, 2007. The accompanying financial statements do not include any adjustments as a result of the termination of the Trust.

 

Additionally, the Trust has $3,741 in cash reserved for Trust expenses as of December 31, 2009 and had unpaid invoices of approximately $368,000. Based on current general and administrative expenditures, in the absence of Royalty Revenues the Trustee expects that it will be required to borrow money in accordance with the Trust Agreement to fund future Trust expenses. However, no assurance can be given that the Trustee will be able to borrow money on terms the Trustee considers reasonable or at all. The Trust Agreement permits, but does not require, The Bank of New York Mellon Trust Company, N.A. or an affiliate to lend funds to the Trustee. In the event any loans are made to the Trust, the Trust Agreement will prohibit the Trustee from making any distributions to unit holders until those loans are repaid in full.

 

 

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

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NOTES TO FINANCIAL STATEMENTS — (Continued)

 

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.

 

As noted previously, on November 11, 2009, the Trust sold its interest in the south Louisiana acreage described in the Trust’s public filings as the “Fee Lands”. The sale resulted in cash proceeds to the Trust, net of fees of $24,828 paid to the auction company that conducted the sale, of approximately $500,000.

 

The Trustee engaged an independent joint venture auditor to review payments to the Trust for a portion of the Trust properties as part of the termination of the Trust. The joint venture auditor reviewed the period from January 2004 through December 2007. As a result of the review, one of the Working Interest Owners made a payment of approximately $437,000 in March 2008 to the Trust to settle certain issues identified.

 

 

The financial statements were prepared on the basis of cash receipts and disbursements and are not intended to be a presentation in conformity with accounting principles generally accepted in the United States of America that may require a liquidation basis of accounting. 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 financial statements of the Trust do not include any adjustments as a result of the termination of the Trust as described in notes 1 and 2 and 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) The carrying value of the Trust’s royalty interests at December 31, 2009 is not necessarily indicative of the fair market value of the interests held by the Trust.

 

This basis for reporting distributable income is considered to be the most meaningful because distributions to the unitholders for a month are based on net cash receipts for such month. However, it will differ from the basis used for financial statements prepared in accordance with accounting principles generally accepted in the United States because, under such accounting principles, royalty income for a month would be based on net proceeds from sales for such month without regard to when calculated or received and interest income for a month would be calculated only through the end of such month, and accounting principles generally accepted in the United States would require a liquidation basis of accounting.

 

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

 

 

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

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NOTES TO FINANCIAL STATEMENTS — (Continued)

 

not as a “simple” or “complex” trust (a “non-grantor” trust), (c) the Partnership will be classified as a partnership and not as an association taxable as a corporation, (d) the Company will not recognize gain or loss upon the transfer of the Royalties to the Trust or upon the distribution of the Units to its stockholders, (e) each Royalty will be considered an economic interest in oil and gas in place, and each Overriding Royalty will constitute a single property within the meaning of Section 614(a) of the Internal Revenue Code (Code), (f) the steps taken to create the Trust and the Partnership and to distribute the Units would be viewed for federal income tax purposes as a distribution of the Royalties by the Company to its stockholders, followed by the contribution of the Royalties by the stockholders to the Partnership in exchange for interests therein, which in turn was followed by the contribution by the stockholders of the interests in the Partnership to the Trust in exchange for Units, and (g) the transfer of a Unit of the Trust will be considered for federal income tax purposes to be the transfer of the proportionate part of the Partnership interest attributable to such Unit.

 

Subsequent to the distribution of the Units, the IRS ruled favorably on all requested rulings except (d). Because the Rulings were issued after the distribution of the Units, however, the rulings could be revoked by the IRS if it changes its position on the matters they address. If the IRS changed its position on these issues, challenged the Trust and the Unit holders and was successful, the result could be adverse.

 

The Company withdrew its requested ruling (d) that the Company did not recognize gain or loss upon the transfer of the Royalties to the Trust or upon distribution of the Units to its stockholders because the IRS proposed to rule that the transfer and distribution resulted in the recapture of ordinary income attributable to intangible drilling and development costs under Section 1254 of the Code (IDC Recapture Income). Counsel for the Company expressed no opinion on this issue. The Company and the IRS subsequently litigated the issue, and in 1989 the Tax Court rendered an opinion favorable to the Company. The Tax Court held that the 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.

 

The Trustee assumes that some Trust Units are held by a middleman; as such term is broadly defined in U.S. Treasury Regulations (and includes custodians, nominees, certain joint owners, and brokers holding an interest for a custodian in street name). Therefore, the Trustee considers the Trust to be a non-mortgage widely held fixed investment trust (“WHFIT”) for U.S. federal income tax purposes. The Bank of New York Mellon Trust Company, N.A., 919 Congress Avenue, Austin, Texas 78701, telephone number 1-900-852-1422, is the representative of the Trust that will provide tax information in accordance with applicable U.S. Treasury regulations governing the information reporting requirements of the Trust as a WHFIT.

 

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

 

 

Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicated that the carrying amount may not be recoverable. For assets held and used, impairment may occur if projected undiscounted cash flows are not adequate to cover the carrying value of the assets. In such cases, additional analysis is conducted to determine the amount of loss to be recognized. The impairment loss is determined by the difference between the carrying amount of the asset and the fair value measured by future discounted cash flows. The analysis requires estimates of the amount and timing of projected cash flows and, where applicable, judgments associated with, among other factors, the appropriate discount rate. Such estimates are critical in determining whether any impairment charge should be recorded and the amount of such charge if an impairment loss is deemed to be necessary. In addition, future events impacting cash flows for existing assets could render a writedown necessary that previously required no such writedown.

LL&E ROYALTY TRUST

 

NOTES TO FINANCIAL STATEMENTS — (Continued)

 

An impairment related to the Jay Field was recorded in 2008 as a result of the continuous shut-down of this property by its operator. The remaining carrying value of the Jay Field property of $1,705,100 was written off. This resulted in a full write down of the asset, which was included in the amortization of royalty interest in the Trust Corpus, as this amount does not affect cash earnings. As of December 31, 2009, the carrying value of the Trust’s royalty interests was fully depleted

 

 

According to the September 30, 2009 reserve report, dated May 24, 2011, included in the Trust’s Annual Report on Form 10-K for the year ended December 31, 2009, the total future dismantlement costs to the Working Interest Owner are estimated to be $15.8 million for the Jay Field property, $12.7 million for the South Pass 89 property, and $22.9 million for the Offshore Louisiana property. The Trust’s interests in these properties are equivalent to 50% of the net proceeds from Jay Field and South Pass 89 properties and 90% of the net proceeds from the Offshore Louisiana property.

 

The Working Interest Owner, under the terms of the Trust Conveyances, is permitted to escrow or otherwise deduct 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 2009, the Working Interest Owner has withheld $805,683, 50% of which would have been otherwise distributable to the Trust after recovery of excess production costs and payment of all abandonment, dismantlement, and related costs in accordance with conveyances, and $3,239,056, 90% of which would have otherwise been distributable to the Trust after recovery of excess production costs and payment of all abandonment, dismantlement, and related costs in accordance with conveyances, in escrow from the South Pass and Offshore properties, respectively. During the year ended, December 31, 2009, none of the escrowed amounts were expended for Jay Field or South Pass 89, and $3,398,812 was expended for the Offshore Louisiana properties, respectively.

 

The cumulative escrow balances as of December 31, 2009 were $4,543,402, $8,936,923, and $8,812,616 for the Jay Field, South Pass 89 and Offshore Louisiana properties, respectively. Of these amounts, 50% of which for the Jay Field and South Pass 89 properties and 90% of which for the Offshore Louisiana properties would otherwise have been distributable to the Trust after recovery of excess production costs and payment of all abandonment dismantlement and related costs in accordance with the conveyances. The Conveyances prohibit the Working Interest Owner from escrowing additional funds for estimated future Special Costs with respect to a particular Productive Property once the amount escrowed exceeds 125 percent of the aggregate estimated future Special Costs for that Property. The Conveyances permit the Working Interest Owner to release funds from any of the Special Costs escrows at any time if it determines in its sole discretion that there no longer exists a need for escrowing all or any portion of such funds. However, the Working Interest Owner is not required to do so.

 

The Working Interest Owner has advised the Trustee that it intends to continue monitoring its estimates of relevant factors in order to evaluate the necessity of escrowing funds on an ongoing basis. The Working Interest Owner is under no obligation to give any advance notice to the Trustee or the Unit holders in the event it determines that additional funds should be escrowed.

 

As previously disclosed, the conveyances do not require the Working Interest Owners to place the “escrowed” funds into an actual escrow account or to segregate funds in any other manner, and none of the working interest owners has done so. However, under the conveyances, each Working Interest Owner (or any successor owner of the working interest) is required to calculate Gross Proceeds as though such funds had been escrowed and then subsequently utilized for purposes of paying actual abandonment and related costs.

LL&E ROYALTY TRUST

 

NOTES TO FINANCIAL STATEMENTS — (Continued)

 

 

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.

 

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.

 

 

Pursuant to Financial Accounting Standards Board (FASB) in Accounting Standards Codification 932 — Extraction Activities — Oil and Gas (formerly known as Statement of Financial Accounting Standards No. 69), the Trustee is required to include as supplementary information estimates (which are unaudited) 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, 2009, 2008 and 2007. Reserve quantities imputed to the Trust are calculated by multiplying Miller and Lents’ estimated 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 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. 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, 2009, 2008 and 2007.

 

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, 2009, 2008 and 2007 (of which estimates were prepared by Miller and Lents). Imputed proved reserves are stated in thousands of barrels of liquids and millions of cubic feet of natural gas. The estimated future net revenues do not necessarily represent actual dollar amounts to be paid to the Trust by the Working Interest Owner. In estimating future net revenues, Miller and Lents took into consideration capital expenditures estimated by the Working Interest Owner to be necessary to develop proved reserves only. In addition, the estimates should be evaluated in light of the many uncertainties inherent in estimating oil and gas reserve quantities and in forecasting production levels, prices 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.

LL&E ROYALTY TRUST

 

NOTES TO FINANCIAL STATEMENTS — (Continued)

 

Present Value of Estimated Future Net Revenues from Proved Reserves

 

 

Changes in Imputed Proved Reserves and Present Value of Estimated Future Net Revenues

 

 

The computation of the present value of future net revenues relating to proved reserves at September 30, 2009 was based on commodity prices in effect as of September 30, 2009, of $4.56 per MMBtu for natural gas, of $60.30 per barrel for crude oil and of $37.55 per barrel for natural gas liquids.

 

 

LL&E ROYALTY TRUST

 

NOTES TO FINANCIAL STATEMENTS — (Continued)

 

 

Recent SEC Rule-Making Activity

 

In December 2008, the SEC announced that it had approved revisions designed to modernize the oil and gas company reserve reporting requirements. The most significant amendments to the requirements include the following:

 

 

The rules are effective for fiscal years ending on or after December 31, 2009, and early adoption is not permitted. The Trust notes that these new rules did not have a material impact on its reported oil and gas reserves.

 

Selected Quarterly Financial Data (Unaudited)

 

 

 

As previously disclosed in the Trust’s filings, the Trust is now required by the terms of the Trust Agreement to sell its assets and to liquidate. As previously disclosed, the Trustee engaged the Financial Advisor to market the Trust’s assets in anticipation of a sale in accordance with the terms of the Trust Agreement. The Financial Advisor marketed the Trust’s interest in the Jay Field and had received preliminary indications of interest in late 2010, and the Trustee intended to sell the Jay Field interest in accordance with the terms of the Trust Agreement. However, also as previously announced, in November 2010 the Trust and Trustee were named as defendants in a Complaint for Legal and Equitable Relief (the “Complaint”) filed by Jeff Beckett in the United States District Court for the Eastern District of Michigan (the “Court”). Mr. Beckett’s Complaint seeks a judicial modification of the terms of the Trust Agreement governing the Trust, a judgment declaring that the termination provisions of the Trust Agreement

LL&E ROYALTY TRUST

 

NOTES TO FINANCIAL STATEMENTS — (Continued)

 

do not apply and an order preventing the sale of the Trust’s assets. The Complaint also makes a number of other allegations and seeks removal of the Trustee and other relief.

 

As a result of Mr. Beckett’s lawsuit, certain bidders who had submitted preliminary indications of interest to the Financial Advisor indicated that they were unwilling to proceed with the purchase of the Jay Field interest from the Trust until the Beckett lawsuit was resolved. Consequently, as previously disclosed, the Trustee suspended the sale process pending resolution of the lawsuit.

 

On July 7, 2011, Mr. Beckett and the Trust entered into a settlement agreement pursuant to which Mr. Beckett agreed to dismiss his lawsuit with prejudice within ten days after the Trust holds a meeting of the Unit holders for the purpose of voting on a proposal to remove the Trustee and to appoint a successor trustee of the Trust, provided that notice of the meeting is mailed by August 1, 2011 and the meeting occurs by September 1, 2011. Notice of the meeting was mailed prior to August 1, 2011, and the meeting was convened on August 12, 2011. Because the proposed successor trustee withdrew its consent to serve shortly prior to the meeting, the meeting has been adjourned until August 24, 2011.

 

 

In December 2008, the SEC announced that it had approved revisions designed to modernize the oil and gas company reserve reporting requirements. The most significant amendments to the requirements include the following: