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EX-31 - EXHIBIT 31 - TEL OFFSHORE TRUST	a2195367zex-31.htm
EX-32 - EXHIBIT 32 - TEL OFFSHORE TRUST	a2195367zex-32.htm

STATEMENTS OF CHANGES IN TRUST CORPUS

(Unaudited)

The accompanying notes are an integral part of these financial statements.

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TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS
(Unaudited)

Note 1—Trust Organization

        Tenneco Offshore Company, Inc. ("Tenneco Offshore") created the TEL Offshore Trust ("Trust") effective January 1, 1983, pursuant to the Plan of Dissolution ("Plan") approved by Tenneco Offshore's stockholders on December 22, 1982. In accordance with the Plan, the TEL Offshore Trust Partnership ("Partnership") was formed in which the Trust owns a 99.99% interest and Tenneco Oil Company initially owned a .01% interest. In general, the Plan was effected by transferring an overriding royalty interest ("Royalty") equivalent to a 25% net profits interest in the oil and gas properties (the "Royalty Properties") of Tenneco Exploration, Ltd. located offshore Louisiana to the Partnership and issuing certificates evidencing units of beneficial interest in the Trust ("Units") in liquidation and cancellation of Tenneco Offshore's common stock. The terms "Working Interest Owner" and "Working Interest Owners," as used herein, refer to the owner or owners of the various Royalty Properties, which owners have changed from time to time since the original ownership of the Royalty Properties by Tenneco Exploration, Ltd.

        On January 14, 1983, Tenneco Offshore distributed Units to holders of Tenneco Offshore's common stock on the basis of one Unit for each common share owned on such date.

        The terms of the Trust Agreement, dated January 1, 1983 (the "Trust Agreement"), provide, among other things, that:

        (a)   the Trust is a passive entity and cannot engage in any business or investment activity or purchase any assets;

        (b)   the interest in the Partnership can be sold in part or in total for cash upon approval of a majority of the Unit holders;

        (c)   the Trustees, as defined below, can establish cash reserves and borrow funds to pay liabilities of the Trust and can pledge the assets of the Trust to secure payments of the borrowings; at December 31, 2008, the reserve amount was $2,233,291;

        (d)   the Trustees will make cash distributions to the Unit holders in January, April, July and October of each year as discussed in Note 4; and

        (e)   the Trust will terminate upon the first to occur of the following events: (i) total future net revenues attributable to the Partnership's interest in the Royalty, as determined by independent petroleum engineers, as of the end of any year, are less than $2.0 million or (ii) a decision to terminate the Trust by the affirmative vote of Unit holders representing a majority of the Units. Future net revenues attributable to the Royalty were estimated at approximately $24.2 million (unaudited) as of October 31, 2008 (such future net revenues do not include any reserves or values attributable to Eugene Island 339, nor does it include the Trust's percentage share of the total plugging and abandonment costs related to Eugene Island 339, with costs for 2009 alone estimated to be approximately $61 million). Upon termination of the Trust, the Corporate Trustee will sell for cash all assets held in the Trust estate and make a final distribution to the Unit holders of any funds remaining, after all Trust liabilities have been satisfied.

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        The Trust is currently administered by The Bank of New York Mellon Trust Company, N.A. (the "Corporate Trustee"), which succeeded JPMorgan Chase Bank, N.A. as the corporate trustee, effective October 2, 2006 pursuant to an agreement under which The Bank of New York acquired substantially all of the corporate trust business of JPMorgan Chase (formerly known as The Chase Manhattan Bank), and Daniel O. Conwill, IV, Gary C. Evans and Jeffrey S. Swanson (the "Individual Trustees"), as trustees (the "Trustees").

Note 2—Basis of Accounting

        The accompanying unaudited financial information has been prepared by the Corporate Trustee. The accompanying financial information is prepared on a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America ("generally accepted accounting principles"). The Corporate Trustee and the Individual Trustees believe that the information furnished reflects all adjustments that are, in the opinion of the Trustees, necessary for a fair presentation of the results for the interim periods presented. Such adjustments are of a normal and recurring nature. The financial information should be read in conjunction with the financial statements and notes thereto included in the Trust's Annual Report on Form 10-K for the year ended December 31, 2008.

        The financial statements of the Trust are prepared on the following basis:

        (a)   Royalty income is recorded when received, including the effect of overtaken or undertaken positions and negative or positive adjustments, by the Corporate Trustee on the last business day of each calendar quarter. In addition, Royalty income includes amounts related to funds deposited or released from the Special Cost Escrow account—see (c); and

        (b)   Trust general and administrative expenses are recorded when paid, except for the cash reserved for future general and administrative expenses; and

        (c)   The funds deposited or released from the Special Cost Escrow account are recorded at the time of payment or receipt. The Special Cost Escrow account is an account of the Working Interest Owners and is not reflected in the financial statements of the Trust.

        This manner of reporting income and expenses is considered to be the most meaningful because the quarterly distributions to Unit holders are based on net cash receipts received from the Working Interest Owners. The financial statements of the Trust differ from financial statements prepared in accordance with generally accepted accounting principles, because, under such principles, Royalty income and Trust general and administrative expenses for a quarter would be recognized on an accrual basis. In addition, amortization of the net overriding royalty interest, which is calculated on a units-of-production basis, is charged directly to Trust corpus since such amount does not affect distributable income.

        On the last business day of each calendar quarter, the Working Interest Owners pay to the Partnership 25% of the Net Proceeds for the immediately preceding Quarterly Period. A Quarterly Period is each period of three months commencing on the first day of February, May, August and November. In turn, the Partnership distributes funds to its partners on the last business day of each calendar quarter. Cash distributions from the Trust are made in January, April, July and October of each year, and are payable to Unit holders of record as of the last business day of each calendar quarter. Thus, the cash conveyed to the Trust from the Royalty during the quarter ended September 30,

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2008 substantially represents the revenues and expenses from the Royalty Properties from May 2008 through July 2008. There was no cash conveyed to the Trust from the Royalty Properties from November 2008 through July 2009. The financial and operating information included in this Form 10-Q for the three months ended September 30, 2009 and 2008 represent financial and operating information with respect to the Royalty Properties for the months of May, June and July 2009 and 2008, respectively. Similarly, financial and operating information with respect to the Royalty Properties for the nine months ended September 30, 2009 and 2008 represent financial and operating information with respect to the Royalty Properties for the immediately preceding months of November through July. Income from the Royalty is recorded by the Trust on a cash basis, when it is received by the Trust from the Partnership.

        Cash and cash equivalents include all highly liquid, short-term investments with original maturities of three months or less.

        The changes in reserve for future Trust expenses include both changes of amounts deemed necessary by the Trustees and related distributions, as well as amounts paid from the reserve during periods when the Trust has insufficient income to pay Trust expenses.

        The Trust reviews the net overriding royalty interest in oil and gas properties for possible impairment whenever events or circumstances indicate the carrying amount of the asset may not be recoverable. If there is an indication of impairment, the Trust prepares an estimate of future cash flows (undiscounted and without interest charges) expected to result from the use of the asset and its eventual disposition. If these cash flows are less than the carrying amount of the asset, an impairment loss may be recognized to write down the asset to the lower of its estimated fair value or net book value. Preparation of estimated expected future cash flows is inherently subjective and is based on the Corporate Trustee's best estimate of assumptions concerning expected future conditions. There were no write downs taken in the periods presented.

        The Special Cost Escrow account (Note 5) is established for the future costs to be incurred to plug and abandon wells, dismantle and remove platforms, pipelines and other production facilities and for the estimated amount of future capital expenditures on the Royalty Properties. The funds held in the Special Cost Escrow account are not reflected in the financial statements of the Trust. However, funds deposited to or released from the Special Cost Escrow account are included in the Royalty income.

        The preparation of financial statements requires the Trustees to make use of estimates and assumptions that affect amounts reported in the financial statements as well as certain discounts. Actual results could differ from those estimates.

        The amount of cash distributions by the Trust is dependent on, among other things, the quantities of oil and gas produced from the Royalty Properties and the sales prices therefor, as well as expenditures by the Working Interest Owners that may or may not be included in the Special Cost Escrow account. As described herein, production ceased at Eugene Island 339 and Ship Shoal 182 and 183 following damages inflicted by Hurricane Ike in September 2008. Chevron intends to pursue the redevelopment of platforms and wells at Eugene Island 339; however, such a redevelopment is not expected to be completed prior to October 2012 and there can be no assurance that production will be restored at Eugene Island 339. Production sales for both oil and natural gas at Ship Shoal 182 and 183 were restored on October 8, 2009 following completion of various ongoing repairs to the third-party transporter's natural gas pipeline. It should be noted that substantial uncertainties exist with regard to future oil and gas prices, which are subject to material fluctuations due to changes in production levels

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and pricing and other actions taken by major petroleum producing nations, as well as the regional supply and demand for gas, weather, industrial growth, conservation measures, competition, economic conditions generally and other variables. The Trust does not enter into any hedging transactions on future production.

        In May 2009, the Financial Accounting Standards Board (FASB) issued what is codified as FASB ASC 855, Subsequent Events ("FASB ASC 855"). FASB ASC 855 establishes principles and standards related to the accounting for and disclosure of events that occur after the date of the balance sheet included in financial statements being presented, but before such financial statements are issued. FASB ASC 855 requires an entity to recognize, in the financial statements, subsequent events that provide additional information regarding conditions that existed at the balance sheet date. Subsequent events that provide information about conditions that did not exist at the balance sheet date are not to be recognized in the financial statements under FASB ASC 855. FASB ASC 855 is effective for interim and annual reporting periods ending after June 15, 2009. The Trust adopted this standard effective as of June 30, 2009. The adoption of FASB ASC 855 did not have a material effect on the Trust's financial statements. Subsequent events were evaluated through November 6, 2009, the date that these financial statements were issued.

Note 3—Net Overriding Royalty Interest

        The Royalty entitles the Trust to its share (99.99%) of 25% of the Net Proceeds attributable to the Royalty Properties. The Conveyance dated January 1, 1983, conveying the Royalty Properties to the Partnership (the "Conveyance"), provides that the Working Interest Owners will calculate, for each period of three months commencing the first day of February, May, August and November, an amount equal to 25% of the Net Proceeds from their oil and gas properties for the period. Generally, "Net Proceeds" means the amounts received by the Working Interest Owners from the sale of minerals from the Royalty Properties less operating and capital costs incurred, management fees and expense reimbursements owing to the Managing General Partner of the Partnership, applicable taxes other than income taxes, and a Special Cost Escrow account. The Special Cost Escrow account (See Note 5) is established for the future costs to be incurred to plug and abandon wells, dismantle and remove platforms, pipelines and other production facilities, and for the estimated amount of future capital expenditures on the Royalty Properties. Net Proceeds do not include amounts received by the Working Interest Owners as advance gas payments, "take-or-pay" payments or similar payments unless and until such payments are extinguished or repaid through the future delivery of gas.

Note 4—Distributions to Unit Holders

        In accordance with the provisions of the Trust Agreement, generally all Net Proceeds received by the Trust, net of Trust general and administrative expenses and any cash reserves established for the payment of contingent or future obligations of the Trust, are distributed currently to the Unit holders. Such distributions are referred to as "distributable income." The amounts distributed are determined on a quarterly basis and are payable to Unit holders of record as of the last business day of each calendar quarter. However, cash distributions are made in January, April, July and October and include interest earned from the quarterly record date to the date of distribution.

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        Set forth below are the quarterly distributions made by the Trust for 2009 and 2008.

        Production ceased at Eugene Island 339 and Ship Shoal 182 and 183 following damages inflicted by Hurricane Ike in September 2008. On March 25, 2009, the Trust announced there would be no first quarter distribution. Similarly, on June 26, 2009 and September 25, 2009, the Trust announced there would be no second and third quarter distribution, respectively.

        There are not likely to be sufficient Net Proceeds from the Royalty Properties for the Trust to make a regularly scheduled quarterly distribution to Unit holders for the foreseeable future. As a result of the damage inflicted by Hurricane Ike, Net Proceeds will continue to be severely impacted by reduced production, from historical levels, and the amount of expenditures incurred that are associated with such damages, including the expenditures required to plug and abandon the wells on Eugene Island 339, and, as currently expected, to redevelop the facility at Eugene Island 339. Future Net Proceeds from the Royalty Properties will take into account the Trust's share of project costs and other related expenditures that are not covered by the insurance of the operators of the Royalty Properties. The Trust's net portion of the aggregate cost to plug and abandon the wells subject to the royalty on Eugene Island 339 is estimated to be approximately $13 million. If development and production costs of the Royalty exceed the proceeds of production from the Royalty Properties, the Trust will not receive Net Proceeds until future proceeds from production exceed the total of the excess costs plus accrued interest. Development activities may not generate sufficient additional revenue to repay such costs. Accordingly, there will not be sufficient Net Proceeds from the Royalty Properties to make distributions for some period of time in the future. At this time, the ultimate outcome of these matters cannot be determined with any degree of certainty.

Note 5—Special Cost Escrow Account

        The Special Cost Escrow is an account of the Working Interest Owners, and it is described herein for informational purposes only. The Conveyance provides for the reserve of funds for estimated future "Special Costs" of plugging and abandoning wells, dismantling platforms and other costs of abandoning the Royalty Properties, as well as for the estimated cost of future drilling projects and other capital expenditures on the Royalty Properties. As provided in the Conveyance, the amount of funds to be reserved is determined based on certain factors, including estimates of aggregate future production costs, aggregate future Special Costs, aggregate future net revenues and actual current net profits interest. Deposits into this account reduce current distributions and are placed in an escrow account and invested in short-term certificates of deposit. Such account is herein referred to as the "Special Cost Escrow" account. The Trust's share of interest generated from the Special Cost Escrow account

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serves to reduce the Trust's share of allocated production costs. Special Cost Escrow funds will generally be utilized to pay Special Costs to the extent there are not adequate current net profits to pay such costs. Special Costs that have been paid are no longer included in the Special Cost Escrow calculation. Deposits to the Special Cost Escrow account will generally be made when the balance in the Special Cost Escrow account is less than 125% of estimated future Special Costs and there is a Net Revenues Shortfall (a calculation of the excess of estimated future costs over estimated future net revenues pursuant to a formula contained in the Conveyance). When there is not a Net Revenues Shortfall, amounts in the Special Cost Escrow account will generally be released, to the extent that Special Costs have been incurred. Amounts in the Special Cost Escrow account will also be released when the balance in such account exceeds 125% of estimated future Special Costs. In the third quarter of 2009 there were no funds released from or deposited into the Special Cost Escrow account. As of September 30, 2009, $4,306,985 remained in the Special Cost Escrow account. The funds held in the Special Cost Escrow account are not reflected in the financial statements of the Trust.

        Chevron U.S.A. Inc. ("Chevron"), in its capacity as the Managing General Partner of the Partnership, has advised the Trust that additional deposits to the Special Cost Escrow account may be required in future periods in connection with other production costs, other abandonment costs, other capital expenditures and changes in the estimates and factors described above. Such deposits could result in a significant reduction in Royalty income in the periods in which such deposits are made, including the possibility that no Royalty income would be received in such periods.

Note 6—Reserve For Future Trust Expenses

        The Trust has generally maintained a cash reserve, equal to approximately three times the average expenses of the Trust during each of the past three years, to provide for future administrative expenses in connection with the winding up of the Trust. During the third quarter of 2009, the Trust used $234,564 from the reserve account for current expenses, leaving a reserve balance of $1,456,936 as of September 30, 2009. The reserve balance of $1,456,936 as of September 30, 2009 is approximately l.9 times the average expenses of the Trust during each of the past three years. The reserve amount at December 31, 2008 was $2,233,291.

        Pursuant to the terms of the Trust Agreement, the Trustees are authorized to borrow funds, and pledge the assets of the Trust to secure payments of such borrowings, in the event that cash on hand is not sufficient to pay the liabilities of the Trust. In the event that the Trustees borrow funds to pay the liabilities of the Trust, no further distributions will be made to the Unit holders until the indebtedness created by such borrowings has been paid in full.

        The Trust Agreement further provides that, if necessary to provide for the payment of specific liabilities of the Trust then due, the Trustees may without a vote of the Unit holders (a) sell all or a portion of the Trust's interest in the Partnership or any other assets of the Trust for such cash consideration as the Trustees shall deem appropriate, (b) exercise their rights under the Partnership Agreement to dissolve the Partnership, or (c) cause a sale by the Partnership of the overriding royalty interest owned by the Partnership.

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Item 2.    Management's Discussion and Analysis of Financial Condition and Results of Operations.

Critical Accounting Policies

        The financial statements of the Trust are prepared on the following basis:

(a)

Royalty income is recorded when received, including the effect of overtaken or undertaken positions and negative or positive adjustments, by the Corporate Trustee on the last business day of each calendar quarter. In addition, Royalty income includes amounts related to funds deposited or released from the Special Cost Escrow account—see (c); and



(b)

Trust general and administrative expenses are recorded when paid, except for the cash reserved for future general and administrative expenses; and



(c)

The funds deposited or released from the Special Cost Escrow account are recorded at the time of payment or receipt. The Special Cost Escrow account is an account of the Working Interest Owners and is not reflected in the financial statements of the Trust.

        This manner of reporting income and expenses is considered to be the most meaningful because the quarterly distributions to Unit holders are based on net cash receipts received from the Working Interest Owners. The financial statements of the Trust differ from financial statements prepared in accordance with generally accepted accounting principles, because, under such principles, Royalty income and Trust general and administrative expenses for a quarter would be recognized on an accrual basis. In addition, amortization of the net overriding royalty interest, calculated on a units-of-production basis, is charged directly to Trust corpus since such amount does not affect distributable income.

        The Trustees, including the Corporate Trustee, have no authority over, have not evaluated and make no statement concerning, the internal control over financial reporting of the Working Interest Owners.

Financial Review

        In May 2007, the Trust engaged an independent oil and gas accounting firm for the purpose of reviewing the books and records of certain Working Interest Owners with respect to the Royalty Properties and the related payments to the Trust. As part of this audit review process, certain adjustments to revenues, production volumes, prices and capital expenditures have occurred, and references below to a prior period audit adjustment, or an audit of prior periods, refers to the audit described in this paragraph. The adjustments resulting from such audit review were completed in the second quarter of 2009. See "—Operational Review".

Three Months Ended September 30, 2009 and 2008

        There were no distributions to the Unit holders for the three months ended September 30, 2009 as compared to distributions of $5,470,387 or $1.151294 per Unit to the Unit holders for the same period in 2008.

        Crude oil and condensate revenues decreased $12,725,234, or 82%, to $2,716,744 in the third quarter of 2009 as compared to $15,441,978 in the third quarter of 2008, due primarily to decreases in production resulting from damages caused by Hurricane Ike in September 2008. Oil volumes decreased 70% to 45,222 barrels in the third quarter of 2009 from 149,125 barrels in the third quarter of 2008.

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The revenues and volumes for the third quarter of 2008 reflect credits of $127,886 in revenues and 23,878 barrels associated with an audit of prior periods. The average price received for crude oil and condensate decreased 42%, or $43.47, to $60.08 per barrel in the third quarter of 2009 from $103.55 per barrel in the third quarter of 2008. Prior to taking into account such adjustments to revenues and volumes in the third quarter of 2008, the average price received for crude oil and condensate would have been $122.27 in the third quarter of 2008.

        Gas revenues decreased $4,049,839, or 99%, to $31,709 in the third quarter of 2009 from $4,081,548 in the third quarter of 2008, due primarily to decreases in production resulting from damages caused by Hurricane Ike in September 2008. Gas volumes decreased 97% to 8,255 Mcf in the third quarter of 2009 from 327,690 Mcf in the third quarter of 2008. The revenues and volumes for the third quarter of 2008 reflect credits of $414,319 in revenues and 29,725 Mcf of gas associated with an audit of prior periods. The average price received for natural gas decreased 69%, or $8.62, to $3.84 per Mcf in the third quarter of 2009 from $12.46 per Mcf in the third quarter of 2008. Prior to taking into account such adjustments to revenues and volumes in the third quarter of 2008, the average price received for natural gas would have been $12.31 per Mcf in the third quarter of 2008. Gas products revenue decreased $1,251,767, or 99%, to $3,764 in the third quarter of 2009 from $1,255,531 in the third quarter of 2008, due primarily to a decrease in production volume of 872,633 gallons, or 99%, to 4,515 gallons in the third quarter of 2009 from 877,148 gallons in the third quarter of 2008.

        Capital expenditures increased $240,391, or 103%, from $233,124 in the third quarter of 2008 to $473,515 in the third quarter of 2009. The capital expenses in the third quarter of 2009 primarily relate to an oil tank replacement and a gas panel upgrade at Ship Shoal 182/183. The capital expenditures in 2008 primarily relate to field workovers at Ship Shoal 182/183 and Eugene Island 339 necessary to help improve production performance.

        Operating expenses increased by $6,614,669, or 419%, from $1,577,986 in the third quarter of 2008 to $8,192,655 in the third quarter of 2009, primarily as a result of well and platform abandonment costs at Eugene Island 339 as a result of Hurricane Ike. Reflected within the operating expenses are management fees to Chevron, as Managing General Partner of the Partnership, of $681,346 and $342,842 for the third quarter of 2008 and the third quarter of 2009, respectively.

        The Royalty Properties had undistributed net loss of $6,247,115 in the third quarter of 2009.

        In the third quarter of 2009, no funds were released from or deposited into the Special Cost Escrow account. As of September 30, 2009, $4,306,985 remained in the Special Cost Escrow account. In the third quarter of 2008, there was a net release of funds from the Special Cost Escrow account. The Trust's share of the funds released was $1,017,783. As of September 30, 2008, $4,335,777 remained in the Special Cost Escrow account. The funds held in the Special Cost Escrow account are not reflected in the financial statements of the Trust. The Special Cost Escrow account is set aside for estimated abandonment costs and future capital expenditures, as provided for in the Conveyance. For additional information relating to the Special Cost Escrow account, see "—Special Cost Escrow Account" below.

Nine Months Ended September 30, 2009 and 2008

        There were no distributions to the Unit holders for the nine months ended September 30, 2009 as compared to distributions of $12,558,805 or $2.643119 per Unit to the Unit holders for the same period in 2008.

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        Crude oil and condensate revenues decreased $31,945,744, or 85%, to $5,539,319 in the first nine months of 2009 as compared to $37,485,063 for the same period in 2008, due primarily to decreases in production resulting from damages caused by Hurricane Ike in September 2008. Oil volumes decreased 74% to 99,207 barrels in the first nine months of 2009 from 385,687 barrels in the first nine months of 2008. The revenues and volumes for the first nine months of 2009 reflect credits associated with an audit for prior periods for $224,511 in revenues and 311 barrels; the revenues and volumes for the first nine months of 2008 reflect credits associated with an audit for prior periods for $278,673 in revenues and 24,880 barrels. The average price received for crude oil and condensate decreased 43%, or $41.35, to $55.84 per barrel in the first nine months of 2009 from $97.19 per barrel in the first nine months of 2008. Prior to taking into account such adjustments to revenues and volumes, the average price received for crude oil and condensate would have been $53.74 per barrel in the first nine months of 2009 and $103.12 per barrel in the first nine months of 2008.

        Gas revenues decreased $9,521,303, or 92%, to $868,071 in the first nine months of 2009 from $10,389,374 for the same period in 2008, due primarily to damages caused by Hurricane Ike in September 2008. Gas volumes decreased 88% to 140,625 Mcf in the first nine months of 2009 from 1,134,953 Mcf for the same period in 2008. The revenues and volumes for the first nine months of 2009 reflect net credits of $808,484 in revenues and 127,711 Mcf of gas for prior adjustments; the revenues and volumes for the first nine months of 2008 reflect credits associated with an audit of prior periods for $1,075,436 in revenues and 116,700 Mcf of gas. The average price received for natural gas decreased 33%, or $3.07, to $6.17 per Mcf in the first nine months of 2009 from $9.24 per Mcf in the same period of 2008. Prior to taking into account such adjustments to revenues and volumes, the average price received for natural gas would have been $4.61 per Mcf in the first nine months of 2009 and $9.15 per Mcf in the first nine months of 2008. Gas products revenue decreased $2,842,328, or 93%, to $199,390 in the first nine months of 2009 from $3,041,718 in the same period of 2008, primarily due to a decrease in production volume of 2,049,244 gallons, or 92%, to 177,425 gallons in the first nine months of 2009 from 2,226,669 gallons in the same period of 2008.

        Capital expenditures increased $641,951, or 540%, from $118,952 in the first nine months of 2008 to $760,903 in the same period of 2009. Reflected within the capital expenditures line item for 2008 is a refund of $495,600 from the Working Interest Owners for certain prior period adjustments. Reflected in the capital expenditures for the first nine months of 2009 is a refund of $59,794 for certain prior period audit adjustments.

        Operating expenses increased by $18,487,239, or 264%, from $6,995,347 in the first nine months of 2008 to $25,482,586 in the first nine months of 2009, primarily as a result of well abandonment costs at Eugene Island 339 as a result of Hurricane Ike. Reflected in the operating expenses for the first nine months of 2009 are cost allocation refunds of an aggregate of $115,252 for certain prior period adjustments. Reflected within the operating expenses are management fees to Chevron, as Managing General Partner of the Partnership, of $1,711,587 and $950,091 for the first nine months of 2008 and the first nine months of 2009, respectively.

        The Royalty Properties had undistributed net loss of $19,538,783 for the nine months ended September 30, 2009.

        In the first nine months of 2009, no funds were released from or deposited into the Special Cost Escrow account. In the first nine months of 2008, there was a net release of funds from the Special Cost Escrow account. The Trust's share of the net funds released was $2,377,787.

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Reserve for Future Trust Expenses

        In accordance with the provisions of the Trust Agreement, generally all Royalty income received by the Trust, net of Trust general and administrative expenses and any cash reserves established for the payment of contingent or future obligations of the Trust, is distributed currently to the Unit holders. The Trust has previously determined that a cash reserve equal to approximately three times the average expenses of the Trust during each of the past three years was sufficient to provide for future administrative expenses in connection with the winding up of the Trust. During the nine-month period ended September 30, 2009, the Trust used $776,355 from the reserve for current expenses, leaving a reserve balance of $1,456,936 as of September 30, 2009. The reserve balance of $1,456,936 as of September 30, 2009 is approximately l.9 times the average expenses of the Trust during each of the past 3 years.

        Pursuant to the terms of the Trust Agreement, the Trustees are authorized to borrow funds, and pledge the assets of the Trust to secure payments of such borrowings, in the event that cash on hand is not sufficient to pay the liabilities of the Trust. In the event that the Trustees borrow funds to pay the liabilities of the Trust, no further distributions will be made to the Unit holders until the indebtedness created by such borrowings has been paid in full.

        The Trust Agreement further provides that, if necessary to provide for the payment of specific liabilities of the Trust then due, the Trustees may without a vote of the Unit holders (a) sell all or a portion of the Trust's interest in the Partnership or any other assets of the Trust for such cash consideration as the Trustees shall deem appropriate, (b) exercise their rights under the Partnership Agreement to dissolve the Partnership, or (c) cause a sale by the Partnership of the overriding royalty interest owned by the Partnership.

Other

        The amount of cash distributions by the Trust is dependent on, among other things, the quantities of oil and gas produced from the Royalty Properties and the sales prices therefor, as well as expenditures by the Working Interest Owners that may or may not be included in the Special Cost Escrow account. As described herein, production ceased at Eugene Island 339 and Ship Shoal 182 and 183 following damages inflicted by Hurricane Ike in September 2008. Chevron intends to pursue the redevelopment of platforms and wells at Eugene Island 339; however, such a redevelopment is not expected to be completed prior to October 2012 and there can be no assurance that production will be restored at Eugene Island 339. Production sales for both oil and natural gas at Ship Shoal 182 and 183 were restored on October 8, 2009 following completion of various ongoing repairs to the third-party transporter's natural gas pipeline. It should be noted that substantial uncertainties exist with regard to future oil and gas prices, which are subject to material fluctuations due to changes in production levels and pricing and other actions taken by major petroleum producing nations, as well as the regional supply and demand for gas, weather, industrial growth, conservation measures, competition, economic conditions generally and other variables. The Trust does not enter into any hedging transactions on future production.

Operational Review

        The platforms and wells on Eugene Island 339 were completely destroyed by Hurricane Ike in September 2008. Crude oil revenues from Eugene Island 339 represented approximately 48% of the

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crude oil and condensate revenues for the Royalty Properties in 2007 and approximately 47% of such revenues for the nine months ended September 30, 2008. Eugene Island 339 contributed approximately 12% of the revenues from natural gas sales from the Royalty Properties in 2007 and approximately 41% of such revenues for the nine months ended September 30, 2008. Based on a prior year reserve study prepared by DeGolyer and MacNaughton, independent petroleum engineering consultants, Eugene Island 339 accounted for approximately 34% of the total future net revenues attributable to the Partnership's interest in the royalty as of October 31, 2007. Chevron is working on the plugging and abandonment of the existing wells, clearing debris and otherwise dealing with the remaining infrastructure, which activities are not expected to be completed until the first quarter of 2012. Chevron has informed the Corporate Trustee that Chevron presently intends to pursue the redevelopment of platforms and wells at Eugene Island 339 in accordance with the terms and conditions established by the Mineral Management Service (the "MMS") in response to Chevron's submission to the MMS of a program to restore production at Eugene Island 339. The activity schedule approved by the MMS contemplates, among other things, commencement of front-end engineering and design work by the end of January 2010, an awarding of fabrication contracts for platform, substructure and equipment by the end of November 2010, and commencement of production ultimately occurring by the end of October 2012. Chevron is required to provide the MMS with periodic updates on Chevron's progress on such redevelopment. The approval by the MMS expires by its terms on November 30, 2010, and Chevron would need to request an extension of such approval from the MMS in order to complete the proposed redevelopment, given that the activity schedule contemplates activity through October 2012. The costs for such a redevelopment would be significant. While Chevron has stated that it intends to pursue such a redevelopment, there is no obligation for Chevron to continue to pursue such redevelopment. Failure or inability to pursue such a redevelopment, and on the timeframes approved by the MMS, could result in a loss of the lease. At this time, there can be no assurance that production will be restored at Eugene Island 339.

        Production at Ship Shoal 182/183 ceased following damage inflicted by Hurricane Ike in September 2008. While the hurricane caused limited surface damage to the facilities at Ship Shoal 182/183, all of the wells at Ship Shoal 182/183 were shut-in following hurricane-related damage to a third-party transporter's natural gas pipeline. Crude oil revenues from Ship Shoal 182/183 represented approximately 50% of the crude oil and condensate revenues for the Royalty Properties in 2007 and approximately 51% of such revenues for the nine months ended September 30, 2008. Ship Shoal 182/183 contributed approximately 77% of the revenues from natural gas sales from the Royalty Properties in 2007 and approximately 42% of such revenues for the nine months ended September 30, 2008. A limited volume of oil production was restored in November 2008. The volume of oil production that can be produced is limited by the amount of gas that is also produced by the oil wells. The third-party transporter's natural gas pipeline repairs were completed and gas sales at Ship Shoal 182/183 were restored on June 26, 2009. However, the pipeline was shut down in mid-September for additional repairs. Production sales for both oil and natural gas at Ship Shoal 182 and 183 were restored on October 8, 2009 following completion of such additional repairs.

        In addition, production from West Cameron 643 and East Cameron 371 ceased following damage inflicted by Hurricane Ike in September 2008 to third-party transporters' pipelines. Chevron, as the Managing General Partner of the Partnership, understands that the pipeline for West Cameron 643 is in the process of being restored, although such pipeline is not expected to be able to take production until at least the first quarter of 2010. At this point in time, there can be no assurance as to when, or if at all, production may be restored at West Cameron 643. The field operator for East Cameron 371 has

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reported to Chevron that a review of the remaining reserves for East Cameron 371 has been conducted, and a decision regarding field abandonment, including the related wells, equipment platforms and any field infrastructure, may be made in the near term. At this point in time, there can be no assurance that production will ultimately be restored at East Cameron 371.

        In May 2007, the Trust engaged an independent oil and gas accounting firm for the purpose of reviewing the books and records of certain Working Interest Owners with respect to the Royalty Properties and the related payments to the Trust. Based on the initial report of the accounting firm, the Trustees believed that certain errors in the books and records had occurred and, through the second quarter of 2009, were involved in ongoing discussions with such Working Interest Owners to resolve these items. As part of this ongoing process, certain adjustments to revenues, production volumes, prices and capital expenditures have occurred, and references herein to an audit of prior periods refers to the audit described in this paragraph. Such audit resulted in an additional cash distribution to the Trust during the first quarter of 2008 and additional credits were made periodically for the benefit of the Trust through the second quarter of 2009, when all remaining audit adjustments were completed.

Three Months Ended September 30, 2009 and 2008

        The following operational information has been based on information provided to the Corporate Trustee by Chevron, as the Managing General Partner of the Partnership, who received operational information from the other Working Interest Owners. The Trustees have no control over these operations or internal controls relating to this information.

        Volumes and dollar amounts discussed below represent amounts recorded by the Working Interest Owners unless otherwise specified.

        Ship Shoal 182/183 crude oil revenues decreased from $7,838,993 in the third quarter of 2008 to $2,638,386 in the third quarter of 2009, primarily due to a decrease in net crude oil production and a decrease in average crude oil prices. Net crude oil production decreased from 63,286 barrels in the third quarter of 2008 to 43,868 barrels in the third quarter of 2009. The average crude oil price decreased from $123.87 per barrel in the third quarter of 2008 to $60.14 per barrel for the same period in 2009. Gas revenues decreased from $1,613,142 in the third quarter of 2008 to $22,265 in the third quarter of 2009 due to a general cessation of gas production since September 2008 resulting from damages caused by Hurricane Ike. The repairs were completed and gas production began June 26, 2009. Gas volumes decreased to 5,759 Mcf in the third quarter of 2009 compared to production of 140,738 Mcf in the third quarter of 2008. The gas revenues and volumes for the third quarter of 2008 reflect credits of $223,767 and 24,894 Mcf associated with an audit of prior periods. The average gas sales price realized during the third quarter of 2009 was $3.87 per Mcf compared to $11.46 during the third quarter of 2008. Prior to taking into account such adjustments to revenues and volumes in the third quarter of 2008, the average gas sales price realized would have been $11.99 during the third quarter of 2008. Capital expenditures increased from $10,532 in the third quarter of 2008 to $473,116 in the third quarter of 2009. Operating expenses increased from $471,151 in the third quarter of 2008 to $611,048 for the same period in 2009 due to an increase in operating and repair costs related to damages inflicted by Hurricane Ike.

        Eugene Island 339 net crude oil revenues decreased from $7,386,151 in the third quarter of 2008 to $0 for the same period in 2009 due to a decrease in volumes from 84,061 barrels in the third quarter of 2008 to 0 barrels in the third quarter of 2009. The crude oil revenues and volumes for the third

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quarter of 2008 reflect credits of $124,691 and 23,845 barrels associated with an audit of prior periods. The average crude oil price was $87.87 per barrel in the third quarter of 2008 and $0 per barrel in the third quarter of 2009. Prior to taking into account such adjustments to revenues and volumes in the third quarter of 2008, the average crude oil price would have been $120.59 in the third quarter of 2008. Gas revenues decreased from $1,861,437 in the third quarter of 2008 to $0 in the third quarter of 2009 due to a decrease in volumes from 132,829 Mcf in the third quarter of 2008 to 0 Mcf in the third quarter of 2009. The gas revenues and volumes for the third quarter of 2008 reflect credits of $187,801 and 4,496 Mcf associated with an audit of prior periods. The average gas sales price realized during the third quarter of 2009 was $0 per Mcf compared to $14.01 per Mcf in the third quarter of 2008. Prior to taking into account such adjustments in the third quarter of 2008, the average gas sales price realized would have been $13.04 during the third quarter of 2008. Capital expenditures decreased from $186,687 in the third quarter of 2008 to $367 in the third quarter of 2009. There were limited capital expenditures during the third quarter of 2009 and the capital expenditures in the third quarter of 2008 primarily relate to repairs associated with a conversion to a water injector. Operating expenses increased from $915,360 in the third quarter of 2008 to $7,452,444 in the third quarter of 2009 due to well abandonment costs incurred as a result of Hurricane Ike.

        West Cameron 643 gas revenues were $567,061 in the third quarter of 2008 and $0 in the third quarter of 2009. Gas production was 50,351 Mcf in the third quarter of 2008 and 0 Mcf in the third quarter of 2009. The average gas sales price realized during the third quarter of 2009 was $0 per Mcf compared to $11.22 per Mcf in the third quarter of 2008. Operating expenses decreased from $152,594 in the third quarter of 2008 to $121,969 for the same period in 2009 due primarily to the decrease in production. Capital expenditures were $7,884 in the third quarter of 2008 as a result of an adjustment related to an audit of prior periods and $0 for the same period in 2009.

        East Cameron 371 crude oil revenues were ($125) in the third quarter of 2008 and $0 in the third quarter of 2009 as a result of the field being shut-in following Hurricane Ike in September 2008. Crude oil revenues in the third quarter of 2008 reflect a $125 credit related to a prior period audit adjustment. Gas revenues were $250 for the third quarter of 2008 and $0 for the third quarter of 2009, also due to the shut-in of the field. Capital expenditures were $0 for the third quarter 2008 and for the third quarter 2009. Operating expenses decreased from $3,811 in the third quarter of 2008 to $0 for the same period in 2009.

        South Timbalier 36/37 crude oil revenues decreased from $198,103 in the third quarter of 2008 to $78,257 for the same period in 2009 primarily due to equipment issues that have since been repaired. There was a decrease in crude oil production volumes to 1,350 barrels in the third quarter of 2009 from 1,610 barrels in the third quarter of 2008. The average crude oil price was $123.05 per barrel in the third quarter of 2008 and $57.95 per barrel in the third quarter of 2009. Gas revenues decreased from $39,346 in the third quarter 2008 to $8,838 in the third quarter of 2009. There was a decrease in natural gas volumes from 3,527 Mcf in the third quarter of 2008 to 2,370 Mcf in the third quarter of 2009. The average gas sales price realized during the third quarter of 2009 was $3.73 per Mcf compared to $11.16 per Mcf in the third quarter of 2008. Capital expenditures decreased from $2,429 in the third quarter of 2008 to $32 in the third quarter of 2009. Operating expenses decreased from $34,490 in the third quarter of 2008 to $7,193 in the third quarter of 2009.

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Nine Months Ended September 30, 2009 and 2008

        Volumes and dollar amounts discussed below represent amounts recorded by the Working Interest Owners unless otherwise specified.

        Ship Shoal 182/183 crude oil revenues decreased from $19,206,631 in the first nine months of 2008 to $5,111,927 in the same period in 2009, primarily due to a decrease in net crude oil production from 183,449 barrels in the first nine months of 2008 to 95,057 in the same period of 2009. Included in the revenues and production for the first nine months of 2008 was an upward adjustment of $46,630 associated with an additional 178 barrels that were included from 2007 production. There was also a decrease in the average crude oil price from $104.70 per barrel in the first nine months of 2008 to $53.78 per barrel for the same period in 2009, excluding the immaterial audit adjustment made during 2008. Gas revenues decreased from $4,227,427 in the first nine months of 2008 to $747,985 in the same period of 2009. Gas production decreased from 477,435 Mcf in the first nine months of 2008, which included an upward adjustment of 44,893 Mcf relating to an audit of prior periods, to 5,759 Mcf in the same period of 2009. However, there was an audit adjustment made in the first quarter of 2009, which resulted in the recognition of $725,720 in gas revenues associated with 107,416 Mcf of gas from a prior period. The inclusion of such adjustment for the 44,893 Mcf in 2008 resulted in an increase in revenues for 2008 of $347,713. The natural gas sales price was $9.24 per Mcf in the first nine months of 2008 compared to $3.87 per Mcf in the first nine months of 2009, excluding the audit adjustment made during 2009. Capital expenditures increased from ($455,967) in the first nine months of 2008 to $500,559 in the same period of 2009 primarily due to a credit of $495,600 in the first nine months of 2008 from an audit adjustment for prior periods. Operating expenses increased from $1,982,544 in the first nine months of 2008 to $2,009,644 for the same period in 2009 due to a decrease in production, but offset by an increase in operating and repair costs related to damages inflicted by Hurricane Ike.

        Eugene Island 339 net crude oil revenues decreased from $17,668,951 in the first nine months of 2008 to $38,544 for the same period in 2009, due to a decrease in volumes from 195,633 barrels in the first nine months of 2008 to 318 barrels in the first nine months of 2009. However, there was no actual crude oil production during the first nine months of 2009 and such crude oil revenues and production volumes are entirely from an audit adjustment made in the first quarter of 2009 and associated with a prior period. The oil revenues for the first nine months of 2008 reflect a $206,251 credit relating to prior periods. The average crude oil price was $90.32 per barrel in the first nine months of 2008. Prior to taking into account such adjustments in the first nine months of 2008, the average crude oil price would have been $101.65 per barrel in the first nine months of 2008. Gas revenues decreased from $4,322,543 in the first nine months of 2008 to $170,231 for the same period in 2009, due to a decrease in natural gas volumes from 448,921 Mcf in the first nine months of 2008 to 33,296 Mcf for the same period in 2009. However, there was no actual gas production during the first nine months of 2009 and such gas revenues and volumes are entirely from an audit adjustment made in the first quarter of 2009 and associated with a prior period. The gas revenues and volumes for the first nine months of 2008 reflect credits of $511,930 and 48,119 Mcf associated with an audit of prior periods. The average gas sales price realized during the first nine months of 2008 was $9.63 per Mcf. Prior to taking into account such adjustments in the first nine months of 2008, the average gas sales price realized in the first nine months of 2008 would have been $9.50 per Mcf. Capital expenditures decreased from $477,067 in the first nine months of 2008 to $180,456 in the same period in 2009. There were limited capital expenditures during the second and third quarter of 2009 and the capital expenditures in the first nine months of 2008 primarily relate to repairs associated with a conversion to a water injector. Operating

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expenses increased from $2,379,294 in the first nine months of 2008 to $21,672,896 in the same period in 2009 due to well abandonment costs incurred as a result of Hurricane Ike.

        West Cameron 643 gas revenues decreased from $1,488,686 in the first nine months of 2008 to ($87,518) for the same period in 2009. This is due to a decrease in gas volumes from 171,963 Mcf in the first nine months of 2008 to (13,001) Mcf for the same period in 2009. There was no actual gas production during the first nine months of 2009 and the revenues and volumes for the first nine months of 2009 are a result of debits to correct an error in revenue allocation in August 2008. Revenues and volumes for the first nine months of 2008 reflect credits of $200,133 and 28,402 Mcf. The average gas sales price realized during the first nine months of 2008 was $8.66 per Mcf. Prior to taking into account such adjustments in the first nine months of 2008, the average gas sales price realized in the first nine months of 2008 would have been $8.98 per Mcf. Operating expenses increased from $ 501,017 for the first nine months of 2008 to $862,299 for the same period in 2009, and capital expenditures were $7,884 for the first nine months of 2008 and $135,291 for the first nine months of 2009.

        East Cameron 371 crude oil revenues were $47,962 for the first nine months of 2008 and $0 for the first nine months of 2009 as a result of the field being shut-in following Hurricane Ike in September 2008. Production decreased from 531 barrels in the first nine months of 2008 to 0 barrels for the same period in 2009. The average crude oil price was $90.26 per barrel in the first nine months of 2008. Gas revenues decreased from $252,855 for the first nine months of 2008 to $0 for the same period in 2009 as a result of a decrease in gas volumes from 32,446 Mcf in the first nine months of 2008 to 0 Mcf for the same period in 2009. The average gas sales price realized during the first nine months of 2008 was $7.80 per Mcf. Capital expenditures were $0 in the first nine months of 2008 and 2009. Operating expenses decreased from $296,793 in the first nine months of 2008 to $0 for the same period in 2009.

        South Timbalier 36/37 crude oil revenues decreased from $483,469 in the first nine months of 2008 to $194,278 for the same period in 2009 due to a four-day field shut-in related to compressor problems and equipment issues that have since been repaired. There was a decrease in crude oil production volumes to 3,759 barrels in the first nine months of 2009 from 4,975 barrels in the first nine months of 2008. The average crude oil price was $97.18 per barrel in the first nine months of 2008 and $51.69 per barrel in the third quarter of 2009. Gas revenues decreased from $96,136 in the first nine months of 2008 to $32,179 in the first nine months of 2009. There was an increase in natural gas volumes from 4,063 Mcf in the first nine months of 2008 to 6,416 Mcf in the first nine months of 2009. Gas volumes for the first nine months of 2008 reflect a debit of 5,464 Mcf related to revised volume allocations for the years 2004 through 2007. The average gas sales price realized was $10.09 per Mcf in the first nine months of 2008, excluding such adjustment, and $5.02 per Mcf in the first nine months of 2009. Capital expenditures decreased from $42,798 in the first nine months of 2008 to $(55,403) in the first nine months of 2009 after taking into account a $56,263 credit in 2009 for a prior period audit adjustment. Operating expenses decreased from $123,502 in the first nine months of 2008 to $(12,105) in the first nine months of 2009 after taking into account a $36,992 credit in 2009 for a prior period audit adjustment.

Liquidity and Capital Resources

        The Trust's source of capital is the Royalty income received from its share of the Net Proceeds from the Royalty Properties.

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        On October 7, 2008, the Trust announced that production from the two most significant oil and gas properties associated with the Trust had ceased following damage inflicted by Hurricane Ike in September 2008. The platforms and wells on Eugene Island 339 were completely destroyed by Hurricane Ike. While Chevron presently intends to pursue the redevelopment of platforms and wells at Eugene Island 339, such redevelopment is not expected to be completed until October 2012 and the costs associated with such redevelopment would be significant. Chevron is continuing to work on the plugging and abandonment of the existing wells, clearing debris and otherwise dealing with the remaining infrastructure, which activities are not expected to be completed until the first quarter of 2012. While Hurricane Ike caused limited surface damage to the facilities at Ship Shoal 182/183, all of the wells at Ship Shoal 182/183 were shut-in following hurricane-related damage to a third-party transporter's natural gas pipeline. While limited production has since occurred at Ship Shoal 182/183, oil and natural gas sales were fully restored at Ship Shoal 182/183 commencing October 8, 2009.

        In addition, production from West Cameron 643 and East Cameron 371 ceased following damage inflicted by Hurricane Ike in September 2008 to third-party transporters' pipelines. Chevron, as the Managing General Partner of the Partnership, understands that the pipeline for West Cameron 643 is in the process of being restored, although such pipeline is not expected to be able to take production until at least the first quarter of 2010. At this point in time, there can be no assurance as to when, or if at all, production will ultimately be restored at West Cameron 643. The field operator for East Cameron 371 has reported to Chevron that a review of the remaining reserves for East Cameron 371 has been conducted, and a decision regarding field abandonment, including the related wells, equipment platforms and any field infrastructure, may be made in the near term. At this point in time, there can be no assurance that production will ultimately be restored at East Cameron 371.

        On December 19, 2008, the Trust announced its fourth quarter distribution of approximately $0.7 million, which was paid on January 9, 2009. Based on the damage caused by Hurricane Ike, the Trust's scheduled distribution for the fourth quarter of 2008 was severely negatively impacted, although there were funds available for distribution given that there was some production from Eugene Island 339 and Ship Shoal 182/183 in August and September 2008. On March 25, 2009, the Trust announced that there would be no trust distribution for the first quarter of 2009. Similarly, on June 26, 2009 and September 25, 2009, the Trust announced that there would be no trust distribution for the second quarter and third quarter of 2009, respectively. There were no Net Proceeds distributed to the Trust for the first, second or third quarter of 2009.

        There are not likely to be sufficient Net Proceeds from the Royalty Properties for the Trust to make a regularly scheduled quarterly distribution to Unit holders for the foreseeable future. As a result of the damage inflicted by Hurricane Ike, Net Proceeds will continue to be severely impacted by both reduced production, from historical levels, and the amount of expenditures incurred that are associated with such damages, including the expenditures required to plug and abandon the wells on Eugene Island 339, and, as currently expected, to redevelop the facility at Eugene Island 339.

        Future Net Proceeds from the Royalty Properties may take into account the Trust's share of project costs and other related expenditures that are not covered by the insurance of the operators of the Royalty Properties. The Trust's net portion of the aggregate cost to plug and abandon the wells subject to the royalty on Eugene Island 339 is estimated to be approximately $13 million. If development and production costs of the Royalty exceed the proceeds of production from the Royalty Properties, the Trust will not receive Net Proceeds until future proceeds from production exceed the total of the excess costs plus accrued interest, at a rate equal to one-fourth of (i) one-half of one

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percent plus (ii) the median between the prime interest rate at the end of a quarterly period in which there are excess costs and the prime interest rate at the end of the preceding quarterly period, during the deficit period. Development activities may not generate sufficient additional revenue to repay the costs. Accordingly, there will not be sufficient Net Proceeds from the Royalty Properties to make distributions for some period of time in the future. At this time, the ultimate outcome of these matters cannot be determined with any degree of certainty.

        For the third quarter of 2009, under the terms of the Conveyance, production costs for the Royalty Properties exceeded gross proceeds thereof, with the Trust's portion of such excess equal to approximately $1.5 million. For the first nine months of 2009, the Trust's portion of the amount by which production costs exceeded gross proceeds is approximately $4.6 million.

        Substantial uncertainties exist with regard to future oil and gas prices, which are subject to material fluctuations due to changes in production levels and pricing and other actions taken by major petroleum producing nations, as well as the regional supply and demand for gas, weather, industrial growth, conservation measures, competition, economic conditions generally and other variables.

        In accordance with the provisions of the Trust Agreement, generally all Net Proceeds received by the Trust, net of Trust general and administrative expenses and any cash reserves established for the payment of contingent or future obligations of the Trust, are distributed currently to the Unit holders.

        See "—Reserve for Future Trust Expenses" for a discussion of the cash reserves established by the Trust and the Trustees' ability to borrow funds and to take certain other actions related to the payment of contingent or future obligations of the Trust.

Future Net Revenues and Termination of the Trust

        Based on a reserve study provided to the Trust by DeGolyer and MacNaughton, independent petroleum engineers, as of October 31, 2008 future net revenues attributable to the Trust's royalty interests were estimated at $24.2 million. Estimates of proved oil and gas reserves attributable to the Partnership's royalty interest are based on existing economic and operating conditions in effect at October 31, 2008 in order to correspond with distributions to the Trust. Such reserve study also indicates that approximately 40% of the future net revenues from the Royalty Properties are expected to be received by the Trust during the next three years. Solely for purposes of being able to complete the reserve study so that the Trust could file its Form 10-K for the year ended December 31, 2008, DeGolyer and MacNaughton assumed that Eugene Island 339 will not be redeveloped. As such, the reserve study does not include any reserves or values attributable to Eugene Island 339, nor does it include the Trust's net portion of the aggregate cost to plug and abandon the wells subject to the royalty on Eugene Island 339, which net portion is estimated to be approximately $13 million. The assumption was made by DeGolyer and MacNaughton because Chevron had not made a decision regarding any redevelopment of Eugene Island 339 and such decision would impact the treatment of Eugene Island 339 for purposes of preparing a reserve study for the Partnership. Because the Trust will terminate in the event estimated future net revenues fall below $2.0 million, it would be possible for the Trust to terminate even though some or all of the Royalty Properties continued to have remaining productive lives. Upon termination of the Trust, the Trustees will sell for cash all of the assets held in the Trust estate and make a final distribution to Unit holders of any funds remaining after all Trust liabilities have been satisfied. The estimates of future net revenues discussed above are subject to large variances from year to year and should not be construed as exact. There are numerous uncertainties

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present in estimating future net revenues for the Royalty Properties. The estimate may vary depending on changes in market prices for crude oil and natural gas, the recoverable reserves, annual production and costs assumed by DeGolyer and MacNaughton. In addition, future economic and operating conditions as well as results of future drilling plans may cause significant changes in such estimate. The discussion set forth above is qualified in its entirety by reference to the Trust's Annual Report on Form 10-K for the year ended December 31, 2008. The Trust's Form 10-K is available at the website of the Securities and Exchange Commission ("SEC") at www.sec.gov or upon request from the Corporate Trustee.

Special Cost Escrow Account

        The Conveyance provides for reserving funds for estimated future "Special Costs" of plugging and abandoning wells, dismantling platforms and other costs of abandoning the Royalty Properties, as well as for the estimated amount of future drilling projects and other capital expenditures on the Royalty Properties. As provided in the Conveyance, the amount of funds to be reserved is determined based on factors including estimates of aggregate future production costs, aggregate future Special Costs, aggregate future net revenues and actual current net proceeds. Deposits into this account reduce current distributions and are placed in an escrow account and invested in short-term certificates of deposit. Such account is herein referred to as the "Special Cost Escrow" account. The Trust's share of interest generated from the Special Cost Escrow account serves to reduce the Trust's share of allocated production costs.

        Special Cost Escrow funds will generally be utilized to pay Special Costs to the extent there are not adequate current Net Proceeds to pay such costs. Special Costs that have been paid are no longer included in the Special Cost Escrow calculation. Deposits to the Special Cost Escrow account will generally be made when the balance in the Special Cost Escrow account is less than 125% of estimated future Special Costs and there is a Net Revenues Shortfall (a calculation of the excess of estimated future costs over estimated future net revenues pursuant to a formula contained in the Conveyance). When there is not a Net Revenues Shortfall, amounts in the Special Cost Escrow account will generally be released, to the extent that Special Costs have been incurred. Amounts in the Special Cost Escrow account will also be released when the balance in such account exceeds 125% of estimated future Special Costs. In the first nine months of 2009, there were no funds released from or deposited into the Special Cost Escrow account. As of September 30, 2009, $4,306,985 remained in the Special Cost Escrow account. The funds held in the Special Cost Escrow account are not reflected in the financial statements of the Trust. The discussion of the terms of the Conveyance and Special Cost Escrow account contained herein is qualified in its entirety by reference to the Conveyance itself, which is an exhibit to this Form 10-Q and is available upon request from the Corporate Trustee.

        Chevron, in its capacity as the Managing General Partner of the Partnership, has advised the Trust that additional deposits to the Special Cost Escrow account may be required in future periods in connection with other production costs, other abandonment costs, other capital expenditures and changes in the estimates and factors described above. Such deposits could result in a significant reduction in Royalty income in the periods in which such deposits are made, including the possibility that no Royalty income would be received in such periods.

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Overview of Production, Prices and Royalty Income

        The following schedule provides a summary of the volumes and weighted average prices for crude oil and condensate and natural gas recorded by the Working Interest Owners for the Royalty Properties, as well as the Working Interest Owners' calculations of the Net Proceeds and the royalties paid to the Trust during the periods indicated. Net Proceeds due to the Trust are calculated for each three month period commencing on the first day of February, May, August and November.

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(1)

Amounts are based on actual production for the three-month period ended July 30 of each year, respectively.

(2)

Undistributed net loss represents the amount of development and production costs associated with the Royalty that exceed the proceeds of production from the Royalty Properties during the period. An undistributed net loss is carried forward and offset, in future periods, by positive proceeds earned by the related Working Interest Owner(s). The Trust will not receive Net Proceeds until future proceeds from production exceed the total of the excess costs plus applicable accrued interest. Undistributed net income represents positive Net Proceeds, generated during the respective period, but not distributed by the Working Interest Owners. As of September 30, 2009, the undistributed net loss was $6,247,115.

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(1)

Undistributed net loss represents the amount of development and production costs associated with the Royalty that exceed the proceeds of production from the Royalty Properties during the period. An undistributed net loss is carried forward and offset, in future periods, by positive proceeds earned by the related Working Interest Owner(s). The Trust will not receive Net Proceeds until future proceeds from production exceed the total of the excess costs plus applicable accrued interest. Undistributed net income represents positive Net Proceeds, generated during the respective period, but not distributed by the Working Interest Owners. As of September 30, 2009, the undistributed net loss was $19,538,783.

Item 3.    Quantitative and Qualitative Disclosures About Market Risk.

        The only assets of and sources of income to the Trust are cash and the Trust's interest in the Partnership, which is the holder of the Royalty. Consequently, the Trust is exposed to market risk associated with the Royalty from fluctuations in oil and gas prices. Reference is also made to Note 2 of the Notes to Financial Statements included in Item 1 of this Form 10-Q.

        The Trust may borrow money to pay expenses of the Trust. Additionally, if development and production costs of the Royalty exceed the proceeds of production from the Royalty Properties, the Trust will not receive Net Proceeds until future proceeds from production exceed the total of the excess costs plus accrued interest, at a rate equal to one-fourth of (i) one-half of one percent plus (ii) the median between the prime interest rate at the end of a quarterly period in which there are excess costs and the prime interest rate at the end of the preceding quarterly period, during the deficit period. Consequently, the Trust will be exposed to interest rate market risk should it borrow money to pay expenses and to the exent that development and production costs of the Royalty exceed the proceeds of production from the Royalty Properties.

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Item 4.    Controls and Procedures.

        Evaluation of disclosure controls and procedures.    The Corporate Trustee maintains disclosure controls and procedures designed to ensure that information required to be disclosed by the Trust in the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and regulations. Disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by the Trust is accumulated and communicated by Chevron, as the Managing General Partner of the Partnership, and the Working Interest Owners to the Corporate Trustee of the Trust, and its employees who participate in the preparation of the Trust's periodic reports as appropriate to allow timely decisions regarding required disclosure.

        As of the end of the period covered by this report, the Corporate Trustee carried out an evaluation of the Trust's disclosure controls and procedures. Mike Ulrich, as Trust Officer of the Corporate Trustee, has concluded that the disclosure controls and procedures of the Trust are effective.

        Due to the contractual arrangements of (i) the Trust Agreement, (ii) the Partnership Agreement and (iii) the rights of the Partnership under the Conveyance regarding information furnished by the Working Interest Owners, the Trustees rely on (A) information provided by the Working Interest Owners, including historical operating data, plans for future operating and capital expenditures, reserve information and information relating to projected production, (B) information from the Managing General Partner of the Partnership, including information that is collected from the Working Interest Owners, and (C) conclusions and reports regarding reserves by the Trust's independent reserve engineers. See Item 1A. Risk Factors "—The Trustees and the Unit holders have no control over the operation or development of the Royalty Properties and have little influence over operation or development" and "The Trustees rely upon the Working Interest Owners and Managing General Partner for information regarding the Royalty Properties" in the Trust's Annual Report on Form 10-K for the year ended December 31, 2008 for a description of certain risks relating to these arrangements and reliance on and applicable adjustments to operating information when reported by the Working Interest Owners to the Corporate Trustee and recorded in the Trust's results of operation.

        Changes in Internal Control Over Financial Reporting.    During the three months ended September 30, 2009, there has been no change in the Trust's internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the Trust's internal control over financial reporting. The Corporate Trustee notes for purposes of clarification that it has no authority over, and makes no statement concerning, the internal control over financial reporting of the Working Interest Owners or the Managing General Partner of the Partnership.

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PART II—OTHER INFORMATION

Item 1A.    Risk Factors.

        There have not been any material changes from risk factors previously disclosed in the Trust's response to Item 1A of Part 1 of the Trust's Annual Report on Form 10-K for the year ended December 31, 2008.

Item 6.    Exhibits.

        (Asterisk indicates exhibit previously filed with the Securities and Exchange Commission and incorporated herein by reference.)

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SIGNATURES

        Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

        The Registrant, TEL Offshore Trust, has no principal executive officer, principal financial officer, board of directors or persons performing similar functions. Accordingly, no additional signatures are available and none have been provided.

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QuickLinks

NOTE REGARDING FORWARD LOOKING STATEMENTS
PART I—FINANCIAL INFORMATION

Item 1. Financial Statements.

TEL OFFSHORE TRUST STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS (Unaudited)
STATEMENTS OF DISTRIBUTABLE INCOME (Unaudited)
STATEMENTS OF CHANGES IN TRUST CORPUS (Unaudited)
TEL OFFSHORE TRUST NOTES TO FINANCIAL STATEMENTS (Unaudited)

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
Item 4. Controls and Procedures.

PART II—OTHER INFORMATION

Item 1A. Risk Factors.
Item 6. Exhibits.

SIGNATURES