Exhibit 99.1

DEGOLYER AND MACNAUGHTON

5001 Spring Valley Road
Suite 800 East
Dallas, Texas 75244

This is a digital representation of a DeGolyer and MacNaughton report.

Each file contained herein is intended to be a manifestation of certain data in the subject report and as such is subject to the definitions, qualifications, explanations, conclusions, and other conditions thereof. The information and data contained in each file may be subject to misinterpretation; therefore, the signed and bound copy of this report should be considered the only authoritative source of such information.

DEGOLYER AND MACNAUGHTON

5001 Spring Valley Road
Suite 800 East
Dallas, Texas 75244

LETTER REPORT
as of
OCTOBER 31, 2009
on
RESERVES and REVENUE
of
CERTAIN PROPERTIES
owned by the
TEL OFFSHORE TRUST PARTNERSHIP

SEC CASE

DEGOLYER AND MACNAUGHTON

5001 Spring Valley Road
Suite 800 East
Dallas, Texas 75244

February 1, 2010

Chevron U.S.A. Inc.

Chevron Place

935 Gravier Street

New Orleans, Louisiana 70012

Gentlemen:

Pursuant to your request, we have prepared estimates, as of October 31, 2009, of the extent and value of the proved crude oil, condensate, and natural gas reserves of a net profits interest owned by TEL Offshore Trust Partnership (the Trust Partnership). This net profits interest (the Trust Partnership Interest) is in certain offshore leases owned by Chevron U.S.A. Inc. (Chevron). The interest appraised consists of a 25-percent net profits interest in 17 leases (the Subject Properties), which are located in the Gulf of Mexico offshore from Louisiana. Certain of the Subject Properties were acquired by Energy Resources Technology (ERT) effective July 1, 2007 and certain other properties were acquired by Hilcorp Energy Company (Hilcorp) effective August 1, 2008. The Managing Partner of the Trust Partnership is Chevron.

Information used in the preparation of this report was obtained from Chevron. During this investigation, we consulted freely with the officers and employees of Chevron and were given access to such accounts, records, geological and engineering reports, and other data as were desired for examination. In the preparation of this report we have relied, without independent verification, upon information furnished by Chevron with respect to property interests owned by the Trust Partnership, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. It was not considered necessary to make a field examination of the physical condition and operation of the Subject Properties. Additionally, this information includes data supplied by Petroleum Information/Dwights LLC; Copyright 2009 Petroleum Information/Dwights LLC.

Our reserves estimates are based on a detailed study of the Subject Properties and were prepared by the use of standard geological and engineering methods generally accepted by the petroleum industry. The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, consideration of the stage of development of the reservoir, and the quality and completeness of basic data.

Reserves estimated herein are expressed as gross and net reserves. Gross reserves are defined as the total estimated petroleum to be produced from the Subject Properties after October 31, 2009. Combined net reserves are defined as those reserves remaining after deducting royalties and interests owned by others from gross reserves. Net reserves are defined as that portion of the combined net reserves attributable to the interests owned by the Trust Partnership. Gas volumes are expressed as sales-gas reserves at a temperature of 60 degrees Fahrenheit and at a legal pressure base of 14.73 pounds per square inch absolute. Sales gas is defined as the total gas to be produced from the reservoirs, measured at the point of delivery, after reduction for fuel usage, flare, and shrinkage resulting from field separation and processing. Condensate reserves estimated herein are those to be obtained by normal separator recovery.

Petroleum reserves included in this report are classified as proved and are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs as of the date the estimate is made, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. Proved reserves classifications used in this report are in accordance with the reserves definitions of Rules 4-10(a) (1)–(13) of Regulation S–X of the United States Securities and Exchange Commission (SEC). The petroleum reserves are classified as follows:

Proved oil and gas reserves – Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of

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changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

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

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

(iii) Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”; (B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite, and other such sources.

Proved developed oil and gas reserves – Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary

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recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

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

All of the proved reserves estimated herein are classified as proved developed. There are no proved undeveloped reserves for the properties evaluated in this report.

The properties evaluated consist of 17 leases located offshore from Louisiana. These 17 leases include 4 productive properties. No reserves have been assigned to 13 properties, including 4 abandoned leases. ERT owns an interest in one nonproductive property. Hilcorp owns an interest in three leases, none of which is productive. Chevron owns an interest in the remaining nine properties, including five to which no reserves have been assigned.

The reserves volumes and revenue values shown in this report were estimated from projections of reserves and revenue attributable to the “Combined Interests,” defined herein as the Trust Partnership Interests and the interests retained in the Subject Properties by Chevron, ERT, or Hilcorp. Net reserves attributable to the Trust Partnership Interests were estimated by allocating to the Trust Partnership a portion of the estimated combined net reserves of the Subject Properties based on future revenue. The formula used to estimate the net reserves attributable to the Trust Partnership Interest is as follows:

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This formula was applied only to the Chevron group of properties to obtain the total reserves for the Trust Partnership Interest. The ERT and Hilcorp properties do not have proved reserves. Because the net reserves volumes attributable to the Trust Partnership Interest are estimated using an allocation of reserves based on estimates of future revenue, a change in prices or costs will result in changes in the estimated net reserves. Therefore, the estimated net reserves attributable to the Trust Partnership Interest will vary if different future price and cost assumptions are used. Trust Partnership Interest net revenue and net reserves estimates included in this report have been estimated from reserves and revenue attributable to the Combined Interests using procedures and calculation methods as specified by Chevron and represented by Chevron to be in accordance with the Conveyance of Overriding Royalty Interests.

Data available from wells drilled on the appraised properties through October 2009 were used in estimating gross ultimate recovery. Gross production through October 31, 2009, was deducted from the gross ultimate recovery to arrive at estimates of gross reserves. This required 3 months of estimated production for the non-operated royalty interest property, Eugene Island 342, since production for this property was available only through July 31, 2009.

During September 2008, the platforms and wells associated with the Eugene Island 339 field were completely destroyed by Hurricane Ike. Chevron is proceeding with the work required to clear the remaining infrastructure and abandon existing wells. A cost estimate for this work was not available during the preparation of the October 31, 2008, report. Therefore, at the request of Chevron, the Eugene Island 339 field was omitted from the October 31, 2008, report.

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Estimated net proved reserves attributable to the Trust Partnership Interest, as of October 31, 2009, are summarized as follows, expressed in barrels (bbl) and thousands of cubic feet (Mcf):

(1)               Eugene Island 330 abandonment costs not included.

(2)               Production was estimated based on the ratio as of October 31, 2008, of the Trust Partnership Interest net reserves to the Combined Interests net reserves. This ratio was then applied to the production net to the Combined Interests for the period from November 1, 2008, through October 31, 2009.

(3)               Eugene Island 330 abandonment costs included.

Revenue values in this report are expressed in terms of estimated combined future net revenue, future net revenue attributable to the Trust Partnership Interest, and present worth of these future net revenues. Future gross revenue is that revenue which will accrue from the production and sale of the estimated combined net reserves. Combined future net revenue values were calculated by deducting operating expenses and capital costs from the future gross revenue of the Combined Interests. These monthly values for the aggregate of the Combined Interests in the Subject Properties were reduced by a trust overhead charge furnished by Chevron. Capital and abandonment costs for longer-life properties were accrued at the end of each quarter in amounts specified by Chevron beginning in January 2010. The future accrual or escrow amounts for each of the three groups of properties were deducted from the combined future net revenue at the end of each quarter, as specified by Chevron. Interest on the balance of the accrued capital and abandonment costs at the rate of 0.18 percent per year as specified by Chevron was credited monthly. The adjusted revenue resulting from subtracting the overhead charge and accrued capital and abandonment costs was multiplied by a factor of 25 percent to arrive at the future net revenue attributable to the Trust Partnership Interest. The above calculations were made monthly for the properties. Interest was charged monthly on the net profits deficit balances (costs not recovered currently) at the rate of 0.18 percent per year as specified by Chevron. Present worth is defined as

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future net revenue discounted at a specified arbitrary discount rate compounded monthly over the expected period of realization; in this report, present worth values using a discount rate of 10 percent are reported. Future income tax expenses were not taken into account in estimating future net revenue and present worth. No deductions were made in the foregoing reserves estimates for any outstanding production payments.

Revenue values in this report were estimated using the initial prices and costs provided by Chevron. Future prices were estimated using guidelines established by the United States Securities and Exchange Commission (SEC) and the Financial Accounting Standards Board (FASB). These guidelines require the use of prices for oil and condensate in effect on October 31, 2009. The following assumptions were used for estimating future prices and costs:

Oil and Condensate Prices

Oil and condensate prices were furnished by Chevron and were the prices in effect on October 31, 2009. These prices were used as initial prices with no increases based on inflation.

Natural Gas Prices

Initial gas prices furnished by Chevron were prices in effect on October 31, 2009. These initial prices were held constant for the life of the properties.

Operating Expenses and Capital Costs

Current estimates of operating expenses were used for the life of the properties with no increases in the future based on inflation. Future capital expenditures were estimated using 2009 values and were not adjusted for inflation. Abandonment costs have been estimated as capital costs for all properties, including leases which are considered depleted and to which no reserves have been assigned.

A summary of estimated revenue and costs attributable to the Combined Interests in proved reserves of the Subject Properties and the future net revenue and present worth attributable to the Trust Partnership Interest, as of October 31, 2009, is as follows, expressed in dollars ($):

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(1) Includes abandonment costs.

(2) Escrow balance for the Hilcorp properties is zero.

(3) Future income tax expenses were not taken into account in the preparation of these estimates.

In our opinion, the information relating to estimated proved reserves, estimated future net revenue from proved reserves, and present worth of estimated future net revenue from proved reserves of oil, condensate, natural gas liquids, and gas contained in this report has been prepared in accordance with Paragraphs 10–13, 15, and 30(a)–(b) of Statement of Financial Accounting Standards No. 69 (November 1982) of the FASB and Rules 4-10(a) (1)–(13) of Regulation S–X and Rule 302(b) of Regulation S–K of the SEC; provided, however, future income tax expenses have not been taken into account in estimating the future net revenue and present worth values set forth herein.

To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature or information beyond the scope of this report, we are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.

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In our opinion, we have made the investigations necessary to enable us to estimate the petroleum reserves reported herein. Estimates of oil, condensate, and gas reserves and future net revenue should be regarded only as estimates that may change as further production history and additional information become available. Not only are such reserves and revenue estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.

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