Exhibit 99.1

DeGolyer and MacNaughton
5001 Spring Valley Road
Suite 800 East
Dallas, Texas 75244

LETTER REPORT
as of
OCTOBER 31, 2010
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

January 21, 2011

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, 2010, 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. 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 2010 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, 2010. 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. Only proved reserves have been evaluated for this report. Reserves classifications used in this report are in accordance with the reserves definitions of Rules 4-10(a) (1)-(32) of Regulation S-X of the SEC. Reserves 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 consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:

        Proved oil and gas reserves— Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

          (i)  The area of the reservoir considered as proved includes:

        (A)  The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

         (ii)  In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

        (iii)  Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

        (iv)  Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

        (A)  Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

         (v)  Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

        Developed oil and gas reserves— Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

          (i)  Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

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         (ii)  Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

        Undeveloped oil and gas reserves— Undeveloped oil and gas reserves are reserves of any category 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.

          (i)  Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

         (ii)  Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

        (iii)  Under no circumstances shall estimates for 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 projects in the same reservoir or an analogous reservoir, as defined in [section 210.4-10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty.

        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 5 productive properties. No reserves have been assigned to 12 properties, including 6 abandoned leases.

        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:

        This formula was applied only to the Chevron group of properties to obtain the total reserves for the Trust Partnership Interest. The Hilcorp property does 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 2010 were used in estimating gross ultimate recovery. Gross production through October 31, 2010, was deducted from the gross ultimate recovery to arrive at estimates of gross reserves. This required 2 months of estimated production for the non-operated royalty interest property, Eugene Island 342, since production for this property was available only through August 31, 2010.

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        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.

        Estimated net proved reserves attributable to the Trust Partnership Interest, as of October 31, 2010, are summarized as follows, expressed in barrels (bbl) and thousands of cubic feet (Mcf):

        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 2011. 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 0.20 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 0.20 percent per year as specified by Chevron. Present worth is defined as 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

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require the use of prices for oil and condensate in effect on October 31, 2010. The following assumptions were used for estimating future prices and costs:

Oil and Condensate Prices

        The oil and condensate prices were based on a 12-month average price (reference price), calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. Chevron supplied differentials by field to a West Texas Intermediate reference price of $78.22 per barrel and the prices were held constant thereafter. The volume-weighted average price is $79.05 per barrel.

Natural Gas Prices

        The natural gas prices were based on a reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. The gas prices were calculated for each property using differentials to a Henry Hub reference price of $4.46 per Mcf furnished by Chevron and held constant thereafter. The volume-weighted average price is $4.60 per Mcf.

Operating Expenses and Capital Costs

        Operating expenses and capital costs, based on information provided by Chevron, were used in estimating future costs required to operate the properties. 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, 2010, is as follows, expressed in dollars ($):

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        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 932-235-50-4 through 932-235-50-7, 932-235-50-9, 932-235-50-30, and 932-235-50-31(a), (b), and (e) of the Accounting Standards Update 932-235-50, Extractive Industries—Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the Financial Accounting Standards Board and Rules 4-10(a) (1)-(32) of Regulation S-X and Rules 302(b), 1201, and 1202(a) (1), (2), (3), (4), (8) of Regulation S-K of the Securities and Exchange Commission; 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, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.

        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.

		Submitted,
		DeGOLYER and MacNAUGHTON Texas Registered Engineering Firm F-716
		Paul J. Szatkowski, P.E. Senior Vice President DeGolyer and MacNaughton

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Exhibit 99.1