Exhibit 99.1

DEGOLYER AND MACNAUGHTON

5001 SPRING VALLEY ROAD

SUITE 800 EAST

DALLAS, TEXAS 75244

APPRAISAL REPORT

as of

DECEMBER 31, 2009

on

CERTAIN PROPERTIES

owned by

DUNE ENERGY, INC.

SEC CASE

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DEGOLYER AND MACNAUGHTON

APPRAISAL REPORT

as of

DECEMBER 31, 2009

on

CERTAIN PROPERTIES

owned by

DUNE ENERGY, INC.

SEC CASE

FOREWORD

Scope of Investigation

This report presents an appraisal, as of December 31, 2009, of the extent and value of the proved, probable, and possible crude oil, condensate, and natural gas reserves of certain properties owned by Dune Energy, Inc. (Dune). The reserves estimated in this report are located in Louisiana and Texas and represent 100 percent of Dune’s reserves. The properties appraised are listed in detail in the related DeGolyer and MacNaughton report entitled “Appraisal Report as of December 31, 2009 on Certain Properties owned by Dune Energy, Inc.”

Reserves estimated in this report are expressed as gross and net reserves. Gross reserves are defined as the total estimated petroleum to be produced from these properties after December 31, 2009. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by Dune after deducting royalties and interests owned by others.

This report also presents values that were estimated for proved, probable, and possible reserves using initial prices and costs provided by Dune. Prices, as required by the Securities and Exchange Commission (SEC) are the average of the price at the beginning of the previous 12 months. Oil and condensate prices are related to ConocoPhillips West Texas Intermediate (WTI) price of $57.80 per barrel. Natural gas prices are related to the Henry Hub Louisiana Onshore price of $3.87 per million British thermal units (MMBtu). No escalation has been applied to prices and costs. A detailed explanation of the future price and cost assumptions is included in the Valuation of Reserves section of this report.

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DEGOLYER AND MACNAUGHTON

Values of proved, probable, and possible reserves in this report are expressed in terms of estimated future gross revenue, future net revenue, and present worth. Future gross revenue is that revenue which will accrue to the appraised interests from the production and sale of the estimated net reserves. Future net revenue is calculated by deducting estimated production taxes, ad valorem taxes, operating expenses, and capital costs from the future gross revenue. Operating expenses include field operating expenses, transportation expenses, compression charges, and an allocation of overhead that directly relates to production activities. Future income tax expenses were not taken into account in the preparation of these estimates. 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.

Estimates of oil, condensate, natural gas liquids, 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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Authority

This report was prepared at the request of Mr. James Watt, President and CEO, Dune.

Source of Information

Data used in the preparation of this report were obtained from Dune, from records on file with the appropriate regulatory agencies, and from public sources. Additionally, this information includes data supplied by Petroleum Information/Dwights LLC; Copyright 2009 Petroleum Information/Dwights LLC. In the preparation of this report we have relied, without independent verification, upon information furnished by Dune with respect to its property interests, 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. A field examination of the properties was not considered necessary for the purposes of this report.

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DEGOLYER AND MACNAUGHTON

DEFINITION of RESERVES

Petroleum reserves included in this report are classified by degree of proof as proved, probable, or possible. 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,

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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.

Probable reserves – Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

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(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv) See also guidelines in paragraphs (iv) and (vi) of the definition of possible reserves.

Possible reserves – Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and

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engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(vi) Pursuant to paragraph (iii) of the proved oil and gas definition, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

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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

(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 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.

The extent to which probable and possible reserves ultimately may be reclassified as proved reserves is dependent upon future

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drilling, testing, and well performance. The degree of risk to be applied in evaluating probable and possible reserves is influenced by economic and technological factors as well as the time element. Probable and possible reserves in this report have not been adjusted in consideration of these additional risks and therefore are not comparable with proved reserves.

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ESTIMATION of RESERVES

Estimates of reserves were prepared by the use of 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, stage of development, quality and completeness of basic data, and production history.

When applicable, the volumetric method was used to estimate the original oil in place (OOIP) and original gas in place (OGIP). Structure maps were prepared to delineate each reservoir, and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses, and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation. When adequate data were available and when circumstances justified, material-balance and other engineering methods were used to estimate OOIP or OGIP.

Estimates of ultimate recovery were obtained after applying recovery factors to OOIP or OGIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and the production histories. When applicable, material-balance and other engineering methods were used to estimate recovery factors. An analysis of reservoir performance, including production rate, reservoir pressure, and gas-oil ratio behavior, was used in the estimation of reserves.

For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production based on current economic conditions.

In certain cases, when the previously named methods could not be used, reserves were estimated by analogy with similar wells or reservoirs for which more complete data were available.

Gas volumes included herein are expressed as wet gas and sales gas. Wet gas is the indigenous gas in the reservoir to

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be produced. Sales gas is defined as that gas to be delivered into a gas pipeline for sale after separation, processing, fuel use, and flare. Gross gas reserves are reported as wet gas. The net gas reserves are reported as sales gas. All gas quantities are expressed at a temperature base of 60 degrees Fahrenheit (°F) and at the legal pressure base of the state or area in which the reserves are located. Condensate reserves estimated herein are those to be recovered by conventional lease separation.

In the preparation of this report, as of December 31, 2009, gross production estimated to December 31, 2009, was deducted from gross ultimate recovery to arrive at the estimate of gross reserves. In some fields, this required that the production rates be estimated for up to 2 months, since production data from certain properties were available only through October 2009. Data available from wells drilled through December 31, 2009, were used in this report.

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DEGOLYER AND MACNAUGHTON

The following table presents estimates of the proved reserves, as of December 31, 2009, of the properties appraised, expressed in thousands of barrels (Mbbl) or millions of cubic feet (MMcf):

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The following table presents estimates of probable reserves, as of December 31, 2009, of the properties appraised, expressed in thousands of barrels (Mbbl) or millions of cubic feet (MMcf):

Note: Probable reserves have not been risk adjusted to make them comparable to proved reserves.

The following table presents estimates of possible reserves, as of December 31, 2009, of the properties appraised, expressed in thousands of barrels (Mbbl) or millions of cubic feet (MMcf):

Note: Possible reserves have not been risk adjusted to make them comparable to proved reserves.

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DEGOLYER AND MACNAUGHTON

VALUATION of RESERVES

Revenue values in this report were estimated using the initial prices and costs provided by Dune. Future prices were estimated using guidelines established by the SEC and the Financial Accounting Standards Board (FASB). The following assumptions were used for estimating future prices and costs:

Oil and Condensate Prices

Oil and condensate prices were calculated using differentials furnished by Dune for each lease to a ConocoPhillips WTI price of $57.80 per barrel and held constant thereafter. The weighted average price over the lives of the properties was $58.05 per barrel.

Natural Gas Prices

Natural gas prices were calculated for each lease using differentials furnished by Dune to a Henry Hub Louisiana Onshore price of $3.87 per MMBtu and held constant thereafter. The weighted average price over the lives of the properties was $4.135 per thousand cubic feet.

Operating Expenses and Capital Costs

Current operating expenses and capital costs, based on information provided by Dune, were used in estimating future costs required to operate the properties. In certain cases, future costs, either higher or lower than current costs, may have been used because of anticipated changes in operating conditions. These costs were not escalated for inflation.

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The future revenue to be derived from the production and sale of the proved reserves, as of December 31, 2009, of the properties appraised is estimated as follows:

Note: Future income taxes have not been taken into account in the preparation of these estimates.

The estimated future revenue to be derived from the production and sale of the probable reserves, as of December 31, 2009, of the properties appraised, expressed in thousands of dollars (M$) is summarized as follows:

Notes:

The estimated future revenue to be derived from the production and sale of the possible reserves, as of December 31, 2009, of the properties appraised, expressed in thousands of dollars (M$) is summarized as follows:

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Notes:

Timing of capital expenditures and the resulting development of production were based on a development plan provided by Dune.

In our opinion, the information relating to estimated proved, probable, and possible 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, 932-235-50-6, 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, 1202(a) (1), (2), (3), (4), (5), (8), and 1203(a) 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 that the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature or information beyond the scope of our 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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SUMMARY and CONCLUSIONS

Dune owns working interests in certain properties located in Louisiana and Texas. The estimated net proved reserves of the properties appraised, as of December 31, 2009, are summarized as follows, expressed in thousands of barrels (Mbbl) or millions of cubic feet (MMcf):

The estimated net probable reserves, as of December 31, 2009, of the properties appraised are summarized as follows, expressed in thousands of barrels (Mbbl) or millions of cubic feet (MMcf).

Note: Probable reserves have not been risk adjusted to make them comparable to proved reserves.

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The estimated net possible reserves, as of December 31, 2009, of the properties appraised are summarized as follows, expressed in thousands of barrels (Mbbl) or millions of cubic feet (MMcf).

Note: Possible reserves have not been risk adjusted to make them comparable to proved reserves.

The estimated revenue and expenditures attributable to Dune’s interests in the proved reserves, as of December 31, 2009, of the properties appraised under the aforementioned assumptions concerning future prices and costs are summarized as follows:

Note: Future income taxes have not been taken into account in the preparation of these estimates.

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The estimated future revenue to be derived from the production and sale of the probable reserves, as of December 31, 2009, of the properties appraised, expressed in thousands of dollars (M$) is summarized as follows:

Notes:

The estimated future revenue to be derived from the production and sale of the possible reserves, as of December 31, 2009, of the properties appraised, expressed in thousands of dollars (M$) is summarized as follows:

Notes:

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While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its oil and gas reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2009, estimated oil and gas volumes. The reserves estimated in this report can be produced under current regulatory guidelines.

DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over 70 years. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in Dune. Our fees were not contingent on the results of our evaluation. This report has been prepared at the request of Dune and should not be used for purposes other than those for which it is intended. DeGolyer and MacNaughton has used all procedures, data, and methods that it considers necessary to prepare this report.

All gas quantities in this report are expressed at a temperature base of 60 °F and at the legal pressure base of the state or area in which the reserves are located.

SIGNED: February 2, 2010

DEGOLYER AND MACNAUGHTON

CERTIFICATE of QUALIFICATION

I, Paul J. Szatkowski, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas 75244, U.S.A., hereby certify:

SIGNED: February 2, 2010