SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549

                                   FORM 10-KSB/A

|X|   Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange
      Act of 1934 for the fiscal year ended December 31, 2006

|_|   Transition Report under Section 13 of 15(d) of the Securities Exchange Act
      of 1934

      For the transition period from ___________ to __________

                         Commission file number: 0-27897

                                DUNE ENERGY, INC.
                 (Name of small business issuer in its charter)

                    Delaware                             95-4737507
        (State or other jurisdiction of     (I.R.S. Employer Identification No.)
        incorporation or organization)

3050 Post Oak Blvd., Suite 695, Houston, Texas             77056
   (Address of principal executive offices)             (Zip code)

         Issuer's telephone number, including area code: (713) 888-0895

         Securities registered under Section 12(b) of the Exchange Act:

       Title of each class             Name of each exchange on which registered
       -------------------             -----------------------------------------
               N/A                                        N/A

         Securities registered under Section 12(g) of the Exchange Act:

                                  Common Stock,
                            $.001 par value per share
                            -------------------------
                                (Title of class)

      Check whether the issuer is not required to file reports pursuant to
Section 13 or 15(d) of the Exchange Act. |_|

      Check whether the issuer: (1) filed all reports required to be filed by
Section 13 or 15(d) of the Exchange Act during the past 12 months (or for such
shorter period that the registrant was required to file such reports), and (2)
has been subject to such filing requirements for the past 90 days.
Yes |X| No |_|

      Check if there is no disclosure of delinquent filers in response to Item
405 of Regulation S-B contained in this form, and no disclosure will be
contained, to the best of registrant's knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this Form 10-KSB
or any amendment to this form 10-KSB. |X|

      Indicate by check mark whether the registrant is a shell company (as
defined in Rule 12b-2 of the Exchange Act). YES |_| NO |X|

      The issuer's revenues for its fiscal year ended December 31, 2006 were
$7,580,034.

      As of March 15, 2007, the aggregate market value of the issuer's common
equity held by non-affiliates was $40,746,005, based on the closing price of
$1.82 for its common stock on the American Stock Exchange on March 15, 2007.
60,810,813 shares of the issuer's common stock were outstanding as of March 15,
2007.

                       DOCUMENTS INCORPORATED BY REFERENCE

N/A

Transitional Small Business Disclosure Formats (check one): Yes |_| No |X|

<PAGE>

                                Explanatory Note

Dune Energy, Inc. (referred to herein as "Dune", "We", or the "Company") filed
this Annual Report on Form 10-KSB on April 2, 2007. After that filing date, Dune
concluded that it was necessary to amend this Annual Report in order to restate
its consolidated financial statements for the year ended December 31, 2006 to
restate proved properties impairment expense and the supplemental oil and gas
information related to the revision of the Reserve Report of Independent
Engineer for the correction of natural gas prices used in the calculation of
year end reserves.

The consolidated financial statements and other financial information included
in this Amendment No. 1 to this Annual Report have been restated accordingly.
Dune's shareholders should no longer rely on Dune's previously filed financial
statements for the year ended December 31, 2006. These matters have been
discussed by Dune's authorized officers with Dune's independent registered
public accounting firm.

In order to preserve the nature and character of the disclosures set forth in
this Annual Report as originally filed, no attempt was made in the amendments
described above to modify or update the disclosures in the original Annual
Report except Dune included the restatements described above in Part II, Item 7
and Dune has made changes to Management's Discussion and Analysis of Results of
Operations and Financial Condition in Part II, Item 6 and the Risk Factors to
conform to these restatements. Reference is made to our Current Report on Form
8-K filed with the Securities and Exchange Commission on April 18, 2007,
disclosing among other things, certain changes in our management and our entry
into a definitive stock purchase and sale agreement. No attempt to include the
information contained therein has been included in this Amendment.



                                       1
<PAGE>

Cautionary Notice Regarding Forward Looking Statements

      Dune Energy, Inc. (referred to herein as "Dune", "we" or the "Company")
desires to take advantage of the "safe harbor" provisions of the Private
Securities Litigation Reform Act of 1995. This report contains a number of
forward-looking statements that reflect management's current views and
expectations with respect to our business, strategies, future results and events
and financial performance. All statements made in this Annual Report other than
statements of historical fact, including statements that address operating
performance, events or developments that management expects or anticipates will
or may occur in the future, including statements related to revenues, cash flow,
profitability, adequacy of funds from operations, statements expressing general
optimism about future operating results and non-historical information, are
forward looking statements. In particular, the words "believe," "expect,"
"intend," " anticipate," "estimate," "may," "will," variations of such words,
and similar expressions identify forward-looking statements, but are not the
exclusive means of identifying such statements and their absence does not mean
that the statement is not forward-looking. These forward-looking statements are
subject to certain risks and uncertainties, including those discussed below. Our
actual results, performance or achievements could differ materially from
historical results as well as those expressed in, anticipated or implied by
these forward-looking statements. We do not undertake any obligation to revise
these forward-looking statements to reflect any future events or circumstances.

      Readers should not place undue reliance on these forward-looking
statements, which are based on management's current expectations and projections
about future events, are not guarantees of future performance, are subject to
risks, uncertainties and assumptions (including those described below) and apply
only as of the date of this report. Our actual results, performance or
achievements could differ materially from the results expressed in, or implied
by, these forward-looking statements. Factors that could cause or contribute to
such differences include, but are not limited to, those discussed below in "Risk
Factors" as well as those discussed elsewhere in this report, and the risks
discussed in our press releases and other communications to shareholders issued
by us from time to time which attempt to advise interested parties of the risks
and factors that may affect our business. We undertake no obligation to publicly
update or revise any forward-looking statements, whether as a result of new
information, future events or otherwise.


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<PAGE>

                                     PART I

Item 1. Description of Business.

      We are an independent energy company engaged in the exploration,
development, and acquisition of natural gas and crude oil properties. Presently,
we have an interest in the following areas in Texas and Louisiana:

      Barnett Shale - working interests (ranging between 92% and 100%) in
certain oil and gas leases covering approximately 2,258 gross acres in Denton
and Wise Counties, Texas. Dune currently owns an interest in 21 producing wells
and has 3 wells awaiting fracture stimulation and 1 well drilling. Dune operates
all of its Barnett Shale properties which are located on the fairway of the
prolific Barnett Shale play in the North Texas Fort Worth Basin (the "Barnett
Shale Properties");

      Bayou Couba - working interests (ranging between 10% and 25%) in certain
exclusive exploration and development rights covering approximately 11,100 gross
contiguous acres in St. Charles Parish, Louisiana, together with an undivided
working interest (ranging between 10% and 90%) in 21 producing wells. In January
of 2007, we successfully bid on and purchased, a 2,500 acre lease from the State
of Louisiana contiguous to our existing acreage in St. Charles Parish. Presently
we have a 100% working interest in this lease (the "Bayou Couba Property");

      Welder Ranch - leases covering approximately 7,950 contiguous acres on the
Welder Ranch located in Victoria County, Texas, together with an undivided
working interest in 5 producing wells and 1 shut-in well (the "Welder Ranch
Property");

      Pearsall Field - a working interest in leases covering 1,567 acres in the
Pearsall Field, located in Frio County, Texas, together with an undivided
working interest in one producing well (the "Pearsall Property"); and two proved
and undeveloped locations; and

      Los Mogotes Field - a small working interest in an 18,000 acre lease
containing multiple wells in the Los Mogotes Field, located in Zapata County,
Texas ("Los Mogotes Property"). The Welder Ranch, Pearsall and Los Mogotes
Properties are referred to as the "South Texas Properties".

      The Company was incorporated in the State of Delaware on November 20,
1998, under the name of IP Factory, Inc. In May 2001, Hitthebeach.com, Inc., a
private company, was merged into the Company. On May 7, 2003, Merchant Builders,
Inc., a private company, merged into the Company and the Company changed its
name to Dune Energy, Inc.

      As of March 15, 2007 we have 11 employees, of which 10 are full time
employees and 1 is a part time employee.

      Business Strategy

      Growth Through the Drill Bit. We believe that our personnel have knowledge
in identifying, drilling and stimulating hydrocarbon bearing formations and more
specifically tight formations and believe that we can continue to internally
generate drilling prospects.

      Focused Exploration and Development. We intend to focus exploration and
development in proven prolific Gulf Coast trends, as well as low risk
extensional drilling in the Barnett Shale. With respect to operating in
concentrated areas, we hope to more efficiently control overhead and operating
expenses, thereby allowing ourselves to manage a greater amount of acreage with
fewer employees and minimizing the marginal costs of increased drilling and
production. This targeting of operations allows us to more efficiently
capitalize on geological, geophysical, exploration, development, completion and
subsequent production in those areas.


                                       3
<PAGE>

      Diversify Risk Geologically. We intend to allocate a majority of our
capital to low risk development and exploitation projects, and the remainder to
moderate-higher risk exploration plays. We set limits on the amount of capital
invested in any one exploration project. With our Barnett Shale, Bayou Couba,
and South Texas Properties, we believe we have a complementary mix of
exploration and development opportunities.

      Generate Prospects and Maintain Multiyear Drilling Portfolio. We intend to
proactively search for acquisitions and/or joint ventures in our core areas of
concentration. We have identified 22 potential drilling locations on our Barnett
Shale Properties, approximately 7 developmental locations and 14 exploration
leads on our Bayou Couba Property, and a number of prospects and/or leads on our
Welder Ranch Property.

      Control of Operations. We prefer to control the operation of all of our
significant properties to efficiently allocate capital. We prefer to generate
and retain operating control over our own prospects, as we believe this allows
more effective control of operating costs, the timing and plans for future
development, the level of drilling and the marketing of production on the
property. In certain instances, we may choose to hire an operator with technical
proficiency in certain areas, if we believe it to be in the Company's best
interests.

      Use of Advanced Technology. We utilize 3-D seismic and interpretation
techniques to reduce drilling risks. We have used these techniques on all of our
exploratory prospects, including those on the Welder Ranch Property and Bayou
Couba properties. We also employ the latest fracing technique for all of our
wells requiring such treatment.

Regulation

      Our business is or may be affected by numerous laws and regulations,
including those relating to energy, environment, and conservation. Failure to
comply with these laws and regulations may result in the assessment of
administrative, civil and/or criminal penalties, the imposition of injunctive
relief or both. Changes in any of these laws and regulations could have a
material adverse effect on our business. In view of the many uncertainties with
respect to current and future laws and regulations, including their
applicability to us, we cannot predict the overall effect of such laws and
regulations on its future operations.

      We believe that current operations comply in all material respects with
applicable laws and regulations, and that they have no more restrictive effect
than on other similar companies in the energy industry.

      Our operations are subject to regulation at the state level and, in some
cases, county, municipal and local governmental levels. Such regulation includes
(1) requiring permits for the drilling of wells, (2) maintaining bonding
requirements to drill or operate wells, and (3) regulating the location of
wells, the method of drilling and casing wells, surface use and restoration of
properties upon which wells are drilled, and (4) plugging and abandoning of
wells and the disposal of fluids used and produced in connection with
operations.

      Our operations are also subject to various conservation laws and
regulations relating to well spacing, and safety issues for gathering systems.

Environmental Matters

      We are subject to extensive federal, state, and local environmental laws
and regulations that, among other things, regulate the discharge or disposal of
substances into the environment and otherwise are intended to protect the
environment. Numerous governmental agencies issue rules and regulations to
implement and enforce such laws, which are often difficult and costly to comply
with and which carry substantial administrative, civil, and/or criminal
penalties and, in some cases, injunctive relief for failure to comply. Some laws
and regulations relating to the protection of the environment may, in certain
circumstances, impose "strict liability" for environmental contamination. Other
laws and regulations may require the rate of oil and natural gas production to
be below the economically optimal rate or may even restrict or prohibit
exploration or production activities in environmentally sensitive areas. In
addition, state laws often require some form of remedial action such as closure
of inactive pits and plugging of abandoned wells to prevent pollution from
former or suspended operations.


                                       4
<PAGE>

      We believe that we are in substantial compliance with current applicable
laws and regulations and that continued compliance with existing requirements
will not have a material adverse impact. However, from time to time, legislation
or other initiatives are proposed to place more onerous conditions. Adoption of
such proposals could adversely impact our operating costs, capital expenditures,
earnings, and/or competitive position.

Risk Factors

RISKS RELATED TO THE BUSINESS

WE HAVE HAD OPERATING LOSSES AND LIMITED REVENUES TO DATE.

      We have been operating at a loss each year since its inception. Net losses
applicable to common stockholders for the years ended December 31, 2005 and
December 31, 2006 were $1,584,643 and $53,635,691, respectively. Revenues for
the years ended December 31, 2005 and 2006 were $3,724,278 and $7,580,034,
respectively. We may not be able to generate significant revenues in the future.
In addition, we expect to incur substantial operating expenses in connection
with our gas and oil exploration and development activities. As a result, we may
continue to experience negative cash flow for at least the foreseeable future
and cannot predict when, or even if, we might become profitable.

WE HAVE SUBSTANTIAL CAPITAL REQUIREMENTS THAT, IF NOT MET, MAY HINDER
OPERATIONS.

      We have experienced and expect to continue to experience substantial
capital needs as a result of our active exploration, development, and
acquisition programs. We expect that additional external financing will be
required in the future to fund our growth. We may not be able to obtain
additional financing, and financing under existing or new credit facilities may
not be available in the future. Without additional capital resources, we may be
forced to limit or defer our planned natural gas and oil exploration and
development program and this will adversely affect the recoverability and
ultimate value of our natural gas and oil properties, in turn negatively
affecting our business, financial condition, and results of operations.

NATURAL GAS AND OIL PRICES ARE HIGHLY VOLATILE, AND LOWER PRICES WILL NEGATIVELY
AFFECT OUR FINANCIAL RESULTS.

      Our revenue, profitability, cash flow, oil and gas reserves value, future
growth, and ability to borrow funds or obtain additional capital, as well as the
carrying value of our properties, are substantially dependent on prevailing
prices of natural gas and oil. Historically, the markets for natural gas and oil
have been volatile, and those markets are likely to continue to be volatile in
the future. It is impossible to predict future natural gas and oil price
movements with certainty. Prices for natural gas and oil are subject to wide
fluctuations in response to relatively minor changes in the supply of and demand
for natural gas and oil, market uncertainty, and a variety of additional factors
beyond our control. These factors include:

      o     the level of consumer product demand;
      o     overall economic conditions;
      o     weather conditions;
      o     domestic and foreign governmental relations;
      o     the price and availability of alternative fuels;
      o     political conditions;
      o     the level and price of foreign imports of oil and liquefied natural
            gas; and
      o     the ability of the members of the Organization of Petroleum
            Exporting Countries to agree upon and maintain oil price controls.

      Declines in natural gas and oil prices may materially adversely affect our
financial condition, liquidity, and ability to finance planned capital
expenditures and results of operations.


                                       5
<PAGE>

DRILLING FOR NATURAL GAS AND OIL IS A SPECULATIVE ACTIVITY AND INVOLVES NUMEROUS
RISKS AND SUBSTANTIAL AND UNCERTAIN COSTS THAT COULD ADVERSELY AFFECT US.

      Our success will be largely dependent upon the success of our drilling
program. Drilling for natural gas and oil involves numerous risks, including the
risk that no commercially productive natural gas or oil reservoirs will be
discovered. The cost of drilling, completing, and operating wells is substantial
and uncertain, and drilling operations may be curtailed, delayed, or canceled as
a result of a variety of factors beyond our control, including:

      o     unexpected or adverse drilling conditions;
      o     elevated pressure or irregularities in geologic formations;
      o     equipment failures or accidents;
      o     adverse weather conditions;
      o     compliance with governmental requirements; and
      o     shortages or delays in the availability of drilling rigs, crews, and
            equipment.

      Even if drilled, our completed wells may not produce reserves of natural
gas or oil that are economically viable or that meet our earlier estimates of
economically recoverable reserves. Our overall drilling success rate or our
drilling success rate for activity within a particular project area may decline.
Unsuccessful drilling activities could result in a significant decline in our
production and revenues and materially harm our operations and financial
condition by reducing our available cash and resources. Because of the risks and
uncertainties of our business, our future performance in exploration and
drilling may not be comparable to our historical performance.

WE DEPEND ON SUCCESSFUL EXPLORATION, DEVELOPMENT, AND ACQUISITIONS TO MAINTAIN
RESERVES AND REVENUE IN THE FUTURE.

      In general, the volume of production from natural gas and oil properties
declines as reserves are depleted, with the rate of decline depending on
reservoir characteristics. Except to the extent that we conduct successful
exploration and development activities or acquire properties containing proved
reserves, or both, our proved reserves will decline as reserves are produced.
Our future natural gas and oil production is, therefore, highly dependent on our
level of success in finding or acquiring additional reserves. Additionally, the
business of exploring for, developing, or acquiring reserves is capital
intensive. Recovery of our reserves, particularly undeveloped reserves, will
require significant additional capital expenditures and successful drilling
operations. To the extent cash flow from operations is reduced and external
sources of capital become limited or unavailable, our ability to make the
necessary capital investment to maintain or expand our asset base of natural gas
and oil reserves would be impaired. In addition, we are dependent on finding
partners for our exploratory activity. To the extent that others in the industry
do not have the financial resources or choose not to participate in our
exploration activities, we will be adversely affected.

RESERVE ESTIMATES DEPEND ON MANY ASSUMPTIONS THAT MAY TURN OUT TO BE INACCURATE

      Any material inaccuracies in these reserve estimates or underlying
assumptions could materially affect the quantities and present values of our
reserves. The process of estimating natural gas and oil reserves is complex. It
requires interpretations of available technical data and various assumptions,
including assumptions relating to economic factors. Any significant inaccuracies
in these interpretations or assumptions could materially affect the estimated
quantities and present value of reserves shown in this report. In order to
prepare these estimates, we must project production rates and timing of
development expenditures. We must also analyze available geological,
geophysical, production and engineering data, and the extent, quality and
reliability of this data can vary. The process also requires economic
assumptions relating to matters such as oil and natural gas prices, drilling and
operating expenses, capital expenditures, taxes and availability of funds.
Therefore, estimates of oil and natural gas reserves are inherently imprecise.


                                       6
<PAGE>

      Actual future production, oil and natural gas prices, revenues, taxes,
development expenditures, operating expenses and quantities of recoverable oil
and natural gas reserves most likely will vary from our estimates. A significant
variance could materially affect the estimated quantities and pre-tax present
value of reserves shown in this report. In addition, we may adjust estimates of
proved reserves to reflect production history, results of exploration and
development, prevailing oil and natural gas prices and other factors, many of
which are beyond our control.

A SUBSTANTIAL PERCENTAGE OF OUR PROVED RESERVES CONSISTS OF UNDEVELOPED
RESERVES.

      As of the end of our last fiscal year, approximately 53% of our proved
reserves were classified as undeveloped reserves. Accordingly, there can be no
assurances that we will be successful in the recovery of such undeveloped
reserves.

OUR FUTURE ACQUISITIONS MAY YIELD REVENUES OR PRODUCTION THAT VARIES
SIGNIFICANTLY FROM OUR PROJECTIONS.

      In acquiring producing properties, we assess the recoverable reserves,
future natural gas and oil prices, operating costs, potential liabilities and
other factors relating to the properties. Our assessments are necessarily
inexact and their accuracy is inherently uncertain. Our review of a subject
property in connection with its acquisition assessment will not reveal all
existing or potential problems or permit us to become sufficiently familiar with
the property to assess fully its deficiencies and capabilities. We may not
inspect every well, and we may not be able to observe structural and
environmental problems even when we do inspect a well. If problems are
identified, the seller may be unwilling or unable to provide effective
contractual protection against all or part of those problems. Any acquisition of
property interests may not be economically successful, and unsuccessful
acquisitions may have a material adverse effect on our financial condition and
future results of operations. We cannot assure you that:

      o     we will be able to identify desirable gas and oil prospects and
            acquire leasehold or other ownership interests in such prospects at
            a desirable price;
      o     any completed, currently planned, or future acquisitions of
            ownership interests in gas and oil prospects will include prospects
            that contain proven gas or oil reserves;
      o     we will have the ability to develop prospects which contain proven
            gas or oil reserves to the point of production;
      o     we will have the financial ability to consummate additional
            acquisitions of ownership interests in gas and oil prospects or to
            develop the prospects which we acquire to the point of production;
            or
      o     that we will be able to consummate such additional acquisitions on
            terms favorable to us.


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<PAGE>

SEISMIC STUDIES DO NOT GUARANTEE THAT HYDROCARBONS ARE PRESENT OR IF PRESENT
WILL PRODUCE IN ECONOMIC QUANTITIES.

      We rely on seismic studies to assist us with assessing prospective
drilling opportunities on our properties, as well as on properties that we may
acquire. Such seismic studies are merely an interpretive tool and do not
necessarily guarantee that hydrocarbons are present or if present will produce
in economic quantities.

WE MAY EXPERIENCE DIFFICULTY IN ACHIEVING AND MANAGING FUTURE GROWTH.

      Future growth may place strains on our resources and cause us to rely more
on project partners and independent contractors, possibly negatively affecting
our financial condition and results of operations. Our ability to grow will
depend on a number of factors, including:

      o     our ability to obtain leases or options on properties for which we
            have 3-D seismic data;
      o     our ability to acquire additional 3-D seismic data;
      o     our ability to identify and acquire new exploratory prospects;
      o     our ability to develop existing prospects;
      o     our ability to continue to retain and attract skilled personnel;
      o     our ability to maintain or enter into new relationships with project
            partners and independent contractors;
      o     the results of our drilling program;
      o     hydrocarbon prices; and
      o     our access to capital.

      We may not be successful in upgrading our technical, operations, and
administrative resources or in increasing our ability to internally provide
certain of the services currently provided by outside sources, and we may not be
able to maintain or enter into new relationships with project partners and
independent contractors. Our inability to achieve or manage growth may adversely
affect our financial condition and results of operations.

OUR BUSINESS MAY SUFFER IF WE LOSE KEY PERSONNEL.

      We depend to a large extent on the services of certain key management
personnel, including our executive officers and other key employees, the loss of
any of whom could have a material adverse effect on our operations. We have
entered into employment agreements with each of Alan Gaines, our Chairman and
CEO, Amiel David, our President and COO. See "Executive Compensation -
Employment Agreements." We do not maintain key-man life insurance with respect
to any of our employees. Our success will be dependent on our ability to
continue to employ and retain skilled technical personnel.

WE FACE STRONG COMPETITION FROM OTHER NATURAL GAS AND OIL COMPANIES.

      We encounter competition from other natural gas and oil companies in all
areas of our operations, including the acquisition of exploratory prospects and
proven properties. Our competitors include major integrated natural gas and oil
companies and numerous independent natural gas and oil companies, individuals,
and drilling and income programs. Many of our competitors are large,
well-established companies that have been engaged in the natural gas and oil
business much longer than we have and possess substantially larger operating
staffs and greater capital resources than we do. These companies may be able to
pay more for exploratory projects and productive natural gas and oil properties
and may be able to define, evaluate, bid for, and purchase a greater number of
properties and prospects than our financial or human resources permit. In
addition, these companies may be able to expend greater resources on the
existing and changing technologies that we believe are and will be increasingly
important to attaining success in the industry. We may not be able to conduct
its operations, evaluate, and select suitable properties and consummate
transactions successfully in this highly competitive environment.


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<PAGE>

THE UNAVAILABILITY OR HIGH COST OF DRILLING RIGS, EQUIPMENT, SUPPLIES OR
PERSONNEL COULD AFFECT ADVERSELY OUR ABILITY TO EXECUTE ON A TIMELY BASIS OUR
EXPLORATION AND DEVELOPMENT PLANS WITHIN BUDGET, WHICH COULD HAVE A MATERIAL
ADVERSE EFFECT ON OUR FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

      Shortages or the high cost of drilling rigs, equipment, supplies or
personnel could delay or affect adversely our exploration and development
operations, which could have a material adverse effect on our financial
condition and results of operations. Demand for drilling rigs, equipment,
supplies and personnel currently is very high in the areas in which we operate,
particularly in the Barnett Shale. An increase in drilling activity in the areas
in which we operate could further increase the cost and decrease the
availability of necessary drilling rigs, equipment, supplies and personnel.

WE MAY NOT BE ABLE TO KEEP PACE WITH TECHNOLOGICAL DEVELOPMENTS IN OUR INDUSTRY.

      The natural gas and oil industry is characterized by rapid and significant
technological advancements and introductions of new products and services using
new technologies. As others use or develop new technologies, we may be placed at
a competitive disadvantage, and competitive pressures may force us to implement
those new technologies at substantial costs. In addition, other natural gas and
oil companies may have greater financial, technical, and personnel resources
that allow them to enjoy technological advantages and may in the future allow
them to implement new technologies before we can. We may not be able to respond
to these competitive pressures and implement new technologies on a timely basis
or at an acceptable cost. If one or more of the technologies we use now or in
the future were to become obsolete or if we are unable to use the most advanced
commercially available technology, our business, financial condition, and
results of operations could be materially adversely affected.

WE ARE SUBJECT TO VARIOUS GOVERNMENTAL REGULATIONS AND ENVIRONMENTAL RISKS.

      Natural gas and oil operations are subject to various federal, state, and
local government regulations that may change from time to time. Matters subject
to regulation include discharge permits for drilling operations, plug and
abandonment bonds, reports concerning operations, the spacing of wells,
unitization and pooling of properties, and taxation. From time to time,
regulatory agencies have imposed price controls and limitations on production by
restricting the rate of flow of natural gas and oil wells below actual
production capacity in order to conserve supplies of natural gas and oil. Other
federal, state, and local laws and regulations relating primarily to the
protection of human health and the environment apply to the development,
production, handling, storage, transportation, and disposal of natural gas and
oil, by-products thereof, and other substances and materials produced or used in
connection with natural gas and oil operations. In addition, we may be liable
for environmental damages caused by previous owners of property we purchase or
lease. Some environmental laws provide for joint and several strict liability
for remediation of releases of hazardous substances, rendering a person liable
for environmental damage without regard to negligence or fault on the part of
such person. In addition, we may be subject to claims alleging personal injury
or property damage as a result of alleged exposure to hazardous substances such
as oil and gas related products. As a result, we may incur substantial
liabilities to third parities or governmental entities and may be required to
incur substantial remediation costs. We also are subject to changing and
extensive tax laws, the effects of which cannot be predicted. Compliance with
existing, new, or modified laws and regulations could have a material adverse
effect on our business, financial condition, and results of operations.


                                       9
<PAGE>

OUR ABILITY TO PRODUCE SUFFICIENT QUANTITIES OF OIL AND GAS FROM OUR PROPERTIES
MAY BE ADVERSELY AFFECTED BY A NUMBER OF FACTORS OUTSIDE OF OUR CONTROL.

      Our business of exploring for and producing oil and gas involves a
substantial risk of investment loss. Drilling oil and gas wells involves the
risk that the wells may be unproductive or that, although productive, do not
produce oil and/or gas in economic quantities. Other hazards, such as unusual or
unexpected geological formations, pressures, mechanical failures, explosions,
fires, blowouts, release of toxic gases, loss of circulation of drilling fluids,
pipeline ruptures or spills, or other conditions may substantially delay or
prevent completion of any well. This could result in a total loss of our
investment in a particular property. Adverse weather conditions can also hinder
drilling operations. A productive well may become uneconomic if water or other
deleterious substances are encountered, which impair or prevent the production
of oil and/or gas from the well. In addition, production from any well may be
unmarketable if it is impregnated with water or other deleterious substances. As
with any petroleum property, there can be no assurance that oil and gas will be
produced from the properties in which we have interests. In addition, the
marketability of oil and gas which may be acquired or discovered is affected by
numerous factors beyond our control. These factors include the proximity and
capacity of oil and gas pipelines and processing equipment, market fluctuations
of prices, taxes, royalties, land tenure, allowable production and environmental
protection. We cannot predict how, when, or if any or all of these factors will
adversely affect our business. If we are unable to produce oil and/or natural
gas from our properties in commercial quantities, our operations will be
severely affected.

WE MAY NOT HAVE ENOUGH INSURANCE TO COVER ALL OF THE RISKS WE FACE.

      In accordance with customary industry practices, we maintain insurance
coverage against some, but not all, potential losses in order to protect against
the risks we face. We do not carry business interruption insurance. We may elect
not to carry insurance if our management believes that the cost of available
insurance is excessive relative to the risks presented. In addition, we cannot
insure fully against pollution and environmental risks. The occurrence of an
event not fully covered by insurance could have a material adverse effect on our
financial condition and results of operations.

WE CANNOT CONTROL THE ACTIVITIES ON PROPERTIES WE DO NOT OPERATE AND ARE UNABLE
TO ENSURE THEIR PROPER OPERATION AND PROFITABILITY.

      We do not operate all of the properties in which we have an interest. As a
result, we have limited ability to exercise influence over, and control the
risks associated with, operations of these properties. The failure of an
operator of our wells to adequately perform operations, an operator's breach of
the applicable agreements, or an operator's failure to act in ways that are in
our best interests could reduce our production and revenues. The success and
timing of our drilling and development activities on properties operated by
others depends upon a number of factors outside of our control, including the
operator's:

      o     timing and amount of capital expenditures;
      o     expertise and financial resources;
      o     inclusion of other participants in drilling wells; and
      o     use of technology.

OPERATORS OF PROSPECTS IN WHICH WE PARTICIPATE MAY NOT MAINTAIN OR MAY FAIL TO
OBTAIN ADEQUATE INSURANCE.

      Oil and gas operations are subject to particular hazards incident to the
drilling and production of oil and gas, such as blowouts, cratering, explosions,
uncontrollable flows of oil, gas or well fluids, fires and pollution and other
environmental risks. These hazards can cause personal injury and loss of life,
severe damage to and destruction of property and equipment, pollution or
environmental damage and suspension of operation. We do not operate all of the


                                       10
<PAGE>

properties in which we have an interest. In the projects in which we own a
non-operating interest directly or own an equity interest in a limited
partnership which in turn owns a non-operating interest, the operator for the
prospect maintains insurance of various types to cover our operations with
policy limits and retention liability customary in the industry. We believe the
coverage and types of insurance are adequate. The occurrence of a significant
adverse event that is not fully covered by insurance could result in the loss of
our total investment in a particular prospect which could have a material
adverse effect on our financial condition and results of operations.

THE FINANCIAL CONDITION OF OUR OPERATORS COULD NEGATIVELY IMPACT OUR ABILITY TO
COLLECT REVENUES FROM OPERATIONS.

      We do not operate all of the properties in which we have working
interests. In the event that an operator of our properties experiences financial
difficulties, this may negatively impact our ability to receive payments for our
share of net production that we are entitled to under our contractual
arrangements with such operator. While we seek to minimize such risk by
structuring our contractual arrangements to provide for production payments to
be made directly to us by first purchasers of the hydrocarbons, there can be no
assurances that we can do so in all situations covering our non-operated
properties.

THE MARKETABILITY OF OUR NATURAL GAS PRODUCTION DEPENDS ON FACILITIES THAT WE
TYPICALLY DO NOT OWN OR CONTROL, WHICH COULD RESULT IN A CURTAILMENT OF
PRODUCTION AND REVENUES.

      The marketability of our production depends in part upon the availability,
proximity, and capacity of natural gas gathering systems, pipelines, and
processing facilities. We generally deliver natural gas through gas gathering
systems and gas pipelines that we do not own under interruptible or short-term
transportation agreements. Under the interruptible transportation agreements,
the transportation of our gas may be interrupted due to capacity constraints on
the applicable system, for maintenance or repair of the system, or for other
reasons as dictated by the particular agreements. Our ability to produce and
market natural gas on a commercial basis could be harmed by any significant
change in the cost or availability of such markets, systems, or pipelines.

WE HEDGE THE PRICE RISKS ASSOCIATED WITH OUR PRODUCTION. OUR HEDGE TRANSACTIONS
MAY RESULT IN OUR MAKING CASH PAYMENTS OR PREVENT US FROM BENEFITING TO THE
FULLEST EXTENT POSSIBLE FROM INCREASES IN PRICES FOR NATURAL GAS AND OIL.

      Because natural gas and oil prices are unstable, we have entered into
price-risk-management transactions such as swaps, collars, futures, and options
to reduce our exposure to price declines associated with a portion of our
natural gas and oil production and thereby to achieve a more predictable cash
flow. The use of these arrangements will limit our ability to benefit from
increases in the prices of natural gas and oil. Our hedging arrangements may
apply to only a portion of our production, thereby providing only partial
protection against declines in natural gas and oil prices. These arrangements
could expose us to the risk of financial loss in certain circumstances,
including instances in which production is less than expected, our customers
fail to purchase contracted quantities of natural gas and oil, or a sudden,
unexpected event materially impacts natural gas or oil prices.


                                       11
<PAGE>

RISKS RELATED TO THE COMMON STOCK

YOU MAY EXPERIENCE DILUTION OF YOUR OWNERSHIP INTERESTS DUE TO THE FUTURE
ISSUANCE OF ADDITIONAL SHARES OF OUR COMMON STOCK.

      We may in the future issue our previously authorized and unissued
securities which will result in the dilution of the ownership interests of our
present stockholders. We are currently authorized to issue 100,000,000 shares of
Common Stock and 1,000,000 shares of preferred stock with such designations,
preferences and rights as determined by our board of directors. As of the date
hereof, we have outstanding 60,810,813 shares of Common Stock and have
outstanding options and warrants to purchase an additional 4,454,324 shares of
Common Stock. Some of these securities contain provisions that will result in
the issuance of additional shares in the event we sell additional shares of
Common Stock at prices less than the applicable conversion price. Issuance of
these shares of Common Stock may substantially dilute the ownership interests of
our existing stockholders. The potential issuance of such additional shares of
Common Stock may create downward pressure on the trading price of our Common
Stock that in turn will require us to issue additional shares to raise funds
through sales of our securities. We may also issue additional shares of our
capital stock in connection with the hiring of personnel, future acquisitions,
future private placements of our securities for capital raising purposes, or for
other business purposes. This will further dilute the interests of our existing
holders.

WE DO NOT INTEND TO PAY DIVIDENDS IN THE FORESEEABLE FUTURE.

      We have never declared or paid a dividend on our Common Stock. We intend
to retain earnings, if any, for use in our operations and the expansion of our
business and therefore do not anticipate paying any dividends in the foreseeable
future.

A SIGNIFICANT MARKET FOR OUR COMMON STOCK MAY NOT DEVELOP.

      Our Common Stock began trading on the American Stock Exchange on May 9,
2005. The average daily volume for the Common Stock over the past three months
is approximately 93,000 shares. We are not certain that an active trading market
in our Common Stock will develop, or if such a market develops, that it will be
sustained.

THE TRADING PRICE OF OUR COMMON STOCK MAY BE VOLATILE.

      The trading price of our shares has from time to time fluctuated widely
and in the future may be subject to similar fluctuations. The trading price may
be affected by a number of factors, including the risk factors set forth herein,
as well as our operating results, financial condition, announcements or drilling
activities, general conditions in the oil and gas exploration and development
industry, and other events or factors. In addition, we filed a registration
statement to permit the public resale of the shares sold in our private
placement completed as of February 1, 2006 and certain other of our outstanding
securities. The influx of such a substantial number of shares into the public
market could have significant negative effect on the trading price of our Common
Stock. In recent years, broad stock market indices, in general, and smaller
capitalization companies, in particular, have experienced substantial price
fluctuations. In a volatile market, we may experience wide fluctuations in the
market price of our Common Stock. These fluctuations may have an extremely
negative effect on the market price of our Common Stock.


                                       12
<PAGE>

Item 2. Description of Property.

      Our headquarters are located at 3050 Post Oak Blvd., Suite 695, Houston,
Texas. We presently lease 5,373 square feet at such location at an annual rent
of $104,540. Our office lease expires June 1, 2009. Our telephone number is
(713) 888-0895.

Barnett Shale Properties:

      Since 2005 we have acquired the majority of our 2,258 gross acres in the
Barnett Shale through several transactions with Voyager Partners, Ltd.
("Voyager"). The vast majority of these properties are located in Denton County,
with the remainder in Wise County, both on the fairway of the prolific Barnett
Shale in the North Texas Fort Worth Basin. We expect all our Barnett acreage to
provide significant initial production rates and high impact, low risk
extensional drilling opportunities.

      In addition to the current 25 wells that we own an interest in, based on
current well spacing rules, we estimate that there are approximately 21
additional drilling locations on our remaining acreage. In addition, lower
spacing requirements will vastly increase the number of proved locations.

      During 2006 we closed additional transactions with Voyager, acquiring
approximately 1,177 acres for a purchase price of $14,548,371. These purchases
included 3 wells that had already been drilled and completed and 3 wells
subsequently fraced by us. All 6 wells have since been placed on production.

      In April 2006, we signed a long term contract with Itera Rig, LLC for a
rig dedicated exclusively for our use. From time to time, we also contracted for
other rigs on a short-term basis.

      Thus far in 2007, we have fracture stimulated 3 wells and turned them to
sales at an aggregate initial rate of production of approximately 2.9 MMcf per
day. We have drilled 3 additional wells in 2007 and, together with a well
drilled in December 2006, now have 4 wells scheduled to be fracture stimulated
during April which will be turned to sales shortly thereafter. We are currently
drilling the Forest T # 1 well and anticipate reaching total depth within 4
weeks, followed by fracture stimulation on this well during May. We plan to
continue to drill 1 well a month under our long term rig contract with Itera
Rig.

      The table below lists our activity in the Barnett Shale from 2005 through
March 31, 2007:

  Number of Barnett Shale wells drilled by Dune as Operator                   13
  Number of Barnett Shale wells fracture stimulated by Dune as Operator       11
  Number of Barnett Shale wells turned to sales by Dune as Operator           12
  Number of Barnett Shale dry holes drilled by Dune as Operator                0
  Number of Barnett Shale wells abandoned due to mechanical problems           1
  Number of Barnett Shale wells currently awaiting fracture stimulation        4
  Number of Barnett Shale wells currently drilling                             1

      On March 5, 2007, we announced management's decision not to purchase 1,600
acres from Voyager for cash consideration of approximately $25.8 million, as
previously contemplated. Management decided to forego such acquisition when it
became apparent that the financing for such transaction would be too dilutive
and not in the best interests of the Company's stockholders. In connection with
the termination of the transaction, we released and discharged outstanding
obligations due from Voyager totaling $1.35 million, stemming from joint
interest expenses covering oil and gas leases and retained interests. In
exchange for such release of Voyager's obligations, Voyager conveyed to us, its
undivided 5% working interest in those Barnett Shale properties that we owned
95% in immediately prior to the conveyance, thereby increasing our ownership to
100% in the properties we have acquired from Voyager.


                                       13
<PAGE>

Bayou Couba Property:

      On October 19, 2005, we entered into a definitive Exploration and
Development Agreement (the "ANEC Agreement") with American Natural Energy
Corporation ("ANEC"). Pursuant to the ANEC Agreement, which had an effective
date of August 26, 2005, we acquired certain exclusive exploration and
development rights in ANEC's Joint Development Agreement with a major integrated
energy company (the "Development Agreement"), covering approximately 11,100
contiguous acres in St. Charles Parish, Louisiana (the "Bayou Couba Field"). Of
the 11,100 acres covered by an area of mutual interest by the Development
Agreement, approximately 1,300 acres pertain to a lease held by ANEC, referred
to as the Delta Securities Lease ("DSCI Lease"). The ANEC Agreement provides us
with the right to participate in 50% of ANEC's development rights in the Delta
Securities Lease in exchange for our prior payment of $1 million. In addition,
we have the right to participate in all of ANEC's exploration rights in the
remaining AMI under the Development Agreement. Each party will pay its
respective share of drilling, completion and operations costs. The term of the
Development Agreement has been extended from November 2007 to November 2009.

      The Bayou Couba Field was discovered by Gulf Oil in 1942. The field is
situated on a crest of a highly faulted salt dome which is productive from 30
sands. The nature of the faultline system creates traps that in the past were
overlooked or created a potential for bypassed oil and gas production. In
addition, preliminary analysis of reprocessed, state of the art 3-D seismic
indicates numerous hydrocarbon traps at depths ranging between 4,000 and 20,000
feet. There are several leads that indicate significant potential reserves in
the subsalt area. Initial drilling has focused and will continue to focus on
numerous (i) development prospects with updip PUD potential, (ii) extensional
prospects with trapped bypassed hydrocarbons and (iii) near field exploratory
prospects with analog production.

      On December 26, 2006, we purchased from TransAtlantic Petroleum Corp.
("TNP"), TNP's 10% working interest and related interest in the Bayou Couba
project, St. Charles Parish, Louisiana held by its subsidiary, TransAtlantic
Petroleum (USA) Corp., and certain 8% Convertible Secured Debentures issued by
American Natural Energy Corp. ("ANEC") in the principal face amount of $3.0
million held by TNP (the "Debentures"). The Debentures, which are secured by
substantially all of ANEC's assets, matured on September 30, 2006 and are now in
default. Total consideration for the purchase was $2 million, which we obtained
from our senior lender. The purchase included TNP's working interest in 17 wells
and 10% direct working interest in the DSCI Lease. In February 2007, we acquired
additional Debentures in the aggregate principal amount of $4,895,000, in
exchange for 1,380,641 shares of our Common Stock.

      Since signing the ANEC Agreement in 2005, we have successfully
participated in the drilling and completion of 6 wells at Bayou Couba and, as a
result of our transaction with TNP, we now hold working interests in 21 wells.

      On March 8, 2006, ANEC entered into a Seismic Survey Participation
Agreement (the "Participation Agreement") with Seismic Exchange, Inc. ("SEI"),
to acquire a license with respect to the geophysical data covering 60 square
miles of the 3-D Seismic Survey to be conducted pursuant to the Participation
Agreement (the "Licensed Data"). The area to be surveyed by this shoot covers
the 11,100 acre AMI we have exploration and development rights in under our ANEC
Agreement, as well as additional acres surrounding it. We paid a total of $2
million to SEI for the seismic license. Pursuant to our agreements with SEI,
Dune has a one-year exclusive license with respect to the Licensed Data.

      Subject to rig availability, and to further reprocessing the 3-D seismic
which was delivered to us by SEI in February 2007, we anticipate that over the
next 12 months, we will drill several exploration and development wells with the
remainder to be held in inventory. Additionally, we believe that there is
significant untested sub-salt gas potential and, pending the processing of the
3-D survey, we would anticipate drilling an exploratory well beneath the salt
dome by 2008. We are currently developing plans to drill the next well on our
Bayou Couba Property and anticipate spudding such well in the second half of
2007.


                                       14
<PAGE>

South Texas Properties:
The Welder Ranch Property:

      The Welder Ranch Property consists of 7,950 contiguous acres of land in
Victoria County, Texas. The Welder Leases are held by Vaquero Partners, LLC, our
wholly-owned subsidiary ("Vaquero Partners"), and are operated by Dune Operating
Company, which is also our wholly-owned subsidiary. Per the terms of the Welder
Leases, Vaquero Partners receives 70% of net revenue generated on the Welder
Ranch Property.

      To date, our primary focus on the Welder Ranch Property has been on the
Wilcox Formation. The Wilcox Formation is one of the most prolific formations
along the Texas Gulf Coast. Our primary targets regarding exploration activity
in the area are the geopressured lower and middle sands of the Wilcox formation.
The Wilcox is productive at depths ranging from 8,300 feet to below 17,000 feet.
The upper Wilcox sands have four producing intervals that are normally
pressured. The middle and lower sands, beginning at approximately 9,500 feet,
are geopressured. These geopressured zones are the primary targets on the Welder
Ranch Property.

      In the first quarter of 2006 we drilled one successful shallow well and
one shallow dry hole on our Welder Ranch leases. After a brief production
period, our producer turned out to be uneconomical and the well was abandoned.

      In July 2006, we entered into a farm out agreement with Chesapeake Energy
Corporation ("Chesapeake") covering our Welder Ranch property. The agreement did
not cover existing producing wells. Pursuant to the agreement, Chesapeake paid
$1.8 million to Vaquero Partners in exchange for 75% of Vaquero Partner's
interest in its two Welder Ranch leases. In addition, Chesapeake committed and
drilled two wells by November 1, 2006, targeting the geo-pressured Middle Wilcox
formation. We were carried to casing point, and subsequently paid for its
proportional share of completion costs. Both wells are currently producing at a
combined rate of 500 Mcf/d and 15 bbls/d. In February 2007, Chesapeake informed
us that it would not seek to drill additional wells under the term of the farm
out agreement and thus relinquished its rights in the Welder Ranch Property back
to the Company. We are currently evaluating the drilling opportunities available
on the Welder Ranch and anticipate, subject to rig availability and availability
of sufficient capital, spudding a well to test below 12,000 feet by October 1,
2007. Doing so will earn us an additional six months in the primary term of the
leases.

The Pearsall Property

      Our Pearsall Property presently consists of leases covering approximately
516 gross acres in the Pearsall Field, located in the Austin Chalk trend in Frio
County, Texas. San Antonio based Alamo Operating Company is currently the
contract operator. We have a 40% working interest and a 30% net revenue interest
in the Voss lease. The Voss C # 1, continues to produce at a current steady rate
of 65 bbls/d. We recently elected to participate in a salt water disposal well
in order to more economically dispose of the water production.

The Los Mogotes Property

      In May of 2004, we completed the purchase of a small non-operated working
interest (0.7% W.I.) in the Haynes Lease (covering approximately 18,000 acres)
located within Los Mogotes Field in Zapata County for $874,500. The Los Mogotes
Field is an onshore U.S. development project in the South Texas Wilcox trend,
with production averaging approximately 90 MMcfe of gas per day. We continue to
participate for our share of drilling additional wells on the Los Mogotes
Property of approximately 1 well a month.


                                       15
<PAGE>

Oil & Gas Properties:

      The following table summarizes our gross and net developed and undeveloped
oil and natural gas acreage under lease as of March 31, 2007.

                                                      Gross          Net
                                                    ----------------------
      Developed acres
              Barnett Shale                              847           840
              Bayou Couba(1)                             840           191
              Welder Ranch                             1,920         1,212
              Pearsall                                   516           206
              Los Mogotes                             16,944           119
                                                    ----------------------

                                                      21,067         2,568
                                                    ======================

      Undeveloped acres
              Barnett Shale                            1,411         1,411
              Bayou Couba(1)                           2,977         2,617
              Welder Ranch                             5,878         5,878
              Pearsall                                 1,051           421
              Los Mogotes                                892             6
                                                    ----------------------
                                                      12,209        10,333
                                                    ======================

                                                    ----------------------
      Total Acreage                                   33,276        12,901
                                                    ======================

1) Bayou Couba does not include acreage available through our Exploration and
Development Agreement with ANEC to participate in the AMI under the Development
Agreement covering approximately 11,100 acres.

      A developed acre is considered to be an acre spaced or assignable to
productive wells. A gross acre is an acre in which a working interest is owned.
A net acre is the result that is obtained when our fractional ownership working
interest is multiplied by gross acres. The number of net acres is the sum of the
fractional working interests owned in gross acres expressed as whole numbers and
fractions thereof.

      Undeveloped acreage is considered to be those lease acres on which wells
have not been drilled or completed to a point that would permit the production
of commercial quantities of oil or natural gas, regardless of whether that
acreage contains proved reserves, but does not include undrilled acreage held by
production under the terms of a lease. As is customary in the oil and gas
industry, we can generally retain our interest in undeveloped acreage by
drilling activity that establishes commercial production sufficient to maintain
the leases or by paying delay rentals during the remaining primary term of
leases.

      The oil and gas leases in which we have an interest are for varying
primary terms, and if production under a lease continues from our developed
lease acreage beyond the primary term, we are entitled to hold the lease for as
long as oil or natural gas is produced.


                                       16
<PAGE>

      We do not have any obligations under existing contracts or agreements
calling for the provision of fixed and determinable quantities of oil and gas
over the next three years, and have therefore not filed any information or
reports with any federal authority or agency containing estimates of total
proved developed or undeveloped net oil or gas reserves. Our oil and gas
properties consist primarily of oil and gas wells and our interests in leasehold
acreage, both developed and undeveloped.

Oil & Gas Reserves:

      Our estimates of oil and gas reserves are derived from reports prepared by
DeGolyer and MacNaughton, petroleum consultants.

      Proved reserves are the estimated quantities that geologic engineering
data demonstrate with reasonable certainty to be recoverable in future years
from known reservoirs under existing economic and operating conditions. Due to
the inherent uncertainties and the limited nature of reservoir data, such
estimates are subject to change as additional information becomes available. The
estimates of reserves, future cash flows and present value are based on various
assumptions, including those prescribed by the SEC, and are inherently
imprecise. Although we believe these estimates are reasonable, actual future
production, cash flows, taxes, development expenditures, operating expenses and
quantities of recoverable oil and natural gas reserves may vary substantially
from these estimates. Also, the use of a 10% discount factor for reporting
purposes may not necessarily represent the most appropriate discount factor,
given actual interest rates and risks to which our business or the oil and
natural gas industry in general are subject.

      Based on reserve report prepared by DeGolyer and MacNaughton dated
December 31, 2006, we had estimated total proved reserves of 29,407 MMcfe of
which 13,800 MMcfe were proved developed reserves. We have not reported our
reserves to any federal authority or agency.

      The following table sets forth certain information as of December 31, 2006
with respect to our estimated proved oil and gas reserves pursuant to SEC
guidelines, and the present value of our proved oil and gas reserves.

<TABLE>
<CAPTION>
                                                     Proved Reserves
                                                                           Present Value of
                                                            Undiscounted   Proved Reserves
                                                             Future Net     Discounted at
                                     Oil         Gas          Revenue           10%
                                    Mbbls        MMcf           (M$)            (M$)
                                  --------------------------------------------------------
      <S>                              <C>        <C>           <C>             <C>
      Developed Producing              179         9,203        35,939          22,957
      Developed Nonproducing             5         3,493        10,428           6,992
      Proved Undeveloped               256        14,068        25,405           5,269
                                  --------------------------------------------------------
      Total Proved                     440        26,764        71,772          35,218
</TABLE>


                                       17
<PAGE>

      The following table summarizes our estimated proved oil and gas reserves
by area as of December 31, 2006.

<TABLE>
<CAPTION>
                                                                          Present Value of
                                                                           Proved Reserves     Percent of
                                             Total Gas      Percent of      Discounted at       Present
                     Oil          Gas        Equivalent       Proved             10%        Value of Proved
                    Mbbls         MMcf         MMcfe         Reserves         ($000's)          Reserves
                  -----------------------------------------------------------------------------------------
<S>                  <C>        <C>           <C>               <C>           <C>                 <C>
Bayou Couba          205.5         973.6        2206.6            7.5%         7,780.5             22.1%
Los Mogotes            0.5         689.2         692.2            2.4%         1,190.1              3.4%
Barnett               81.1      24,187.9      24,674.5           83.9%        22,978.7             65.2%
Pearsal              133.4          60.2         860.6            2.9%         2,218.4              6.3%
Welder Ranch          19.9         853.2         972.6            3.3%         1,049.9              3.0%
                  -----------------------------------------------------------------------------------------
                     440.4      26,764.1      29,406.5          100.0%        35,217.6            100.0%
</TABLE>

      These calculations were prepared using standard geological and engineering
methods generally accepted by the petroleum industry and in accordance with SEC
financial accounting and reporting standards. The estimated present value of
proved reserve does not give effect to indirect expenses such as general and
administrative expenses, debt service and future income tax expense or to
depletion, depreciation, and amortization.

      In accordance with applicable financial accounting and reporting standards
of the SEC, the estimates of our proved reserves and the present value of proved
reserves set forth herein are made using oil and gas sales prices estimated to
be in effect as of the date of such reserve estimates and are held constant
throughout the life of the properties. Estimated quantities of proved reserves
and their present value are affected by changes in oil and gas prices. The
average prices utilized for the purpose of estimating our proved reserves and
the present value of proved reserves as of December 31, 2006 were $61.05 per bbl
of oil and natural gas liquids and $5.635 per Mcf of gas.

Productive Wells and Acreage

      As of March 31, 2007, we had 177 productive wells. 13 of these wells are
categorized as oil wells and the remaining 164 wells are categorized as gas. We
had total gross acreage of 33,276 acres, consisting of 21,067 developed acres
and 12,209 undeveloped acres. We had total net acres of 12,901 acres, consisting
of 2,568 developed acres and 10,333 undeveloped acres.


                                       18
<PAGE>

Production Volumes, Revenue, Prices and Production Costs

      The following table sets forth certain information regarding the
production volumes, revenue, average prices received and average production
costs associated with our sale of oil and natural gas for the three years ended
December 31, 2006.

                             Year Ended December 31,

<TABLE>
<CAPTION>
                                                                   2006                 2005                2004
<S>                                                         <C>                  <C>                 <C>
Net Production
          Oil                     (bbl)                          34,767               12,352                   0
          Natural Gas             (Mcf)                         880,373              364,236             162,690
          Gas Equivalent          (Mcfe)                      1,088,975              438,348             162,690
Oil and Gas Sales
          Oil                                               $ 2,077,920          $   716,555         $        --
          Natural Gas                                       $ 5,273,514          $ 2,875,723         $   894,797
                                                            ----------------------------------------------------
          Total                                             $ 7,351,434          $ 3,592,278         $   894,797
Average Sales Price
          Oil                     ($ per bbl)                    $59.77               $58.01               $0.00
          Natural Gas             ($ per Mcf)                     $5.99                $7.90               $5.50
          Gas Equivalent          ($ per Mcfe)                    $6.75                $8.20               $5.50
Oil and Natural Gas costs:
          Lease operating expenses                          $ 1,234,686          $   378,163         $    37,478
          Production taxes                                  $   775,922          $   341,309         $    65,196
Average production cost per Mcfe                                  $1.85                $1.64               $0.63
</TABLE>

Drilling Activity

      The following table sets forth our drilling activity during the twelve
month period ended December 31, 2006 and 2005 and 2004 (excluding wells in
progress at the end of the period).

      Drilling Activity

<TABLE>
<CAPTION>
                                                               Year Ended December 31,
                                              2006                       2005                       2004
                                       Gross         Net          Gross         Net          Gross         Net
<S>                                     <C>         <C>             <C>         <C>           <C>          <C>
      Development
           Productive                   32.0        11.7            8.0         1.2           28.0         0.2
           Non-productive                1.0         0.9            0.0         0.0            0.0         0.0
      Exploratory
           Productive                    2.0         0.5            4.0         2.0            1.0         1.0
           Non-productive                1.0         1.0            0.0         0.0            2.0         1.6
</TABLE>

      The information contained in the foregoing table should not be considered
indicative of future drilling performance, nor should it be assumed that there
is any necessary correlation between the number of productive wells drilled and
the amount of oil and gas that may ultimately be recovered by us.

      We do not own any drilling rigs, and all of our drilling activities are
conducted by independent drilling contractors.


                                       19
<PAGE>

Present Activities

      A description of our present activities is contained within Item 1,
Property Descriptions

Delivery Commitments

      At December 31, 2006, we had no delivery commitments with our purchasers.

Item 3. Legal Proceedings.

      On or about February 12, 2007, the Company was named as a defendant in a
lawsuit numbered Cause No. 2007-08076 and styled Lane Vaughn v. Dune Energy,
Inc., and Glenn Andrews, pending in the 190th Judicial District Court of Harris
County, Texas. The plaintiff, Lane Vaughn, claims that Glenn Andrews, whom the
plaintiff alleges was formerly an employee of the Company, hired the plaintiff
to provide legal services to the Company for which the Company allegedly failed
to pay. The plaintiff seeks $150,000 in actual damages, $200,000 in exemplary
damages based on a claim that the Company's alleged failure to pay was
fraudulent in nature, and $30,000 in attorneys' fees. The Company filed its
Original Answer on March 16, 2007, in which the Company denied all liability and
that Mr. Andrews was ever an employee of the Company.

Item 4. Submission of Matters to a Vote of Security Holders.

      On May 30, 2006, we held our annual meeting of stockholders. The three
proposals submitted for shareholder involved (i) election of the seven current
members of our Board of Directors, (ii) approval and adoption of our 2005
Non-Employee Director Incentive Plan (the "Plan") and (iii) ratification of the
appointment of Malone & Bailey PC as our independent auditors for the year ended
December 31, 2006.

      With respect to the election of Directors, there was no opposition to the
slate proposed by the Company at the annual meeting, and all seven of Company's
incumbent Directors who were nominated to serve as Director received a plurality
of votes cast at the meeting and were reelected as members of our Board of
Directors. The seven persons re-elected were Alan Gaines, Valery Otchertsov,
Raissa Frenkel, Steven Sisselman, Richard Cohen, Steven Barrenechea and Marshall
Lynn Bass. On February 1, 2007, Mr. Otchertsov resigned from the Board and Mr.
Igor Marchenko was appointed to fill the vacancy.

      With respect to the approval of our 2005 Non-Employee Director Incentive
Plan, 43,440,746 votes were cast FOR the Plan, 246,889 votes were cast against
the Plan and 10,905 votes abstained. Accordingly, our stockholders approved the
Plan.

      With respect to the ratification of our independent auditors, 43,671,430
votes were cast FOR ratification, 18,910 votes were cast against retention and
8,200 votes abstained. Accordingly, our stockholders approved the appointment of
Malone & Bailey PC as our independent auditors.


                                       20
<PAGE>

                                     PART II

Item 5. Market for Common Equity, Related Stockholder Matters and Small Business
        Issuer Purchases of Equity Securities.

      On May 9, 2005, our Common Stock began trading on the American Stock
Exchange under the symbol "DNE". Prior to May 9, 2005, our Common Stock was
traded on the OTC Bulletin Board under the symbol "DENG." Our Common Stock
became eligible for quotation on the OTC Bulletin Board on May 11, 2004. The
following table sets forth, for periods prior to May 9, 2005, the high and low
bid prices per share of the Common Stock for each of the calendar quarters
identified below as reported by the OTC Bulletin Board. These quotations
represent inter-dealer prices, without retail mark-up, markdown or commission,
and may not represent actual transactions. The following table also sets forth,
for the period from May 9, 2005 to December 31, 2006, the high and low sale
prices of the Common Stock on the American Stock Exchange.

         2006:                                                    High      Low
         -----                                                    ----      ---

Quarter ended December 31, 2006................................  $3.06     $1.46
Quarter ended September 30, 2006...............................  $3.03     $1.30
Quarter ended June 30, 2006 ...................................  $4.08     $2.84
Quarter ended March 31, 2006...................................  $4.48     $2.75

         2005:                                                    High      Low
         -----                                                    ----      ---

Quarter ended December 31, 2005................................  $3.00     $1.81
Quarter ended September 30, 2005...............................  $2.80     $2.81
Quarter ended June 30, 2005 (May 9, 2005 through June 30, 2005)  $2.92     $1.85
Quarter ended June 30, 2005 (through May 8, 2005) .............  $3.05     $2.00
Quarter ended March 31, 2005...................................  $3.00     $0.73

      The last sales price of our Common Stock as reported on the American Stock
Exchange on December 29, 2006 was $2.33 per share.

      As of March 15, 2007, there were approximately 275 holders of record of
our Common Stock.

      We have not paid any cash dividends to date, and have no intention of
paying any cash dividends on the Common Stock in the foreseeable future. The
declaration and payment of dividends is subject to the discretion of our Board
of Directors and to certain limitations imposed under Delaware corporation law.
The timing, amount and form of dividends, if any, will depend on, among other
things, our results of operations, financial condition, cash requirements and
other factors deemed relevant by our Board of Directors. The agreements and
instruments that we entered into in 2006 in connection with our debt financings
contain significant restrictions on our ability to pay dividends on our Common
Stock.

      As of March 15, 2007, approximately 4,454,324 shares of our Common Stock
were subject to issuance upon exercise or conversion of outstanding options or
warrants to purchase shares of Common Stock.


                                       21
<PAGE>

      The following table provides information as of December 31, 2006 about our
equity compensation plans and arrangements as of December 31, 2006.

            Equity Compensation Plan Information - December 31, 2006

<TABLE>
<CAPTION>
                                                                                                       (c)
                                                                                               Number of securities
                                                                                             remaining available for
                                               (a)                         (b)                future issuance under
                                     Number of securities to        Weighted-average           equity compensation
                                     be issued upon exercise        exercise price of            plans (excluding
                                     of outstanding options,      outstanding options,       securities reflected in
        Plan Category                  warrants and rights         warrants and rights             column (a))
-----------------------------        -----------------------      --------------------       -----------------------
<S>                                           <C>                        <C>                      <C>
  Equity compensation plans
 approved by security holders                   300,000 (1)              $ 2.35                   1,700,000 (2)
-----------------------------        -----------------------      --------------------       -----------------------
Equity compensation plans not
 approved by security holders                 3,179,324 (3)              $ 2.00                        N/A
-----------------------------        -----------------------      --------------------       -----------------------
            Total                             3,479,324                  $ 2.03                   1,700,000 (2)
=============================        =======================      ====================       =======================
</TABLE>

----------
      (1) Consists of options issued August 28, 2005 to our directors pursuant
to our 2005 Non-Employee Director Incentive Plan (the "2005 Incentive Plan") to
purchase up to 300,000 shares of our Common Stock at $2.35 per share.

      (2) Calculated based on the number of shares authorized upon the adoption
of the 2005 Incentive Plan on May 30, 2006 and not awarded as of December 31,
2006. However, the following shares may return to the 2005 Incentive Plan and be
available for issuance in connection with a future award: (i) shares covered by
an award that expires or otherwise terminates without having been exercised in
full; (ii) shares that are forfeited or repurchased by us prior to becoming
fully vested; (iii) shares covered by an award that is settled in cash; (iv)
shares withheld to cover payment of an exercise price or cover applicable tax
withholding obligations; (v) shares tendered to cover payment of an exercise
price; and (vi) shares that are cancelled pursuant to an exchange or repricing
program.

      (3) Consists of warrants and options granted to our employees, officers,
directors and consultants, to the extent vested and exercisable (within the
meaning of Rule 13d-3(d)(1) promulgated by the Commission under the Securities
and Exchange Act of 1934, as amended) as of December 31, 2006.

      Set forth below is a description of the individual compensation
arrangements or equity compensation plans that were not required to be approved
by our security holders pursuant to which the 3,179,324 shares of our Common
Stock included in the chart above were issuable as of December 31, 2006:

      o Option granted November 1, 2003 to consultant in consideration of
services performed on our behalf, which option expires October 31, 2008 and is
currently exercisable to purchase up to 200,000 shares of our Common Stock at an
exercise price of $0.54 per share;

      o Option granted December 4, 2004 to a former director in consideration of
services performed on our behalf, which option expires December 3, 2009 and is
currently exercisable to purchase up to 50,000 shares of our Common Stock at an
exercise price of $0.90 per share;

      o Option granted December 15, 2004 to director in consideration of
services performed on our behalf, which option expires December 14, 2009 and is
currently exercisable to purchase up to 25,000 shares of our Common Stock at an
exercise price of $0.85 per share;


                                       22
<PAGE>

      o Option granted December 15, 2005 to officer and director in
consideration of services performed on our behalf, which option expires December
14, 2010 and is currently exercisable to purchase up to 250,000 shares of our
Common Stock at an exercise price of $1.25 per share;

      o Option granted April 4, 2005 to officer in consideration of services
performed on our behalf, which option expires April 3, 2010 and is currently
exercisable to purchase up to 50,000 shares of our Common Stock at an exercise
price of $2.56 per share;

      o Options granted May 12, 2005 to officers and directors in consideration
of services performed on our behalf, which options expire May 11, 2010 and are
currently exercisable to purchase up to an aggregate of 750,000 shares of our
Common Stock at an exercise price of $2.44 per share;

      o Option granted July 18, 2005 to employee in consideration of services
performed on our behalf, which option expires July 17, 2010 and is currently
exercisable to purchase up to 15,000 shares of our Common Stock at an exercise
price of $2.30 per share;

      o Option granted August 3, 2005 to employee in consideration of services
performed on our behalf, which option expires August 2, 2010 and is currently
exercisable to purchase up to 30,000 shares of our Common Stock at an exercise
price of $2.54 per share;

      o Warrant issued September 30, 2005 to consultant in consideration of
services performed on our behalf, which warrant expires September 29, 2010 and
is currently exercisable to purchase up to 324,324 shares of our Common Stock at
an warrant exercise price of $1.85 per share;

      o Warrant issued February 1, 2006 to consultant in consideration of
services performed on our behalf, which warrant expires January 31, 2011 and is
currently exercisable to purchase up to 900,000 shares of our Common Stock at an
warrant exercise price of $2.65 per share;

      o Option granted April 4, 2006 to officer and director in consideration of
services performed on our behalf, which option expires April 3, 2011 and is
currently exercisable to purchase up to 25,000 shares of our Common Stock at an
exercise price of $2.35 per share;

      o Options granted August 28, 2006 to employees in consideration of
services performed on our behalf, which options expire April 27, 2011 and are
currently exercisable to purchase up to an aggregate of 60,000 shares of our
Common Stock at an exercise price of $1.50 per share; and

      o Warrant issued September 26, 2006 to consultant in consideration of
services performed on our behalf, which warrant expires September 25, 2011 and
is currently exercisable to purchase up to 500,000 shares of our Common Stock at
a warrant exercise price of $1.35 per share.


                                       23
<PAGE>

Item 6. Management's Discussion and Analysis or Plan of Operations.

Introduction

      We are engaged in the exploration, development, exploitation and
production of oil and natural gas. We sell our oil and gas primarily to domestic
pipelines and refineries. We entered into a number of property acquisitions and
joint ventures during 2005 and 2006 as described in Note 2 to our consolidated
financial statements filed with this report. These acquisitions and joint
ventures significantly affected our results of operations during 2005 and 2006
and had the effect of significantly increasing both our revenues and expenses.
Our financial statements consolidate our accounts with those of our wholly-owned
subsidiary, Vaquero Partners LLC ("Vaquero Partners"), and all inter-company
balances and transactions between Dune Energy, Inc. and Vaquero Partners have
been eliminated in such consolidation.

Results of Operations

      Year ended December 31, 2006 compared to year ended December 31, 2005

Revenues:

Our revenues increased $3,855,756 or 104% from 2005 to 2006 based on increased
oil sales of 22,415 bbls and 516,137 Mcfs. Although gas prices decreased
$1.91/mcf during the comparable years, increased oil prices of $1.76/bbl and
increased volumes more than offset the drop in gas prices.

Operating expenses:

General and administrative expense (G&A expense)

G&A expense increased $2,273,033 or 89% from 2005 to 2006. Over half of the
increase or $1,324,714 results from our adoption of SFAS No. 123(R) in 2006
which requires all share-based payments to employees and directors be expensed
in the financial statements based on their fair value. The remaining increase
reflects additional costs associated with our growth in 2006 which is reflected
in essentially every area of G&A expense.

Direct operating expenses

Our direct operating expense increased from $719,472 in 2005 to $2,010,608 in
2006 resulting in a 180% increase. Both components of direct operating expense
reflected significant increases in 2006 with lease operating expense increasing
$856,523 and production taxes increasing $434,613. These increases are
indicative of the impact on operating expense of going from thirteen producing
properties in 2005 to thirty-two in 2006.

Accretion expense

We recorded our asset retirement obligation in the fourth quarter of 2005 giving
rise to the initial impact of accretion expense on the financial statements of
$2,173. For 2006, accretion expense amounted to $24,848 which reflects a full
year of accretion expense and includes the impact of changes in well lives
resulting from changes in the reserve report.

Depletion, depreciation and amortization (DD&A)

DD&A increased from $923,471 in 2005 to $4,402,267 in 2006. This increase is
primarily attributable to DD&A of the Company's oil and gas properties under the
full cost method. In 2006, the cost per Mcfe increased from $2.09 to $3.91 while
total production increased from 438,348 Mcfe to 1,088,975 Mcfe. These
substantial increases largely contributed to the 377% increase in DD&A expense.

Proved property impairment expense

Net capitalized costs of oil and gas properties less related deferred taxes are
limited to the sum of (a) future net revenues (using prices and cost rates as of
the balance sheet date) from proved reserves at 10 percent per annum plus (b)
cost not being amortized less (c) related income tax effects. Excess costs are
charged to proved property impairment expense. In 2006, we incurred a proved
property impairment expense of $42,913,184.


                                       24
<PAGE>

Operating loss:

Operating loss increased $46,123,068 from $471,387 in 2005 to $46,594,455 in
2006. For reasons previously documented, we incurred significant increases in
all areas of operating expenses including an impairment expense of $42,913,184
which were not offset by corresponding increases in revenue.

Other income(expense):

Interest income

Interest income increased from $48,893 in 2005 to $217,405 in 2006. The majority
of the $168,512 increase occurred in the first quarter of 2006 resulting from
higher cash balances associated with the February 1, 2006 stock sale. As the
proceeds from the stock sale were used to fund property acquisitions and our
2006 drilling program, interest income amounts leveled off.

Minority interest

We acquired the minority interest in Vaquero Partners in the fourth quarter of
2005. Consequently, there was no minority interest in 2006 and resulted in a
reduction of $52,611.

Interest expense

Interest expense amounted to $775,427 in 2005 with the majority incurred in the
fourth quarter of 2005 when the Company borrowed $30,598,000 for two
acquisitions. Interest expense in 2006 amounted to $4,582,168 which includes a
full year's interest on the fourth quarter of 2005 borrowings plus additional
borrowings of $17,028,000. These factors caused interest expense to increase
$3,806,741 in 2006.

Amortization of deferred financing costs

Loan costs and fees are amortized over the term of the debt instruments to which
they relate. Amortization expense amounted to $143,558 in 2005 and $2,148,282 in
2006. Two factors contributed to this increase of $2,004,724. First, the expense
for 2005 represented only two months amortization as the loan fees were incurred
in November and December, 2005. Second, we refinanced our original credit
agreement in September, 2006 and expensed all loan fees associated with this
borrowing.

Loss on embedded derivative liability

We initially entered into derivative contracts in the fourth quarter of 2005.
During 2005, our mark-to-market activity resulted in recording a loss of
$190,553. Our mark-to-market balance at December 31, 2006 reflected an out of
the money balance giving rise to recording a $33,733 loss for the year.

Other expense

Other expense in 2006 amounted to $494,458 which was comprised of two
components. First, we were required to pay a registration failure penalty of
$395,169 associated with the February 1, 2006 stock sale. Second, we incurred
expenses of $99,289 associated with an unsuccessful effort to find additional
debt financing.

Net Loss

The Company's net loss increased from $1,584,643 in 2005 to $53,635,691 in
2006. The major components contributing to this significant increase include
increases in share-based compensation, DD&A, amortization of deferred loan
costs, interest expense and proved property impairment expense as more fully
detailed above.

Impact of Inflation

Inflation has not had a material effect on our results of operations.

Financial Liquidity and Capital Resources

Provided that borrowings under our existing credit facility remain available to
us, we believe that our cash requirements over the next twelve months will be
met by our revenues from operations, our cash reserves and draws available under
our current banking facilities.


                                       25
<PAGE>

Private Equity Placements

      In February 2006, we closed a private equity offering pursuant to which we
sold a total of 9,000,000 shares of our Common Stock at a price of $2.65 per
share. Gross proceeds raised in this offering were $23,850,000. Sanders Morris
Harris ("SMH") served as our lead placement agent and C.K. Cooper & Company
served as co-placement agent. From the gross proceeds, we paid our investment
bankers a placement agent fee of $1,192,500 (5% of the gross proceeds) and we
paid SMH a financial advisory fee of $477,000 (2% of the gross proceeds). We
also issued to SMH, a warrant exercisable for up to 900,000 shares our Common
Stock, at an exercise price of $2.65 per share. The price per share in this
offering was determined by taking the thirty (30) day volume weighted average
market price of our Common Stock as of January 17, 2006, and discounting it by
approximately 10% to account for investors' receiving unregistered stock.

Debt Financings

      During the third quarter of 2006, we amended and restated our Credit
Agreement with Standard Bank Plc, as administrative agent, Standard Americas
Inc., as collateral agent, and the lenders described therein, dated as of
November 17, 2005 (the "Original Credit Agreement").

      The Original Credit Agreement was amended and restated pursuant to the
terms and conditions of an Amended and Restated Credit Agreement (the "Amended
Credit Agreement"), dated as of September 26, 2006, among the Company, D.B.
Zwirn Special Opportunities Fund, L.P., as administrative agent, and the lenders
named therein (the "Lenders"). Subject to numerous conditions precedent and
covenants, the Amended Credit Agreement provides for a credit commitment of up
to $50 million (the "Commitment"), consisting of an initial commitment of $30.2
million (the "Initial Commitment") and subsequent commitment increases of up to
$19.8 million (the "Subsequent Commitment Increases"). From time to time and
subject to our satisfaction of various terms and conditions contained in the
Amended Credit Agreement, we may request Subsequent Commitment Increases to fund
(i) Development Projects and (ii) the acquisition of additional Oil and Gas
Properties.

      On September, 27, 2006, the Lenders advanced $16,494,908 of their Initial
Commitment to us under the Amended Credit Agreement. Proceeds of this Initial
Funding were used to (i) payoff all amounts outstanding under our Original
Credit Agreement, (ii) fund the drilling and development of wells located on our
Barnett Shale and Bayou Couba Properties, (iii) purchase additional properties
in the Barnett Shale pursuant to our Purchase Agreement with Voyager Partners
Ltd. and (iv) fund certain fees and expenses incurred by us in connection with
our entering into the Amended Credit Agreement. In addition, $1.2 million
included in the Initial Funding was utilized by us to purchase a seismic license
covering certain lands located in St. Charles Parish, Louisiana. This $1.2
million, together with an additional $3.3 million that has been funded to date,
are treated as "Bridge Loans" under the Amended Credit Agreement.

      We agreed to pay the Administrative Agent (i) a "Commitment Fee" equal to
1.5% of all amounts committed to be loaned by the Lenders (except with respect
to amounts advanced under the Original Credit Agreement and for commitments
associated with the Bridge Loans), (ii) a "Bridge Loan Fee" equal to 5% of all
amounts committed to be loaned as Bridge Loans, (iii) an "Administrative Fee" of
$25,000 semi-annually on each August 15 and February 15 that the Amended Credit
Agreement is in effect and (iv) an "Exit Fee" equal to 5% of all amounts
committed to be loaned as Bridge Loans, payable upon the earlier of repayment of
Bridge Loans or April 16, 2007. In addition, we have granted the Lenders an
overriding royalty interest ("ORRI") ranging between 1% and 2% in (i) our
existing Oil and Gas Properties and (ii) Oil and Gas Properties that we acquire
after the date hereof until the Amended Credit Agreement is terminated.

      Unless earlier payment is required under the Amended Credit Agreement,
loans made by the Lenders pursuant to the Amended Credit Agreement must be
repaid on or before August 14, 2009, provided, however, that all Bridge Loans
were required to be repaid on or before March 26, 2007. With respect to the
repayment of our Bridge Loans, our Lenders have agreed to extend the repayment
date for the Bridge Loans until April 16, 2007, in exchange for a payment of
$550,000 on or before that date. If we do not repay the Bridge Loans by such
date, the Lenders will be entitled to receive an additional ORRI of 1% in our
existing Oil & Gas Properties on that date, and an additional 1% ORRI for each
30 days thereafter until the Bridge Loans are repaid in full. Under the Amended
Credit Agreement, interest on all loans shall accrue at the Prime Rate plus 5%
per annum, provided that the interest rate shall not exceed 15.25% per annum nor
be less than 11.25% per annum. All Loans under the Amended Credit Agreement are
secured by a security interest in, and first lien on, all of our assets.


                                       26
<PAGE>

      As further consideration for the making of the Loans, we issued warrants
to the Lenders, exercisable for up to 500,000 shares of our common stock, at a
strike price of $1.35 per share. Pursuant to a warrant agreement (the "Warrant
Agreement") any unexercised warrants expire on September 26, 2015. The Warrant
Agreement also affords the holders certain anti-dilution protection, as well as
piggy-back registration rights and limited demand registration rights.

      We also further amended the Term Loan Agreement, as amended and restated
(the "Original Loan Agreement"), with our principal stockholder, Itera Holdings
BV ("Itera"), pursuant to the terms and conditions of the Amended and Restated
Term Loan Agreement, dated as of September 26, 2006 (the "Amended Loan
Agreement"). In accordance with the Amended Credit Agreement, the convertible
subordinated note, as amended and restated, issued by the Company in connection
with the Original Loan Agreement, was further amended to provide that we may not
pay interest to Itera in cash, until such time as there is no default or event
of default under the Amended Credit Agreement, the payment thereof would not
cause a default or event of default under the Amended Credit Agreement, or until
such time as the Company is in compliance with the financial covenants set forth
in the Amended Credit Agreement. A copy of the Amended and Restated Convertible
Subordinated Note, dated as of September 26, 2006. As of April 1, 2007, there
was a total of $28,235,380 of outstanding principal and accrued interest under
the Restated Convertible Subordinated Note.

Off-Balance Sheet Arrangements

      We entered into derivative contracts to provide a measure of stability in
the cash flows associated with our oil and gas production and to manage exposure
to commodity prices. None of the derivative contracts we entered into have been
designated as cash flow hedges or fair value hedges. we recorded losses of
$33,733 and $190,553 related to its derivative instruments for the years ended
December 31, 2006 and 2005, respectively.

      On November 2, 2006, we unwound all of our hedges on oil and natural gas
prices for a net cash payment received of $5,000. We then placed new derivative
instruments on the same day, November 2, 2006, with Macquarie Bank.

Natural Gas Derivatives

      We entered into participating collars on natural gas hedges (NG-HOUSTON
SHIP CHANNEL) whereby we receive a floor price and pay a percent of any price
in excess of the floor up to a maximum payment. The following table shows the
monthly volumes hedged, the floor price, percent above the floor price paid
(cost) and the maximum payment for that volume.

<TABLE>
<CAPTION>
                                             Average          Average             Our            Average
      Start        End         Volume         Floor            Cost             Average          Maximum
      Month       Month        MMBTU         $/MMBTU       % over Floor     % Participation      Payment
      -----       -----        -----         -------       ------------     ---------------      -------
     <S>          <C>          <C>           <C>                <C>               <C>            <C>
     Dec-06       Dec-06       90,000        $ 6.620            75%               25%            $ 5.050
     Jan-07       Dec-07       63,000        $ 6.620            75%               25%            $ 5.050
     Jan-08       Dec-08       55,000        $ 6.620            75%               25%            $ 5.050
     Jan-09       Nov-09       41,000        $ 6.620            75%               25%            $ 5.050
</TABLE>

Crude Oil Derivatives

      We entered into collars on crude oil hedges (WTI-NYMEX) whereby we receive
a floor price and pay 100% percent of any price in excess of the floor up to a
maximum payment. The following table shows the monthly volumes hedged, the floor
price, percent above the floor price paid (cost) and the maximum payment for
that volume.

<TABLE>
<CAPTION>
                                             Average         Average              Our            Average
      Start        End         Volume         Floor            Cost             Average          Maximum
      Month       Month         BBLS         $/BBLS        % over Floor     % Participation      Payment
      -----       -----         ----         ------        ------------     ---------------      -------
     <S>          <C>          <C>          <C>                <C>                 <C>          <C>
     Nov-06       Dec-06       3,200        $ 60.000           100%                0%           $ 12.500
     Jan-07       Dec-07       2,150        $ 60.000           100%                0%           $ 12.500
     Jan-08       Dec-08       1,400        $ 60.000           100%                0%           $ 12.500
     Jan-09       Oct-09         840        $ 60.000           100%                0%           $ 12.500
</TABLE>


                                       27
<PAGE>

New Accounting Standards

      FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes -
An Interpretation of FASB Statement No. 109, ("FIN 48"). FIN 48 clarifies the
accounting for uncertainty in income taxes recognized in an enterprise's
financial statements in accordance with SFAS No. 109. FIN 48 prescribes a
recognition threshold and measurement attribute for the financial statement
recognition and measurement of a tax position taken or expected to be taken in a
tax return. The new FASB standard also provides guidance on derecognition,
classification, interest and penalties, accounting in interim periods,
disclosure, and transition. The evaluation of a tax position in accordance with
FIN 48 is a two-step process. The first step is a recognition process whereby
the enterprise determines whether it is more likely than not that a tax position
will be sustained upon examination, including resolution of any related appeals
or litigation processes, based on the technical merits of the position. In
evaluating whether a tax position has met the more-likely-than-not recognition
threshold, the enterprise should presume that the position will be examined by
the appropriate taxing authority that has full knowledge of all relevant
information. The second step is a measurement process whereby a tax position
that meets the more-likely-than-not recognition threshold is calculated to
determine the amount of benefit to recognize in the financial statements. The
tax position is measured at the largest amount of benefit that is greater than
50% likely of being realized upon ultimate settlement. The provisions of FIN 48
are effective for fiscal years beginning after December 15, 2006. Earlier
application is permitted as long as the enterprise has not yet issued financial
statements, including interim financial statements, in the period of adoption.
The provisions of FIN 48 are to be applied to all tax positions upon initial
adoption of this standard. Only tax positions that meet the more-likely-than-not
recognition threshold at the effective date may be recognized or continue to be
recognized upon adoption of FIN 48. The cumulative effect of applying the
provisions of FIN 48 should be reported as an adjustment to the opening balance
of retained earnings (or other appropriate components of equity or net assets in
the statement of financial position) for that fiscal year. We are currently
evaluating the statement and have not yet determined the impact of such on our
financial statements.

      SFAS No. 157, Fair Value Measurement, ("SFAS 157"). This new standard
provides guidance for using fair value to measure assets and liabilities. The
FASB believes the standard also responds to investors' requests for expanded
information about the extent to which companies measure assets and liabilities
at fair value, the information used to measure fair value, and the effect of
fair value measurements on earnings. SFAS 157 applies whenever other standards
require (or permit) assets or liabilities to be measured at fair value but does
not expand the use of fair value in any new circumstances. The standard
clarifies that for items that are not actively traded, such as certain kinds of
derivatives, fair value should reflect the price in a transaction with a market
participant, including an adjustment for risk, not just the company's
mark-to-model value. SFAS 157 also requires expanded disclosure of the effect on
earnings for items measured using unobservable data. Under SFAS 157, fair value
refers to the price that would be received to sell an asset or paid to transfer
a liability in an orderly transaction between market participants in the market
in which the reporting entity transacts. In this standard, the FASB clarifies
the principle that fair value should be based on the assumptions market
participants would use when pricing the asset or liability. In support of this
principle, SFAS 157 establishes a fair value hierarchy that prioritizes the
information used to develop those assumptions. The fair value hierarchy gives
the highest priority to quoted prices in active markets and the lowest priority
to unobservable data, for example, the reporting entity's own data. Under the
standard, fair value measurements would be separately disclosed by level within
the fair value hierarchy. The provisions of SFAS 157 are effective for financial
statements issued for fiscal years beginning after November 15, 2007, and
interim periods within those fiscal years. Earlier application is encouraged,
provided that the reporting entity has not yet issued financial statements for
that fiscal year, including any financial statements for an interim period
within that fiscal year. We are currently evaluating this statement and have not
yet determined the impact of such on our financial statements. We plan to adopt
this statement when required at the start of our fiscal year beginning January
1, 2008.


                                       28
<PAGE>

      Accounting Changes and Error Corrections. In May 2005, the FASB issued
SFAS No. 154 "Accounting Changes and Error Corrections," which replaces
Accounting Principles Board Opinion No. 20, "Accounting Changes" and SFAS No. 3,
"Reporting Accounting Changes in Interim Financial Statements - An Amendment of
APB Opinion No. 28." SFAS No. 154 provides guidance on the accounting for and
reporting of accounting changes and error corrections. It establishes
retrospective application, or the latest practicable date, as the required
method for reporting a change in accounting principle and the reporting of a
correction of an error. SFAS No. 154 is effective for accounting changes and
correction of errors made in fascal years beginning after December 15, 2005. We
adopted the provisions of SFAS No. 154 on January 1, 2006.

Critical Accounting Policies

      Our significant accounting policies are more fully described in Note 1 to
the audited financial statements included with this report. The preparation of
financial statements in conformity with accounting principles generally accepted
in the United States of America requires management to make estimates and
assumptions that affect the reported amounts of assets, liabilities, revenues
and expenses, and the related disclosures of contingent assets and liabilities.
Actual results could differ from those estimates under different assumptions or
conditions.

Proved Natural Gas and Oil Reserves

      Proved reserves is defined by the SEC as the estimated quantities of crude
oil, condensate, natural gas and natural gas liquids that geological and
engineering data demonstrate with reasonable certainty are recoverable in future
years from known reservoirs under existing economic and operating conditions.
Valuations include consideration of changes in existing prices provided only by
contractual arrangements, but not on escalations based upon future conditions.
Prices do not include the effect of derivative instruments, if any, entered into
by the Company.

      Proved developed reserves are those reserves expected to be recovered
through existing equipment and operating methods. Additional oil and gas volumes
expected to be obtained through the application of fluid injection or other
improved recovery techniques for supplementing the natural forces and mechanisms
of primary recovery are included as proved developed reserves only after testing
of 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 are those reserves that are expected to be
recovered from new wells on non-drilled acreage, or from existing wells where a
relatively major expenditure is required for re-completion. Reserves on
non-drilled acreage are limited to those drilling units offsetting productive
units that are reasonably certain of production when drilled. Proved reserves
for other non-drilled units are claimed only where it can be demonstrated with
certainty that there is continuity of production from the existing productive
formation.

      Volumes of reserves are estimates that, by their nature, are subject to
revision. The estimates are made using all available geological and reservoir
data as well as production performance data. There are numerous uncertainties in
estimating crude oil and natural gas reserve quantities, projecting future
production rates and projecting the timing of future development expenditures.
Natural gas and oil reserve engineering must be recognized as a subjective
process of estimating underground accumulations of natural gas and oil that
cannot be measured in an exact way. Estimates of independent engineers that we
use may differ from those of other engineers. The accuracy of any reserve
estimate is a function of the quantity and quality of available data and of
engineering and geological interpretation and judgment. Accordingly, future
estimates are subject to change as additional information becomes available.


                                       29
<PAGE>

Revenue Recognition

      We record natural gas and oil revenues using the entitlement method of
accounting for production, in which any excess amount received by us above our
share of production is treated as a liability. If we receive less than our share
of production, the underproduction is recorded as an asset. We did not have an
imbalance position relative to volumes or values at December 31, 2006.

Full Cost Accounting

      We utilize the full cost accounting method to account for the costs
incurred in the acquisition, exploration, development and production of oil and
gas reserves. Under this method, all costs, including internal costs directly
related to acquisition, exploration and development activities are capitalizable
as oil and gas property costs. Properties not subject to amortization consist of
exploration and development costs which are evaluated on a property-by-property
basis. Amortization of these unproved property costs begins when the properties
become proved or their values become impaired. We assess the realizability of
unproved properties on at least an annual basis or when there has been an
indication that an impairment in value may have occurred. Impairment of unproved
properties is assessed based on management's intention with regard to future
exploration and development of individually significant properties and our
ability to obtain funds to finance such exploration and development. If the
results of an assessment indicate that the properties are impaired, the amount
of the impairment is added to the capitalized costs to be amortized. There was
no impairment of unproved properties during the years ended December 31, 2006,
2005 and 2004.

Impairment of Properties

      Under full cost accounting rules for each cost center, capitalized costs
of proved properties, less accumulated amortization and related deferred income
taxes, shall not exceed an amount (the "cost ceiling") equal to the sum of (a)
the present value of future net cash flows from estimated production of proved
oil and gas reserves, based on current economic and operating condition,
discounted at 10 percent, plus (b) the cost of properties not being amortized,
plus (c) the lower of cost or estimated fair value of any unproved properties
included in the costs being amortized, less (d) any income tax effects related
to differences between the book and tax basis of the properties involved. If
capitalized costs exceed this limit, the excess is charged as an impairment
expense. During the year ended December 31, 2006, we incurred a proved property
impairment expense of $42,913,184.

Stock-Based Compensation

      Compensation expense has been recorded for common stock grants based on
the fair value of the common stock on the measurement date. Statement of
Financial Accounting Standards No. 123R, "Share-Based Payments" ("SFAS No.
123R"), establishes standards for accounting for transactions in which an entity
exchanges its equity instruments for goods and services. SFAS No. 123R focuses
primarily on accounting for transactions in which an entity obtains employee
services in share-based payment transactions. SFAS No. 123R requires that the
fair value of such equity instruments be recognized as expense in the historical
financial statements as services are performed. SFAS No. 123R was effective for
us as of the beginning of 2006. During 2006, we recorded $1,324,714 of
share-based compensation expense.

Quantitative and Qualitative Disclosure about Market Risk

      Our primary exposure to market risk consists of changes in interest rates
on borrowings under our Credit Agreement with Standard. An increase in interest
rates would adversely affect our operating results and the cash flow available
after debt service to fund operations. We manage exposure to interest rate
fluctuations by optimizing the use of fixed and variable rate debt. Except with
respect to the interest rates under the Credit Agreement, we do not have debts
or hold instruments that are sensitive to changes in interest rates, foreign
currency exchange rates or commodity prices.


                                       30
<PAGE>

Item 7. Financial Statements.

Index to Financial Statements

<TABLE>
<CAPTION>
                                                                                                                          Page
<S>                                                                                                                       <C>
Report of Independent Registered Public Accounting Firm                                                                   F-2

Consolidated Balance Sheet at December 31, 2006                                                                           F-3

Consolidated Statements of Operations for the years ended December 31, 2006 and 2005                                      F-4

Consolidated Statements of Changes in Stockholders' Equity (Deficit) for the years ended December 31, 2006 and 2005       F-5

Consolidated Statements of Cash Flows for the years ended December 31, 2006 and 2005                                      F-6

Notes to Consolidated Financial Statements                                                                                F-7
</TABLE>


                                      F-1
<PAGE>

             REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors
  Dune Energy, Inc.
  Houston, Texas

We have audited the accompanying consolidated balance sheet of Dune Energy Inc.
as of December 31, 2006, and the related statements of operations, stockholders'
equity (deficit), and cash flows for each of the two years then ended. These
financial statements are the responsibility of Dune's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.

We conducted our audits in accordance with standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audits to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Dune Energy Inc., as of
December 31, 2006, and the results of its operations and its cash flows for the
periods described in conformity with accounting principles generally accepted in
the United States of America.

As discussed in Note 14 to the financial statements, errors resulting in an
understatement of losses; and understatement of basic and diluted loss per
share; and an overstatement of assets in 2006 were discovered by management in
2007. Accordingly, adjustments have been made as of and for the year ended
December 31, 2006, to correct the errors.


/s/ MALONE & BAILEY, PC

MALONE & BAILEY, PC
www.malone-bailey.com
Houston, Texas

April 20, 2007


                                      F-2
<PAGE>

                                Dune Energy, Inc.
                           Consolidated Balance Sheet
                                December 31, 2006
                                   (Restated)

ASSETS
Current assets:
   Cash                                                            $  3,574,705
   Accounts receivable                                                3,849,929
   Other current assets                                                 132,272
                                                                   ------------
Total current assets                                                  7,556,906
                                                                   ------------

Property and equipment                                                   62,767
   Less accumulated depreciation                                        (16,721)
                                                                   ------------
Net property and equipment                                               46,046
                                                                   ------------

Oil and gas properties, using full cost accounting:
   Properties being amortized                                        83,503,586
   Properties not subject to amortization                             5,856,461
   Less accumulated depreciation, depletion, amortization
     and impairment                                                 (48,286,003)
                                                                   ------------
Net oil and gas properties                                           41,074,044
                                                                   ------------

Deferred financing costs, net of accumulated amortization
   of $310,711                                                        1,181,554
Deposit - related party                                                 500,000
Other assets                                                            500,000
                                                                   ------------

TOTAL ASSETS                                                       $ 50,858,550
                                                                   ============

LIABILITIES AND STOCKHOLDERS' DEFICIT
Current liabilities:
   Accounts payable and accrued liabilities                        $  4,685,398
   Current portion of long-term debt                                  4,786,000
                                                                   ------------
Total current liabilities                                             9,471,398
                                                                   ------------

Long-term debt                                                       27,815,223
Long-term debt - related party                                       27,423,932
Other long-term liabilities                                           1,397,649
                                                                   ------------
Total liabilities                                                    66,108,202
                                                                   ------------
Commitments and Contingencies                                                --

STOCKHOLDERS' DEFICIT
Common stock, $.001 par value, 100,000,000 shares
   authorized, 59,430,172 shares issued and outstanding                  59,430
Additional paid-in capital                                           43,585,518
Accumulated deficit                                                 (58,894,600)
                                                                   ------------
Total stockholders' deficit                                         (15,249,652)
                                                                   ------------

TOTAL LIABILITIES AND STOCKHOLDERS' DEFICIT                        $ 50,858,550
                                                                   ============

See summary of significant accounting policies and notes to financial
statements.


                                      F-3
<PAGE>

                                Dune Energy, Inc.
                      Consolidated Statements of Operations
                     Years ended December 31, 2006 and 2005

                                                     2006
                                                  (Restated)           2005
                                                 ------------      ------------

Revenues                                         $  7,580,034      $  3,724,278
                                                 ------------      ------------

Operating expenses:
   General and administrative expense               4,823,582         2,550,549
   Direct operating expenses                        2,010,608           719,472
   Accretion expense                                   24,848             2,173
   Depletion, depreciation and amortization         4,402,267           923,471
   Proved property impairment expense              42,913,184                --
                                                 ------------      ------------
Total operating expenses                           54,174,489          4,195,665
                                                 ------------      ------------
Operating loss                                    (46,594,455)         (471,387)
                                                 ------------      ------------
Other income (expense):
   Interest income                                    217,405            48,893
   Minority interest                                       --           (52,611)
   Interest expense                                (4,582,168)         (775,427)
   Amortization of deferred financing costs        (2,148,282)         (143,558)
   Loss on embedded derivative liability              (33,733)         (190,553)
   Other expense                                     (494,458)               --
                                                 ------------      ------------

Total other income (expense)                       (7,041,236)       (1,113,256)
                                                 ------------      ------------
Net loss                                         $(53,635,691)     $ (1,584,643)
                                                 ============      ============

Net loss per share:
   Basic and diluted                             $      (0.92)     $      (0.03)

Weighted average shares outstanding:
   Basic and diluted                               58,583,932        47,557,242

See summary of significant accounting policies and notes to financial
statements.


                                      F-4
<PAGE>

                                Dune Energy, Inc.
      Consolidated Statements of Changes in Stockholders' Equity (Deficit)
                Years ended December 31, 2006 (Restated) and 2005

<TABLE>
<CAPTION>
                                 Preferred Stock -
                                     Series A                    Common Stock
                              -----------------------     --------------------------     Paid-In       Accumulated
                                Shares        Amount         Shares         Amount       Capital         Deficit           Total
                              ----------     --------     ------------    ----------   ------------    ------------    ------------
<S>                             <c>          <C>            <C>           <C>          <C>             <C>             <C>
Balance at

   December 31, 2004             111,111     $    111       45,597,171    $   45,597   $ 14,051,374    $ (3,674,266)   $ 10,422,816

Stock issued for:

   Debt                               --           --        1,182,223         1,182        443,818              --         445,000
   Conversion of preferred
      to common                 (111,111)        (111)         222,222           222           (111)             --              --

Cash paid to consultant
   for stock subscription             --           --               --            --       (398,167)             --        (398,167)

Cash received for stock
   subscription                       --           --        3,243,243         3,243      5,996,757              --       6,000,000

Net loss                              --           --               --            --             --      (1,584,643)     (1,584,643)
                              ----------     --------     ------------    ----------   ------------    ------------    ------------
Balance at

   December 31, 2005                  --           --       50,244,859        50,244     20,093,671      (5,258,909)     14,885,006

Cash received for stock
   subscription                       --           --        9,000,000         9,001     23,840,999              --      23,850,000

Cash paid to consultant
   for stock subscription             --           --               --            --     (1,773,681)             --      (1,773,681)

Cash received for exercise
   of stock options                   --           --          133,333           133         99,867              --         100,000

Stock issued for cashless
   exercise of stock
   options                            --           --           51,980            52            (52)             --              --

Stock-based compensation              --           --               --            --      1,324,714              --       1,324,714

Net loss                              --           --               --            --             --     (53,635,691)    (53,635,691)
                              ----------     --------     ------------    ----------   ------------    ------------    ------------
Balance at

   December 31, 2006                  --     $     --       59,430,172    $   59,430   $ 43,585,518    $(58,894,600)  $ (15,249,652)
                              ==========     ========     ============    ==========   ============    ============   =============
</TABLE>

See summary of significant accounting policies and notes to financial
statements.


                                      F-5
<PAGE>

                                Dune Energy, Inc.
                      Consolidated Statements of Cash Flows
                     Years ended December 31, 2006 and 2005

<TABLE>
<CAPTION>
                                                               2006
                                                            (Restated)            2005
                                                           ------------       ------------
<S>                                                        <C>                <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss                                                   $(53,635,691)      $ (1,584,643)
Adjustments to reconcile net loss to net cash used in
   operating activities:
   Depletion, depreciation and amortization                   4,402,267            923,471
   Amortization of deferred financing costs                   2,148,282            143,558
   Share-based compensation                                   1,324,714                 --
   Accretion of asset retirement obligation                      24,848              2,173
   Loss on derivative mark to market adjustment                  33,733            190,553
   Proved property impairment expense                        42,913,184                 --
   Minority interest                                                 --            (17,201)
   Changes in:
      Accounts receivable                                    (2,253,961)        (1,059,638)
      Other current assets                                      (27,515)                --
      Accounts payable and accrued liabilities                3,431,762          4,002,084
      Other long-term liabilities                                    --             76,509
                                                           ------------       ------------
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES          (1,638,377)         2,676,866
                                                           ------------       ------------
CASH FLOWS FROM INVESTING ACTIVITIES
Investment in proved and unproved properties                (37,328,290)       (43,003,119)
Deposits on oil and gas properties                                   --         (1,820,101)
Purchase of office equipment                                    (23,640)           (39,127)
Increase in deposit - related party                            (500,000)                --
Increase in other assets                                       (500,000)                --
                                                           ------------       ------------
NET CASH USED IN INVESTING ACTIVITIES                       (38,351,930)       (44,862,347)
                                                           ------------       ------------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt                                 37,101,223         39,097,514
Payment on long-term debt issuance costs                       (993,563)        (2,506,745)
Payments on long-term debt                                  (18,500,000)                --
Proceeds from sale of common stock, net                      22,103,232          5,601,833
Proceeds from exercise of options                               100,000                 --
                                                           ------------       ------------
NET CASH PROVIDED BY FINANCING ACTIVITIES                    39,810,892         42,192,602
                                                           ------------       ------------

NET CHANGE IN CASH BALANCE                                     (179,415)             7,121
   Cash balance at beginning of period                        3,754,120          3,746,999
                                                           ------------       ------------
   Cash balance at end of period                           $  3,574,705       $  3,754,120
                                                           ============       ============

SUPPLEMENTAL DISCLOSURES
Interest paid                                              $  2,150,597       $    553,236
Income taxes paid                                                    --                 --

NON-CASH DISCLOSURES
Stock issued for cashless exercise of options              $         52       $         --
Asset retirement obligation incurred                            189,650             76,509
Asset retirement obligation revision                             75,456                 --
Stock issued for conversion of debt                                  --            450,000
Conversion of preferred stock to common stock                        --                222
</TABLE>

See summary of significant accounting policies and notes to financial
statements.


                                      F-6
<PAGE>

                                DUNE ENERGY, INC.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of operations and organization

Dune Energy, Inc., a Delaware corporation ("Dune" or the "Company"), is an
independent energy company that was formed in 1998. Since May 2004, Dune has
been engaged in the exploration, development, exploitation and production of oil
and natural gas. Dune sells its oil and gas products primarily to domestic
pipelines and refineries. Its operations are presently focused in the States of
Texas and Louisiana. Dune, through its 100% owned subsidiary, Vaquero Partners
LLC ("Vaquero"), acquired interests in certain oil and natural gas leases
located in Victoria County, Texas. Dune also directly holds interests in other
properties discussed in this 10-KSB.

Consolidation

The accompanying consolidated financial statement includes all accounts of Dune
and Vaquero. All significant inter-company balances and transactions have been
eliminated in consolidation.

Oil and gas properties

Dune follows the full cost accounting method to account for the costs incurred
in the acquisition, exploration, development and production of oil and gas
reserves. Under this method, all costs, including internal costs directly
related to acquisition, exploration and development activities are capitalizable
as oil and gas property costs.

Properties not subject to amortization consist of exploration and development
costs which are evaluated on a property-by-property basis. Amortization of these
unproved property costs begins when the properties become proved or their values
become impaired. Dune assesses the realizability of unproved properties on at
least an annual basis or when there has been an indication that an impairment in
value may have occurred. Impairment of unproved properties is assessed based on
management's intention with regard to future exploration and development of
individually significant properties and the ability of Dune to obtain funds to
finance such exploration and development. If the results of an assessment
indicate that the properties are impaired, the amount of the impairment is added
to the capitalized costs to be amortized. There was no impairment of unproved
properties during the years ended December 31, 2006 and 2005. The costs not
subject to amortization as of December 31, 2006 are as follows:

                                                             Year Incurred
                                         As of        --------------------------
                                   December 31, 2006       2006           2005
                                   -----------------  -----------     ----------

Acquisition costs                      $  391,221      $  391,221     $       --

Exploration and development costs       5,465,240       2,395,041      3,070,199
                                       ----------      ----------     ----------
                                       $5,856,461      $2,786,262     $3,070,199
                                       ==========      ==========     ==========

The fair value of an asset retirement obligation is recognized in the period in
which it is incurred if a reasonable estimate of fair value can be made. The
present value of the estimated asset retirement costs is capitalized as part of
the carrying amount of the long-lived asset. For Dune, asset retirement
obligations relate to the abandonment of oil and gas producing facilities. The
amounts recognized are based upon numerous estimates and assumptions, including
future retirement costs, future recoverable quantities of oil and gas, future
inflation rates and the credit-adjusted risk-free interest rate.

Costs of oil and gas properties are amortized using the units of production
method. Amortization expense per equivalent physical unit of production amounted
to $4,268,782 and $916,147 for the years ended December 31, 2006 and 2005,
respectively.


                                      F-7
<PAGE>

Under full cost accounting rules for each cost center, capitalized costs of
proved properties, less accumulated amortization and related deferred income
taxes, shall not exceed an amount (the "cost ceiling") equal to the sum of (a)
the present value of future net cash flows from estimated production of proved
oil and gas reserves, based on current economic and operating condition,
discounted at 10 percent, plus (b) the cost of properties not being amortized,
plus (c) the lower of cost or estimated fair value of any unproved properties
included in the costs being amortized, less (d) any income tax effects related
to differences between the book and tax basis of the properties involved. If
capitalized costs exceed this limit, the excess is charged as an impairment
expense. During the year ended December 31, 2006, the Company incurred a proved
property impairment expense of $42,913,184 which is reflected in the
accompanying Consolidated Statement of Operations.

Revenue recognition

Dune records oil and gas revenues following the entitlement method of accounting
for production, in which any excess amount received above Dune's share is
treated as a liability. If less than Dune's share is received, the
underproduction is recorded as an asset. Dune did not have an imbalance position
in terms of volumes or values at December 31, 2006.

Cash and cash equivalents

Cash and cash equivalents include cash in banks and certificates of deposit
which mature within three months of the date of purchase.

Use of estimates

The preparation of these financial statements in conformity with accounting
principles generally accepted in the United States of America requires
management to make estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent assets and liabilities at
the date of the financial statements and the reported amount of revenues and
expenses during the reporting period. Actual results could differ from those
estimates.

Property and equipment

Property and equipment is valued at cost. Additions are capitalized and
maintenance and repairs are charged to expense as incurred. Gains and losses on
dispositions of equipment are reflected in other income.

Deferred financing costs

In connection with debt financings in 2006, Dune has paid $993,563 in fees.
These fees were recorded as deferred financing costs and are being amortized
over the life of the loans using the straight-line method which approximates the
effective interest method as the principal amounts on the debt financings are
due at maturity.

Long-lived assets

Long-lived assets to be held and used or disposed of other than by sale are
reviewed for impairment whenever events or changes in circumstances indicate
that the carrying amount may not be recoverable. When required, impairment
losses on assets to be held and used or disposed of other than by sale are
recognized based on the fair value of the asset. Long-lived assets to be
disposed of by sale are reported at the lower of the asset's carrying amount or
fair value less cost to sell.


                                      F-8
<PAGE>

Deposit - related party

Dune entered into a definitive contract with Itera Rig LLC, an affiliate of
Itera Holdings, BV, Dune's majority shareholder. The terms of the contract call
for the construction of and subsequent long-term contract for a drilling rig for
its exclusive use on its Barnett Shale properties. The contract calls for a
$500,000 deposit which will be applied to payments due at the end of the
contract period.

Derivatives

Derivative financial instruments, utilized to manage or reduce commodity price
risk related to Dune's production and interest rate risk related to Dune's
long-term debt, are accounted for under the provisions of SFAS No. 133,
"Accounting for Derivative Instruments and for Hedging Activities", and related
interpretations and amendments. Under this statement, derivatives are carried on
the balance sheet at fair value. If the derivative is designated as a fair value
hedge, the changes in the fair value of the derivative and of the hedged item
attributable to the hedged risk are recognized in earnings. If the derivative is
designated as a cash flow hedge, the effective portions of changes in the fair
value of the derivative are recorded in other comprehensive income and are
recognized in the statement of operations when the hedged item affects earnings.
If the derivative is not designated as a hedge, changes in the fair value are
recognized in other expense. Ineffective portions of changes in the fair value
of cash flow hedges are also recognized in other expense.

Share-based compensation

On January 1, 2006, Dune adopted SFAS No. 123(R), "Share-Based Payment". SFAS
123(R) replaced SFAS No. 123 and supersedes APB Opinion No. 25. SFAS 123(R)
requires all share-based payments to employees, including grants of employee
stock options, to be recognized in the financial statements based on their fair
values. The pro forma disclosures previously permitted under SFAS 123 are no
longer an alternative to financial statement recognition. Dune adopted SFAS
123(R) using the modified prospective method which requires the application of
the accounting standard as of January 1, 2006. The consolidated financial
statements for the year ended December 31, 2006 reflect the impact of adopting
SFAS 123(R). In accordance with the modified prospective method, the
consolidated financial statements for prior periods have not been restated to
reflect, and do not include, the impact of SFAS 123(R).

Prior to 2006, Dune accounted for share-based compensation to employees and
directors under the intrinsic value method under APB Opinion No. 25. Under this
method, Dune had not recognized compensation expense for stock granted when the
underlying number of shares is known and the exercise price of the option is
greater than or equal to the fair market value of the stock on the grant date.
Had Dune determined compensation expense for stock option grants based on their
estimated fair value at their grant date, Dune's net loss and net loss per share
would have been as follows:

<TABLE>
<CAPTION>
                                                                            Year ended
                                                                        December 31, 2005
                                                                        -----------------
      <S>                                                                  <C>
      Net loss, as reported                                                $(1,584,643)

      Deduct: share-based compensation expense determined under fair
      value based method                                                    (2,234,056)

                                                                           -----------
      Pro forma net loss                                                   $(3,818,699)
                                                                           ===========

      Net loss per share, basic and diluted:
      As reported                                                          $     (0.03)
      Pro forma                                                            $     (0.08)
</TABLE>

The weighted average fair value of the stock options granted during the year
ended December 31, 2005 was $2.05. Variables used in the Black-Scholes
option-pricing model include (1) risk-free interest rates of 2.0%, (2) expected
option life is the actual remaining life of the options, (3) expected volatility
is 135.72% and (4) zero expected dividends.


                                      F-9
<PAGE>

Income taxes

Dune recognizes deferred tax assets and liabilities based on differences between
the financial reporting and tax bases of assets and liabilities using the
enacted tax rates and laws that are expected to be in effect when the
differences are expected to be recovered. Dune provides a valuation allowance
for deferred tax assets for which it does not consider realization of such
assets to be more likely than not.

Loss per share

Basic and diluted net loss per share calculations are presented in accordance
with Financial Accounting Standards Statement 128 and are calculated on the
basis of the weighted average number of common shares outstanding during the
year. They include the dilutive effect of common stock equivalents in years with
net income. Basic and diluted loss per share is the same due to the absence of
common stock equivalents.

New Accounting Pronouncements

      FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes -
An Interpretation of FASB Statement No. 109, ("FIN 48"). FIN 48 clarifies the
accounting for uncertainty in income taxes recognized in an enterprise's
financial statements in accordance with SFAS No. 109. FIN 48 prescribes a
recognition threshold and measurement attribute for the financial statement
recognition and measurement of a tax position taken or expected to be taken in a
tax return. The new FASB standard also provides guidance on derecognition,
classification, interest and penalties, accounting in interim periods,
disclosure, and transition. The evaluation of a tax position in accordance with
FIN 48 is a two-step process. The first step is a recognition process whereby
the enterprise determines whether it is more likely than not that a tax position
will be sustained upon examination, including resolution of any related appeals
or litigation processes, based on the technical merits of the position. In
evaluating whether a tax position has met the more-likely-than-not recognition
threshold, the enterprise should presume that the position will be examined by
the appropriate taxing authority that has full knowledge of all relevant
information. The second step is a measurement process whereby a tax position
that meets the more-likely-than-not recognition threshold is calculated to
determine the amount of benefit to recognize in the financial statements. The
tax position is measured at the largest amount of benefit that is greater than
50% likely of being realized upon ultimate settlement. The provisions of FIN 48
are effective for fiscal years beginning after December 15, 2006. Earlier
application is permitted as long as the enterprise has not yet issued financial
statements, including interim financial statements, in the period of adoption.
The provisions of FIN 48 are to be applied to all tax positions upon initial
adoption of this standard. Only tax positions that meet the more-likely-than-not
recognition threshold at the effective date may be recognized or continue to be
recognized upon adoption of FIN 48. The cumulative effect of applying the
provisions of FIN 48 should be reported as an adjustment to the opening balance
of retained earnings (or other appropriate components of equity or net assets in
the statement of financial position) for that fiscal year. We are currently
evaluating the statement and have not yet determined the impact of such on our
financial statements.

      SFAS No. 157, Fair Value Measurement, ("SFAS 157"). This new standard
provides guidance for using fair value to measure assets and liabilities. The
FASB believes the standard also responds to investors' requests for expanded
information about the extent to which companies measure assets and liabilities
at fair value, the information used to measure fair value, and the effect of
fair value measurements on earnings. SFAS 157 applies whenever other standards
require (or permit) assets or liabilities to be measured at fair value but does
not expand the use of fair value in any new circumstances. The standard
clarifies that for items that are not actively traded, such as certain kinds of
derivatives, fair value should reflect the price in a transaction with a market
participant, including an adjustment for risk, not just the company's
mark-to-model value. SFAS 157 also requires expanded disclosure of the effect on
earnings for items measured using unobservable data. Under SFAS 157, fair value
refers to the price that would be received to sell an asset or paid to transfer
a liability in an orderly transaction between market participants in the market
in which the reporting entity transacts. In this standard, the FASB clarifies


                                      F-10
<PAGE>

the principle that fair value should be based on the assumptions market
participants would use when pricing the asset or liability. In support of this
principle, SFAS 157 establishes a fair value hierarchy that prioritizes the
information used to develop those assumptions. The fair value hierarchy gives
the highest priority to quoted prices in active markets and the lowest priority
to unobservable data, for example, the reporting entity's own data. Under the
standard, fair value measurements would be separately disclosed by level within
the fair value hierarchy. The provisions of SFAS 157 are effective for financial
statements issued for fiscal years beginning after November 15, 2007, and
interim periods within those fiscal years. Earlier application is encouraged,
provided that the reporting entity has not yet issued financial statements for
that fiscal year, including any financial statements for an interim period
within that fiscal year. We are currently evaluating this statement and have not
yet determined the impact of such on our financial statements. We plan to adopt
this statement when required at the start of our fiscal year beginning January
1, 2008.

NOTE 2 -- PROPERTY ACQUISITIONS

On October 19, 2005, Dune acquired certain exclusive exploration and development
rights from American Natural Energy Corporation ("ANEC"), with an effective date
of August 26, 2005, in ANEC's Joint Development Agreement with a major
integrated energy company, covering approximately 11,100 acres in St. Charles
Parish, Louisiana. Dune has the right to participate in 50% of ANEC's
development rights in the Delta Securities Lease in exchange for $1 million.

On November 17, 2005, Dune acquired the interests in certain oil and gas
properties (the "Springside Properties") from Voyager Partners, Ltd.
("Voyager"). Dune paid a total of $5.5 million for the Springside Properties
with an effective date of July 1, 2005.

On December 16, 2005, Dune acquired the interests in certain producing and
non-producing natural gas properties and related property and equipment located
in the Barnett Shale play in the North Texas Fort Worth Basin from Voyager
("Voyager Tranche 1"). The purchase price for the properties was $24.6 million
with an effective date of May 1, 2005.

On May 31, 2006, Dune acquired the interest in certain producing and
non-producing natural gas properties and related property and equipment located
in the Barnett Shale play in the North Texas Fort Worth Basin from Voyager
("Voyager Tranche 2 - 1st Closing"). The purchase price for the properties was
$6.0 million with an effective date of May 2, 2005.

On July 31, 2006 Dune acquired the interest in certain non-producing natural gas
properties located in the Barnett Shale play in the North Texas Fort Worth Basin
from Voyager ("Voyager Tranche 2 - 2nd Closing"). The purchase price for the
properties was $1.26 million with an effective date of May 1, 2005.

On October 10, 2006, Dune acquired the interests in certain producing properties
and non-producing natural gas properties and related equipment located in the
Barnett Shale play in the North Texas Fort Worth Basin from Voyager ("Voyager
Tranche 2 and Tranche 3). The purchase price for the properties was $7.3 million
with an effective date of August 1, 2006. We determined that audited financial
statements and pro forma amounts were not required under Items 9.01(a) and (b)
of Form 8-K as the acquisition of Tranche 2 and Tranche 3 was less than 20% of
our total assets as of December 31, 2005.

On December 26, 2006, Dune acquired from TransAtlantic Petroleum Corp. ("TNP")
an interest in oil and gas properties in the Bayou Couba held by its subsidiary,
TransAtlantic Petroleum Corp., and certain 8% Convertible Secured Debentures
issued by American Natural Energy Corporation in the principal face amount of
$3.0 million held by TNP. Total consideration for the purchase was $2 million
with an effective date of December 1, 2006.

NOTE 3 -- CONVERTIBLE DEBENTURES

In March 2004, Dune issued a convertible debenture with a face value of $45,000.
The debenture was convertible into Dune common stock at $0.45 per share at the
option of the holder.

During the year ended December 31, 2004, nineteen holders converted $766,500 of
convertible debentures into 1,792,150 shares of common stock. During the year
ended December 31, 2005, the remaining holders converted $445,000 in convertible
debentures into 1,182,223 shares of common stock. As of December 31, 2005, there
are no remaining convertible debentures outstanding.


                                      F-11
<PAGE>

Dune analyzed these convertible debentures for derivative accounting
consideration under SFAS No. 133 and EITF 00-19. The Company determined that
derivative accounting is not applicable for the convertible debentures.

NOTE 4 -- DEBT FINANCING

On September 26, 2006, Dune amended and restated their credit agreement with
Standard Bank Plc, as administrative agent, Standard Americas Inc., as
collateral agent, and the lenders described therein, dated as of November 17,
2005 (the "original credit agreement").

The original credit agreement was amended and restated pursuant to the terms and
conditions of an amended and restated credit agreement, dated as of September
26, 2006, among the Company, D.B. Zwirn Special Opportunities Fund, L.P., as
administrative agent, and the lenders. Subject to numerous conditions precedent
and covenants, the amended credit agreement provides for a credit commitment of
up to $50 million, consisting of an initial commitment of $30.2 million and
subsequent commitment increases of up to $19.8 million.

On September 27, 2006, the lenders advanced $16,494,908 of their initial
commitment to Dune. The proceeds of this initial funding were used to pay off
all amounts outstanding under the original credit agreement. Additionally, the
unamortized balance of deferred loan costs associated with the original credit
agreement of $1,311,683 was expensed. During the fourth quarter of 2006, the
lenders advanced an additional $16,106,315 of their commitment to Dune. In
addition, $1.2 million included in the initial funding, together with an
additional $2.1 million that was funded in the 4th quarter of 2006, shall be
treated as bridge loans. From time to time and subject to our satisfaction of
various terms and conditions, Dune may request subsequent commitment increases.
As of December 31, 2006, Dune was due additional funding of $699,970. This
balance is included in other long-term liabilities in the accompanying
consolidated balance sheet.

Unless earlier payments is required, repayments on loans made by the lenders
must begin to be repaid on each quarterly date beginning March 31, 2007 through
the loan maturity date August 14, 2009, prinicipal payments are to be equal to
50% of "Free Cash Flow" which is defined as all revenues earned as of each
quarterly date less costs. Dune has estimated the payments on the long term debt
during 2007 to be $1,486,000, based on expected revenues and costs. Actual
results and resulting payments could differ from this estimate. Provided,
however, that all bridge loans must be repaid on or before March 26, 2007.
Interest on all loans shall accrue at the prime rate plus 5% per annum, provided
that the interest rate shall not exceed 15.25% per annum. All loans are secured
by a security interest in, and first lien on, all of Dune's assets. Our lenders
have agreed to extend the deadline of the repayment of the Bridge Loans to April
13, 2007.

Additionally, Dune agreed to pay the administrative agent (i) a commitment fee
equal to 1.5% of all amounts committed to be loaned by the lenders (except with
respect to amounts advanced under the original credit agreement and for
commitments associated with the bridge loans), (ii) a bridge loan fee equal to
5% of all amounts committed to be loaned as bridge loans, (iii) an
administrative fee of $25,000 semi-annually on each August 15 and February 15
that the amended credit agreement is in effect and (iv) an exit fee equal to 5%
of all amounts committed to be loaned as bridge loans, payable upon the earlier
of repayment of bridge loans or March 26, 2007. In addition, Dune has granted
the lenders an overriding royalty interest ("ORRI") ranging between 1% and 2% in
(i) Dune's existing oil and gas properties and (ii) oil and gas properties that
we acquire until the amended credit agreement is terminated.

Dune also amended the long-term loan agreement with Itera Holdings BV ("Itera")
as of September 26, 2006. The convertible subordinated note, as amended and
restated, issued by Dune in connection with the original loan agreement, was
further amended to provide that Dune may not pay interest to Itera in cash,
until such time as there is no default or event of default under the amended
credit agreement, the payment thereof would not cause a default or event of
default under the amended credit agreement and until such time as Dune is in
compliance with the financial covenants set forth in the amended credit
agreement. We analyzed the notes for derivative accounting consideration under
SFAS 133 and EITF 00-19. We determined that the notes were conventional debt
because the contract contains a fixed number of shares to be delivered upon
settlement and this number will not change based on a future event. We also
determined that the notes conversion feature met the criteria for classification
in stockholders' equity under SFAS 133 and EITF 00-19 because physical
settlement is required. Net cash settlement is neither required nor an option.
Therefore, derivative accounting is not applicable for the notes.


                                      F-12
<PAGE>

NOTE 5 -- DERIVATIVE FINANCIAL INSTRUMENTS

Dune entered into derivative contracts to provide a measure of stability in the
cash flows associated with Dune's oil and gas production and to manage exposure
to commodity prices. None of the derivative contracts Dune entered into have
been designated as cash flow hedges or fair value hedges. Dune recorded losses
of $33,733 and $190,553 related to its derivative instruments for the years
ended December 31, 2006 and 2005, respectively.

On November 2, 2006, Dune unwound all of their hedges on oil and natural gas
prices for a net cash payment received of $5,000. Dune then placed new
derivative instruments on the same day, November 2, 2006, with Macquarie Bank.

Natural Gas Derivatives

Dune entered into participating collars on natural gas hedges (NG-HOUSTON SHIP
CHANNEL) whereby Dune receives a floor price and pays a percent of any price in
excess of the floor up to a maximum payment. The following table shows the
monthly volumes hedged, the floor price, percent above the floor price paid
(cost) and the maximum payment for that volume.

<TABLE>
<CAPTION>
                                            Average         Average           Average          Average
      Start         End        Volume        Floor           Cost               Dune           Maximum
      Month        Month       MMBTU        $/MMBTU      % over Floor     % Participation      Payment
      -----        -----       -----        -------      ------------     ---------------      -------
      <S>          <C>         <C>          <C>               <C>               <C>           <C>
      Dec-06       Dec-06      90,000       $ 6.620           75%               25%           $   5.050
      Jan-07       Dec-07      63,000       $ 6.620           75%               25%           $   5.050
      Jan-08       Dec-08      55,000       $ 6.620           75%               25%           $   5.050
      Jan-09       Nov-09      41,000       $ 6.620           75%               25%           $   5.050
</TABLE>

Crude Oil Derivatives

Dune entered into collars on crude oil hedges (WTI-NYMEX) whereby Dune receives
a floor price and pays 100% percent of any price in excess of the floor up to a
maximum payment. The following table shows the monthly volumes hedged, the floor
price, percent above the floor price paid (cost) and the maximum payment for
that volume.

<TABLE>
<CAPTION>
                                              Average         Average            Average          Average
       Start        End         Volume         Floor            Cost               Dune           Maximum
       Month       Month         BBLS         $/BBLS        % over Floor     % Participation      Payment
       -----       -----         ----         ------        ------------     ---------------      -------
      <S>          <C>          <C>         <C>                 <C>                 <C>          <C>
      Nov-06       Dec-06       3,200       $   60.000          100%                0%           $  12.500
      Jan-07       Dec-07       2,150       $   60.000          100%                0%           $  12.500
      Jan-08       Dec-08       1,400       $   60.000          100%                0%           $  12.500
      Jan-09       Oct-09        840        $   60.000          100%                0%           $  12.500
</TABLE>

NOTE 6 -- ASSET RETIREMENT OBLIGATION

Dune had asset retirement obligations at December 31, 2005 of $78,682. In
accordance with the provisions of SFAS No. 143, Dune records an abandonment
liability associated with its oil and gas wells when those assets are placed in
service. Asset retirement obligations are included other long-term liabilities
on Dune's consolidated balance sheet. The following table is a reconciliation of
the asset retirement obligation liability for 2006 and 2005:

                                                             2006         2005
                                                             ----         ----

Asset retirement obligation at beginning of year           $ 78,682     $      0
Liabilities incurred                                        189,650       76,509
Liabilities settled                                               0            0
Accretion expense                                            24,848        2,173
Revisions in estimated liabilities                           75,456            0
                                                           --------     --------

Asset retirement obligation at end of year                 $368,636     $ 78,682
                                                           ========     ========


                                      F-13
<PAGE>

NOTE 7 -- PREFERRED STOCK

During the year ended December 31, 2005, 111,111 shares of Series A Convertible
Preferred Stock were converted into 222,222 shares of common stock.

As of December 31, 2006 there are no Series A Convertible Preferred shares
outstanding.

NOTE 8 -- COMMON STOCK

During the year ended December 31, 2005, note holders converted $445,000 in
convertible notes payable into 1,182,223 shares of common stock.

During the year ended December 31, 2005, 111,111 shares of Series A Convertible
Preferred Stock were converted into 222,222 shares of common stock.

On September 30, 2005, Dune closed a $6 million private equity offering. A total
of 3,243,243 shares of common stock were sold at a price of $1.85 per share.
Dune paid the investment banker, Sanders Morris Harris Inc., a placement agent
fee consisting of (i) cash equal to 5% of the gross proceeds and (ii) a warrant
exercisable for up to 324,324 shares our common stock, at an exercise price of
$1.85 per share. The private offering was made in reliance upon Section 4(2) of
the Securities Act of 1933, as amended and Rule 506 of Regulation D. The
accounting treatment of the warrants yielded a debit of $600,000 to additional
paid-in capital as a reduction in the amount received from the private placement
and a corresponding credit of $600,000 to additional paid-in capital for the
value of the warrants resulting in a $0 impact on the balance sheet.

On February 1, 2006, Dune sold a total of 9,000,000 shares of common stock at a
price of $2.65 per share in a private equity offering. Gross proceeds raised in
the offering were $23,850,000. From the gross proceeds, Dune paid the investment
bankers a placement agent fee of $1,192,500 (5% of the gross proceeds), a
financial advisory fee of $477,000 (2% of the gross proceeds) and expenses of
$104,184, of which $26,916 had been prepaid as of December 31, 2005. Dune also
issued a warrant exercisable for up to 900,000 shares of its common stock at an
exercise prices of $2.65 per share. Pursuant to rights granted by Dune to
investors in the February offering, Dune was required to file a registration
statement covering all shares purchased and to have such registration statement
declared effective June 1, 2006. Because such registration statement was not
declared effective by the SEC until July 5, 2006, Dune was required to pay to
the investors a registration failure penalty equal to one and one-half percent
(1.5%) of their aggregate investment for each 30-day period beyond June 1, 2006.
This resulted in Dune paying investors in the February offering an aggregate of
$395,168, which was recorded as other expense for the year ended December 31,
2006.

On May 3, 2006, a shareholder exercised 133,333 stock options to purchase
133,333 shares of common stock at a price of $0.75 per share. Dune received
$100,000.

On August 3, 2006, an option holder exercised 40,000 stock options on a cashless
basis for 29,200 shares of common stock. This transaction resulted in an
increase in common stock of $29.20 and a reduction in paid-in-capital of $29.20.
On August 22, 2006, the same option holder exercised 10,000 stock options on a
cashless basis for 6,900 shares of common stock. This transaction resulted in an
increase in common stock of $6.90 and a reduction in paid-in-capital of $6.90.
The option holders executed their rights to exercise the options on a cashless
basis. Dune received no cash consideration in either transaction.

On August 28, 2006, Dune granted stock options to two employees, exercisable in
the aggregate, for up to 60,000 shares of common stock for services rendered.
Such options expire in five years and are exercisable at $1.50 per share.

As further consideration for amending and restating their Credit Agreement (see
Note 4), Dune issued warrants to their lenders, exercisable for up to 500,000
shares of our common stock, at a strike price of $1.35 per share. Pursuant to a
warrant agreement (the "Warrant Agreement") any unexercised warrants expire on
September 26, 2015. The Warrant Agreement also affords the holders certain
anti-dilution protection, as well as piggy-back registration rights and limited
demand registration rights. We analyzed the lender warrants for derivative
accounting consideration under SFAS 133 and EITF 00-19. We determined that
derivative accounting is not applicable for these lender warrants.


                                      F-14
<PAGE>

On December 28, 2006, an option holder exercised 25,000 stock options on a
cashless basis for 15,880 shares of common stock. This transaction resulted in
an increase in common stock of $15.88 and a reduction in paid-in-capital of
$15.88. The option holder executed their rights to exercise the options on a
cashless basis. Dune received no cash consideration in this transaction.

NOTE 9 -- STOCK OPTIONS

During 2006 and 2005, Dune's Board of Directors granted stock options, some of
which are immediately exercisable and some vest over a three year period. The
following table summarizes stock option activity:

                                                                       Weighted
                                                                       Average
                                                        Options         Price
                                                      ----------     ----------

Outstanding as of December 31, 2005                    2,278,333     $     1.93
Granted during 2006                                      160,000           2.03
Cancelled or Expired                                          --             --
Exercised                                               (208,333)         (0.71)
                                                      ----------     ----------
Outstanding as of December 31, 2006                    2,230,000     $     1.95
                                                      ==========     ==========

The weighted average fair value of the stock options granted during the year
ended December 31, 2006 was $2.00. Variables used in the Black-Scholes
option-pricing model include (1) risk-free interest rates of between 4.6% and
4.7%, (2) expected option life is the actual remaining life of the options as of
each period end, (3) expected volatility is 118.73% to 129.59% and (4) zero
expected dividends.

Options outstanding and exercisable at December 31, 2006 are as follows:

<TABLE>
<CAPTION>
                                     Outstanding
                         ---------------------------------
                                                                    Exercisable
                             Number                                    Number
    Exercise Price          Of Shares       Remaining life           of Shares
    --------------          ---------       --------------           ---------
         <S>                <C>                <C>                   <C>
         0.54                 200,000          2.8 years               200,000
         0.85                  25,000          3.0 years                25,000
         0.90                  50,000          2.9 years                50,000
         1.25                 250,000          3.1 years               250,000
         1.50                  60,000          4.7 years                60,000
         2.30                  15,000          3.5 years                15,000
         2.35                 400,000          3.9 years               325,000
         2.44               1,125,000          3.4 years             1,125,000
         2.54                  30,000          3.6 years                30,000
         2.56                  75,000          3.3 years                75,000
                         ------------                             ------------
                            2,230,000                                2,155,000
                         ============                             ============
</TABLE>

NOTE 10 -- COMMITMENTS AND CONTINGENCIES

Dune signed new employment agreements with Alan Gaines (CEO) and Amiel David
(President/COO). Each of the agreements is for an initial term of twenty five
(25) months, commencing May 12, 2005 and expiring on June 30, 2007. The
agreements provide for base salaries as follows: Mr. Gaines - $400,000 for the
first thirteen (13) months and $460,000 for the next twelve (12) months; Dr.
David - $300,000 for the first thirteen (13) months and $330,000 for the next
twelve (12) months. Mr. Gaines' agreement provides that for each of the 12
months ended June 30, 2006 and 2007, he will be entitled to receive a
performance bonus equal to one percent (1%) of Dune's "free cash flow" (defined
as Dune's earnings before depreciation, depletion, amortization and capital
expenditures) up to $8 million and two percent (2%) of free cash flow above $8
million. Dr. David shall be entitled to receive a performance bonus equal to


                                      F-15
<PAGE>

three quarters of one percent (.75%) of Dune's "free cash flow" up to $8 million
and one and one half percent (1.5%) of free cash flow above $8 million. The
agreements provide that in the event Mr. Gaines or Dr. David are terminated
without "cause" (as defined in the agreements), they are to receive a severance
payment equal to the greater of (i) twelve (12) months base salary and (ii)
their base salary for the remainder of the term. Each agreement contains
covenants restricting each of the foregoing officers from participating in any
business which is then engaged in the drilling, exploration or production of
natural gas or oil, within the area contemplated by that certain Area of Mutual
Interest Agreement dated November 17, 2003 between Dune and Vaquero Oil & Gas,
Inc. In connection with their extensions, Dune granted stock options to Mr.
Gaines and Dr. David to acquire 625,000 and 500,000 shares of Dune's common
stock, respectively. Of the 625,000 options granted to Mr. Gaines, 250,000
vested immediately, with an additional 250,000 and 125,000 vesting on each of
the next two anniversary dates. Of the 500,000 options granted to Dr. David,
250,000 vested immediately and 250,000 vest on the first anniversary date.

On April 4, 2006, Dune entered into an employment agreement with Hugh Idstein to
serve as the Company's Chief Financial Officer. The agreement was for an initial
term of one year and provides for a base salary of $160,000 per annum. In
addition, upon completion of the initial term, Mr. Idstein will receive a
guaranteed bonus of $24,000 and will be eligible for a discretionary performance
bonus up to an additional $32,000. The Agreement provides that in the event Mr.
Idstein is terminated without "cause" (as defined in the Agreement), he will
receive a severance payment equal to six (6) months base salary. His agreement
also contains covenants restricting him from participating in any business which
is then engaged in the drilling, exploration or production of natural gas or
oil, within the area contemplated by that certain Area of Mutual Interest
Agreement dated November 17, 2003 between Dune and Vaquero Oil & Gas, Inc.

In October 2006, Dune amended the lease for office space in Houston, Texas to
expand its space to 5,373 square feet. The monthly rent is now $8,703 per month
and expires July 31, 2009. The future minimum lease payments are $266,201.

               Year ending December 31,                Amount
               ------------------------                ------

                         2007                       $  104,540
                         2008                          105,649
                         2009                           56,012
                                                    ----------
                                                    $  266,201
                                                    ==========

There were no material outstanding contingent liabilities at December 31, 2006.

NOTE 11 -- INCOME TAXES

The tax effect of temporary differences that give rise to significant portions
of the deferred tax assets and deferred tax liabilities at December 31, 2006 and
2005 are as follows:

                                                2006              2005
      Federal income taxes:
        Current                             $        --       $        --
        Deferred                              7,007,631         1,738,659
        Less: Valuation allowance            (7,007,631)       (1,738,659)
                                            -----------       -----------
          Total                             $        --       $        --
                                            ===========       ===========

Dune had net operating loss carryforwards of approximately $20,600,000 as of
December 31, 2006. Available carryforwards expire 15 to 20 years from when
incurred.

NOTE 12 -- UNAUDITED PRO FORMA INFORMATION

On December 16, 2005, Dune Energy, Inc. ("Dune") acquired certain producing and
non-producing natural gas properties and related property and equipment located
in the Barnett Shale play in the North Texas Fort Worth Basin, from Voyager
Partners, Ltd. ("Voyager"). The purchase price for the properties was $24.6
million with an effective date of May 1, 2005.


                                      F-16
<PAGE>

Voyager logged the first well on the Voyager Property on March 26, 2004 and
recognized its first Proved Undeveloped Reserves. February, 2005 marked the
first month of production when the first well was fracture stimulated and turned
to sales. By the time of our purchase, four wells were drilled, completed,
fracture stimulated and on sales.

On November 17, 2005, Dune Energy, Inc. ("Dune") acquired interests in oil and
gas properties (the "Springside Properties") from Voyager. Dune paid a total of
$5,451,362 for the Springside Properties with an effective date of July 1, 2005.

The following unaudited pro forma information for the year ended Decmeber 31,
2005 is presented to show the pro forma effects of the acquisition of oil and
gas properties from the Voyager Property and the Springside Properties during
the fourth quarter of 2005.

                                          As reported          Pro forma
                                          -----------          ---------
      Revenues                            $ 3,724,278         $ 5,708,590
      Net loss                             (1,584,643)         (3,590,035)
      Net loss per share                        (0.03)              (0.07)

NOTE 13 -- SUBSEQUENT EVENTS

On January 24, 2007, Dune's Board of Directors granted a stock option to
purchase up to 200,000 shares of common stock to Dune's President, and options
to purchase an aggregate of 300,000 shares of common stock to Dune's six outside
directors. All options expire on January 24, 2012 and may be exercised at $1.94
per share.

On January 30, 2007, Dune announced that it had acquired Louisiana State Lease
19246, which totals 2,498 acres, and is located on the north shore of Lake
Salvador. The property is contiguous to Dune's highly prospective Bayou Couba
salt dome acreage in St. Charles Parish. The lease has an initial term of one
year, with two annual extensions possible, unless drilled and subsequently
converted to a production lease. The royalty payable to the State of Louisiana
is 22.5%. The acquisition of this acreage reflected management's strong
conviction regarding the likelihood of the existence of substantial oil and
natural gas reserve potential, which could materially increase future
production, cash flow and proved reserves.

In February 2007, Dune acquired 8% Convertible Secured Debentures issued by
American Natural Energy Corp., in the aggregate principal amount of $4,895,000.
In exchange for such debentures, Dune issued 1,380,641 shares of its common
stock.

On March 5, 2007 Dune announced it decided not to purchase 1,600 acres from
Voyager Partners, Ltd. ("Voyager") for cash consideration of approximately $25.8
million, as previously contemplated. The properties are located in the Barnett
Shale play in Denton County, Texas. In addition, Dune released and discharged
outstanding obligations due from Voyager totaling $1.35 million, stemming from
joint interest expenses covering oil and gas leases and retained interests. In
exchange for the $1.35 million owed to Dune, Voyager has conveyed to Dune, its
undivided 5% working interest in those Barnett Shale properties 95% owned by
Dune prior to the conveyance.


NOTE 14 -- RESTATEMENT OF PREVIOUSLY ISSUED FINANCIAL STATEMENTS

Summary of Restatement Items

In April 2007, Dune concluded that it was necessary to restate its financial
results for the fiscal year ended December 31, 2006 to record additional proved
property impairment expense related to the revision of the Reserve Report of
Independent Engineer for the correction of prices used in the calculation of
year end reserves. Dune had previously recognized impairment of the $33,166,802.
After further review, Dune has determined that the prices used by the
independent engineer to determine the estimated value of reserves in the reserve
report were too high thus overstating the value of the related reserves. As a
result, Dune has obtained a revised report and has increased the proved property
impairment expense to $42,913,184. Dune has also revised the supplement oil and
gas disclosure to conform to the revised reserve report.

The consolidated financial statements and other financial information in this
Amendment No. 1 to the December 31, 2006 Form 10-KSB have been restated
accordingly.


                                      F-17
<PAGE>

As summary of the effects of this restatement is shown in the following table:

<TABLE>
<CAPTION>
                                                                      As previously
                                                                        reported                As restated
     <S>                                                              <C>                      <C>
     Consolidated Balance Sheet
       Net oil and gas properties                                     $ 50,820,426             $ 41,074,044
       Total assets                                                     60,604,932               50,858,550
       Accumulated deficit                                             (49,148,218)             (58,894,600)
       Total stockholders' deficit                                      (5,503,270)             (15,249,652)

     Consolidated Statement of Operations
       Proved property impairment expense                               33,166,802               42,913,184
       Total operating expense                                          44,428,107               54,174,489
       Operating loss                                                  (36,848,073)             (46,594,455)
       Net loss                                                        (43,889,309)             (53,635,691)
       Net loss per share, basic and diluted                                 (0.75)                   (0.92)
</TABLE>

NOTE 15 -- SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

Capitalized Costs

Capitalized costs incurred in property acquisition, exploration and development
activities as of December 31, 2006 are as follows:

   Total capitalized costs:
     Properties being amortized                                $ 83,503,586
     Properties not subject to amortization                       5,856,461
   Less: Accumulated depletion, depreciation and impairment     (48,286,003)
                                                               ------------
   Net capitalized costs                                       $ 41,074,044
                                                               ============

Costs incurred for property acquisition, exploration and development activities
for the year ended December 31, 2006 are as follows:

<TABLE>
<CAPTION>
Acquisition of properties:                 Evaluated     Unevaluated        Total
<S>                                       <C>            <C>            <C>
  Proved                                  $36,527,938    $         0    $36,527,938
  Unproved                                          0        391,221        391,221
Exploration and development activities              0      2,395,041      2,395,041
                                          -----------    -----------    -----------
Total Costs                               $36,527,938    $ 2,786,262    $39,314,200
                                          ===========    ===========    ===========
</TABLE>

Oil and Gas Reserve Data

An independent petroleum engineer estimated proved developed and undeveloped
reserves for Dune's properties. Reserve definitions and pricing requirements
prescribed by the Securities and Exchange Commission were used. The
determination of oil and gas reserve quantities involves numerous estimates
which are highly complex and interpretive. The estimates are subject to
continuing re-evaluation and reserve quantities may change as additional
information becomes available. Estimated value of proved reserves was computed
by applying prices in effect at December 31, 2006. The average price used was
$61.05 per barrel of oil at $5.64 per Mcf of gas.

<TABLE>
<CAPTION>
                                                            2006                                   2005
                                             ----------------------------------     ----------------------------------
                                                Oil          Gas                       Oil         Gas
                                              (MBbls)      (MMcf)        MMcfe       (MBbls)      (MMcf)        MMcfe
                                             --------     --------     --------     --------     --------     --------
<S>                                              <C>       <C>          <C>            <C>         <C>          <C>
Proved developed and undeveloped reserves
      Beginning of year                           578       26,047       29,515        1,309        5,534       13,388
      Purchases                                    86       13,166       13,682           75       18,307       18,758
      Discoveries and extensions                    2           56           68           --           --           --
      Improved recovery                            --           --           --           --           --           --
      Revisions of previous estimates            (191)     (11,625)     (12,771)        (794)       2,570       (2,194)
      Production                                  (35)        (880)      (1,090)         (12)        (364)        (438)
                                             --------     --------     --------     --------     --------     --------
      End of year                                 440       26,764       29,404          578       26,047       29,514
                                             ========     ========     ========     ========     ========     ========

Proved developed reserves:
      Beginning of year                           131        5,432        6,218            3          965          983
      End of year                                 174       12,696       13,740          131        5,432        6,218
</TABLE>


                                      F-18
<PAGE>

In 2005, we reflected a negative revision to oil reserves due to disappointing
drilling results at Pearsall. In addition, we recorded a positive revision to
gas reserves due to drilling success at Welder Ranch and Los Mogotes.

In 2006, we reflected a negative revision to oil reserves for Pearsall due to
plugging one well, and revised down oil reserves for Welder Ranch, and Los
Mogotes due to disappointing production results. In addition, Dune had positive
revisions to oil reserves for the Barnett Shale and Bayou Couba for better than
expected oil production. Dune reflected a negative revision to gas reserves on
the Bayou Couba, Welder Ranch and Barnett Shale as production was disappointing
compared to original estimates. Los Mogotes gas reserves were revised up for
2006.

Standardized measure of discounted future net cash flows are as follows:

<TABLE>
<CAPTION>
                                                              Year Ended December 31,
                                                               -----------------------
                                                                  2006          2005
                                                               ---------     ---------
                                                                    (In Thousands)
<S>                                                            <C>           <C>
   Future cash inflows                                         $ 174,385     $ 281,498
   Future production costs                                        59,908        57,336
   Future development costs                                       42,705        46,266
   Future income tax expense                                       2,961        34,285
                                                               ---------     ---------

     Future gross cash flows                                      68,811       143,611

   Less: 10% annual discount of
      estimated timing of cash flows                             (35,175)      (48,135)
                                                               ---------     ---------

Standardized measure of discounted future net cash flows
   relating to proved oil and gas reserves                     $  33,636     $  95,476
                                                               =========     =========

<CAPTION>
                                                                  2006          2005
                                                               ---------     ---------
                                                                    (In Thousands)
<S>                                                            <C>           <C>
Beginning of year                                              $  95,476     $  37,190
     Sales of oil and gas produced, net of production costs       (5,569)       (3,005)
     Net changes in prices and production costs                  (38,710)       18,836
     Sales of reserves                                           (18,962)           --
     Discoveries, improved recovery                                  347            --
     Net changes in estimated future development costs             5,708        (2,947)
     Revisions                                                   (25,147)      (10,347)
     Purchase of reserves                                         22,404        48,326
     Net change in timing                                        (28,668)       (2,130)
     Accretion discount                                            9,681         3,719
     Future income tax expense                                    17,076         5,834
                                                               ---------     ---------

End of year                                                    $  33,636     $  95,476
                                                               =========     =========
</TABLE>


                                      F-19
<PAGE>

Item 8. Changes in and Disagreements with Accountants on Accounting and
        Financial Disclosure.

      None.

Item 8A. Controls and Procedures.

      We maintain disclosure controls and procedures that are designed to ensure
that information required to be disclosed in its Exchange Act reports is
recorded, processed, summarized and reported within the time periods specified
in the SEC's rules and forms, and that such information is accumulated and
communicated to our management, including our Chief Executive Officer and Chief
Financial Officer, as appropriate, to allow timely decisions regarding required
disclosure based closely on the definition of "disclosure controls and
procedures" in Rule 13a-15(e). In designing and evaluating the disclosure
controls and procedures, management recognized that any controls and procedures,
no matter how well designed and operated, can provide only reasonable assurance
of achieving the desired control objectives, and management necessarily was
required to apply its judgment in evaluating the cost-benefit relationship of
possible controls and procedures.

      At the end of the period covered by this Annual Report, we carried out an
evaluation, under the supervision and with the participation of our management,
including our Chief Executive Officer and Chief Financial Officer, of the
effectiveness of the design and operation of the Company's disclosure controls
and procedures. Based upon the foregoing, our Chief Executive Officer and Chief
Financial Officer concluded that, as of December 31, 2006, the disclosure
controls and procedures of the Company were not effective to ensure that the
information required to be disclosed in the Company's Exchange Act reports was
recorded, processed, summarized and reported on a timely basis. Management's
conclusion was based on the restatement of the proved property impairment
expense relating to the revision of the Reserve Report of our Independent
Engineer for the correction of natural gas prices used in the calculation of our
year end reserves. We are implementing procedures whereby reports received from
our outside consultants/advisors are more thoroughly reviewed.


      There were no changes in internal controls over financial reporting that
occurred during the fiscal quarter ended December 31, 2006, that have materially
affected, or are reasonably likely to materially affect, our internal control
over financial reporting.

                                    PART III

Item 9. Directors, Executive Officers, Promoters and Control Persons; Compliance
        with Section 16(a) of the Exchange Act.

      The following table sets forth information with respect to our directors
and executive officers.

Name                               Age     Position
-------------------                ---     -------------------------------------
Alan Gaines                        51      Chairman and Chief Executive Officer
Amiel David                        67      President and Chief Operating Officer
Hugh Idstein                       48      Chief Financial Officer
Richard M. Cohen                   55      Director and Secretary
Steven Barrenechea                 47      Director
Igor Marchenko                     38      Director
Raissa S. Frenkel                  45      Director
Steven M. Sisselman                48      Director
Marshall Lynn Bass                 37      Director

      Alan Gaines is the Chairman and Chief Executive Officer of the Company and
has served as a Director of the Company since May 2001. Since April 2005, Mr.
Gaines has served as Vice Chairman of Baseline Oil & Gas Corp., a public
company. In 1983, Mr. Gaines founded Gaines, Berland Inc., a full service
brokerage firm and investment bank specializing in global energy markets, with
particular emphasis given to small to mid-capitalization exploration and
production, pipeline, midstream, and oilfield services companies. Mr. Gaines
served as President of Gaines, Berland from 1983 to 1998. Mr. Gaines holds a BBA
in Finance from Baruch College, and an MBA ("With Distinction") from the Zarb
School, Hofstra University School of Management.


                                       31
<PAGE>

      Amiel David has served as the President/Chief Operating Officer of the
Company since February 2004 and has over 35 years of engineering and investment
banking experience within the energy sector. From 1993 - 2001, he was the Senior
Vice President and Chief Engineer for the First City Bank and later First Union
Securities (Wachovia Bank) where he was responsible for the technical viability
of in excess of $3.5 billion of energy credits. From 2001 through 2003, Dr.
David was the Managing Director, Senior Vice President and Chief Engineer of
Duke Capital Partners. Dr. David holds a PhD in Petroleum Engineering from
Stanford University and an MBA from The University of Pittsburgh.

      Hugh Idstein has served as the Chief Financial Officer of the Company
since April 4, 2005. Prior to joining our Company, Mr. Idstein served as CFO of
Houston based Black Stone Minerals Company, L.P., an oil and gas mineral
exploration company. In addition Mr. Idstein has acted as a consultant for
several oil and gas companies regarding international oil and gas opportunities.
He earned an MBA and a BS in Energy Management from Eastern Illinois University.

      Richard M. Cohen has served as a Director of the Company since December
2003. From December 2003 to April 2005, he served as our Chief Financial
Officer. Since 1996, Mr. Cohen has been the President of Richard M. Cohen
Consultants, a private financial services consulting company that assists both
public and private companies with their corporate governance and corporate
finance needs. In 1999, Mr. Cohen was the President of National Auto Credit, a
publicly traded sub-prime auto finance company. From 1992-1995, Mr. Cohen was
the President of General Media Inc., a publicly reporting international
diversified publishing and communications company. Mr. Cohen is a Certified
Public Accountant and worked at Arthur Andersen & Co. from 1975 to 1977. He
received a BS ("With Honors") from The University of Pennsylvania (Wharton) and
an MBA from Stanford University.

      Steven Barrenechea has served as a Director of the Company since May 2001.
From April 2005 to January 2006, Mr. Barrenechea served as a Director of
Baseline Oil & Gas Corp., a public company. Mr. Barrenechea is a member of the
Board of Directors of the Creative Coalition, The Milford (Connecticut) Red
Cross, and The Child Guidance Center of Fairfield County. Mr. Barrenechea holds
a BBA from New York University.

      Igor Marchenko has served as a Director of our Company since February 1,
2007. Mr. Marchenko presently serves as Vice-President International Projects
and Business Structuring to the Itera Group, an affiliate of Itera Holdings BV.
From February 2006 through October 2006, he served as a Director of Merchant
Banking at Renaissance Capital and from February 1997 through February 2006, he
held various positions at JSC Sibneft, a large vertically integrated oil and gas
company.

      Raissa Frenkel has served as a Director of our Company since May 2004. Dr.
Frenkel has been a member of the Board of Directors of the Itera Oil and Gas
Company Ltd (Itera) since 2002. Itera's operating entities are engaged in the
business of production, transportation, marketing and sales of natural gas
throughout the Former Soviet Union. Since 2003, Dr. Frenkel has been Executive
Vice-President of Itera International Energy Corp. an Itera subsidiary operating
in the US gas, real estate and commodity business. From 1994-2002 Dr. Frenkel
was a Vice-President with Itera International Energy Corp. She graduated from
the Kazan Finance and Economics Institute in 1982 and received her PHD from
Kazan State University in 1989.

      Steven Sisselman has served as a Director of our Company since May 2004.
From 1995 to the present, Mr. Sisselman has been a Vice-President of Business
Development with Itera International Energy Corp., an Itera subsidiary operating
in the US gas, real estate and commodity business. From 1992-1994, Mr. Sisselman
was Vice-President of Dalon Inc., a petroleum trading company, responsible for
trading crude oil and petroleum products from the former Soviet Union. For the
12 years prior to 1992, Mr. Sisselman was employed by Charter Oil Company, UBS
AG, and Astra Oil working in various financial and trading positions both in the
US and London, England. He graduated from University of Florida in 1980 with a
BS in Business Administration with a major in Finance.


                                       32
<PAGE>

      Marshall Lynn Bass has served as a Director of our Company and a member of
the Company's audit committee since September 29, 2004. From 1998 to December
2001, he served as an associate, and from 2002 to present, he served as a
principal of Weisser, Johnson & Co., a Houston based energy investment bank. He
is also a principal and co-founder of GasRock Capital, LLC, a finance company
which makes direct investments in energy companies or projects. He graduated
from Purdue University in 1992 with a BS in economics and from Rice University
with a Masters in business administration.

Section 16(a) Beneficial Ownership Reporting Compliance

      Section 16(a) of the Securities Exchange Act of 1934 requires our
directors, executive officers and beneficial owners of more than 10% of our
Common Stock to file with the SEC reports of their holdings of, and transactions
in, our Common Stock. Based solely upon our review of copies of such reports and
written representations from reporting persons that were provided to us, we
believe that our officers, directors and 10% stockholders complied with these
reporting requirements with respect to 2005.

Code of Ethics

      The Company has adopted a written code of ethics that applies to the
Company's principal executive officer, principal financial officer, principal
accounting officer and any persons performing similar functions. The Company
will provide a copy of its code of ethics to any person without charge upon
written request addressed to Dune Energy, Inc., 3050 Post Oak Blvd., Suite 695,
Houston, Texas 77056.


                                       33
<PAGE>

Item 10. Executive Compensation.

      The following table shows for fiscal years ended December 31, 2006, 2005
and 2004, respectively, certain compensation which we awarded or paid to, or
which was earned from us by, our executive officers (collectively, the "Named
Executive Officers").

                       Summary Compensation Table

<TABLE>
<CAPTION>
                                                                                                    Long Term
                                                          Annual Compensation                      Compensation
                                                     ----------------------------     ------------------------------------
                                                                                                          Securities Under
                                                                                                          Options Granted
                                      Fiscal                                           Other Annual    Or Restricted Stock
Name and Principal Position            Year          Salary($)           Bonus($)     Compensation($)         Award (#)
---------------------------            ----          ---------           --------     ---------------         ---------
<S>                                    <C>           <C>                  <C>           <C>                    <C>
Alan Gaines,                           2006          434,987(1)               --        $ 11,867(2)                 --
Chairman and Chief Executive           2005          408,333(3)               --          14,203(2)            625,000
Officer                                2004          262,920                  --              --                    --

Amiel David,                           2006          317,493(1)               --          16,122(2)                 --
President and Chief Operating          2005          287,498(3)               --          14,076(2)            750,000
Officer                                2004          143,956                  --              --                    --

Hugh Idstein,                          2006          153,755              40,500          18,132(2)            100,000
Chief Financial Officer                2005          103,631                  --          16,279(2)             75,000
                                       2004               --                  --              --                    --
</TABLE>

(1)   Includes salary for January 2007 paid in 2006.
(2)   Represents amounts paid by the Company for health insurance premiums.
(3)   Includes salary for January 2006 paid in 2005.


                                       34
<PAGE>

                        Option Grants in Last Fiscal Year

      As set forth in the following table, during 2006 we granted the following
stock options to the Named Executive Officers:

                    Option Grants In Last Fiscal Year (2006)

<TABLE>
<CAPTION>
                                                   Number of         % of
                                                  Securities     Total Options
                                                  Underlying      Granted to
                                                    Options      Employees in       Exercise      Expiration
                                         Year       Granted       Fiscal Year         Price          Date
                                         ----       -------       -----------         -----          ----
<S>                                      <C>       <C>                <C>             <C>           <C> <C>
Hugh Idstein .......................     2006      100,000(1)         62%             $2.35         4/4/11
</TABLE>

1.    Mr. Idstein received options to purchase 100,000 shares at $2.35 per
      share. Such options vested with respect to 25,000 shares immediately as of
      the date of grant (April 4, 2006) and will vest with respect to 50,000
      shares on April 4, 2007 and an additional 25,000 shares on April 4, 2008.

                 Aggregated Option Exercises in Last Fiscal Year
                        and Fiscal Year-End Option Values

                        Option Value at December 31, 2006

<TABLE>
<CAPTION>
                                                Number of Securities                           Value of
                                               Underlying Unexercised                  Unexercised In-The-Money
                                            Options at December 31, 2006             Options at December 31, 2006
                                          --------------------------------        ---------------------------------
                                          Exercisable        Unexercisable        Exercisable(1)   Unexercisable(1)
                                          -----------        -------------        --------------   ----------------
<S>                                       <C>                 <C>                  <C>                  <C>
Alan Gaines .....................         500,000 (2)         125,000 (2)          $      0 (2)         $0 (2)
Amiel David .....................         750,000 (3)             -0-              $270,000 (3)         $0 (3)
Hugh Idstein ....................          75,000 (4)         100,000 (4)          $      0 (4)         $0 (4)
</TABLE>

(1)   Based on the last sale price of the Common Stock at $2.33 on December 29,
      2006, the last trading day of 2006.

(2)   Reflects option granted on May 12, 2005, exercisable for up to 625,000
      shares at $2.44 per share.

(3)   Reflects (i) option granted on February 15, 2005, exercisable for up to
      250,000 shares at $1.25 per share and (ii) option granted on May 12, 2005,
      exercisable for up to 625,000 shares at $2.44 per share.

(4)   Reflects (i) 50,000 shares underlying an option granted on April 4, 2005,
      exercisable at $2.56 per share and (ii) 25,000 shares underlying an option
      granted on April 4, 2006, exercisable at $2.35 per share.


                                       35
<PAGE>

Employment Agreements

      Both Alan Gaines, our Chairman and CEO, and Amiel David, our President and
COO, entered into Employment Agreements with us in May 2005 that extended the
term of their employment from May 31, 2005 to June 30, 2007. Per their
respective agreements, Mr. Gaines receives a base salary of $400,000 in year one
and a base salary of $460,000 in year two of his contract. Dr. David receives a
base salary of $300,000 in year one and $330,000 in year two. Mr. Gaines'
agreement provides that, for the twelve months ended June 30, 2006 and 2007, he
will be entitled to receive a performance bonus equal to one percent (1%) of our
"free cash flow" (defined as our earnings before depreciation, depletion,
amortization and capital expenditures) up to $8 million and two percent (2%) of
free cash flow above $8 million. Dr. David shall be entitled to receive a
performance bonus equal to three quarters of one percent (0.75%) of our "free
cash flow" up to $8 million and one and one half percent (1.5%) of free cash
flow above $8 million. The agreements provide that in the event Mr. Gaines or
Dr. David are terminated without "cause" (as defined in the agreements), they
are to receive a severance payment equal to the greater of (i) twelve (12)
months base salary and (ii) their base salary for the remainder of the term.
Each agreement contains covenants restricting each of the foregoing officers
from participating in any business which is then engaged in the drilling,
exploration or production of natural gas or oil, within the area contemplated by
that certain Area of Mutual Interest Agreement, dated November 17, 2003, between
us and Vaquero Partners. In connection with their Agreements, we granted stock
options to Mr. Gaines and Dr. David to acquire 625,000 and 500,000 shares of our
Common Stock, respectively. During the first quarter of 2007, we granted stock
options to Dr. David to acquire up to an additional 200,000 shares of common
stock at an exercise price of $1.94 per share. Such stock option is fully vested
and expires January 29, 2012.

      On April 4, 2006, we extended our Employment Agreement (the "Idstein
Agreement") with Hugh Idstein, our Chief Financial Officer. The Idstein
Agreement is for an additional term of one year and provides for a base salary
of $160,000 per annum. In addition, upon completion of the current term, Mr.
Idstein will receive a guaranteed bonus of $24,000 and will be eligible for a
discretionary performance bonus up to an additional $32,000. Upon signing the
Idstein Agreement, we granted a five year stock option to Mr. Idstein, to
purchase up to 100,000 shares of our Common Stock, at an exercise price of $2.35
per share. The option is immediately exercisable with respect to 25,000 shares.
The option is exercisable for an additional 50,000 shares on the first
anniversary date of the grant and an additional 25,000 shares on the second
anniversary date of the grant, provided that Mr. Idstein is employed by us on
such dates. The Idstein Agreement provides that, in the event Mr. Idstein is
terminated without "cause" (as defined in the Idstein Agreement), he will
receive a severance payment equal to six (6) months' base salary. The Idstein
Agreement also contains covenants restricting Mr. Idstein from participating in
any business which is then engaged in the drilling, exploration or production of
natural gas or oil, within the area contemplated by that certain Area of Mutual
Interest Agreement, dated November 17, 2003, between us and Vaquero Partners.

Director Compensation

      Each of our outside Directors receives $5,000 per quarter for serving on
the Board and $1,000 per quarter for serving on a committee. Except as set forth
above, Directors are not compensated in cash for their services but are
reimbursed for out of pocket expenses incurred in furtherance of our business.
In January of 2007, pursuant to the Company's 2005 Non-Employee Director
Incentive Plan, we granted stock options to acquire up to 50,000 shares of
Common Stock to each of our six outside directors. Such stock options may be
exercised at any time prior to January 24, 2012 at an exercise price of $1.94
per share.


                                       36
<PAGE>

Item 11. Security Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters.

      The following table sets forth certain information regarding the
beneficial ownership of our Common Stock as of March 15, 2007 by (i) each person
who, to our knowledge, beneficially owns more than 5% of our outstanding Common
Stock; (ii) each of our current directors and executive officers (titles are set
forth in parentheses next to the names of individuals listed below); and (iii)
all of our current and executive officers and directors as a group:

Name of                                                                 Percent
Beneficial Owner                                     Amount(1)          of Class
----------------                                     ---------          --------

Itera Holdings BV                                    35,464,397          58.3%
Alan Gaines (Chairman and CEO)                      3,315,501(2)          5.4%
Amiel David (President and COO)                     1,106,250(3)          1.8%
Hugh Idstein (Chief Financial Officer)              150,000((4))           *
Steven Barrenechea (Director)                     222,500((5))(6)          *
Richard M. Cohen (Secretary and Director)           312,185((6))           *
Steven Sisselman (Director)                         100,000((6))           *
Raissa S. Frenkel (Director)                        100,000((6))           *
Marshall Lynn Bass (Director)                          112,800((6))        *
Igor Marchenko (Director)                                0                 *
All Officers & Directors as a Group (9
persons)                                       5,419,316(2)(3)(4)(5)      8.6%
                                                       (6)(7)

* Indicates ownership of less than 1%.

----------
(1) A person is deemed to be the beneficial owner of securities that can be
acquired by such person within 60 days from March 15, 2007. Each beneficial
owner's percentage ownership is determined by assuming that options that are
held by such person (but not held by any other person), and which are
exercisable within 60 days from March 15, 2007, have been exercised.

(2) Includes 625,000 shares underlying a stock option granted May 12, 2005.

(3) Includes (i) 250,000 shares underlying a stock option granted on February
15, 2005, (ii) 500,000 shares underlying a stock option granted May 12, 2005 and
(iii) 200,000 shares underlying a stock option granted January 24, 2007.

(4) Includes (i) 75,000 shares underlying a stock option granted on April 4,
2005 and (ii) 75,000 shares underlying a stock option granted on April 4, 2006.

(5) Includes 25,000 shares underlying a stock option granted on December 15,
2004.

(6) Includes (i) 50,000 shares underlying a stock option granted on October 28,
2005 and (ii) 50,000 shares underlying a stock option granted on January 24,
2007.

(7) Excludes 50,000 shares underlying a stock option granted on October 28,
2005.


                                       37
<PAGE>

Item 12. Certain Relationships and Related Transactions, and Director
Independence.

      In September 2006, we amended our Term Loan Agreement with our majority
stockholder, Itera Holdings BV ("Itera"). Amounts borrowed from Itera under the
Term Loan Agreement are subordinated to all obligations under our Credit
Agreement and Swap Agreement with our senior lenders and are evidenced by a
Convertible Subordinated Note in the aggregate principal amount of $25 million.
As of April 1, 2007, there was a total of $28,235,380 of principal and accrued
interest outstanding under the Convertible Subordinated Note. See Item 6 - "Debt
Financings".

      In April 2006 we entered into a contract with Itera Rig, LLC to provide a
drilling rig exclusively for our use. Itera Rig LLC is an affiliate of Itera.
The contract is for an initial term of two years with an extension clause. The
fixed day rate of $18,000 was based on current market rates and may be
renegotiated in April of 2007.

      As of March 15, 2007, Itera held 35,464,397 shares of our common stock
which constituted 58.3% of our outstanding common stock on that date. In
addition, three members of our Board of Directors are affiliates of Itera. As a
result, Itera is a parent of the Company.

      Our independent directors are Steven Barrenechea and Marshall Lynn Bass.
Mr. Bass and Mr. Barrenechea serve on our audit committee. Our Common Stock is
listed on the American Stock Exchange ("AMEX") and we are subject to its rules
with respect to director independence. Under AMEX rules, by virtue of Itera's
ownership of more than 50% of the voting power of the Company, we are a
"controlled company" and we are not required to comply with the requirement that
a majority of our board of directors be independent.

      During 2006, our Board of Directors held four meetings and no director
attended fewer than 75% of such meetings. We do not have a Nominating Committee
or a Compensation Committee. Messrs. Bass and Barrenechea constitute the Audit
Committee of our Board of Directors, established by the Board in accordance with
Section 3(a)(58)(A) of the Exchange Act, for the purpose of overseeing our
accounting and financial reporting processes and the audits of our financial
statements.


                                       38
<PAGE>

Item 13. Exhibits.

Exhibit Nos.
------------

3.1             Amended and Restated Certificate of Incorporation (1)

3.1.1           Certificate of Designation for Series A Convertible Preferred
                Stock (2)

3.2             Amended and Restated By-Laws (3)

4.1             Form of Convertible Subordinated Note, issued November 17, 2005,
                from the Registrant to Itera Holdings BV (12)

4.1.1           Form of Convertible Subordinated Note issued November 17, 2005,
                as amended and restated August 31, 2006, from Registrant to
                Itera Holdings BV (13)

4.1.2           Form of Convertible Subordinated Note issued November 17, 2005,
                as amended and restated September 26, 2006, from Registrant to
                Itera Holdings BV (14)

4.2             Form of Placement Agent Warrant

4.3             Form of Investor Registration Rights Agreement

4.4             Form of Warrant, dated as of September 26, 2006, from Registrant
                to Bernard National Senior Funding, Ltd. and Drawbridge Special
                Opportunities Fund LP (14)

10.1            Oil and Gas Lease and Option Agreement dated as of August 22,
                2003 between the Registrant and the Lessors named therein with
                respect to the Welder property (1)

10.1.1          Amendment to the First Welder Lease Agreement dated February 5,
                2004 (4)

10.1.2          Second Amendment to the First Welder Lease Agreement dated April
                8, 2004 (5)

10.1.3          Oil and Gas Lease dated as of August 19, 2004 between the
                Registrant and the Lessors named therein with respect to the
                Welder property (6)

10.2            Agreement dated as of October 30, 2003 between the Registrant
                and Penroc Oil Corporation with respect to Los Mogotes (1)

10.2.1          Closing Agreement with Penroc (7)

10.2.2          Assignment, Conveyance and Bill of Sale with respect to Los
                Mogotes (7)

10.3            Agreement dated as of September 26, 2003 between the Registrant
                and Seitel Data, Ltd. With respect to 3-D seismic data (1)

10.3.1          Amendment to Seitel Agreement dated December 28, 2003 (4)

10.4            Agreement dated as of August 22, 2003 by and among Vaquero
                Partners LLC, Vaquero Oil & Gas, Inc., and the Registrant (1)

10.4.1          Amendment dated November 17, 2003 to Agreement between Vaquero
                Partners LLC, Vaquero Oil & Gas, Inc., and the Registrant (4)

10.4.2          Amendment dated May 18, 2004 to Agreement between Vaquero
                Partners LLC, Vaquero Oil & Gas, Inc., and the Registrant (7)

10.5            Area of Mutual Interest Agreement dated November 17, 2003
                between the Registrant and Vaquero Oil & Gas, Inc. (4)

10.6            Employment Agreement dated as of April 4, 2005 between the
                Registrant and Hugh Idstein (8)

10.7            Employment Agreement dated as of May 12, 2005 between the
                Registrant and Alan Gaines (9)


                                       39
<PAGE>

Exhibit Nos.
------------

10.8            Employment Agreement dated as of May 12, 2005 between the
                Registrant and Amiel David (9)

10.9            Amended and Restated Asset Purchase and Sale Agreement between
                Voyager Partners, Ltd. and the Registrant, dated November 4,
                2005 (10)

10.9.1          Second Amended and Restated Asset Purchase and Sale Agreement
                dated as of October 6, 2006 between Voyager Partners, Ltd. and
                Registrant (15)

10.9.2          Fifth Amendment to Second Amended and Restated Asset Purchase
                and Sale Agreement dated as of January 31, 2007 between Voyager
                Partners, Ltd. and Registrant (16)

10.9.3          Final Closing Agreement dated as of February 22, 2007 between
                Voyager Partners, Ltd. and Registrant (17)

10.10           Exploration and Development Agreement between Registrant and
                American Natural Energy Corporation, dated effective as of
                August 26, 2005 (11)

10.11           Credit Agreement, dated November 17, 2005, among Registrant,
                Standard Bank PLC, Standard Americas Inc. as Collateral Agent,
                and Standard Americas Inc. as Sole Lead Arranger and Sole
                Bookrunner (12)

10.11.1         Second Amendment to Credit Agreement dated as of May 15, 2006
                among Registrant, the signatory guarantors and lenders, and
                Standard Bank plc, as administrative agent for lenders (18)

10.11.2         Third Amendment to Credit Agreement dated as of June 1, 2006
                among Registrant, the signatory guarantors and lenders, and
                Standard Bank plc, as administrative agent for lenders (19)

10.11.4         Fifth Amendment to Credit Agreement dated as of August 31, 2006
                among Registrant, the signatory guarantors and lenders, and
                Standard Bank plc, as administrative agent for lenders (13)

10.12           Term Loan Agreement, dated November 17, 2005, between Registrant
                and Itera Holdings BV (12)

10.12.1         Amended and Restated Term Loan Agreement dated as of August 31,
                2006 between Registrant and Itera Holdings BV (13)

10.12.2         Amended and Restated Term Loan Agreement dated as of September
                26, 2006 between Registrant and Itera Holdings BV (14)

10.13           Agreement dated as of June 1, 2006 among Vaquero Partners LLC,
                JVR Petroleum Inc., First Australian Resources, Inc. and
                Chesapeake Exploration Limited Partnership (20)

10.14           Amended and Restated Credit Agreement dated as of September 26,
                2006 among Registrant, lenders party thereto and D.B. Zwirn
                Special Opportunities Fund, L.P., as administrative agent for
                lenders (14)

10.15           Amended and Restated Credit Agreement dated as of September 26,
                2006 among Registrant, lenders party thereto and D.B. Zwirn
                Special Opportunities Fund, L.P., as administrative agent for
                lenders (21)

10.16           Purchase and Sale Agreement dated as of November 14, 2006 among
                Transatlantic Petroleum (USA) Corp., Transatlantic Petroleum
                Corp. and Registrant (22)

21.1            List of Subsidiaries (23)

23.1            Consent of Independent Reserve Engineers

                                       40
<PAGE>

Exhibit Nos.
------------

31.1*           Certification of Chief Executive Officer pursuant to Section 302
                of the Sarbanes-Oxley Act of 2002

31.2*           Certification of Chief Financial Officer pursuant to Section 302
                of the Sarbanes-Oxley Act of 2002

32.1*           Certification pursuant to 18 U.S.C. 1350, adopted pursuant to
                Section 906 of the Sarbanes-Oxley Act of 2002, by Chief
                Executive Officer

32.2*           Certification pursuant to 18 U.S.C. 1350, adopted pursuant to
                Section 906 of the Sarbanes-Oxley Act of 2002, by Chief
                Financial Officer

99.1*           Reserve Report Of Independent Engineer

* Indicates filed herewith

(1) Previously filed as an exhibit to the Registrant's 10-KSB for the year ended
December 31, 2002, and incorporated by reference herein.

(2) Previously filed as an exhibit to the Registrant's 10-QSB for the quarter
ended June 30, 2004, and incorporated by reference herein.

(3) Previously filed as an exhibit to the Registrant's Report on Form 8-K, filed
on May 19, 2004, and incorporated by reference herein.

(4) Previously filed as an exhibit to the Registrant's 10-KSB for the year ended
December 31, 2003, and incorporated by reference herein.

(5) Previously filed as an exhibit to the Registrant's Report on Form 8-K, filed
on April 20, 2004, and incorporated by reference herein.

(6) Previously filed as an exhibit to the Registrant's Report on Form 8-K, filed
on September 8, 2004, and incorporated by reference herein.

(7) Previously filed as an exhibit to the Registrant's Report on Form 8-K, filed
on June 3, 2004, and incorporated by reference herein.

(8) Previously filed as an exhibit to the Registrant's Report on Form 8-K, filed
on April 7, 2005, and incorporated by reference herein.

(9) Previously filed as an exhibit to the Registrant's 10-QSB for the quarter
ended March 31, 2005, and incorporated by reference herein.

(10) Previously filed as an exhibit to the Registrant's Report on Form 8-K,
filed on November 7, 2005, and incorporated by reference herein.

(11) Previously filed as an exhibit to the Registrant's Report on Form 8-K,
filed on October 24, 2005, and incorporated by reference herein.

(12) Previously filed as an exhibit to the Registrant's Report on Form 8-K,
filed on November 21, 2005, and incorporated by reference herein.

(13) Previously filed as an exhibit to the Registrant's Report on Form 8-K,
filed on September 18, 2006, and incorporated by reference herein.


                                       41
<PAGE>

(14) Previously filed as an exhibit to the Registrant's Report on Form 8-K,
filed on September 28, 2006, and incorporated by reference herein.

(15) Previously filed as an exhibit to the Registrant's Report on Form 8-K,
filed on October 12, 2005, and incorporated by reference herein.

(16) Previously filed as an exhibit to the Registrant's Report on Form 8-K,
filed on February 1, 2007, and incorporated by reference herein.

(17) Previously filed as an exhibit to the Registrant's Report on Form 8-K,
filed on March 2, 2007, and incorporated by reference herein.

(18) Previously filed as an exhibit to the Registrant's Form 10-KSB for the
quarter ended March 31, 2006, filed on May 15, 2006, and incorporated by
reference herein.

(19) Previously filed as an exhibit to the Registrant's Report on Form 8-K,
filed on June 21, 2006, and incorporated by reference herein.

(20) Previously filed as an exhibit to the Registrant's Report on Form 8-K filed
on July 24, 2006, and incorporated by reference herein.

(21) Previously filed as an exhibit to the Registrant's Report on Form 8-K,
filed on October 12, 2006, and incorporated by reference herein.

(22) Previously filed as an exhibit to the Registrant's Report on Form 8-K,
filed on December 26, 2006, and incorporated by reference herein.

(23) Previosly filed as an exhibit to the Registrant's Report on Form 10-KSB,
filed on April 2, 2007, and incorporated by reference herein.


                                       42
<PAGE>

Item 14. Principal Accountant Fees and Services.

      During fiscal year 2006 and fiscal year 2005, the aggregate fees which we
paid to Malone & Bailey, PC, our independent auditors, for professional services
were as follows:

--------------------------------------------------------------------------------
                                                      Fiscal Year Ended
--------------------------------------------------------------------------------
                                       December 31, 2006       December 31, 2005
--------------------------------------------------------------------------------
Audit Fees (1)                              $100,000                $62,000
--------------------------------------------------------------------------------
Audit-Related Fees                           N/A                      N/A
--------------------------------------------------------------------------------
Tax Fees (2)                                $11,300                 $9,000
--------------------------------------------------------------------------------
All Other Fees                               N/A                      N/A
--------------------------------------------------------------------------------

(1)   Fees for audit services include fees associated with the annual audit and
      the review of our quarterly reports on Form 10-QSB.

(2)   Consist primarily of professional services rendered for tax compliance,
      tax advice and tax planning.

Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of
Independent Registered Public Accounting Firm.

      As required by the Audit Committee charter, the Audit Committee
pre-approves the engagement of Malone & Bailey, PC for all audit and permissible
non-audit services. The Audit Committee annually reviews the audit and
permissible non-audit services performed by Malone & Bailey, PC, and reviews and
approves the fees charged by Malone & Bailey, PC The Audit Committee has
considered the role of Malone & Bailey, PC in providing tax and audit services
and other permissible non-audit services to us and has concluded that the
provision of such services was compatible with the maintenance of Malone &
Bailey, PC's independence in the conduct of its auditing functions.


                                       43
<PAGE>

                                   SIGNATURES

      In accordance with Section 13 or 15(d) of the Exchange Act, the registrant
has duly caused this report to be signed on its behalf by the undersigned,
thereunto duly authorized.

                                                  DUNE ENERGY, INC.


Date: April 20, 2007                              By: /s/ James A. Watt
                                                      --------------------------
                                                      James A. Watt
                                                      Chief Executive Officer

      In accordance with the Exchange Act, this report has been signed below by
the following persons on behalf of the registrant and in the capacities and on
the dates indicated.

Signature                                                              Date
---------                                                              ----


/s/ James A. Watt                                                 April 20, 2007
-------------------------------------
James A. Watt
Chief Executive Officer


/s/ Frank T. Smith, Jr.                                           April 20, 2007
-------------------------------------
Frank T. Smith, Jr.
Chief Financial Officer


/s/ Alan Gaines                                                   April 20, 2007
-------------------------------------
Alan Gaines
Chairman of the Board


/s/ Richard M. Cohen                                              April 20, 2007
-------------------------------------
Richard M. Cohen
Director and Secretary


/s/ Steven Barrenechea                                            April 20, 2007
-------------------------------------
Steven Barrenechea
Director


/s/ Steven M. Sisselman                                           April 20, 2007
-------------------------------------
Steven M. Sisselman
Director


/s/ William E. Greenwood                                          April 20, 2007
-------------------------------------
William E. Greenwood
Director


                                       44