Dune Energy (DUNRQ) 10-K 2007 FY Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2007

or

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from              to             

Commission file number 000-32497

DUNE ENERGY, INC.

(Exact name of registrant as specified in its charter

Delaware	95-4737507
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
Two Shell Plaza, 777 Walker Street, Suite 2300 Houston, Texas	77002
(Address of principal executive offices)	(Zip Code)

(713) 229-6300

Registrant’s telephone number, including area code

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Name of each exchange on which registered
Common Stock, $0.001 par value	American Stock Exchange, Inc.

Securities registered pursuant to section 12(g) of the Act: None (Title of class)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ¨    No  x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 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  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not 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-K or any amendment to this Form 10-K  x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer," "accelerated filer,” and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer  ¨	Accelerated filer  x
Non-accelerated filer  ¨    (Do not check if a smaller reporting company)	Smaller reporting company  ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes  ¨    No  x

As of June 30, 2007, the aggregate market value of the common stock of the registrant held by non-affiliates (excluding shares held by directors, officers and other holding more than 5% of the outstanding shares of the class) was $75,074,571, based upon a closing sale price of $2.33.

As of March 4, 2008, the registrant had outstanding 79,532,386 shares of common stock.

DOCUMENTS INCORPORATED BY REFERENCE

The information required by Part III will be incorporated by reference into this Form 10-K from the Registrant’s Definitive Proxy Statement to be filed pursuant to Regulation 14A within 120 days after the end of the Registrant’s fiscal year covered by this Form 10-K.

TABLE OF CONTENTS

Cautionary Notice Regarding Forward-Looking Statements	2
PART I	3
Item 1. and Item 2. Business and Properties	3
Item 1A. Risk Factors	16
Item 1B. Unresolved Staff Comments	28
Item 3. Legal Proceedings	28
Item 4. Submission of Matters to a Vote of Security Holders of the Registrant	29
PART II	30
Item 5. Market for Registrant’s Common Stock, Related Shareholder Matters and Issuer Purchases of Equity Securities	30
Item 6. Selected Financial Data	33
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	33
Item 7A. Qualitative and Quantitative Disclosures About Market Risk	43
Item 8. Financial Statements and Supplementary Data	43
Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure	43
Item 9A. Controls and Procedures	43
Item 9B. Other Information	44
PART III	44
Item 10. Directors, Executive Officers and Corporate Governance	44
Item 11. Executive Compensation	44
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters	44
Item 13. Certain Relationships and Related Transactions, and Director Independence	44
Item 14. Principal Accountant Fees and Services	44
PART IV	45
Item 15. Exhibits and Financial Statement Schedules	45
Certificate of Correction to Certificate of Designations, dated February 26, 2008
Form of Global 10 1/2% Senior Secured Exchange Note due 2012
Code of Conduct and Ethics
List of Subsidiaries
Consent of DeGolyer and MacNaughton, independent petroleum engineers
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906
Summary of Reserve Report

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.

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 stockholders issued by us from time to time which attempt to advise interested parties of the risks and factors that may affect our business. Except as may be required under the federal securities laws, 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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PART I

Items 1 and 2. Business and Properties.

Overview

Dune Energy, Inc. (“Dune, the “Company” or “we”) is an independent energy company based in Houston, Texas. Since May of 2004, we have been engaged in the exploration, development, acquisition and exploitation of natural gas and crude oil properties, with interests along the Gulf Coast and in the fairway of the Barnett Shale in north Texas. On May 15, 2007, we acquired all of the capital stock of Goldking Energy Corporation (“Goldking”), whereby we acquired certain assets including additional working interests in natural gas and crude oil properties located onshore and in state waters along the Gulf Coast. Our properties cover over 100,000 gross acres across 23 producing oil and natural gas fields along the Texas and Louisiana Gulf Coast and in the fairway of the Barnett Shale in north Texas.

Our total proved reserves as of December 31, 2007 were 175.4 Bcfe, consisting of 117.6 Bcf of natural gas and 9.6 MMbbls of oil. The PV-10 of our proved reserves at year end was $728.6 million. During 2007, we purchased 109.4 Bcfe, added 45.5 Bcfe through extensions, discoveries and revisions and produced 9 Bcfe.

Our Business Strategy

We intend to use our competitive strengths to continue increasing reserves, production and cash flow in order to maximize value for stockholders. The following are key elements of this strategy:

Grow Through Exploitation, Development and Exploration of Our Properties. We intend to focus our development and exploitation efforts in our Gulf Coast properties, and continue low risk development drilling in the Barnett Shale. We believe that our extensive acreage position within major producing fields will allow us to grow organically through low risk development drilling. We also have opportunities to dramatically expand our reserves and production base through field extensions and deeper pool exploratory tests on our Gulf Coast property base. We will, from time to time, participate in new exploratory ventures in various basins.

Actively Manage the Risks and Rewards of Our Drilling Program. We operate approximately 90% of the reserves comprising our PV-10 as of December 31, 2007. In most major properties our working interest is 100%. This high working interest and operatorship is critical as it allows us to better control the technology applied, the timing of operations and the costs of drilling and production activities. The high working interest also allows us to reduce our working interest in higher risk/high reward projects by bringing in industry partners to disproportionately share the costs associated with exploratory drilling operations. This provides the company the opportunity to participate in the upside opportunities without the full risk cost exposure. We continually review our property base with the idea of monetizing assets that no longer fit our strategic goals.

Maintain and Utilize State of the Art Technological Expertise. We utilize our technical and operations teams’ knowledge of salt-dome structures and multiple stacked producing zones common in the Gulf Coast to enhance our growth prospects and reserve potential. We will employ technical advancements, including 3-D seismic data, pre-stack depth migration, directional drilling, and fracture stimulation techniques to identify and exploit new opportunities in our asset base.

Pursue Opportunistic Acquisitions of Underdeveloped Properties. We continually review opportunities to acquire companies, producing properties, leasehold acreage and drilling prospects. In these acquisitions we are seeking to acquire operational control of properties that we believe have a solid proved reserves base coupled with significant exploitation and exploration potential. We intend to continue to evaluate acquisition opportunities and make acquisitions that we believe will further enhance our operations and reserves in a cost effective manner.

2008 Budget. For 2008 we have adopted a capital budget of $121 million primarily focused on development drilling or low risk exploitation within our existing fields. We anticipate the budget will allow for moving

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approximately 30 Bcfe of PUD reserves to PDP reserves and the budget will expose us to approximately 70 Bcfe of unbooked potential. This budget will be managed to stay within our cash flow and available line of credit and consequently will be most aggressively pursued in the latter half of the year. Early in the year we will focus on field enhancements to increase productive capability, on workovers and on evaluation of our 3-D seismic base. These activities should prepare the company to add more exploratory opportunities into the portfolio for 2009 and 2010.

Employees

As of March 1, 2008, we had 60 full time employees. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We believe our relationships with our employees are good. From time to time, we utilize the services of independent contractors to perform various field and other services.

Offices

Our headquarters are located at Two Shell Plaza, 777 Walker Street, Suite 2300, Houston, Texas 77002. Our telephone number is (713) 229-6300.

Core Areas of Operation and Certain Key Properties

As of December 31, 2007, 80.9% of our proved reserves were located in 23 producing fields along the Texas and Louisiana Gulf Coast (collectively, the “Gulf Coast Properties”) and 19.1% of our proved reserves were located in the Barnett Shale play in North Texas (the “Barnett Shale Properties”). During 2007, we added significant reserves and production through our acquisition of Goldking Energy Corporation, and our aggressive drilling program.

Set forth below is a description of certain key fields and activities completed in 2007 and planned for 2008.

Garden Island Bay (“GIB”). The GIB field is located at the mouth of the Mississippi River in Plaquemines Parish, Louisiana, approximately 75 miles southeast of New Orleans. The field is structured by a large, shallow, piercement salt dome with large radial faults and overhangs. The field was discovered by Texaco in 1934. This field has had cumulative production of over 231 MMbbl of oil and 252 Bcf of natural gas from over 900 primarily shallow wells. The field covers over 16,000 acres and has had minimal deep drilling conducted to date. During 2007 we drilled 10 development wells. In 2008 we anticipate drilling 7 new wells targeting shallow reservoirs defined by the 2007 program and new opportunities defined by a recently reprocessed 3-D data set. We are working toward a depth migration of the existing 3-D data set or potentially a new survey to define deeper exploratory upside on the flanks of the dome and possibly sub-salt opportunities. Drilling for these high potential opportunities will not commence until 2009 or 2010.

Comite. The Comite field is located in East Baton Rouge Parish, Louisiana, due east of the city of Baton Rouge. The field was discovered in 1981 and two wells have been drilled to date. The field is located down-thrown to the first Tuscaloosa expansion fault, a part of an east-west trending regional fault system. Field reservoirs are located at approximately 18,000 feet. This field has had cumulative production of over 23 MMbbl of oil and 101 Bcf of natural gas. We operate and own a 65% working interest in the Comite field and we hold 856 net acres under lease. In 2007 we sidetracked the Cobb well with a 100% working interest as other partners non-consented the operation. The sidetrack was designed to penetrate a partially depleted PUD zone and test a deeper sand. The sidetracking operations were successful and the well tested gas from the deeper reservoir. The production facilities are currently being upgraded to handle the new production.

Leeville. The Leeville field is located in southern Lafourche Parish, Louisiana, about 50 miles south of New Orleans. Texaco discovered the field in 1931 and drilled more than 500 mostly shallow wells to exploit

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discovered oil and natural gas. The majority of these wells penetrated depths of less than 10,000 feet. The Leeville field was created by a shallow piercement salt dome with the top of the salt at 3,500 feet. Production comes from 45 different pay sands at depths ranging from 1,400 to 19,000 feet. This field has had cumulative production of over 108 MMbbl of oil and 171 Bcf of natural gas. We operate and own a 20% to 100% working interest in the Leeville field and hold 7,763 net acres down to 12,950 feet. In 2007, we acquired 100% of the Chevron deep rights under the field and are currently evaluating 3-D data to better determine both the shallow and deep potential of the field. We have an established joint venture with a private operator and expect to drill four wells in 2008 under this program. We will have up to a 43.75% working interest in these wells. We anticipate commencing drilling on the deep rights in 2009 or 2010.

Chocolate Bayou. The Chocolate Bayou field is located in Brazoria County, Texas. The field was discovered in 1939 by Texaco and Phillips and over 400 wells have been drilled to date in the field and nearby surrounding areas. The field is located on a northeast-southwest trending subsurface structure which was formed by a large growth fault. Reservoirs in the field range in depth from 8,700 feet to 14,500 feet. We operate and own a 20% to 100% working interest in the Chocolate Bayou field holding 1,166 net acres under lease. During the fourth quarter of 2007, we drilled the Weiting #30 with a 100% working interest to a total depth of 14,500 feet to the Frio age IP Farms section. Wireline log analysis in the IP Farms zone indicated pay sands. Mechanical problems prevented attempting a test or completion in this section. During the first quarter of 2008, we completed the Weiting #30 in the primary target, the Andrau sand at a depth of 12,450 feet. We anticipate drilling a well later this year to further evaluate the IP Farms, plus shallower PUD zones identified in the Weiting #30 well.

Live Oak. The Live Oak field is located in Vermilion Parish, Louisiana approximately 30 miles south of the city of Lafayette. The field was discovered in 1954 by the Houston Oil Co. The field is comprised of two anticlinal structures separated by a large east-west trending growth fault. This field has had cumulative production of approximately 660 Bcf of natural gas and 9.8 MMbbl of oil from pay sands that range in depth from 9,200 feet to 15,200 feet. We operate and own an 85% to 100% working interest in the Live Oak field and we hold 583 net acres under lease. In 2007, production in the field was enhanced through several workovers and we anticipate two new wells in 2008.

South Florence. The South Florence field is located in western Vermilion Parish, approximately 40 miles southwest of Lafayette, Louisiana. The field was discovered in 1971 by Amoco Production Company when production was established in the Lower Miocene sand section. Thirty two wells have been drilled on the structure and over 50 recognized Miocene pay sands have been penetrated to date. Depth of the pay zones ranges from 1,800 to 11,050 feet. This field has had cumulative production of over 8.4 MMbbl of oil and 70.7 Bcf of natural gas. Dune operates and owns a 100% working interest in the South Florence field and holds 2,080 gross and net acres under lease. One successful development well was drilled in 2007 and in 2008 we anticipate only performing well workovers.

Bayou Couba. 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 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”). In June 2007, we acquired additional interests in the area of mutual interest in consideration of the payment of $3.0 million to ANEC. We now have the contractual right to participate in a 25% to 37.5% of the AMI acreage. These rights are in addition to the direct 10% working interest that we hold in a particular lease covering approximately 1,300 acres within the AMI acreage. Effective September 1, 2007, we became the operator at Bayou Couba, at which time we paid $500,000 to ANEC. The term of the Development Agreement has been extended from November 2007 to November 2009. On January 30, 2007, we acquired Louisiana State Lease 19246, which totals 2,498 acres, and is located on the north shore of Lake Salvador. 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%.

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In 2007 we drilled and cased the Fee #5 well to a total depth of 13,065 feet. The initial completion zone depleted on test and we plan to sidetrack the well approximately 1,000 feet to the north in an attempt to recover PUD reserves assigned to the well. We anticipate commencing this sidetrack in the second quarter of 2008. We had a 100% working interest in this well due to farmouts and non-consents of our partners.

We are presently working with our partners to complete the reprocessing and depth migration of the 3-D seismic. This will provide better definitions of the deeper opportunities available within the field area. In 2008 we anticipate the Fee #5 sidetrack plus an additional two wells will be drilled in the field.

Barnett Shale. Since 2005 we have acquired approximately 5,400 net acres in the Barnett Shale through several transactions. The vast majority of these properties are located in Denton County, with the remainder in Wise County, both in the fairway of the prolific Barnett Shale in the North Texas Fort Worth Basin. Much of this acreage is covered by a “drill to own” contract whereby we are assigned the acreage when it is drilled. To date, we have purchased or earned approximately 3,655 net acres and have approximately 2,500 acres remaining under the drill to earn contracts. Under these contracts, Dune typically pays no up-front costs for the acreage but pays 100% of the well costs through initial production to earn 90% or 92% working interest in the production. At year end 2007, we had 41 wells with proved producing or behind pipe reserves, 13 PUD locations and approximately 40 drill to earn locations. We anticipate maintaining a 1-2 rig program through 2008.

Other Fields. The above listed fields comprise 73.6% of our year-end 2007 proved reserves. We maintain an interest in several additional fields where our activities will be concentrated on field level production enhancements, workovers and some low risk development drilling.

Natural Gas and Oil Reserves.

Due to the inherent uncertainties and the limited nature of reservoir data, proved reserves 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 Securities and Exchange Commission (“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.

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 reserves does not include 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 natural 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 natural 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, 2007 were $92.66 per barrel of oil and $7.324 per Mcf of natural gas.

The following table sets forth our estimated net proved oil and natural gas reserves and the PV-10 value of such reserves as of December 31, 2007. The reserve data and the present value as of December 31, 2007 were prepared by DeGolyer and MacNaughton, independent petroleum engineers. For further information concerning our independent engineer’s estimates of our proved reserves as of December 31, 2007, see the reserve report filed as Exhibit 99.1 to this Annual Report on Form 10-K. The PV-10 value is not intended to represent the current

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market value of the estimated oil and natural gas reserves owned by us. For further information concerning the present value of future net revenues from these proved reserves, see Note 11 of Notes to Consolidated Financial Statements.

	Oil	Natural Gas	Undiscounted Future Net Revenue		Present Value of Proved Reserves Discounted at 10% (1)
	(Mbbl)	(MMcf)	($ thousands)		($ thousands)
Developed Producing	2,919	40,577	$	316,017	$	241,162
Developed Nonproducing	4,023	36,298		478,638		271,420
Proved Undeveloped	2,689	40,689		345,693		216,067
Total Proved	9,631	117,564	$	1,140,348	$	728,649

(1) Management believes that the presentation of PV-10 may be considered a non-GAAP financial measure as defined in Item 10(e) of Regulation S-K. Therefore we have included a reconciliation of the measure to the most directly comparable GAAP financial measure (standardized measure of discounted future net cash flows in the table immediately below). Management believes that the presentation of PV-10 value provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Because many factors that are unique to each individual company may impact the amount of future income taxes to be paid, the use of the pre-tax measure provides greater comparability when evaluating companies. It is relevant and useful to investors for evaluating the relative monetary significance of our natural gas and oil properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. Management also uses this pre-tax measure when assessing the potential return on investment related to its oil and gas properties and in evaluating acquisition candidates. The PV-10 value is not a measure of financial or operating performance under GAAP, nor is it intended to represent the current market value of the estimated oil and natural gas reserves owned by us. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP.

The table below provides a reconciliation of PV-10 to the standardized measure of discounted future net cash flows.

	As of December 31, 2007
	(dollars in thousands)
PV-10	$	728,649
Future income taxes, discounted at 10%		(91,498	)
Standardized income of discounted future net cash flows	$	637,151

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Oil and Natural Gas Volumes, Prices and Operating Expense

The following tables set 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, 2007, 2006 and 2005.

	Year Ended December 31,
	2007		2006		2005
Net Production:
Oil (Bbl)		580,470		34,767		12,352
Natural Gas (Mcf)		5,539,374		880,373		364,236
Natural Gas Equivalent (Mcfe)		9,022,194		1,088,975		438,348
Oil and Natural Gas Sales (dollars in thousands):
Oil	$	44,195	$	2,078	$	717
Natural Gas		40,139		5,274		2,876
Total		84,334		7,352		3,593
Average Sales Price:
Oil ($ per Bbl)	$	76.14	$	59.77	$	58.01
Natural Gas ($ per Mcf)		7.25		5.99		7.90
Natural Gas Equivalent ($ per Mcfe)	$	9.35	$	6.75	$	8.20
Oil and Natural Gas Costs (dollars in thousands):
Lease operating expenses	$	25,570	$	1,235	$	378
Production taxes		6,847		776		341
Average production cost per Mcfe	$	3.59	$	1.85	$	1.64

Exploration, Development and Acquisition Capital Expenditures

The following table sets forth certain information regarding the gross costs incurred in the purchase of proved and unproved properties and in development and exploration activities.

	Year Ended December 31,
	2007		2006		2005
	(in thousands)
Property acquisition costs	$	391,438	$	36,528	$	29,531
Unproved prospects		455		391		—
Exploration costs		383		2,024		817
Development costs		148,161		363		13,557
Asset retirement obligation		2,737		274		76
Total consolidated operations	$	543,174	$	39,580	$	43,981
Asset retirement obligation (non-cash)		2,737		274		76

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Drilling Activity

The following table sets forth our drilling activity during the twelve month periods ended December 31, 2007, 2006 and 2005 (excluding wells in progress at the end of the period). In the table, “gross” refers to the total number of wells in which we have a working interest and “net” refers to gross wells multiplied by our working interest therein.

	Year Ended December 31,
	2007		2006		2005
	Gross	Net	Gross	Net	Gross	Net
Development wells
Productive	31	29.1	32	11.7	8	1.2
Non-productive	3	3.0	1	0.9	—	—
Exploratory wells
Productive	—	—	2	0.5	4	2.0
Non-productive	—	—	1	1.0	—	—

Productive Wells

The following table sets forth the number of productive oil and natural gas wells in which we owned an interest as of December 31, 2007. Productive wells are wells that are capable of producing natural gas or oil.

	Company Operated		Non-operated		Total
	Gross	Net	Gross	Net	Gross	Net
Oil	62	35.1	8	0.5	70	35.6
Natural Gas	106	75.1	208	1.5	314	76.6
Total	168	110.2	216	2	384	112.2

Acreage Data

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

	Developed acres		Undeveloped acres
	Gross	Net	Gross	Net
Gulf Coast Properties (1)	93,557.0	67,193.9	10,511.5	7,967.2
Barnett Shale Properties	3,732.0	3,655.0	—	—
Other (2)	—	—	14,250.0	4,275.0
Total	97,289.0	70,848.9	24,761.5	12,242.2

(1) Includes 7,848 gross / 5,437 net undeveloped acres at Welder Ranch. Primary term expires April 1, 2008. Includes 1,320 gross / 372 net acres developed at Bayou Couba within the DSCI lease. 2,500 gross/net acres undeveloped in S.L. 19246

(2) Includes 14,250 gross / 4,275 net acres being evaluated at the Delaware Deep Prospect, Sweetwater County, Wyoming.

As is customary in the oil and natural 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 natural 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.

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Our oil and natural gas properties consist primarily of oil and natural gas wells and our interests in leasehold acreage, both developed and undeveloped.

Major Customers

The Company sold oil and natural gas production representing more than 10% of its oil and natural gas revenues as follows:

2007:
Texon LP	52.08%
2006:
Targa North Texas LP (Dynegy)	19.16	%
Crosstex Gulf Coast Marktg Ltd	18.07	%
North Central Oil Corp.	15.10	%
Jerry Hess Operating Co	12.39	%
2005:
Hesco Gathering Co, LLC	45.05	%
North Central Oil Corp.	29.67	%
Alamo Operating Company, LC	10.60	%

Because alternate purchasers of natural gas and oil are readily available, we believe that the loss of any of our purchasers would not have a material adverse effect on our financial results.

Competition

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. Many of our competitors are large, well-established companies that have been engaged in the natural gas and oil business for much longer than we have and possess substantially larger operating staffs and greater capital resources than we do. Our ability to explore for oil and natural gas reserves and to acquire additional properties in the future will be dependent upon our ability to conduct our operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. We believe that our technological expertise, our exploration, land, drilling and production capabilities and the experience of our management generally enable us to compete effectively.

Marketing

Our production is marketed to third parties consistent with industry practices. Typically, oil is sold at the wellhead at field-posted prices plus a bonus and natural gas is sold under contract at a negotiated price based upon factors normally considered in the industry, such as distance from the well to the pipeline, well pressure, estimated reserves, quality of natural gas and prevailing supply and demand conditions.

Our marketing objective is to receive the highest possible wellhead price for our product. We are aided by the presence of multiple outlets near our production in the Barnett Shale area and the Texas and Louisiana onshore Gulf Coast area. We take an active role in determining the available pipeline alternatives for each property based on historical pricing, capacity, pressure, market relationships, seasonal variances and long-term viability.

Regulation of the Oil and Natural Gas Industry

Regulation of Transportation and Sale of Oil

Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

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Our sales of crude oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. The Federal Energy Regulatory Commission, or the FERC, regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances. Effective January 1, 1995, the FERC implemented regulations establishing an indexing system (based on inflation) for transportation rates for oil that allowed for an increase or decrease in the cost of transporting oil to the purchaser. A review of these regulations by the FERC in 2000 was successfully challenged on appeal by an association of oil pipelines. On remand, the FERC in February 2003 increased the index slightly, effective July 2001. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.

Regulation of Transportation and Sale of Natural Gas

Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and regulations issued under those Acts by the FERC. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the Natural Gas Policy Act. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act. The Decontrol Act removed all Natural Gas Act and Natural Gas Policy Act price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993.

FERC regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Since 1985, the FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers. The FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Beginning in 1992, the FERC issued Order No. 636 and a series of related orders to implement its open access policies. As a result of the Order No. 636 program, the marketing and pricing of natural gas have been significantly altered. The interstate pipelines’ traditional role as wholesalers of natural gas has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. Although the FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

In 2000, the FERC issued Order No. 637 and subsequent orders, which imposed a number of additional reforms designed to enhance competition in natural gas markets. Among other things, Order No. 637 effected changes in FERC regulations relating to scheduling procedures, capacity segmentation, penalties, rights of first refusal and information reporting.

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We cannot accurately predict whether the FERC’s actions will achieve the goal of increasing competition in markets in which our natural gas is sold. Additional proposals and proceedings that might affect the natural gas industry are pending before the FERC and the courts. The natural gas industry historically has been very heavily regulated. Therefore, we cannot provide any assurance that the less stringent regulatory approach recently established by the FERC will continue. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers.

Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states on shore and in state waters. Although its policy is still in flux, FERC has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of getting natural gas to point of sale locations.

Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

Regulation of Production

The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. All of the states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

Environmental Matters and Other Regulation

General

Our operations are subject to stringent and complex federal, state and local laws and regulations governing environmental protection as well as the discharge of materials into the environment. These laws and regulations may, among other things:

• require the acquisition of various permits before drilling commences;

• restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and natural gas drilling and production activities;

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• limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and

• require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells.

These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and gas industry could have a significant impact on our operating costs.

The following is a summary of some of the existing laws, rules and regulations to which our business operations are subject.

Waste Handling

The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the federal Environmental Protection Agency, or EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of crude oil or natural gas are currently regulated under RCRA or state non-hazardous waste provisions. Releases or spills of these regulated materials may result in remediation liabilities under these statutes. It is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position.

Comprehensive Environmental Response, Compensation, and Liability Act

The Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, also known as the Superfund Law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current or former owner or operator of the site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

In the course of our operations, we generate wastes that may fall within CERCLA’s definition of hazardous substances. Further, we currently own, lease or operate properties that have been used for oil and natural gas exploration and production for many years. Hazardous substances or petroleum may have been released on, at or under the properties owned, leased or operated by us, or on, at or under other locations, including off-site locations, where such hazardous substances or other wastes have been taken for disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose handling, treatment and disposal of hazardous substances, petroleum, or other materials or wastes were not under our control. These properties and the substances or materials disposed or released on, at or under them may be subject to CERCLA, RCRA or analogous or other state laws. Under such laws, we could be required to remove previously disposed substances and wastes or released petroleum, remediate contaminated property or perform remedial plugging or pit closure operations to prevent future contamination.

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Water Discharges

The Federal Water Pollution Control Act, or the Clean Water Act, and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances into waters of the United States or state waters. Under these laws, the discharge of pollutants into regulated waters is prohibited except in accordance with the terms of a permit issued by EPA or an analogous state agency. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

The Oil Pollution Act of 1990, or OPA, which amends and augments the Clean Water Act, establishes strict liability for owners and operators of facilities that are the site of a release of oil into waters of the United States. In addition, OPA and regulations promulgated pursuant thereto impose a variety of regulations on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills. OPA also requires certain oil and natural gas operators to develop, implement and maintain facility response plans, conduct annual spill training for certain employees and provide varying degrees of financial assurance.

In connection with the acquisition of Goldking, we inherited an environmental contingency which after conducting our due diligence and subsequent testing believe is the responsibility of a third party. The matter is being reviewed by the Federal regulators to deem the cause of the responsibility. While the final outcome can not be currently determined and any cost to remediate the area are not covered by insurance, we do not believe it will have a material impact on its results of operations or financial position.

We are not aware of any other environmental claims existing as of December 31, 2007, which have not been provided for, covered by insurance, or would otherwise have a material impact on our financial position or results of operations. There can be no assurance, however, that current regulatory requirements will not change, or past non-compliance with environmental laws will not be discovered on our properties.

Air Emissions

The Federal Clean Air Act and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, EPA has developed and continues to develop stringent regulations governing emissions of toxic air pollutants at specified sources. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the Federal Clean Air Act and associated state laws and regulations. Oil and gas operations may in certain circumstances and locations be subject to permits and restrictions under these statutes for emissions of air pollutants, including volatile organic compounds, nitrous oxides, and hydrogen sulfide.

National Environmental Policy Act

Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions that have the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay the development of oil and natural gas projects.

Endangered Species, Wetlands and Damages to Natural Resources

Various state and federal statutes prohibit certain actions that adversely affect endangered or threatened species and their habitat, migratory birds, wetlands, and natural resources. These statutes include the Endangered

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Species Act, the Migratory Bird Treaty Act, the Clean Water Act and CERCLA. Where takings of or harm to species or damages to wetlands, habitat, or natural resources occur or may occur, government entities or at times private parties may act to prevent oil and gas exploration or production or seek damages to species, habitat, or natural resources resulting from filling or construction or releases of oil, wastes, hazardous substances or other regulated materials.

OSHA and Other Laws and Regulations

We are subject to the requirements of the federal Occupational Safety and Health Act (OSHA) and comparable state statutes. The OSHA hazard communication standard, the Emergency Planning and Community Right to Know Act and similar state statutes require that we organize and/or disclose information about hazardous materials stored, used or produced in our operations.

Recent studies have indicated that emissions of certain gases may be contributing to warming of the Earth’s atmosphere. In response to these studies, many nations have agreed to limit emissions of “greenhouse gases” pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol.” Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of oil and natural gas, and refined petroleum products, are “greenhouse gases” regulated by the Kyoto Protocol. Although the United States is not participating in the Kyoto Protocol, several states have adopted legislation and regulations to reduce emissions of greenhouse gases. Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect our operations and demand for our products. Additionally, the U.S. Supreme Court has ruled, in Massachusetts, et al. v. EPA, that the U.S. Environmental Protection Agency abused its discretion under the Clean Air Act by refusing to regulate carbon dioxide emissions from mobile sources. This Supreme Court decision could result in federal regulation of carbon dioxide emissions and other greenhouse gases, and may affect the outcome of other climate change lawsuits pending in U.S. federal courts in a manner unfavorable to our industry. Currently, our operations are not adversely impacted by existing state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.

Private Lawsuits

In addition to claims arising under state and federal statutes, where a release or spill of hazardous substances, oil and gas or oil and gas wastes have occurred, private parties or landowners may bring lawsuits against oil and gas companies under state law. The plaintiffs may seek property damages, personal injury damages, remediation costs or injunctions to require remediation or restoration of contaminated property, soil, groundwater or surface water. In some cases, oil and gas operations are located near populated areas and emissions or accidental releases could affect the surrounding properties and population.

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Item 1A. Risk Factors

You should carefully consider each of the risks described below, together with all of the other information contained in this report, before deciding to invest in our securities. If any of the following risks develop into actual events, our business, financial condition or results of operations could be materially adversely affected and you may lose all or part of your investment.

We have had operating losses and limited revenues to date.

We have operated at a loss each year since inception. Net losses applicable to common stockholders of Dune for the fiscal years ended December 31, 2005, 2006 and 2007 were $3.0 million, $45.6 million and $42.2 million, respectively. Dune’s loss in the fiscal year ended December 31, 2006 was primarily attributed to a proved property impairment expense as a result of a drop in commodity prices from the fiscal year ended 2005 to the fiscal year ended 2006. Dune’s revenues for the fiscal years ended December 31, 2005, 2006 and 2007 were $3.7 million, $7.6 million and $84.3 million, 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 natural 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 and expect to continue to have 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 natural 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:

• the level of consumer product demand;

• the domestic and foreign supply of oil and natural gas;

• overall economic conditions;

• weather conditions;

• domestic and foreign governmental regulations and taxes;

• the price and availability of alternative fuels;

• political conditions in or affecting oil and natural gas producing regions;

• the level and price of foreign imports of oil and liquefied natural gas; and

• the ability of the members of the Organization of Petroleum Exporting Countries and other state controlled oil companies to agree upon and maintain oil price and production controls.

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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 and may reduce the amount of oil and natural gas that we can produce economically.

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. Our prospects are in various stages of evaluation, ranging from prospects that are ready to drill to prospects that will require substantial additional seismic data processing and interpretation and other types of technical evaluation. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects. 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:

• unexpected or adverse drilling conditions;

• elevated pressure or irregularities in geologic formations;

• equipment failures or accidents;

• adverse weather conditions;

• compliance with governmental requirements; and

• 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. A productive well may become uneconomic if water or other deleterious substances are encountered, which impair or prevent the production of oil and/or natural gas from the well. 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

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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 our petroleum engineering reserve reports. 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.

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 the reserves shown in our petroleum engineering reserve reports. In addition, the 10% discount factor we use to calculate the net present value of future net cash flows for reporting purposes may not necessarily be the most appropriate discount factor. Further, 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 consist of undeveloped reserves.

As of the end of our 2007 fiscal year, approximately 32.4% of our proved reserves were classified as undeveloped reserves. These reserves may not ultimately be developed or produced. As a result, we may not find commercially viable quantities of oil and natural gas, which in turn may have a material adverse effect on our results of operations.

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:

• we will be able to identify desirable natural gas and oil prospects and acquire leasehold or other ownership interests in such prospects at a desirable price;

• any completed, currently planned, or future acquisitions of ownership interests in natural gas and oil prospects will include prospects that contain proved natural gas or oil reserves;

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• we will have the ability to develop prospects which contain proven natural gas or oil reserves to the point of production;

• we will have the financial ability to consummate additional acquisitions of ownership interests in natural gas and oil prospects or to develop the prospects which we acquire to the point of production; or

• that we will be able to consummate such additional acquisitions on terms favorable to us.

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:

• our ability to obtain leases or options on properties for which we have 3-D seismic data;

• our ability to acquire additional 3-D seismic data;

• our ability to identify and acquire new exploratory prospects;

• our ability to develop existing prospects;

• our ability to continue to retain and attract skilled personnel;

• our ability to maintain or enter into new relationships with project partners and independent contractors;

• the results of our drilling program;

• hydrocarbon prices; and

• 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 James A. Watt, our President and Chief Executive Officer, Alan Gaines, the Chairman of our board of directors, Frank T. Smith, Jr., our Senior Vice President and Chief Financial Officer and our other executive officers and key employees. These individuals have extensive experience and expertise in evaluating and analyzing producing oil and natural gas properties and drilling prospects, maximizing production from oil and natural gas properties, marketing oil and natural gas production and developing and executing financing and hedging strategies. The loss of any of these individuals could have a material adverse effect on our operations. 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.

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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 proved 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 our operations, evaluate, and select suitable properties and consummate transactions successfully in this highly competitive environment.

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. 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 or 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.

Governmental regulation and liability for environmental matters may adversely affect our business, financial condition and results of operations.

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

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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 natural 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.

We may not have enough insurance to cover all of the risks we face and operators of prospects in which we participate may not maintain or may fail to obtain adequate insurance.

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. The impact of Hurricanes Katrina and Rita have resulted in escalating insurance costs and less favorable coverage terms. In addition, we have not yet been able to determine the full extent of our insurance recovery and the net cost to us resulting from hurricanes.

Oil and natural gas operations are subject to particular hazards incident to the drilling and production of oil and natural gas, such as blowouts, cratering, explosions, uncontrollable flows of oil, natural 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 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.

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:

• timing and amount of capital expenditures;

• expertise and financial resources;

• inclusion of other participants in drilling wells; and

• use of technology.

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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.

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.

If we are unable to successfully integrate companies we acquire into our operations on a timely basis, our profitability could be negatively affected.

Increasing our reserve base through acquisitions is an important part of our business strategy. Although we expect that our acquisitions will result in certain business opportunities and growth prospects, we may never realize these expected business opportunities and growth prospects. Successful integration will require, among other things, combining the companies:

• business development efforts;

• financial and accounting systems;

• key personnel;

• geographically separate facilities; and

• business and executive cultures.

We also may experience increased competition that limits our ability to expand our business. Our assumptions underlying estimates of expected cost savings may be inaccurate or general industry and business conditions may deteriorate. Acquisitions involve numerous risks, including, but not limited to:

• difficulties in assimilating and integrating the operations, technologies and products acquired;

• the diversion of our management’s attention from other business concerns;

• current operating and financial systems and controls may be inadequate to deal with our growth;

• the risk that we will be unable to maintain or renew any of the government contracts of businesses we acquire;

• the risks of entering markets in which we have limited or no prior experience; and

• the loss of key employees.

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If these factors limit our ability to integrate the operations of our acquisitions, successfully or on a timely basis, our expectations of future results of operations may not be met. In addition, our growth and operating strategies for businesses we acquire may be different from the strategies that such businesses currently are pursuing. If our strategies are not the proper strategies for a company we acquire, it could have a material adverse effect on our business, financial condition and results of operations. Further, there can be no assurance that we will be able to maintain or enhance the profitability of any acquired business or consolidate the operations of any acquired business to achieve cost savings.

In addition, there may be liabilities that we fail, or are unable, to discover in the course of performing due diligence investigations on each company or business we have already acquired or may acquire in the future. Such liabilities could include those arising from employee benefits contribution obligations of a prior owner or non-compliance with, or liability pursuant to, applicable federal, state or local environmental requirements by prior owners for which we, as a successor owner, may be responsible. In addition, there may be additional costs relating to acquisitions including, but not limited to, possible purchase price adjustments. We cannot assure you that rights to indemnification by sellers of assets to us, even if obtained, will be enforceable, collectible or sufficient in amount, scope or duration to fully offset the possible liabilities associated with the business or property acquired. Any such liabilities, individually or in the aggregate, could have a material adverse effect on our business.

Increasing our reserve base through acquisitions is a component of our business strategy. Our failure to integrate acquired properties successfully into our existing business, or the expense incurred in consummating future acquisitions, could result in our incurring unanticipated expenses and losses. In addition, we may have to assume cleanup or reclamation obligations or other unanticipated liabilities in connection with these acquisitions, and the scope and cost of these obligations may ultimately be materially greater than estimated at the time of the acquisition.

If oil and natural gas prices decrease, we may be required to take write-downs of the carrying values of our oil and natural gas properties.

Certain accounting rules may require us to write down the carrying value of our properties when oil and natural gas prices decrease or when we have substantial downward adjustments of our estimated proved reserves, increases in our estimates of development costs or deterioration in our exploration results. Once incurred, a write-down of our oil and natural gas properties is not reversible at a later date. Any write-down would constitute a non-cash charge to earnings and could have a material adverse effect on our results of operations for the periods in which such charges are taken. For example, for the year ended December 31, 2006, we incurred a proved property impairment expense of $31.4 million, which reduced the carrying value of the properties, due to a drop in commodity prices from year end 2005 to year end 2006. Also, a substantial decrease in oil and natural gas prices would accelerate our plugging and abandonment liability obligations which could have a material adverse effect on our results of operations.

Our producing properties are located in regions which make us vulnerable to risks associated with operating in one major contiguous geographic area, including the risk of damage or business interruptions from hurricanes.

Our properties are located onshore and in state waters along the Texas and Louisiana Gulf Coast region of the United States and in the Barnett Shale of north Texas. As a result of this geographic concentration, we are disproportionately affected by any delays or interruptions in production or transportation in these areas caused by governmental regulation, transportation capacity constraints, natural disasters, regional price fluctuations or other factors. This is particularly true of our inland water drilling and offshore operations, which are susceptible to hurricanes and other tropical weather disturbances. Such disturbances have in the past and will in the future have any or all of the following adverse effects on our business:

• interruptions to our operations as we suspend production in advance of an approaching storm;

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• damage to our facilities and equipment, including damage that disrupts or delays our production;

• disruption to the transportation systems we rely upon to deliver our products to our customers; and

• damage to or disruption of our customers’ facilities that prevents us from taking delivery of our products.

Our identified drilling locations are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

Our management has specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These scheduled drilling locations represent a significant component of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including oil and natural gas prices, the availability of capital, costs, drilling results, regulatory approvals and other factors. Because of these uncertainties, we do not know if the potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.

Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.

Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of our reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of transport vessels, gathering systems, pipelines and processing facilities owned and operated by third parties under interruptible or short-term transportation agreements. Under the interruptible transportation agreements, the transportation of our natural 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 failure to obtain such services on acceptable terms could materially harm our business. We may be required to shut in wells due to lack of a market or the inadequacy or unavailability of natural gas pipeline or gathering system capacity. If that were to occur, we would be unable to realize revenue from those wells unless and until we made arrangements for delivery of their production to market.

Terrorist attacks aimed at our energy operations could adversely affect our business.

The continued threat of terrorism and the impact of military and other government action has led and may lead to further increased volatility in prices for oil and natural gas and could affect these commodity markets or the financial markets used by us. In addition, the U.S. government has issued warnings that energy assets may be a future target of terrorist organizations. These developments have subjected our oil and natural gas operations to increased risks. Any future terrorist attack on our facilities, those of our customers, the infrastructure we depend on for transportation of our products, and, in some cases, those of other energy companies, could have a material adverse effect on our business.

Our leverage and debt service obligations may adversely affect our cash flow.

We have a substantial amount of debt. As of December 31, 2007, we had total debt of $289.3 million, primarily consisting of our 10-1/2% senior secured notes due 2012 (the “Senior Notes”). There were no borrowings under our $20 million revolving credit facility (“May 2007 Credit Facility”) at year-end, however, $13.7 million of letters of credit were issued against the commitment. We are presently permitted to borrow and/or issue letters of credit up to $40.0 million and to use up to $20.0 million to collateralize hedging obligations.

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Our substantial level of indebtedness could have important consequences to you, including the following:

• it may make it difficult for us to satisfy our obligations under our indebtedness and contractual and commercial commitments;

• we must use a substantial portion of our cash flow from operations to pay interest on our indebtedness, which will reduce the funds available to us for other purposes;

• our ability to obtain additional debt financing in the future for working capital, capital expenditures, acquisitions or general corporate purposes may be limited;

• our flexibility in reacting to changes in the industry may be limited and we could be more vulnerable to adverse changes in our business or economic conditions in general; and

• we may be at a competitive disadvantage to those of our competitors who operate on a less leveraged basis.

Furthermore, all of our borrowings under our May 2007 Credit Facility will bear interest at variable rates. If these rates were to increase significantly, our ability to borrow additional funds may be reduced, our interest expense would significantly increase, and the risks related to our substantial indebtedness would intensify.

In addition, the indenture governing the Senior Notes and our May 2007 Credit Facility contain various restrictive covenants (including in the case of our revolving credit facility, certain financial covenants), which covenants limit our ability to engage in activities that may be in our long-term best interests. Our failure to comply with these covenants would result in an event of default which, if not cured or waived, could result in the acceleration of all of our indebtedness, and have a material adverse effect on our liquidity, financial condition and results of operations.

Any failure to meet our debt obligations could harm our business, financial condition, results of operations or cash flows.

If our cash flow and capital resources are insufficient to fund our debt obligations, we may be forced to sell assets, seek additional equity or debt capital or restructure our debt. In addition, any failure to make scheduled payments of interest and principal on our outstanding indebtedness would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness on acceptable terms. Our cash flow and capital resources may be insufficient for payment of interest on and principal of our debt in the future and any such alternative measures may be unsuccessful or may not permit us to meet scheduled debt service obligations, which could cause us to default on our obligations and impair our liquidity.

The indenture governing the Senior Notes, the certificate of designations relating to our 10% Senior Redeemable Convertible Preferred Stock and our revolving credit facility impose significant operating and financial restrictions on us that may prevent us from pursuing certain business opportunities and restrict our ability to operate our business.

The indenture governing the Senior Notes, the certificate of designations relating to the our 10% senior redeemable convertible preferred stock issued to finance in part the acquisition of Goldking and our May 2007 Credit Facility each contain covenants that restrict our ability and the ability of certain of our subsidiaries to take various actions, such as:

• incurring or generating additional indebtedness or issuing certain preferred stock;

• paying dividends on our capital stock or redeeming, repurchasing or retiring our capital stock or subordinated indebtedness or making other restricted payments;

• entering into certain transactions with affiliates;

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• creating or incurring liens on our assets;

• transferring or selling assets;

• incurring dividend or other payment restrictions affecting certain of our existing and future subsidiaries; and

• consummating a merger, consolidation or sale of all or substantially all of our assets.

In addition, our May 2007 Credit Facility includes other and more restrictive covenants including those that restrict our ability to prepay our other indebtedness while borrowings under such revolving credit facility remain outstanding. Our May 2007 Credit Facility also requires us to achieve specified financial and operating results and maintain compliance with specified financial ratios. Our ability to comply with these ratios may be affected by events beyond our control.

The restrictions contained in the indenture governing the Senior Notes, the certificate of designations relating to the preferred stock and our May 2007 Credit Facility could:

• limit our ability to plan for or react to market conditions or meet capital needs or otherwise restrict our activities or business plans; and

• adversely affect our ability to finance our operations, strategic acquisitions, investments or alliances or other capital needs or to engage in other business activities that would be in our interest.

A breach of any of the restrictive covenants or our inability to comply with the required financial ratios could result in a default under our May 2007 Credit Facility.

If a default occurs, the lenders under our May 2007 Credit Facility may elect to:

• declare all borrowings outstanding thereunder, together with accrued interest and other fees, to be immediately due and payable;

• or prevent us from making payments on the Senior Notes;

either of which (after the expiration of any applicable grace periods) would result in an event of default under the indenture governing the Senior Notes and could result in a cross default under our other debt instruments. The lenders would also have the right in these circumstances to terminate any commitments they have to provide us with further borrowings. If the borrowings under our May 2007 Credit Facility and the Senior Notes were to be accelerated, we cannot assure you that we would be able to repay in full the Senior Notes.

We may not be able to generate sufficient cash flow to meet our debt service and other obligations due to events beyond our control.

Our ability to generate cash flows from operations and to make scheduled payments on our indebtedness, including the Senior Notes, will depend on our future financial performance. Our future performance will be affected by a range of economic, competitive, legislative, operating and other business factors, many of which we cannot control, such as general economic and financial conditions in our industry or the economy at large. A significant reduction in operating cash flows resulting from changes in economic conditions, increased competition, or other events could increase the need for additional or alternative sources of liquidity and could have a material adverse effect on our business, financial condition, results of operations and prospects and our ability to service our debt, including the Senior Notes, and other obligations. If we are unable to service our indebtedness, we will be forced to adopt an alternative strategy that may include actions such as reducing or delaying acquisitions and capital expenditures, selling assets, restructuring or refinancing our indebtedness or seeking equity capital. We cannot assure you that any of these alternative strategies could be effected on satisfactory terms, if at all, or that they would yield sufficient funds to make required payments on the Senior Notes and our other indebtedness.

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Any failure to meet our debt obligations could harm our business, financial condition, results of operations or cash flows.

If our cash flow and capital resources are insufficient to fund our debt obligations, we may be forced to sell assets, seek additional equity or debt capital or restructure our debt. In addition, any failure to make scheduled payments of interest and principal on our outstanding indebtedness would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness on acceptable terms. Our cash flow and capital resources may be insufficient for payment of interest on and principal of our debt in the future, including payments on the Senior Notes, and any such alternative measures may be unsuccessful or may not permit us to meet scheduled debt service obligations, which could cause us to default on our obligations and impair our liquidity.

The Conversion Price of our 10% Senior Convertible Preferred Stock is subject to a reset based on the prevailing market price of our common stock during a specified period, and if such reset is triggered, the conversion price of our 10% Senior Convertible Preferred Stock will be reduced, potentially resulting in substantial dilution of the equity ownership of holders of our common stock.

If the volume weighted average price of our common stock for the 30 trading days up to and including April 30, 2008 is less than $2.50 then, effective as of May 1, 2008, the conversion price of our 10% senior convertible preferred stock will decrease to the higher of (A) $1.75 or (B) the volume weighted average price of our common stock for the 30 trading days up to and including April 30, 2008 plus 10%. In addition, if the conversion price is decreased to $1.75, the rate at which cumulative dividends accrue on our 10% senior convertible preferred stock will increase by 200 basis points. As of March 5, 2008, the last sale price of our common stock on the American Stock Exchange was $1.77. If such reset were to occur, upon conversion of our 10% senior convertible preferred stock, we would be required to issue substantially more shares of our common stock, thereby diluting holders of our common stock.

Conversion of shares of our 10% Senior Convertible Preferred Stock prior to June 1, 2010, will require us to make certain make-whole payments, which payments may consist of shares of our common stock, resulting in the dilution of the equity ownership of holders of our common stock.

In the event a holder of our 10% senior convertible preferred stock elects to convert such shares prior to June 1, 2010, then such holder shall be entitled to a make whole premium consisting of the present value of all dividends on the preferred stock as if paid in cash from the date of conversion through June 10, 2010, computed using a discount rate equal to the Reinvestment Yield. Should we elect to pay this amount in shares of our common stock, the equity ownership of holders of our common stock could be significantly diluted.

The market price of our common stock may be volatile.

The trading price of our common stock and the price at which we may sell common stock in the future are subject to large fluctuations in response to any of the following:

• limited trading volume in our common stock;

• quarterly variations in operating results;

• our involvement in litigation;

• general financial market conditions;

• the prices of natural gas and oil;

• announcements by us and our competitors;

• our liquidity;

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• our ability to raise additional funds;

• changes in government regulations; and

• other events.

Sales of substantial amounts of shares of our common stock could cause the price of our common stock to decrease.

We have registered for resale a substantial number of shares of our common stock issuable upon conversion of our 10% senior redeemable convertible preferred stock and certain other securities convertible into or exercisable for shares of our common stock. Our stock price may decrease due to the additional amount of shares available in the market.

We do not intend to pay dividends on our common stock and our ability to pay dividends on our common stock is restricted.

We have not historically paid a dividend on our common stock, cash or otherwise, and do not intend to in the foreseeable future. We are currently restricted from paying dividends on common stock by our the indenture governing our Senior Notes, the agreement relating to our existing credit facility and, in some circumstances, by the terms of our 10% senior redeemable convertible preferred stock. Any future dividends also may be restricted by our then-existing debt agreements.

Provisions of Delaware law and our charter and bylaws may delay or prevent transactions that would benefit stockholders.

Our certificate of incorporation and bylaws and the Delaware General Corporation Law contain provisions that may have the effect of delaying, deferring or preventing a change of control of the company. These provisions, among other things, provide for a classified Board of Directors with staggered terms, restrict the ability of stockholders to take action by written consent, authorize the Board of Directors to set the terms of preferred stock and restrict our ability to engage in transactions with stockholders with 15% or more of outstanding voting stock.

Because of these provisions, persons considering unsolicited tender offers or other unilateral takeover proposals may be more likely to negotiate with our board of directors rather than pursue non-negotiated takeover attempts. As a result, these provisions may make it more difficult for our stockholders to benefit from transactions that are opposed by an incumbent board of directors.

Item 1B. Unresolved Staff Comments.

None.

Item 3. Legal Proceedings.

From time to time, we are party to certain legal actions and claims arising in the ordinary course of business. While the outcome of these events cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on our financial position or results of operations.

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

As previously reported by us in our definitive Information Statement on Schedule 14C filed with the Securities and Exchange Commission on November 20, 2007, stockholders holding an aggregate of 45,520,263 of our shares, representing 58.4% percent of the 78,004,278 shares of our common stock issued and outstanding as of November 8, 2007 (the “Record Date”), consented in writing to our (i) amending our Certificate of Incorporation to increase the authorized number of shares of our common stock from 200,000,000 shares to 300,000,000 shares and (ii) adopting the Dune Energy, Inc. 2007 Stock Incentive Plan.

No other matters were submitted to the vote or consent of the holders of the outstanding shares of our common stock during the quarter ended December 31, 2007.

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PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Market for Our Common Stock

Since May 9, 2005, our common stock has been traded on the American Stock Exchange under the symbol “DNE”. The following table sets forth, for the periods indicated, the high and low sales prices of our common stock on the American Stock Exchange.

2007:	High		Low
Quarter ended December 31, 2007	$	2.30	$	1.65
Quarter ended September 30, 2007	$	2.45	$	2.08
Quarter ended June 30, 2007	$	2.98	$	1.75
Quarter ended March 31, 2007	$	2.51	$	1.65
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

The last sales price of our common stock on the American Stock Exchange on December 31, 2007 was $2.04 per share. As of March 4, 2008, the closing sale price of a share of our common stock was $1.75. As of March 4, 2008, there were approximately 345 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 our 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 2007 in connection with our note and preferred stock financings, as well as our credit facility, contain significant restrictions on our ability to pay dividends on our common stock.

There were no repurchases of securities during the fourth quarter of 2007.

Recent Sales of Unregistered Securities

We have reported all sales of our unregistered equity securities that occurred during 2007 in our Reports on Form 10-Q or Form 8-K, as applicable.

As previously reported by us in our definitive Information Statement on Schedule 14C filed with the Securities and Exchange Commission on November 20, 2007, our Compensation Committee awarded an aggregate of 1,268,946 shares of Restricted Stock under the Dune Energy, Inc. 2007 Stock Incentive Plan to employees and non-employee directors of our Company.

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Securities Authorized for Issuance Under Equity Compensation Plans

The following table provides information as of December 31, 2007 about our equity compensation plans and arrangements.

Equity Compensation Plan Information—December 31, 2007

Plan category	(a) Number of securities to be issued upon exercise of outstanding options, warrants and rights		(b) Weighted-average exercise price of outstanding options, warrants and rights		(c) Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by security holders	600,000	(1)(2)	$	2.15	9,157,054	(3)(4)
Equity compensation plans not approved by security holders	4,074,324	(5)	$	2.05	3,050,000	(6)
Total			$	2.06

(1) Represents options issued to our directors pursuant to our 2005 Non-Employee Director Incentive Plan (the “2005 Plan”) (i) on October 28, 2005 to purchase up to 300,000 shares of our common stock at an exercise price of $1.94 per share and (ii) on January 24, 2007 to purchase up to 300,000 shares of our common stock at an exercise price of $2.35 per share. The 2005 Plan, which authorized the issuance of up to 2,000,000 shares in stock awards and options, was approved by stockholders on May 30, 2006.

(2) Excludes 1,242,946 shares of restricted stock awarded to employees pursuant to our 2007 Stock Incentive Plan (the “2007 Plan”). The 2007 Plan, which authorized the issuance of up to 7,000,000 shares in stock awards and options, was approved by stockholders holding a majority of our outstanding shares of common stock by written consent in lieu of a meeting of stockholders. An information statement pursuant to Regulation 14C reporting the approval of our 2007 Plan was mailed to stockholders on November 21, 2007.

(3) Includes 1,400,000 shares available under the 2005 Plan and 5,757,054 shares available under our 2007 Plan. The following shares may return to the 2007 Plan or the 2005 Plan, as the case may be, 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.

(4) Also includes an aggregate of 2,000,000 shares of restricted stock awarded but not yet vested pursuant to one of the two Restricted Stock Agreements dated April 17, 2007 entered into with two of our officers. The grant of the shares under the Restricted Stock Agreements was approved by stockholders holding a majority of our outstanding shares of common stock by written consent in lieu of a meeting of stockholders. An information statement pursuant to Regulation 14C reporting the authorization of the issuance of shares under the Restricted Stock Agreements was mailed to stockholders on May 21, 2007.

(5) 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, 2007.

(6) Includes an aggregate of 3,050,000 shares of restricted stock awarded pursuant to Restricted Stock Agreements dated April 17, 2007 entered into with two of our officers, which shares vest over the next three years.

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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 4,074,324 shares of our Common Stock included in the chart above were issuable as of December 31, 2007:

• 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 105,000 shares of our Common Stock at an exercise price of $0.54 per share;

• 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;

• 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;

• Option granted December 15, 2005 to a former 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;

• Option granted May 12, 2005 to an officer and director in consideration of services performed on our behalf, which option expires May 11, 2010 and is currently exercisable to purchase up to an aggregate of 625,000 shares of our Common Stock at an exercise price of $2.44 per share;

• Option granted May 12, 2005 to a former officer in consideration of services performed on our behalf, which option expires May 11, 2010 and is currently exercisable to purchase up to an aggregate of 500,000 shares of our Common Stock at an exercise price of $2.44 per share;

• Option granted July 18, 2005 to a former 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;

• 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;

• 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;

• 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;

• Option granted August 28, 2006 to employee in consideration of services performed on our behalf, which option expires April 27, 2011 and is currently exercisable to purchase up to an aggregate of 50,000 shares of our Common Stock at an exercise price of $1.50 per share;

• 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;

• Option granted January 24, 2007 to a former officer in consideration of services performed on our behalf, which option expires January 23, 2012 and is currently exercisable to purchase up to an aggregate of 200,000 shares of our Common Stock at an exercise price of $1.94 per share; and

• Options granted April 12, 2007 to consultants in consideration of services performed on our behalf, which options expire April 11, 2012 and are currently exercisable to purchase up to 500,000 shares of our Common Stock at an exercise price of $1.87 per share.

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Item 6. Selected Financial Data.

The following table sets forth selected financial data of the Company and its consolidated subsidiaries over the five-year period ended December 31, 2007, which information has been derived from the Company’s audited financial statements. This information should be read in connection with, and is qualified in its entirety by the more detailed information in the Company’s financial statements of Item 7 in this Form 10-K.

	As of or For the Year Ended December 31,
	2007(1)			2006(2)			2005(2)			2004(2)			2003(2)
				(as adjusted)			(as adjusted)			(as adjusted)			(as adjusted)
	(In thousands, except per share amounts)
Income Statement Data
Total revenues	$	84,334		$	7,580		$	3,724		$	1,022			—
Loss available to common shareholders		(42,218	)		(45,555	)		(3,029	)		(2,945	)		(430	)
Net loss per common share:
Basic and diluted		(.59	)		(.78	)		(.06	)		(.10	)		(.04	)
Balance Sheet Data
Total assets	$	616,632		$	55,664		$	55,257		$	11,163		$	1,365
Long-term debt		287,244			55,239			39,098			—			450
Redeemable convertible preferred stock		216,975			—			—			—			—
Shareholders’ equity (deficit)		(30,161	)		(10,443	)		11,611			10,423			(449	)
Common shares outstanding		79,258			59, 430			50,245			45,597			14,238

(1) For a discussion of the Goldking acquisition see Note 4 of the Company’s audited financial statements in this Form 10-K.

(2) Amounts have been adjusted to reflect the change in accounting for oil and gas properties from full cost to successful efforts. See Note 1 of the Company’s audited financial statements in this Form 10-K.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The following discussion will assist you in understanding our financial position, liquidity, and results of operations. The information below should be read in conjunction with the consolidated financial statements, and the related notes to consolidated financial statements. Our discussion contains both historical and forward-looking information. We assess the risks and uncertainties about our business, long-term strategy, and financial condition before we make any forward-looking statements, but we cannot guarantee that our assessment is accurate or that our goals and projections can or will be met. Statements concerning results of future exploration, exploitation, development, and acquisition expenditures as well as expense and reserve levels are forward-looking statements. We make assumptions about commodity prices, drilling results, production costs, administrative expenses, and interest costs that we believe are reasonable based on currently available information.

Critical Estimates and Accounting Policies

We prepare our consolidated financial statements in this report using accounting principles that are generally accepted in the United States (“GAAP”). GAAP represents a comprehensive set of accounting and disclosure rules and requirements. We must make judgments, estimates, and in certain circumstances, choices between acceptable GAAP alternatives as we apply these rules and requirements. The most critical estimate we make is the engineering estimate of proved oil and gas reserves. This estimate affects the application of the successful efforts method of accounting, the calculation of depreciation, depletion, and amortization of oil and gas properties and the estimate of the impairment of our oil and gas properties. It also affects the estimated lives used to determine asset retirement obligations. In addition, the estimates of proved oil and gas reserves are the basis for the related standardized measure of discounted future net cash flows.

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Estimated proved oil and gas reserves

The evaluation of our oil and gas reserves is critical to management of our operations and ultimately our economic success. Decisions such as whether development of a property should proceed and what technical methods are available for development are based on an evaluation of reserves. These oil and gas reserve quantities are also used as the basis of calculating the unit-of-production rates for depreciation, evaluating impairment and estimating the life of our producing oil and gas properties in our asset retirement obligations. Our proved reserves are classified as either proved developed or proved undeveloped. Proved developed reserves are those reserves which can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves include reserves expected to be recovered from new wells from undrilled proven reservoirs or from existing wells where a significant major expenditure is required for completion and production.

Independent reserve engineers prepare the estimates of our oil and gas reserves presented in this report based on guidelines promulgated under GAAP and in accordance with the rules and regulations of the Securities and Exchange Commission. The evaluation of our reserves by the independent reserve engineers involves their rigorous examination of our technical evaluation and extrapolations of well information such as flow rates and reservoir pressure declines as well as other technical information and measurements. Reservoir engineers interpret these data to determine the nature of the reservoir and ultimately the quantity of proved oil and gas reserves attributable to a specific property. Our proved reserves in this report include only quantities that we expect to recover commercially using current prices, costs, existing regulatory practices and technology. While we are reasonably certain that the proved reserves will be produced, the timing and ultimate recovery can be effected by a number of factors including completion of development projects, reservoir performance, regulatory approvals and changes in projections of long-term oil and gas prices. Revisions can include upward or downward changes in the previously estimated volumes of proved reserves for existing fields due to evaluation of (1) already available geologic, reservoir, or production data or (2) new geologic or reservoir data obtained from wells. Revisions can also include changes associated with significant changes in development strategy, oil and gas prices, or production equipment/facility capacity.

Standardized measure of discounted future net cash flows

The standardized measure of discounted future net cash flows relies on these estimates of oil and gas reserves using commodity prices and costs at year-end. In our 2007 year-end reserve report, we used December 31, 2007 ConocoPhillips West Texas Intermediate posted price of $92.70 per Bbl and a Henry Hub Onshore price of $7.095 per MMbtu adjusted by property for energy content, quality, transportation fees, and regional price differentials. The weighted average price over the lives of the properties was $92.66 per Bbl for oil and $7.324 per Mcf for gas. While we believe that future operating costs can be reasonably estimated, future prices are difficult to estimate since the market prices are influenced by events beyond our control. Future global economic and political events will most likely result in significant fluctuations in future oil prices.

Successful efforts method of accounting

Oil and gas exploration and production companies choose one of two acceptable accounting methods, successful efforts or full cost. The most significant difference between the two methods relates to the accounting treatment of drilling costs for unsuccessful exploration wells (“dry holes”) and exploration costs. Under the successful efforts method, exploration costs and dry hole costs (the primary uncertainty affecting this method) are recognized as expenses when incurred and the costs of successful exploration wells are capitalized as oil and gas properties. Entities that follow the full cost method capitalize all drilling and exploration costs including dry hole costs into one pool of total oil and gas property costs.

While it is typical for companies that drill exploration wells to incur dry hole costs, our primary activities during 2007 focused on development wells and our exploratory drilling activities were immaterial. Nevertheless, we will selectively expand our exploration drilling in the future. It is impossible to accurately predict specific dry holes. Because we can not predict the timing and the magnitude of dry holes, quarterly and annual net income can vary dramatically.

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The calculation of depreciation, depletion and amortization of capitalized costs under the successful efforts method of accounting differs from the full cost method in that the successful efforts method requires us to calculate depreciation, depletion and amortization expense on individual properties rather than one pool of costs. In addition, under the successful efforts method we assess our properties individually for impairment compared to one pool of costs under the full cost method.

Depreciation, Depletion and Amortization of Oil and Gas Properties

The unit-of-production method of depreciation, depletion and amortization of oil and gas properties under the successful efforts method of accounting is applied pursuant to the simple multiplication of units produced by the costs per unit on a field by field basis. Leasehold cost per unit is calculated by dividing the total cost by the estimated total proved oil and gas reserves associated with that field. Well cost per unit is calculated by dividing the total cost by the estimated total proved producing oil and gas reserves associated with that field. The volumes or units produced and asset costs are known and while the proved reserves have a high probability of recoverability, they are based on estimates that are subject to some variability. The factors which create this variability are included in the discussion of estimated proved oil and gas reserves above.

Impairment of Oil and Gas Properties

We test for impairment of our properties based on estimates of proved reserves. Proved oil and gas properties are reviewed for impairment whenever events or circumstances indicate that the carrying amount may not be recoverable. We estimate the future undiscounted cash flows of the affected properties to judge the recoverability of the carrying amounts. Initially this analysis is based on proved reserves. However, when we believe that a property contains oil and gas reserves that do not meet the defined parameters of proved reserves, an appropriately risk adjusted amount of these reserves may be included in the impairment evaluation. These reserves are subject to much greater risk of ultimate recovery. An asset would be impaired if the undiscounted cash flows were less than its carrying value. Impairments are measured by the amount by which the carrying value exceeds its fair value.

Impairment analysis is performed on an ongoing basis. In addition to using estimates of oil and gas reserve volumes in conducting impairment analysis, it is also necessary to estimate future oil and gas prices. The impairment evaluation triggers include a significant long-term decrease in current and projected prices, or reserve volumes, an accumulation of project costs significantly in excess of the amount originally expected, and historical and current negative operating losses. Although we evaluate future oil and gas prices as part of the impairment analysis, we do not view short-term decreases in prices, even if significant, as impairment triggering events.

Exploratory Drilling Costs

The costs of drilling an exploratory well are capitalized as uncompleted wells pending the determination of whether the well has found proved reserves. If proved reserves are not found, these capitalized costs are charged to expense. On the other hand, the determination that proved reserves have been found results in the continued capitalization of the well and its reclassification as a well containing proved reserves.

Asset Retirement Obligation

The Company follows SFAS No. 143, “Accounting for Asset Retirement Obligations,” which requires entities to record the fair value of a liability for legal obligations associated with the retirement obligations of tangible long-lived assets in the period in which it is incurred. The fair value of asset retirement obligation liabilities has been calculated using an expected present value technique. Fair value, to the extent possible, should include a market risk premium for unforeseeable circumstances. No market risk premium was included in the Company’s asset retirement obligations fair value estimate since a reasonable estimate could not be made. When the liability is initially recorded, the entity increases the carrying amount of the related long-lived asset. Over time, accretion of the liability is recognized each period, and the capitalized cost is amortized over the

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useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. This standard requires the Company to record a liability for the fair value of the dismantlement and plugging and abandonment costs, excluding salvage values

Derivatives

Derivative financial instruments, utilized to manage or reduce commodity price risk related to Dune’s production, 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 or loss 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 loss on derivative liabilities.

Effective January 1, 2008, the Company discontinued, prospectively, the designation of its derivatives as cash flow hedges. The net derivative loss related to the discontinued cash flow hedges, as of December 31, 2007, will continue to be reported in accumulated other comprehensive income until such time that they are charged to income or loss as the volumes underlying the cash flow hedges are realized. Beginning January 1, 2008, the gain or loss on derivatives will be recognized currently in earnings.

Stock-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). Our Notes to Consolidated Financial Statements included in this report have additional discussion of our significant accounting policies.

Business Strategy

Dune is an independent energy company engaged in the exploration, development, acquisition and exploitation of natural gas and crude oil properties, with interests along the Gulf Coast and in the fairway of the Barnett Shale in north Texas. On May 15, 2007, we closed the Stock Purchase and Sale Agreement, to acquire all of the capital stock of Goldking from Goldking Energy Holdings, L.P. Goldking was an independent energy company focused on the exploration, exploitation and development of natural gas and crude properties located onshore and in state waters along the Gulf Coast. The acquisition of Goldking substantially increased our proved reserves, provided significant drilling upside, and increased our geographic and geological well diversification. Additionally, the acquisition of Goldking provided us with exploration opportunities within our core geographic area.

Our properties now cover over 100,000 gross acres across 23 oil and natural gas fields onshore and in state waters along the Texas and Louisiana Gulf Coast and in the fairway of the Barnett Shale in north Texas.

We intend to focus our development and exploration efforts in our Gulf Coast properties and utilize low risk extensional drilling in the Barnett Shale. We believe that our extensive acreage position will allow us to grow

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organically through low risk drilling in the near term. We have attractive opportunities to expand our reserve base through field extensions, delineating deeper formations within existing fields and high risk/high reward exploratory drilling for 2008 and beyond. We will review and rationalize our properties on a continuous basis in order to optimize our existing asset base.

We expect to utilize our technical and operations teams’ knowledge of salt-dome structures and multiple stacked producing zones common in the Gulf Coast to enhance our growth prospects and reserve potential. We will employ technical advancements, including 3-D seismic data, pre-stack depth migration and directional drilling to identify and exploit new opportunities in our asset base. We also plan to employ the latest drilling, completion and fracturing technology in all of our wells to enhance recoverability and accelerate cash flows associated with these wells.

We continually review opportunities to acquire producing properties, leasehold acreage and drilling prospects that are in core operating areas. We are seeking to acquire operational control of properties that we believe have a solid proved reserves base coupled with significant exploitation and exploration potential. We intend to continue to evaluate acquisition opportunities and make acquisitions that we believe will further enhance our operations and reserves in a cost effective manner.

In summary, our strategy is to increase our oil and gas reserves and production while keeping our finding and development costs and operating costs (on a per Mcf equivalent (Mcfe) basis) competitive with our industry peers. We will implement this strategy through drilling exploratory and development wells from our inventory of available prospects that we have evaluated for geologic and mechanical risk and future reserve or resource potential. Our drilling program will contain some high risk/high reserve potential opportunities as well as some lower risk/lower reserve potential opportunities, in order to achieve a balanced program of reserve and production growth. Success of this strategy is contingent on various risk factors, as discussed elsewhere in the 10-K.

In addition to acquiring Goldking on May 15, 2007, we have invested $149.0 million in oil and gas properties and added 45.5 Bcfe through extensions, discoveries and revisions and produced 9 Bcfe.

Capital Costs ($000):	Year Ended 2007			Year Ended 2006			Year Ended 2005			Three Years Ended 12/31/07
Acquisitions—Proved	$	391,438		$	36,528		$	29,531		$	457,497
Acquisitions—Unproved		455			391			—			846
Exploration		383			2,024			817			3,224
Development		148,161			363			13,557			162,081
Total CAPEX before ARO		540,437			39,306			43,905			623,648
ARO		2,737			274			76			3,087
Total CAPEX including ARO	$	543,174		$	39,580		$	43,981		$	626,735
Proved Reserves (MMcfe):
Beginning		29,404			29,515			13,388			13,388
Production		(9,022	)		(1,090	)		(436	)		(10,548	)
Purchases		109,377			13,682			18,757			141,816
Discoveries & Extensions		38,012			68			—			38,080
Revisions		7,576			(12,771	)		(2,194	)		(7,389	)
Ending Reserves		175,347			29,404			29,515			175,347
Reserve Additions (MMcfe)		154,965			979			16,563			172,507

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The implementation of our strategy requires that we continually incur significant capital expenditures in order to replace current production and find and develop new oil and gas reserves. In order to finance our capital and exploration program, we depend on cash flow from operations or bank debt and equity offerings as discussed below in Liquidity and Capital Resources.

Liquidity and Capital Resources

Our main sources of liquidity and capital resources for 2008 are internally generated cash flows from operations and committed credit facilities.

During 2007, net cash flow provided by operations increased by $55.8 million to $54.2 million, compared to ($1.6 million) for 2006, primarily because of the Goldking acquisition, increased oil and gas production and higher hydrocarbon prices.

We expect our cash flow provided by operations for 2008 to increase because of higher projected production from the acquired properties, combined with oil and gas prices consistent with 2007 and steady operating, general and administrative, interest and financing costs per Mcfe.

Excluding the effects of significant unforeseen expenses or other income, our cash flow from operations fluctuates primarily because of variations in oil and gas production and prices, or changes in working capital accounts and actual well performance. In addition, our oil and gas production on the Gulf Coast may be curtailed due to factors beyond our control. Hurricanes in the Gulf of Mexico may shut down our production for the duration of the storm’s presence, or damage production facilities so that we cannot produce from a particular property for an extended amount of time. In addition, downstream activities on major pipelines can also cause us to shut-in production for various lengths of time. Several of these possibilities were realized in varying degrees by pipeline and other Gulf hydrocarbon infrastructure disruptions occurring on the heels of Hurricanes Katrina and Rita in 2005.

Our realized oil and gas prices vary significantly due to world political events, supply and demand of products, production storage levels, and weather patterns. We sell approximately 50% of our production at spot market prices. Accordingly, product price volatility will affect our cash flow from operations. To mitigate price volatility and comply with the terms of our credit arrangement with our lender, we employ various hedging contracts for the remaining production in order to partially offset potential swings in hydrocarbon prices. See additional discussion in Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

We incurred capital and drilling expenditures totaling $540.4 million during 2007. The capital expenditures included $391.4 million for the Goldking acquisition, and $149.0 million for exploration and development costs.

We expect to continue to make significant capital expenditures over the next several years as part of our long-term growth strategy. We have budgeted $121 million for capital and exploration expenditures in 2008. Our 2008 capital and exploration budget includes $7.5 million for exploration and $102.3 million for development costs with the remaining $11.2 million allocated to lease acquisitions, facilities and workovers. We project that we will spend $80.3 million in the Gulf Coast region, $29.5 million on the Barnett Shale and the remaining $11.2 million on leasehold acquisitions, facilities, and workovers. If our exploratory and development drilling results in significant new discoveries, we will have to expend additional capital in order to finance the completion, development, and potential additional opportunities generated by our success. The 2008 budget will be managed to stay within our cash flow from operations and committed credit facilities and consequently will be more aggressively pursued in the latter half of the year.

Interest on our 10 1/2% Senior Secured Notes was due and payable on December 1, 2007 and semi-annually thereafter. The principle on the Senior Secured Notes is not due until 2012. Shares of our 10% Redeemable Convertible Preferred Stock are not redeemable until December 1, 2012 or upon a change in control. Dividends

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are payable quarterly beginning September 1, 2007 with the Company having the option of paying any dividend on the preferred stock in shares of common stock, shares of preferred stock or cash.

Effective May 15, 2007, we agreed with our lender to maintain our borrowing base at $20.0 million under our Revolver Commitment with Wells Fargo. As of December 31, 2007, we had nothing borrowed under the facility. The lender reviews the borrowing base semi-annually and, at their discretion, may decrease or propose an increase to the borrowing base relative to a redetermined estimate of proved oil and gas reserves. Subsequent to year end, we requested and received an increase in the Revolver Commitment to $40 million effective February 29, 2008.

Our oil and gas properties are pledged as collateral for the line of credit and the Senior Secured Notes. Additionally, we have agreed not to pay dividends on common stock. The most significant restrictive financial covenant in the line of credit is an EBITDA test that becomes operative if our cash plus unused credit availability under our line of credit is less than $10 million at the end of a fiscal quarter. This covenant has not yet been operative because our cash position at these measuring points has never fallen to the $10 million minimum. Consequently, we are currently in compliance with the financial covenant. If we do not comply with the covenant on a continuous basis, the lender has the right to refuse to advance additional funds under the facility and/or declare any outstanding principal and interest immediately due and payable.

The following table summarizes our contractual obligations and commercial commitments as of December 31, 2007:

	Payments due by period
	Total		Less than 1 year		1 - 3 years		4 - 5 years		After 5 years
	(in thousands)
Contractual obligations:
Debt and interest	$	439,125	$	31,500	$	63,000	$	344,625	$	—
Office Lease		2,909		702		1,595		612		—
Total	$	442,034	$	32,202	$	64,595	$	345,237	$	—

Changes in our working capital accounts from 2006 to 2007 include an increase in our accounts receivable (a decrease in our cash flow provided by operations) due to higher oil and gas prices, increased production and increased balances due from our joint interest participants as a result of the Goldking acquisition and increased operating activities (drilling wells and facilities construction) at year end. Due to the increase in operating activities, our accounts payable balance increased by $63.9 million.

On December 31, 2007, our current assets were less than our current liabilities by $39.8 million.

We believe our short-term and long-term liquidity augmented by sale of non-core properties, if needed, is adequate to fund operations, including capital expenditures, interest and repayment of debt maturities.

Results of Operations

Comparison of 2007 and 2006

Revenue

Revenue for the year ended 2007 increased $76.7 million from the comparable 2006 period to $84.3 million. The Goldking acquisition made up $64.3 million of this increase. For the year ended 2007, oil sales volumes of 580 Mbbls accounted for $44.2 million of total revenue while gas sales volumes of 5.5 Bcfs resulted in $40.1 million. This represented an average sales price for oil and gas of $76.14 per Bbl and $7.25 per Mcf, respectively. In 2006, oil and gas sales volumes were 35 Mbbls and 0.9 Bcf, respectively and yielded average prices of $59.77 per Bbl and $5.99 per Mcf. The increases in volume and revenue were attributable to the Goldking acquisition, higher hydrocarbon prices and increased production during the last half of 2007.

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The following table discloses the net oil and gas production volumes, sales, and sales prices for each of the two years ended December 31, 2007 and 2006.

	2007		% Increase (Decrease)		2006
Oil production volume (Mbbls)		580	1557	%		35
Oil sales revenue ($000)	$	44,195	2027	%	$	2,078
Price per Bbl	$	76.14	27	%	$	59.77
Increase in oil sales revenue due to:
Change in prices	$	569
Change in production volume		41,548
Total increase in oil sales revenue	$	42,117
Gas production volume (Mmcf)		5,539	529	%		880
Gas sales revenue	$	40,139	661	%	$	5,274
Price per Mcf	$	7.25	21	%	$	5.99
Increase in gas sales revenue due to:
Change in prices	$	1,105
Change in production volume		33,760
Total increase in gas sales revenue	$	34,865

Operating expenses

Lease operating expense and production taxes

Total operating costs for 2007 increased $30.4 million from the comparable 2006 period. The Goldking acquisition and the concomitant increase in the number of operating properties made up the vast amount of this increase. However, this increase also includes $6 million of workover expense on some of the Goldking properties that is not anticipated to continue in future quarters. Severance taxes (production taxes) accounted for a $0.47 per Mcfe increase. However, 2007 operating costs, not including workovers, amounted to $2.93 or $1.08 per Mcfe increase over 2006.

The following table presents the major components of our operating costs on a per Mcfe basis:

	Years Ending December 31,
	2007				2006				2005
	Total		Per Mcfe		Total		Per Mcfe		Total		Per Mcfe
Direct operating expense	$	17,042	$	1.89	$	1,214	$	1.11	$	363	$	0.83
Workovers		5,975		0.66		—		—		15		0.03
Ad valorem taxes		717		0.08		21		0.02		—		—
Production taxes		6,847		0.76		310		0.29		237		0.54
Transportation		1,835		0.20		466		0.43		104		0.24
	$	32,416	$	3.59	$	2,011	$	1.85	$	719	$	1.64

Exploration Expenses

Exploration costs for the year ended 2007 totaled $0.4 million compared to $2 million in 2006. This reduction of $1.6 million is the result of the Company’s focus on drilling development wells in order to convert proved undeveloped reserves to proved developed reserves.

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Accretion of asset retirement obligation

Accretion expense for the year increased from $0.02 million in 2006 to $0.89 million in 2007 representing an $0.87 million increase. This reflects the impact of the Goldking acquisition which recorded $0.85 million of accretion expense for the period of May 15, 2007 to December 31, 2007.

Depletion, depreciation and amortization (DD&A)

For 2007, the Company recorded DD&A expense of $36.3 million compared to $5.8 million for 2006 representing an increase of $30.5 million. DD&A attributable to the Goldking acquisition amounted to bulk of this increase. The remaining is primarily attributable to the active drilling program in the Barnett Shale.

General and administrative expense (G&A expense)

G&A expense for 2007 increased $17.3 million from the comparable 2006 period to $22.1 million. The Goldking acquisition was primarily responsible for the significant increase. The two major components of the increase included personnel expense which increased $9.2 million and stock-based compensation which increased $6.7 million over the twelve month period. Also included in G&A expense was $0.4 million of one-time severance payments to former Goldking employees whose employment was terminated by Dune following the acquisition. Furthermore, G&A also reflected $2.9 million of accruals for 2008 target bonus payments for employees and officers of the Company. Nevertheless, overall G&A expense per Mcfe declined from $4.43 per Mcfe to $2.46 per Mcfe or 44%.

Bad debt expense

Included in revenues receivable is a balance of $0.4 million due from American Energy Corp. (“ANEC”). Due to the financial situation of ANEC, Dune elected to establish a reserve for doubtful accounts in the first quarter of 2007 for the entire balance, giving rise to bad debt expense of $0.4 million in the year ended 2007.

Loss on impairment of investment

In 2006 Dune purchased 8% Convertible Secured Debentures issued by ANEC in the aggregate principal amount of $3.0 million for a cash price of $0.5 million from TransAtlantic Petroleum Corp. Early in 2007, the Company purchased additional Debentures from unrelated third parties in the aggregate principal amount of $4.9 million by issuing 1,380,641 shares of Dune’s common stock at a price of $1.95 or $2.7 million. As a result of the continued decline in the financial situation of ANEC, Dune elected in the latter part of the first quarter of 2007 to establish a reserve for the entire value assigned to the ANEC Debentures giving rise to a loss on impairment of investment of $3.2 million recorded for the year ended December 31, 2007.

Other income (expense)

Interest income

Interest income increased $1.5 million for the year ended 2007 compared to the 2006 comparable period. These increases are attributable to interest income on large cash balances resulting from our financing arrangements of $300 million in Senior Secured Notes and $216 million in Convertible Preferred Stock that occurred on May 15, 2007 and June 5, 2007. Although the majority of these funds were used to finance the Goldking acquisition, cash balances at December 31, 2007 amounted to $16.8 million.

Interest expense

On May 15, 2007, the Company issued $300 million in Senior Secured Notes at the rate of 10 1/2% per annum in order to finance the Goldking acquisition. Additionally, on April 16, 2007, the Company borrowed $65 million from Jefferies Funding at a rate of 14% per annum for 30 days as interim financing. These factors along with the amortization of the debt discount and deferred loan costs give rise to an increase in interest expense of $24.4 million to $31.1 million for 2007 compared to 2006.

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Loss on derivative liabilities

Dune entered into derivative contracts to provide a measure of stability in the cash flows associated with the Company’s oil and gas production and to manage exposure to commodity prices. Prior to the Goldking acquisition on May 15, 2007, Dune’s derivatives were designated as fair value hedges with the changes in the fair value of the derivatives and of the hedge items attributable to the hedged risk recognized in earnings. Subsequent to May 15, 2007, Dune’s derivatives were designated as cash flow hedges with the effective portions of changes in fair value recorded in other comprehensive income and recognized in the Statement of Operations when the hedged item affects earnings. For 2007, the Company incurred a loss on embedded derivative of $3.0 million compared to an immaterial loss for 2006. The loss on cash flow hedges is attributable to a decline in the fair market value of open contracts as of December 31, 2007 and the corresponding deferred loss in “Accumulated other comprehensive loss”.

Income tax benefit

Dune recognized a deferred tax benefit totaling $15.3 million for the year ended December 31, 2007 versus no expense for prior years. The benefit recognized this year is due to the deferred tax liability which was established in purchase accounting for the Goldking acquisition (to provide for the difference in the carry over tax basis and the new book basis) and was reduced by the current year net operating loss. In prior years the net deferred tax assets had a valuation reserve and thus were not recognized in income.

Net loss available to common shareholders

For the year ended 2007, the net loss available to common shareholders decreased $3.4 million to ($42.2 million) from the comparable 2006 period. The major components contributing to these changes include increases in stock-based compensation, DD&A, amortization of discount and deferred financing costs, loss on impairment of investment and interest expense as more fully detailed above. These were substantially offset by the $15.3 million deferred tax benefit and no impairment expense of oil and gas properties (versus $31.4 million in 2006). Dune also paid preferred stock dividends totaling $13.8 million during the year.

Comparison of 2006 and 2005

A comparison of activity from 2005 to 2006 focuses on activity of the Company prior to the Goldking acquisition on May 15, 2007. The increase in operating loss from $1.9 million to $38.5 million is primarily attributable to the impairment of oil and gas properties of $31.4 million. Absent this impairment, the Company did reflect a significant increase in revenues in 2006 compared to 2005. However, operating expenses increased over 200% during this same time period which more than offset this increase in revenue.

Other income (expense) increased from $1.1 million to $7.0 million from 2005 to 2006. The significant component of this increase was interest expense. Dune borrowed over $45 million from November, 2005 through December, 2006 in order to finance its acquisition and drilling program in the Barnett Shale.

Consequently, the Company’s net loss increased from $3 million in 2005 to $45.6 million in 2006.

New Accounting Pronouncements

In July 2006, the FASB adopted “Accounting for Uncertainty in Income Taxes,” an interpretation of FAS 109 (“FIN 48”), effective for years beginning after December 15, 2006. FIN 48 establishes a more-likely-than-not threshold for recognizing the benefits of tax return positions in the financial statements. Also, FIN 48 implements a process for measuring those tax positions which meet the recognition threshold, of being ultimately sustained upon examination by the taxing authorities. There are no uncertain tax positions taken by the Company on its tax returns. The adoption of FIN 48 therefore had no material impact to the Company’s consolidated financial statements. The Company files tax returns in the US and states in which it has operations and is subject to taxation. Tax years subsequent to 2004 remain open to examination by U.S. federal and state tax jurisdictions.

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In September 2006, the FASB issued SFAS No. 157 “Fair Value Measurement.” SFAS No. 157 defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. This statement is effective for financial statements issued for fiscal years beginning after November 15, 2007. The Company is continuing to assess the potential impacts this statement might have on Dune’s Consolidated Financial Statements and related footnotes.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

Our primary exposure to market risk is the commodity pricing available to our oil and natural gas production. Realized commodity prices received for such production are primarily driven by the prevailing worldwide price for oil and spot prices applicable to natural gas. To mitigate some of this risk, we engage periodically in certain hedging activities, including price swaps, costless collars and, occasionally, put options, in order to establish some price floor protection (see Note 5 to financial statements). We also have some exposure to market risk consisting of changes in interest rates on borrowings under our credit agreement with our senior lender. 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 debt.

Item 8. Financial Statements and Supplementary Data.

The response to this item is included in Item 15—Financial Statements.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

None.

Item 9A. Controls and Procedures.

(a) Disclosure Controls and Procedures.

We maintain disclosure controls and procedures that are designed to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit to the Securities and Exchange Commission (“SEC”) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms, and that information is accumulated and communicated to our management, including our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), as appropriate to allow timely decisions regarding required disclosure.

In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our CEO and CFO, of the effectiveness of our disclosure controls and procedures as of December 31, 2007. As described below under Management’s Annual Report on Internal Control over Financial Reporting, our CEO and CFO have concluded that, as of December 31, 2007, our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

(b) Management’s Annual Report on Internal Control over Financial Reporting.

Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial

43

reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. The Company’s internal control over financial reporting includes those policies and procedures that:

1. pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;

2. provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and

3. provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2007. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission inInternal Control-Integrated Framework.Based on such assessment and those criteria, management believes that the Company maintained effective internal control over financial reporting as of December 31, 2007.

Malone & Bailey, P.C., our independent registered public accounting firm who also audited the Company’s consolidated financial statements, has issued its own attestation report on management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2007, which is filed herewith.

(c) Changes in Internal Control Over Financial Reporting. There have not been any changes in the Company’s internal control over financial reporting during the fiscal quarter ended December 31, 2007 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Item 9B. Other Information.

None.

PART III

The information required by Part III will be incorporated by reference into this Form 10-K from the Registrant’s Definitive Proxy Statement to be filed pursuant to Regulation 14A within 120 days after the end of the Registrant’s fiscal year covered by this Form 10-K.

44

PART IV

Item 15. Exhibits, Financial Statement Schedules.

(a)(1) Financial Statements

The response to this item is submitted in a separate section of this report.

(a)(3) Exhibits

Exhibit Nos.	Description
3.1	Amended and Restated Certificate of Incorporation (1)
3.1.1	Certificate of Amendment of Certificate of Incorporation (2)
3.2	Amended and Restated By-Laws (3)
4.1	Certificate of Designations, dated May 15, 2007, for 10% Senior Redeemable Convertible Preferred Stock of the Company (4)
4.1.1*	Certificate of Correction to Certificate of Designations, dated February 26, 2008
4.2	Form of Placement Agent Warrant (5)
4.3	Form of Investor Registration Rights Agreement (5)
4.4	Form of Warrant, dated as of September 26, 2006, from Company to Bernard National Senior Funding, Ltd. and Drawbridge Special Opportunities Fund LP (6)
4.5	Indenture, dated May 15, 2007, among the Company, each of Dune Operating Company and Vaquero Partners LLC, as guarantors, and The Bank of New York, as trustee and collateral agent (4)
4.6*	Form of Global 10 1/2% Senior Secured Exchange Note due 2012
10.1	Employment Agreement, dated April 17, 2007, between the Company and James A. Watt (7)
10.2	Employment Agreement, dated April 17, 2007, between the Company and Alan Gaines (7)
10.2.1	Amendment to Employment Agreement of Alan Gaines dated May 9, 2007(2)
10.3	Employment Agreement, dated April 17, 2007, between the Company and Amiel David (7)
10.3.1	Amendment to Employment Agreement of Amiel David dated May 9, 2007(2)
10.4	Restricted Stock Agreement, dated April 17, 2007, between the Company and James A. Watt (7)
10.5	Restricted Stock Agreement, dated April 17, 2007, between the Company and Alan Gaines (7)
10.6	Restricted Stock Agreement, dated April 17, 2007, between the Company and Amiel David (7)
10.7	Restricted Stock Agreement, dated April 17, 2007, between the Company and Frank T. Smith, Jr. (7)
10.8	Exploration and Development Agreement between Company and American Natural Energy Corporation, dated effective as of August 26, 2005(8)
10.9	Agreement dated as of June 1, 2006 among Vaquero Partners LLC, JVR Petroleum Inc., First Australian Resources, Inc. and Chesapeake Exploration Limited Partnership (9)
10.11	Stock Purchase and Sale Agreement dated effective April 13, 2007 between the Company and Goldking Energy Holdings, L.P. (7)
10.12	Form of Registration Rights Agreement (7)
10.13	Purchase Agreement dated as of May 1, 2007 between the Company and Jefferies & Company, Inc. (10)
10.14	Notes Registration Rights Agreement, dated May 15, 2007, between the Company and Jefferies & Company, Inc. (4)
10.15	Preferred Stock Registration Rights Agreement, dated May 15, 2007, between the Company and Jefferies & Company, Inc. (4)
10.16	Security Agreement, dated May 15, 2007, among The Bank of New York, as collateral agent, and each of the Company, Goldking Operating Company and Vaquero Partners LLC, as grantors, and Dune Operating Company and Goldking Energy Corporation, as guarantors (4)

45

Exhibit Nos.	Description
10.17	Intercreditor Agreement, dated May 15, 2007, among Wells Fargo Foothills, Inc., The Bank of New York and the Company, among others named therein (4)
10.18	Credit Agreement dated May 15, 2007 among the Company, its subsidiaries named therein as borrowers, its subsidiaries named therein as guarantors, certain lenders named therein and Wells Fargo Foothill, Inc., as arranger and administrative agent (4)
10.19	1992 ISDA Master Agreement, together with Schedule, dated May 15, 2007 among Wells Fargo Foothill, Inc. and the Company (4)
14.1*	Code of Conduct and Ethics
21.1*	List of Subsidiaries
23.1*	Consent of DeGolyer and MacNaughton, independent petroleum engineers
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 Company’s Annual Report on Form 10-KSB for the year ended December 31, 2002, and incorporated by reference herein.

(2) Previously filed as an exhibit to the Company’s Report on Form 10-Q for the quarterly period ended March 31, 2007, and incorporated by reference herein.

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

(4) Previously filed as an exhibit to the Company’s Report on Form 8-K, filed May 21, 2007, and incorporated by reference herein.

(5) Previously filed as an exhibit to the Company’s Annual Report on Form 10-KSB for year ended December 31, 2006, and incorporated by reference herein.

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

(7) Previously filed as an exhibit to the Company’s Report on Form 8-K, filed April 18, 2007, and incorporated by reference herein.

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

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

(10) Previously filed as an exhibit to the Company’s Report on Form 8-K, filed May 4, 2007, and incorporated by reference herein.

46

DUNE ENERGY INC.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	PAGE
Dune Energy, Inc. –
Report of Independent Registered Public Accounting Firm on Internal Control over Financial Reporting	F-2
Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements	F-3
Consolidated Balance Sheets at December 31, 2007 and 2006	F-4
Consolidated Statements of Operations for the Years Ended December 31, 2007, 2006 and 2005	F-5
Consolidated Statements of Cash Flows for the Years Ended December 31, 2007, 2006 and 2005	F-6
Consolidated Statements of Changes in Stockholders’ Equity for Years Ended December 31, 2007, 2006 and 2005	F-7
Notes to Consolidated Financial Statements	F-8

F-1

Report of Independent Registered Public Accounting Firm on Internal Control over Financial Reporting

To the Board of Directors and Shareholders

Dune Energy, Inc.

Houston, Texas

We have audited Dune Energy, Inc.’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Dune Energy, Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Dune Energy, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the COSO criteria .

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Dune Energy, Inc. as of December 31, 2007 and 2006, and the related consolidated statements of income, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2007 and our report dated March 7, 2008 expressed an unqualified opinion thereon.

/s/     Malone & Bailey, PC

www.malone-bailey.com

Houston, Texas

March 7, 2008

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Dune Energy, Inc

Houston, Texas

We have audited the accompanying consolidated balance sheets of Dune Energy, Inc (a Delaware Corporation) as of December 31, 2007 and 2006, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2007. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform an audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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 consolidated financial statements referred to above present fairly, in all material respects, the financial position of Dune Energy, Inc and its subsidiaries as of December 31, 2007 and 2006, and the results of operations and cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Dune Energy, Inc’s internal control over financial reporting as of December 31, 2007, based on criteria established inInternal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria), and our report dated March 7, 2008 expressed an unqualified opinion thereon.

/s/    Malone & Bailey, PC

www.malone-bailey.com

Houston, Texas

March 7, 2008

F-3

Dune Energy, Inc.

Consolidated Balance Sheets

	December 31,
	2007			2006
				(As adjusted)
ASSETS
Current assets:
Cash	$	16,771,726		$	3,574,705
Accounts receivable, net of reserve for doubtful accounts of $396,629 and $0		31,474,433			3,849,929
Prepayments and other current assets		7,602,405			132,272
Total current assets		55,848,564			7,556,906
Oil and gas properties, using successful efforts accounting—proved		628,087,399			84,912,754
Less accumulated depreciation, depletion, amortization and impairment		(74,886,616	)		(39,032,744	)
Net oil and gas properties		553,200,783			45,880,010
Property and equipment, net of accumulated depreciation of $416,324 and $16,721		2,632,400			46,046
Deferred financing costs, net of accumulated amortization of $371,353 and $310,711		2,220,372			1,181,554
Deposit—related party		500,000			500,000
Other assets		2,229,723			500,000
TOTAL ASSETS	$	616,631,842		$	55,664,516
LIABILITIES AND STOCKHOLDERS’ DEFICIT
Current liabilities:
Accounts payable	$	68,524,965		$	4,550,194
Accrued liabilities		19,072,905			135,199
Current debt		2,053,691			4,786,000
Preferred stock dividend payable		1,899,330			—
Derivative liabilities		4,131,078			—
Total current liabilities		95,681,969			9,471,393
Long-term debt, net of discount of $12,755,924 and $0		287,244,076			27,815,223
Long-term debt—related party		—			27,423,932
Deferred taxes		29,929,436			—
Other long-term liabilities		16,963,158			1,397,649
Total liabilities		429,818,639			66,108,197
Commitments and contingencies		—			—
Redeemable convertible preferred stock, net of discount of $10,943,172, liquidation preference of $1,000 per share, 750,000 shares designated, 227,918 shares issued and outstanding		216,974,828			—
STOCKHOLDERS’ DEFICIT
Preferred stock, $.001 par value, 1,000,000 shares authorized,
250,000 shares undesignated, no shares issued and outstanding		—			—
Common stock, $.001 par value, 300,000,000 shares authorized,
79,258,174 and 59,430,172 shares issued and outstanding		79,258			59,430
Additional paid-in capital		56,079,580			43,585,518
Accumulated other comprehensive loss		(3,831,228	)		—
Accumulated deficit		(82,489,235	)		(54,088,629	)
Total stockholders’ deficit		(30,161,625	)		(10,443,681	)
TOTAL LIABILITIES AND STOCKHOLDERS’ DEFICIT	$	616,631,842		$	55,664,516

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

F-4

Dune Energy, Inc.

Consolidated Statements of Operations

	For the Year Ended December 31,
	2007			2006			2005
				(As adjusted)			(As adjusted)
Revenues	$	84,333,803		$	7,580,034		$	3,724,278
Operating expenses:
Lease operating expense and production taxes		32,416,086			2,010,608			719,472
Exploration expense		383,391			2,024,431			817,024
Accretion of asset retirement obligation		887,344			24,848			2,173
Depletion, depreciation and amortization		36,263,896			5,799,368			1,551,112
General and administrative expense		22,140,782			4,823,582			2,550,549
Bad debt expense		396,629			—			—
Loss on impairment of investment		3,192,250			—			—
Impairment of oil and gas properties		—			31,411,329			—
Total operating expense		95,680,378			46,094,166			5,640,330
Operating loss		(11,346,575	)		(38,514,132	)		(1,916,052	)
Other income(expense):
Interest income		1,672,459			217,405			48,893
Interest expense		(31,070,721	)		(6,730,450	)		(918,985	)
Minority interest		—			—			(52,611	)
Other expense		—			(494,458	)		—
Loss on derivative liabilities		(2,948,403	)		(33,733	)		(190,553	)
Total other income(expense)		(32,346,665	)		(7,041,236	)		(1,113,256	)
Net loss before income taxes		(43,693,240	)		(45,555,368	)		(3,029,308	)
Income tax benefit		15,292,634			—			—
Net loss		(28,400,606	)		(45,555,368	)		(3,029,308	)
Preferred stock dividend		(13,817,330	)		—			—
Net loss available to common shareholders		(42,217,936	)		(45,555,368	)		(3,029,308	)
Other comprehensive loss		(3,831,228	)		—			—
Comprehensive loss	$	(46,049,164	)	$	(45,555,368	)	$	(3,029,308	)
Net loss per share:
Basic and diluted	$	(0.59	)	$	(0.78	)	$	(0.06	)
Weighted average shares outstanding:
Basic and diluted		72,083,522			58,583,932			47,557,242

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

F-5

Dune Energy, Inc.

Consolidated Statements of Cash Flows

	For the Year Ended December 31,
	2007			2006			2005
				(As adjusted)			(As adjusted)
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(28,400,606	)	$	(45,555,368	)	$	(3,029,308	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depletion, depreciation and amortization		36,263,896			5,799,368			1,551,112
Amortization of deferred financing costs and debt discount		7,030,353			2,148,282			143,558
Stock-based compensation		8,071,142			1,324,714			—
Loss on impairment of investment		3,192,250			—			—
Impairment of oil and gas properties		—			31,411,329			—
Exploration expense		383,390			2,024,431			817,024
Bad debt expense		396,629			—			—
Accretion of asset retirement obligation		887,344			24,848			2,173
Loss on derivative liabilities		2,948,403			33,733			190,553
Deferred tax benefit		(15,292,634	)
Minority interest		—			—			(17,201	)
Changes in:
Accounts receivable		(10,339,830	)		(2,253,961	)		(1,059,638	)
Prepayments and other assets		(2,297,871	)		(27,515	)		76,509
Accounts payable		36,981,386			3,431,762			4,002,084
Accrued liabilities		14,383,246			—			—
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		54,207,098			(1,638,377	)		2,676,866
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisition of Goldking, net of $1,155,720 cash received		(309,344,280	)		—			—
Investment in proved and unproved properties		(152,603,844	)		(37,328,290	)		(43,003,119	)
Purchase of furniture and fixtures		(1,114,340	)		(23,640	)		(39,127	)
Increase in other assets		(72,034	)		(500,000	)		—
Increase in deposit—related party		—			(500,000	)		—
Deposits on oil and gas properties		—			—			(1,820,101	)
NET CASH USED IN INVESTING ACTIVITIES		(463,134,498	)		(38,351,930	)		(44,862,347	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from convertible preferred stock		203,677,812			—			—
Proceeds from long-term debt		356,909,062			37,101,223			39,097,514
Proceeds from short-term debt		3,038,007			—			—
Proceeds from sale of common stock, net		—			22,103,232			5,601,833
Proceeds from exercise of options		—			100,000			—
Payment on long-term debt issuance costs		(6,286,413	)		(993,563	)		(2,506,745	)
Payment on preferred stock issuance costs		(1,053,156	)					—
Payments on long-term debt		(104,771,263	)		(18,500,000	)		—
Payments on long-term debt—related parties		(27,423,932	)		—			—
Payments on short-term debt		(1,965,706	)		—			—
NET CASH PROVIDED BY FINANCING ACTIVITIES		422,124,411			39,810,892			42,192,602
NET CHANGE IN CASH BALANCE		13,197,011			(179,415	)		7,121
Cash balance at beginning of period		3,574,705			3,754,120			3,746,999
Cash balance at end of period	$	16,771,716		$	3,574,705		$	3,754,120
SUPPLEMENTAL DISCLOSURES
Interest paid	$	21,340,567		$	2,150,597		$	553,236
Income taxes paid		—			—			—
NON-CASH DISCLOSURES
Common stock issued for conversion of debt	$	2,692,250		$	—		$	450,000
Common stock issued for purchase of Goldking		18,000,000			—			—
Redeemable convertible preferred stock dividends paid and accrued		13,817,330			—			—
Asset retirement obligation revision		2,736,914			273,719			76,509
Deferred taxes associated with acquisition		45,222,070			—			—
Accretion of discount on preferred stock		1,379,016			—			—
Purchase price adjustment for asset retirement obligation		1,418,557			—			—

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

F-6

Dune Energy, Inc.

Consolidated Statements of Changes in Stockholders’ Equity

Years ended December 31, 2007, 2006 and 2005

	Preferred Stock -Series A					Common Stock			Paid-In Capital			Other Comprehensive Loss			Accumulated Deficit			Total Equity
	Shares		Amount			Shares	Amount
															(As adjusted)
Balance at December 31, 2004	111,111		$	111		45,597,171	$	45,597	$	14,051,374		$	—		$	(5,503,953	)	$	8,593,129
Stock issued for:
Debt	—			—		1,182,223		1,182		443,818			—			—			445,000
Conversion of preferred to common stock	(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	—			—		—		—		—			—			(3,029,308	)		(3,029,308	)
Balance at December 31, 2005	—			—		50,244,859		50,244		20,093,671			—			(8,533,261	)		11,610,654
Cash received for stock subscription	—			—		9,000,000		9,001		23,840,999			—			—			23,850,000
Cash paid to consultant for stock subscription	—			—		—		—		(1,773,682	)		—			—			(1,773,682	)
Cash received for exercise of stock options	—			—		133,333		133		99,868			—			—			100,001
Stock issued for cashless exercise of stock options	—			—		51,980		52		(52	)		—			—			—
Stock-based compensation	—			—		—		—		1,324,714			—			—			1,324,714
Net loss	—			—		—		—		—			—			(45,555,368	)		(45,555,368	)
Balance at December 31, 2006	—			—		59,430,172		59,430		43,585,518			—			(54,088,629	)		(10,443,681	)
Stock issued for purchase of investment	—			—		1,380,641		1,381		2,690,869			—			—			2,692,250
Stock issued for Goldking acquisition	—			—		10,055,866		10,056		17,989,944			—	��		—			18,000,000
Unrealized loss on hedge contracts	—			—		—		—		—			(3,831,228	)		—			(3,831,228	)
Restricted stock issued	—			—		8,317,946		8,318		4,371,588			—			—			4,379,906
Stock issued for cashless exercise of stock options	—			—		73,549		73		(73	)		—			—			—
Stock-based compensation	—			—		—		—		3,691,236			—			—			3,691,236
Preferred stock dividends	—			—		—		—		(13,817,330	)		—			—			(13,817,330	)
Preferred stock issuance costs	—			—		—		—		(1,053,156	)		—			—			(1,424,580	)
Accretion of discount on preferred stock	—			—		—		—		(1,379,016	)		—			—			(1,007,592	)
Net loss	—			—		—		—		—			—			(28,400,606	)		(28,400,606	)
Balance at December 31, 2007	—		$	—		79,258,174	$	79,258	$	56,079,580		$	(3,831,228	)	$	(82,489,235	)	$	(30,161,625	)

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

F-7

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.

On May 15, 2007, Dune completed the purchase of all of the issued and outstanding shares of common stock of Goldking Energy Corporation (“Goldking”) pursuant to a Stock Purchase and Sale Agreement (“SPSA”) dated effective April 13, 2007 with Goldking Energy Holdings, L.P. The accompanying consolidated financial statements include all activity for Goldking Energy Corporation from May 15, 2007 (date of acquisition). See Note 4.

Consolidation

The accompanying consolidated financial statements include all accounts of Dune and its subsidiaries. All significant inter-company balances and transactions have been eliminated in consolidation.

Restatement of December 31, 2006 Financial Statements

In April 2007, Dune determined that the natural gas prices used by its independent reserve engineers to determine the estimated value of reserves in the reserve report were incorrect due to a pricing error, thus overstating the value of the related reserves. This resulted in an understatement of net loss and basic and diluted loss per share and an overstatement of assets in 2006. As a result, 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, which it did on April 20, 2007 when it filed its amended Form 10-KSB. Dune, under full cost accounting, had originally recognized an impairment of $33.2 million and restated the impairment to $42.9 million.

Upon conversion to successful efforts, this impairment was adjusted to $31.4 million as reflected in the 2006 Consolidated Statement of Operations. Additionally, Dune obtained a revised independent reserve report in order to make these adjustments as of and for the year ended December 31, 2006 and to revise the 2006 supplement oil and gas disclosure to conform to the revised reserve report.

Oil and gas properties

Oil and gas exploration and production companies choose one of two acceptable accounting methods, successful efforts or full cost. The most significant difference between the two methods relates to the accounting treatment of drilling costs for unsuccessful exploration wells (“dry holes”) and exploration costs. With the acquisition of Goldking, we elected to switch from full cost to successful efforts method of accounting for our investment in oil and gas properties, effective January 1, 2007.

Under the successful efforts method, exploration costs and dry hole costs (the primary uncertainty affecting this method) are recognized as expenses when incurred and the costs of successful exploration wells are capitalized as oil and gas properties. Entities that follow the full cost method capitalize all drilling and exploration costs including dry hole costs into one pool of total oil and gas property costs. We believe that, in light of the Goldking acquisition and our increased level of development and limited exploration activities, the successful efforts method of accounting provides a better matching of expenses to the period in which oil and gas production is realized. As a result, we believe that the change in accounting method was appropriate.

F-8

DUNE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The calculation of depreciation, depletion and amortization of capitalized costs under the successful efforts method of accounting differs from the full cost method in that the successful efforts method required us to calculate depreciation, depletion and amortization expense on individual properties rather than one pool of costs. In addition, under successful efforts method, we assess our properties individually for impairment compared to one pool of costs under the full cost method.

The change in accounting method constituted a “Change in Accounting Principle,” requiring that all prior period financial statements be adjusted to reflect the results and balances that would have been reported had we been following the successful efforts method of accounting from our inception. The cumulative effect of the change in accounting method as of December 31, 2006 was to increase the balance of our net investment in oil and gas properties and retained earnings at that date by $4,805,966. The change in accounting method resulted in an increase (decrease) in the net loss of ($8,080,323) and $1,444,665 for the years ended December 31, 2006 and 2005, respectively. The impact on earnings per share was ($.14) and $.03 for the years ended December 31, 2006 and 2005, respectively. The change in method of accounting had no impact on cash or working capital.

The unit-of-production method of depreciation, depletion and amortization of oil and gas properties under the successful efforts method of accounting is applied pursuant to the simple multiplication of units produced by the costs per unit on a field by field basis. Leasehold cost per unit is calculated by dividing the total cost by the estimated total proved oil and gas reserves associated with that field. Well cost per unit is calculated by dividing the total cost by the estimated total proved producing oil and gas reserves associated with that field. The volumes or units produced and asset costs are known and while the proved reserves have a high probability of recoverability, they are based on estimates that are subject to some variability. Amortization expense amounted to $35,722,445, $5,665,883 and $1,543,788 for the years ended December 31, 2007, 2006 and 2005, respectively.

We test for impairment of our properties based on estimates of proved reserves. Proved oil and gas properties are reviewed for impairment whenever events or circumstances indicate that the carrying amount may not be recoverable. We estimate the future undiscounted cash flows of the affected properties to judge the recoverability of the carrying amounts. Initially this analysis is based on proved reserves. However, when we believe that a property contains oil and gas reserves that do not meet the defined parameters of proved reserves, an appropriately risk adjusted amount of these reserves may be included in the impairment evaluation. These reserves are subject to much greater risk of ultimate recovery. An asset would be impaired if the undiscounted cash flows were less than its carrying value. Impairments are measured by the amount by which the carrying value exceeds its fair value.

Impairment analysis is performed on an ongoing basis. In addition to using estimates of oil and gas reserve volumes in conducting impairment analysis, it is also necessary to estimate future oil and gas prices. The impairment evaluation triggers include a significant long-term decrease in current and projected prices or reserve volumes, an accumulation of project costs significantly in excess of the amount originally expected, and historical and current negative operating losses. Although we evaluate future oil and gas prices as part of the impairment analysis, we do not view short-term decreases in prices, even if significant, as impairment triggering events.

During the year ended December 31, 2006, the Company impaired its oil and gas properties by $31,411,329 which is reflected in the accompanying Consolidated Statements of Operations. No impairment of oil and gas properties was recorded in 2007 or 2005.

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

F-9

DUNE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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 charged to expense. There was no impairment of unproved properties during the years ended December 31, 2007 and 2006. There were no material costs not subject to amortization as of December 31, 2007 and 2006.

Asset retirement obligation

The Company follows SFAS No. 143, “Accounting for Asset Retirement Obligations,” which requires entities to record the fair value of a liability for legal obligations associated with the retirement obligations of tangible long-lived assets in the period in which it is incurred. The fair value of asset retirement obligation liabilities has been calculated using an expected present value technique. Fair value, to the extent possible, should include a market risk premium for unforeseeable circumstances. No market risk premium was included in the Company’s asset retirement obligations fair value estimate since a reasonable estimate could not be made. When the liability is initially recorded, the entity increases the carrying amount of the related long-lived asset. Over time, accretion of the liability is recognized each period, and the capitalized cost is amortized over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. This standard requires the Company to record a liability for the fair value of the dismantlement and plugging and abandonment costs, excluding salvage values.

Concentrations of credit risk and allowance

Substantially all of the Company’s receivables are due from oil and natural gas purchasers. The Company sold 52% of its oil and natural gas production to one customer in 2007, 64% to four customers in 2006, and 85% to three customers in 2005. Historically, credit losses incurred on receivables of the Company have not been significant.

The Company maintains an allowance for doubtful accounts on trade receivables equal to amounts estimated to be uncollectible. This estimate is based upon historical collection experience, combined with a specific review of each customer’s outstanding trade receivable balance. Dune established a reserve for doubtful accounts related to the revenue receivable from ANEC of $396,629. Management believes that the allowance for doubtful accounts is adequate; however, actual write-offs may exceed the recorded allowance.

The Company maintains its cash in bank deposit accounts which, at times, may exceed federally insured limits. Accounts are guaranteed by the Federal Deposit Insurance Corporation (“FDIC”) up to $100,000. At December 31, 2007 and December 31, 2006, the Company had approximately $21,563,885 and $4,940,319, respectively, in excess of FDIC insured limits. The Company has not experienced any losses in such accounts.

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, 2007 or 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.

F-10

DUNE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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.

The most critical estimate we make is the engineering estimate of proved oil and gas reserves. This estimate affects the application of the successful efforts method of accounting, the calculation of depreciation, depletion and amortization of oil and gas properties and the estimate of the impairment of our oil and gas properties. It also affects the estimated lives used to determine asset retirement obligations. In addition, the estimates of proved oil and gas reserves are the basis for the related standardized measure of discounted future net cash flows.

Property and equipment

Property and equipment is valued at cost. Depreciation is computed using the straight-line method over estimated useful lives of 3 to 5 years. 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 financing, Dune paid $6,286,413 and $993,563 in fees for the years ended December 31, 2007 and 2006, respectively. 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.

As a result of refinancing, Dune was required to expense $4,542,177 of such costs. Combined with the aggregate of monthly amortization expense of $2,488,176, total amortization of deferred financing costs and debt discount for the year ended December 31, 2007 amounted to $7,030,353. Amortization expense for 2006 and 2005 amounted to $2,148,282, and $143,558, respectively.

Long-lived assets

Long-lived assets including investments 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.

During the year ended December 31, 2007, Dune acquired from parties unrelated to either entity, 8% Convertible Secured Debentures issued by American Natural Energy Corp. (“ANEC”), in the aggregate principal amount of $4,895,000. As consideration for the debentures, Dune issued a total of 1,380,641 shares of common stock valued at $1.95 per share, for aggregate consideration of $2,692,250 or 55% of the principal face amount of the debentures acquired by Dune. In 2006, Dune purchased $3 million of ANEC debentures from TransAtlantic Petroleum Corp. for a cash price of $0.5 million. Due to the poor financial condition of ANEC, Dune established a reserve for the impairment of the entire balance of the investment of $3,192,250 during the year ended December 31, 2007.

F-11

DUNE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Deposit and payments—related party

In 2006, Dune entered into a definitive contract with its largest shareholder, Itera Holdings, BV. The terms call for the construction of and subsequent long-term contract for a drilling rig for the exclusive use on the 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. Payments totaling $7,053,700 and $1,517,744 were made during the years ended December 31, 2007 and 2006, respectively.

Derivatives

Derivative financial instruments, utilized to manage or reduce commodity price risk related to Dune’s production, 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 or loss 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 loss on derivative liabilities.

Stock-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 stock-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:

	Year ended December 31, 2005
Net loss, as reported	$	(3,029,308	)
Deduct: stock-based compensation expense determined under fair value based method		(2,234,056	)
Pro forma net loss	$	(5,263,364	)
Net loss per share, basic and diluted:
As reported	$	(0.06	)
Pro forma	$	(0.11	)

F-12

DUNE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The weighted average fair value of the stock options granted during the year ended December 31, 2005 was $2.26. Variables used in the Black-Scholes option-pricing model include (1) risk-free interest rate of 2.0%, (2) expected option life is the actual remaining life of the options, (3) expected volatility is 136% and (4) zero expected dividends.

Income taxes

We account for income taxes pursuant to SFAS No. 109, “Accounting for Income Taxes”, which requires recognition of deferred income tax liabilities and assets for the expected future tax consequences of events that have been recognized in our financial statements or tax returns. We provide for deferred taxes on temporary differences between the financial statements and tax basis of assets using the enacted tax rates that are expected to apply to taxable income when the temporary differences are expected to reverse.

In July 2006, the FASB issued “Accounting for Uncertainty in Income Taxes,” an interpretation of FAS 109 (“FIN 48”), effective for years beginning after December 15, 2006. FIN 48 establishes a more-likely-than-not threshold for recognizing the benefits of tax return positions in the financial statements. Also, FIN 48 implements a process for measuring those tax positions which meet the recognition threshold of being ultimately sustained upon examination by the taxing authorities. There are no uncertain tax positions taken by the Company on its tax returns and the adoption of FIN 48 had no material impact to the Company’s consolidated financial statements. The Company files tax returns in the US and states in which it has operations and is subject to taxation. Tax years subsequent to 2004 remain open to examination by U.S. federal and state tax jurisdictions.

Loss per share

Basic earnings per share amounts are calculated based on the weighted average number of shares of common stock outstanding during each period. Diluted earnings per share is based on the weighted average numbers of shares of common stock outstanding for the periods, including the dilutive effects of stock options, warrants granted and convertible preferred stock. Dilutive options and warrants that are issued during a period or that expire or are canceled during a period are reflected in the computations for the time they were outstanding during the periods being reported. Since Dune has incurred losses for all periods, the impact of the common stock equivalents would be antidilutive and therefore are not included in the calculation.

Fair value of financial instruments

The Company’s financial instruments consist of cash, receivables, payables and long-term debt. The carrying amount of cash, receivables and payables approximates fair value because of the short-term nature of these items. The carrying amount of long-term debt and preferred stock approximate fair value due to the limited time the instruments have been outstanding.

Impact of recently issued accounting standards

In September 2006, the FASB issued SFAS No. 157 “Fair Value Measurement.” SFAS No. 157 defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. This statement is effective for financial statements issued for fiscal years beginning after November 15, 2007. The Company is continuing to assess the potential impacts this statement might have on Dune’s Consolidated Financial Statements and related footnotes.

F-13

DUNE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

NOTE 2—DEBT FINANCING

Original and Amended Credit Facilities

On September 26, 2006, Dune amended and restated the credit agreement with Standard Bank Plc and the lenders described therein, dated as of November 17, 2005. The amended credit agreement provided for a credit commitment of up to $50 million.

On April 13, 2007, Dune amended and restated the Amended and Restated Credit Agreement with D.B. Zwirn Special Opportunities Fund, L.P. (“D.B. Zwirn”) and the lenders described therein, dated as of September 26, 2006 (the “Original Amended Credit Agreement”). They amended and restated the Original Amended Credit Agreement by means of an Amended and Restated Credit Agreement (the “Credit Agreement”), dated effective as of April 13, 2007, among us, Jefferies Funding LLC, (“Jefferies Funding”) and the lenders named therein and party thereto (the “Lenders”). Subject to numerous conditions precedent and covenants, the Credit Agreement provided for a credit commitment of up to $65.0 million (the “Commitment”).

On April 16, 2007, the Lenders purchased the loans outstanding under the Original Amended Credit Agreement and advanced the remainder of the Commitment to Dune under the Credit Agreement. Funds borrowed by Dune under the Commitment were used to (i) pay the $15 million Earnest Money deposit pursuant to the agreement to acquire Goldking and (ii) fund certain fees and expenses incurred by Dune in connection with entering into the Credit Agreement and for fees associated with the proposed acquisition of Goldking. The remaining borrowed funds were utilized by Dune to carry out its intended plan of operations and for its working capital needs, subject to the terms of the Credit Agreement.

Subject to various prepayment requirements under the Credit Agreement, loans made by the Lenders pursuant to the Credit Agreement were to be repaid on or before May 13, 2008. Under the Credit Agreement, interest on all loans accrued at a fluctuating interest rate per annum which is equal to the higher of (a) the rate of interest announced publicly by Citibank, N.A., from time to time, as its base rate and (b) 0.5% per annum plus the Federal Funds Effective Rate (the “Base Rate”) plus 5.75% until July 12, 2007, then at the Base Rate plus 6.26% from July 13, 2007 until October 10, 2007, then at the Base Rate plus 6.75% from October 11, 2007 until January 8, 2008 and then at the Base Rate plus 7.25% from January 9, 2008 until May 13, 2008. All loans under the Credit Agreement were secured by a security interest in, and the first lien on, substantially all of Dune’s assets.

On May 15, 2007, Dune fully discharged all of its obligations to Jefferies Funding under the Credit Agreement. The total amount repaid in satisfaction of the obligation was $65,758,333, representing the full outstanding commitment of $65 million under the Credit Facility plus accrued interest in the amount of $758,833. The repayment was made from the net proceeds from the 10 ¹/2% Senior Secured Note and the Redeemable Convertible Preferred Stock as discussed below.

Long Term Debt—Related Party

We also further amended our Amended and Restated Term Loan Agreement (as amended and restated, the “Loan Agreement”), with our then majority shareholder, Itera Holdings BV (“Itera”), pursuant to the terms and conditions of the Lockup Letter and Agreement Regarding Subordinated Indebtedness, dated April 13, 2007 (the “Letter Agreement”). In accordance with the Letter Agreement, Itera agreed to a lock up of our common stock, any other equity security of Dune and any security convertible into common stock owned or held by Itera for a period commencing on the date of the Letter Agreement and terminating upon the repayment of our indebtedness, obligations and liabilities under the Credit Agreement, provided that if it is paid in full contemporaneously with the closing, the lockup will continue until the date that is 90 days after closing. In addition to the foregoing, pursuant to the Letter Agreement, we may not pay or make any cash payment of any

F-14

DUNE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

kind, whether principal or interest, under the Loan Agreement until all our Credit Agreement is paid in full, unless otherwise agreed to in writing by the Lenders.

On May 15, 2007, we also discharged in full all of our obligations to Itera under the Loan Agreement dated as of August 31, 2006. The total amount repaid to Itera by us was $27,831,115, representing the outstanding principal amount of $25 million plus accrued interest in the amount of $2,831,115. Such amounts were repaid from the net proceeds from the 10 ¹/2% Senior Secured Note and the Redeemable Convertible Preferred Stock as discussed below.

Wells Fargo Foothill Credit Agreement

On May 15, 2007, we entered into a credit agreement with certain lenders and Wells Fargo Foothill, Inc. (“Wells Fargo”), as arranger and administrative agent (the “WF Agreement”). Subject to the satisfaction of a Borrowing Base formula (based on the proved producing and non-producing reserves of Dune and our operating subsidiaries), numerous conditions precedent and covenants, the WF Agreement provides for a revolving credit commitment of up to $20 million, which may be extended up to $40 million upon request by us so long as no Default or Event of Default exists or would exist at the time of such request (the “Revolver Commitment”), with a sub-limit of $20 million for issuance of letters of credit. Under the WF Agreement, advances under the Revolver Commitment must be paid on or before May 15, 2010. Under the WF Agreement, interest on advances accrues at either Wells Fargo’s Base Rate or the LIBOR rate, at our option, plus an applicable margin ranging from 0.25% to 2.0% based upon the ratio of outstanding advances and letters of credit usage under the WF Agreement to the Borrowing Base or Revolver Commitment, whichever is less. With respect to letters of credit issued under the WF agreement, fees accrue at a rate equal to the applicable margin for any LIBOR rate advances multiplied by the daily balance of the undrawn amount of all outstanding letters of credit. On May 15, 2007, we utilized approximately $5.2 million for the issuance of standby letters of credit by a Wells Fargo affiliate in substitution for outstanding letters of credit assumed under the Goldking acquisition. Additional standby letters of credit totaling $8.5 million were issued subsequent to May 15, 2007 yielding a total of $13.7 million issued at December 31, 2007. There were no loans outstanding under the Revolver Commitment as of December 31, 2007.

As security for our obligations under the WF Agreement, we and certain of our operating subsidiaries granted Wells Fargo a security interest in and a first lien on all of our existing and after-acquired assets including, without limitation, the oil and gas properties and rights that we acquired in the Goldking acquisition. In addition, two of our subsidiaries have each guaranteed our obligations.

Subsequent to year end, Dune requested and received the extension up to $40 million under the Revolver Commitment effective February 29, 2008.

Senior Secured Notes

On May 15, 2007, we sold to Jefferies & Company, Inc. (the “Initial Purchaser”) $300 million aggregate principal amount of our 10 ¹/2% Senior Secured Notes due 2012 (“Senior Secured Notes”) at a purchase price of $288 million after a discount of $12 million. This yielded an effective interest rate of 11.8%. Net proceeds from the sale of the Senior Secured Notes together with the net proceeds from the sale of our Senior Redeemable Convertible Preferred Stock were used primarily to acquire all of the issued and outstanding capital stock of Goldking, to discharge outstanding indebtedness and for general working capital.

The Senior Secured Notes, bearing interest at the rate of 10 ¹/2 % per annum, were issued under that certain indenture, dated May 15, 2007, among us, the guarantors named therein, and The Bank of New York Trust Company NA, as trustee (the “Indenture”). The Indenture contains customary representations and warranties on our part as well as typical restrictive covenants whereby we have agreed, among other things, to limitations to

F-15

DUNE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

incurrence of additional indebtedness, declaration of dividends, issuance of capital stock, sale of assets and corporate reorganizations.

The Senior Secured Notes are subject to redemption by Dune (i) prior to June 1, 2010, in connection with equity offerings at a repurchase price equal to 110.5% of the aggregate principal amount plus accrued interest for up to 35% of the outstanding principal amount of the Senior Secured Notes, (ii) during the twelve-month period beginning June 1, 2010, at a repurchase price equal to 105.25% of the aggregate principal amount plus accrued interest and (iii) after June 1, 2011, at a repurchase price equal to 100% of the aggregate principal amount plus accrued interest. Holders of the Senior Secured Notes may put such notes to us for repurchase at a repurchase price of 101% of the principal amount plus accrued interest upon a change in control as defined in the Indenture.

The Senior Secured Notes are secured by a lien on substantially all of Dune's assets, including without limitation, those oil and gas leasehold interests located in Texas and Louisiana held by our operating subsidiaries, all as more particularly described in that security agreement with the Initial Purchaser executed by us on May 15, 2007 (the “Security Agreement”). The Senior Secured Notes are unconditionally guaranteed on a senior secured basis by each of our existing and future domestic subsidiaries.

The collateral securing the Senior Secured Notes is subject to, and made subordinate to, the lien granted to Wells Fargo under the WF Agreement, as evidenced by that certain Intercreditor Agreement of even date therewith between the Initial Purchaser, The Bank of New York Trust Company, NA, Wells Fargo Foothill, Inc. and us, among others (the “Intercreditor Agreement”).

The debt discount is being amortized over the life of the notes using the straight-line method which approximates the effective interest method as the principal amounts on the notes are due at maturity. Amortization expense associated with the debt discount amounted to $1,805,084 in 2007.

NOTE 3—REDEEMABLE CONVERTIBLE PREFERRED STOCK

During the quarter ended June 30, 2007, we sold to Jefferies & Company, Inc. (the "Initial Purchaser") pursuant to the Purchase Agreement dated May 1, 2007 (the "Purchase Agreement"), 216,000 shares of our Senior Redeemable Convertible Preferred Stock ("Preferred Stock") for gross proceeds of $216 million less a discount of $10.8 million yielding net proceeds of $205.2 million. As provided in the Certificate of Designations, the Preferred Stock has a liquidation preference of $1,000 per share and pays a dividend at a rate of 10% per annum, payable quarterly, at the option of Dune, in additional shares of Preferred Stock, shares of Dune's common stock (subject to the satisfaction of certain conditions) or cash. The Preferred Stock is initially convertible into 72 million shares of our common stock, based on an initial conversion price of $3.00 per share of the common stock. There is a one-time test for adjustment of the conversion price and the dividend rate, effective as of May 1, 2008, based upon a specified average trading price of our common stock for the 30 trading days up to and including April 30, 2008. If we meet or exceed this target price of $2.50 per share, there will be no adjustment. In addition, the conversion price of the Preferred Stock will be subject to adjustment pursuant to customary anti-dilution provisions and may also be adjusted upon the occurrence of a fundamental change as defined in the instrument. The Preferred Stock is redeemable at the option of the holder on December 1, 2012 or upon a change of control. In the event we fail to redeem shares of Preferred Stock "put" to Dune by a holder, then the conversion price shall be lowered and the dividend rate increased. After December 1, 2012, Dune may redeem shares of Preferred Stock. Holders converting Preferred Stock prior to June 1, 2010 will be entitled to receive a certain make whole premium. The Company analyzed the adjustment of the conversion right and the make whole premium for derivative accounting under SFAS 133 and EITF 00.19 and determined that it was not applicable to either.

F-16

DUNE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Net proceeds from the sale of the Preferred Stock together with the net proceeds from the sale of our Senior Secured Notes were used primarily to acquire all of the issued and outstanding capital stock of Goldking, to discharge outstanding indebtedness and for general working capital.

On September 1, 2007 and December 1, 2007, Dune paid a dividend on the Preferred Stock in the amount of $6,359,000 and $5,559,000, respectively. In lieu of cash, the Company elected to issue 6,359 and 5,559 additional shares of Preferred Stock, respectively.

The Convertible Preferred Stock discount is being amortized over five years and are charged to paid-in capital as the Company has a deficit balance in retained earnings. Charges to paid-in capital in 2007 amounted to $1,379,016.

NOTE 4—ACQUISITION

On May 15, 2007 (the “Closing Date”), we completed our purchase of all of the issued and outstanding shares of common stock of Goldking pursuant to that certain stock purchase and sale agreement dated effective April 13, 2007 with Goldking Energy Holdings, L.P. (the “Shareholder”).

The purchase price was $328,500,000, paid as follows: (a) $310,500,000 in cash and (b) 10,055,866 shares of our common stock, representing shares having a value of $18,000,000 based on the closing price for our common stock on the American Stock Exchange on April 13, 2007. The cash portion of the purchase price was financed from the net proceeds of the $516 million offering of Senior Secured Notes and Preferred Stock. We incurred additional costs of $1,802,414 related to the acquisition.

The acquisition has been accounted for in accordance with the provisions of SFAS No. 141, “Business Combinations.” The total purchase price was allocated to the net tangible assets based on the estimated fair values. The preliminary allocation of the purchase price was based upon valuation data as of May 15, 2007 and updated for year end information and to provide for a deferred tax liability related to differences in book and tax basis of oil and natural gas properties acquired. The estimates and assumptions are subject to change. The purchase price allocation is subject to further adjustment upon the receipt and management’s review of the final valuations and final tax returns. The final valuation is expected to be completed no later than one year from the acquisition date and any changes within this period in the value of net assets will be offset by a corresponding change in oil and natural gas properties. The allocation of the purchase price is as follows:

Assets:
Cash and equivalents	$	1,155,720
Accounts Receivable		17,681,299
Other current assets		3,954,840
Oil and natural gas properties		391,438,250
Other assets		4,739,050
Liabilities:
Accounts payable and accrued liabilities		(32,192,616	)
Current maturities of long-term debt		(981,390	)
Other liabilities		(10,270,669	)
Deferred tax liability		(45,222,070	)
	$	330,302,414

F-17

DUNE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The following unaudited pro forma information assumes the acquisition of Goldking occurred as of the beginning of each year. The pro forma results are not necessarily indicative of what actually would have occurred had the acquisition been in effect for the period presented.

	As Reported			Pro-Forma
Year ended December 31, 2007
Revenues	$	84,333,803		$	112,610,658
Net loss available to common shareholders		(42,217,936	)		(55,527,536	)
Net loss per share	$	(0.59	)	$	(0.73	)
Year ended December 31, 2006
Revenues	$	7,580,034		$	92,938,531
Net loss available to common shareholders		(45,555,368	)		(81,429,495	)
Net loss per share	$	(0.78	)	$	(1.19	)
Year ended December 31, 2005
Revenues	$	3,724,278		$	89,588,603
Net loss available to common shareholders		(3,029,308	)		(31,359,027	)
Net loss per share	$	(0.06	)	$	(0.54	)

NOTE 5—HEDGING AND OTHER COMPREHENSIVE INCOME

Hedging Arrangements

In accordance with a requirement of the WF Agreement, we and our operating subsidiaries also entered into a Swap Agreement (“Swap Agreement”) with Wells Fargo. The WF Agreement provides that we put in place, on a rolling six month basis, separate swap hedges, as adjusted from time to time as specified therein, with respect to notional volumes of not less than 50% and not more than 80% of the estimated aggregate production from (i) Proved Developed Producing Reserves (as defined in the WF Agreement) and (ii) estimated drilling by us and our subsidiaries with respect to each of crude oil and natural gas. As part of the Swap Agreement, Wells Fargo assumed the rights, liabilities, duties and obligations of substantially all Goldking’s counterparties under seven prior crude oil and five prior natural gas hedging arrangements between Goldking and various other banking institutions. These hedging arrangements are summarized as follows:

DUNE ENERGY, INC.

Current Hedge Positions as of December 31, 2007

Crude Oil

Instr.	Beg. Date	Ending Date	Floor		Ceiling		Fixed		Total Bbls 2008	Bbl/d	Total Bbls 2009	Bbl/d	Total Volumes
Collar	Jan-08	Dec-08	$	65.00	$	89.10			96,000	262		—	96,000
Collar	Jan-09	Dec-09	$	55.00	$	60.95				—	264,000	723	264,000
Puts	Jan-08	Dec-08	$	65.00					120,000	328		—	120,000
Swap	Jan-08	Dec-08					$	69.60	120,000	328		—	120,000
Swap/Cap	Jan-07	Dec-09			$	72.50	$	60.00	16,800	46	10,080	28	26,880
									352,800	964	274,080	751	626,880
Days									366		365
Hedged Daily Production									964		751

F-18

DUNE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Natural Gas

Instr.	Beg. Date	Ending Date	Floor		Ceiling		Fixed		Total Mmbtu 2008	Mmbtu/d	Total Mmbtu 2009	Mmbtu/d	Total Volumes
Collar	Jan-08	Dec-08	$	8.00	$	10.50			480,000	1,311		—	480,000
Collar	Jan-09	Dec-09	$	7.25	$	8.77				—	1,680,000	4,603	1,680,000
Puts	Feb-07	Jan-08	$	3.75					10,000	27		—	10,000
Puts	Jan-08	Dec-08	$	8.50					720,000	1,967		—	720,000
Swap	Jan-08	Dec-08					$	8.14	960,000	2,623		—	960,000
3-Way Collar	Jan-07	Dec-09	$	6.62					165,000	451	123,000	337	288,000
					$	13.35	$	6.62	495,000	1,352	369,000	1,011	864,000
									2,830,000	7,732	2,172,000	5,951	5,002,000
Days									366		365
Hedged Daily Production									7,732		5,951

Dune hedges a portion of forecasted crude oil and natural gas production volumes with derivative instruments. Dune uses various derivative instruments in connection with anticipated crude oil and natural gas sales to minimize the impact of commodity price fluctuations. The instruments include fixed price swaps, put options and costless collars. A collar is a combination of a purchased put option and sold call option. Dune accounts for its production hedge derivative instruments as defined in Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended by SFAS No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities” and SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (herein referred as “SFAS No.133”). Under SFAS No. 133, all derivatives are recorded at fair value on the balance sheet.

Those derivatives designated as cash flow hedges that meet certain requirements are granted hedge accounting treatment. Generally, utilizing cash flow hedge accounting, all periodic changes in fair value of the derivatives designated as hedges that are considered to be effective, as defined, are recorded in “Unrealized gain (loss) on hedge contracts” in accumulated other comprehensive income until the underlying production is sold and delivered. At December 31, 2007, there was an unrealized loss on the open hedge contracts of $3,831,828.

Dune is exposed to the risk that periodic changes will not be effective, as defined, or that the derivatives will no longer qualify for hedge accounting. Ineffectiveness, as defined, results when the change in the total fair value of the derivative instrument is greater than the change in the value of Dune’s expected future cash receipt for sale of production. To the extent that the periodic changes in the fair value of the derivatives are not effective, that ineffectiveness is recorded to “gain (loss) on derivative liability” in the statement of operations. Likewise, if a hedge ceases to qualify for hedge accounting, those periodic changes in the fair value of derivative instruments are recorded to “gain (loss) on derivative liability” in the statement of operations in the period of the change along with the impact on earnings of the contracts settled during the reporting period. For the years ended December 31, 2007, 2006 and 2005, Dune recorded a loss of $2,948,403, $33,733, and $190,553 on the derivatives, respectively.

Effective January 1, 2008, the Company discontinued, prospectively, the designation of its derivatives as cash flow hedges. The net derivative loss related to the discontinued cash flow hedges, as of December 31, 2007, will continue to be reported in accumulated other comprehensive income until such time that they are charged to income or loss as the volumes underlying the cash flow hedges are realized. Beginning January 1, 2008, the gain or loss on derivatives will be recognized currently in earnings.

F-19

DUNE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

NOTE 6—COMMITMENTS AND CONTINGENCIES

Dune and its subsidiaries are involved in litigation in the ordinary course of business. These proceedings are subject to the uncertainties inherent in any litigation. Dune is defending itself vigorously in all such matters and does not believe that the ultimate disposition of such proceedings will have a material adverse effect on its consolidated financial position, results of operations or liquidity.

The Company, as an owner or lessee and operator of oil and gas properties, is subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations and subject the lessee to liability for pollution damages. In some instances, the Company may be directed to suspend or cease operations in the affected area. We maintain insurance coverage, which we believe is customary in the industry, although we are not fully insured against all environmental risks.

In connection with the acquisition of Goldking, the Company inherited an environmental contingency which after conducting its due diligence and subsequent testing believes is the responsibility of a third party. The matter is being reviewed by the federal regulators to deem the cause of the responsibility. While the final outcome can not be currently determined and any cost to remediate the area are not covered by insurance, the Company does not believe it will have a material impact on its results of operations or financial position.

The Company is not aware of any other environmental claims existing as of December 31, 2007, which have not been provided for, covered by insurance or otherwise have a material impact on its financial position or results of operations. There can be no assurance, however, that current regulatory requirements will not change, or past non-compliance with environmental laws will not be discovered on the Company’s properties.

The Company has a long-term operating lease agreement for its corporate offices that expires September 30, 2011. Under the terms of the lease agreement, the Company received a buildout allowance that is being amortized to expense over the term of the lease. In October 2007, the Company amended it lease agreement to expand the leased office space. The lease term for the additional space also expires in September, 2011. Rent expense for the years ended December 31, 2007, 2006 and 2005 was $0.5 million, $0.1 Million and $0.06 Million, respectively.

Minimum rentals for each of the five years subsequent to December 31, 2007 are as follows (in thousands):

	Amount
2008	$	702
2009		778
2010		817
2011		612
2012		—
	$	2,909

NOTE 7—STOCK OPTIONS AND WARRANTS

The Company utilizes restricted stock, stock options and warrants to compensate employees, officers, directors, and consultants. Total stock-based compensation expense including options, warrants, and restricted stock was $8,071,142, $1,324,714 and $- for the years ended December 31, 2007, 2006 and 2005, respectively.

F-20

DUNE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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 $1,292,500, a financial advisory fee of $477,000 and expenses of $104,184. Dune also issued a warrant exercisable for up to 900,000 shares of its common stock at an exercise price 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 until July 5, 2006, Dune was required to pay to the investors a registration rights 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 included in other expense in 2006.

As further consideration for amending and restating their Credit Agreement on September 26, 2006, 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 any unexercised warrants expire on September 26, 2015. The 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.

On January 24, 2007, Dune granted stock options for services, exercisable in the aggregate, for up to 500,000 shares of common stock to 6 non-employee directors and its president. Such options vested immediately, expire in five years and are exercisable at $1.94 per share. The fair value of the options amounted to $787,470 and was expensed in 2007. Variables used in the Black-Scholes option-pricing model include (1) risk-free interest rate of 4.4%, (2) expected option life is the actual remaining life of the options, (3) expected volatility of 112% and (4) zero expected dividends.

On April 12, 2007, our board of directors approved the grant of five year stock options for services of two individuals unaffiliated with Dune, to purchase up to an aggregate of 500,000 shares of common stock, at an exercise price of $1.87 (the closing share price on such date). The fair value of the options amounted to $747,701 and was expensed in 2007. Variables used in Black-Scholes option-pricing model include: (1) risk-free interest rate of 4.7%, (2) expected option life is the actual remaining life of the options, (3) expected volatility of 108% and (4) zero expected dividends. The options vested upon the successful completion of the Goldking acquisition on May 15, 2007. Holders of the options were also granted certain piggy-back registration rights.

On April 17, 2007, we entered into four new employment agreements (collectively, the “Employment Agreements”), pursuant to which we: (a) engaged James A. Watt to serve as our President and Chief Executive Officer, (b) engaged Frank T. Smith, Jr. to serve as Senior Vice President and Chief Financial Officer and (c) extended and modified our employment arrangements with each of Alan Gaines and Amiel David. Under the new employment agreements, Mr. Gaines will continue to serve as our Chairman and consented to no longer serve as Chief Executive Officer and Dr. David agreed to resign as President and Chief Operating Officer and to serve as Senior Advisor to our Board of Directors. We also entered into restricted stock agreements with each of the foregoing individuals, pursuant to which we issued 7,075,000 shares of our common stock. The issuance of these shares of restricted stock triggered anti-dilution protection contained in the September 26, 2006 Warrant Agreement with our former lender and resulted in our issuing additional warrants exercisable for 58,172 shares of our common stock, at a strike price of $1.35 per share. The fair value of the warrants amounted to $71,942. Variables used in the Black-Scholes option-pricing model include (1) risk-free interest rate of 4.7%, (2) expected warrant life is the actual remaining life of the warrants, (3) expected volatility of 108% and (4) zero expected dividends. Pursuant to the Warrant Agreement, any unexercised warrants expire on September 26, 2015. The Company analyzed these warrants for derivative accounting consideration under SFAS 133 on EITF 00.19. The determination was made that derivative accounting is not applicable for these warrants.

F-21

DUNE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

During the year ending December 31, 2007, option holders exercised 105,000 options on a cashless basis for 73,549 shares of common stock. This transaction resulted in an increase in common stock of $73 and a reduction in paid-in capital of $73. Dune received no cash consideration in this transaction.

On December 17, 2007, pursuant to its 2007 Stock Incentive Plan, the Company issued a total of 1,242,946 shares of its common stock to its employees and non-employee directors. These shares vest ratably over a three year period with the initial vesting occurring December 17, 2008. Our 2007 Stock Incentive Plan, which was approved by our stockholders, reserves a total of 7,000,000 shares of common stock for issuance to employees and non-employee directors. The Plan is administered by our Compensation Committee.

The weighted average fair value of the stock options granted during the year ended December 31, 2007 and 2006 was $1.54 and $2.03, respectively. Variables used in the Black-Scholes option-pricing model include (1) risk-free interest rates between 4.4% and 4.6%, (2) expected option life is the actual remaining life of the options as of each period end, (3) expected volatility is 108% to 356% and (4) zero expected dividends. A summary of stock option transactions follow:

	Options		Weighted Average Price
Outstanding as of December 31, 2004	483,333		$	0.70
Granted during 2005	1,795,000			2.26
Cancelled or expired	—			—
Exercised	—			—
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
Granted during 2007	1,000,000			1.54
Cancelled or expired	(175,000	)		(2.47	)
Exercised	(105,000	)		(1.24	)
Outstanding as of December 31, 2007	2,950,000		$	1.73

Options outstanding and exercisable at December 31, 2007 are as follows:

Exercise Price	Number of Shares	Remaining Life	Intrinsic Value (In-the-money) Options
0.54	105,000	.8 years	$	158,000
0.85	25,000	1.0 years		30,000
0.90	50,000	1.0 years		57,000
1.25	250,000	2.2 years		198,000
1.50	50,000	3.8 years		27,000
1.87	500,000	4.3 years		85,000
1.94	500,000	4.0 years		50,000
2.30	15,000	2.5 years		—
2.35	300,000	2.8 years		—
2.44	1,125,000	2.4 years		—
2.54	30,000	2.6 years		—
	2,950,000		$	605,000

F-22

DUNE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

A summary of Stock Warrant transactions follow:

	Warrants	Weighted Average Price
Outstanding as of December 31, 2004	—	$	—
Granted during 2005	324,324		1.57
Cancelled or expired	—		—
Exercised	—		—
Outstanding as of December 31, 2005	324,324		1.57
Granted during 2006	1,400,000		2.44
Cancelled or expired	—		—
Exercised	—		—
Outstanding as of December 31, 2006	1,724,324		2.28
Granted during 2007	58,172		1.23
Cancelled or expired	—		—
Exercised	—		—
Outstanding as of December 31, 2007	1,782,496	$	2.24

Warrants outstanding and their relative exercise price at December 31, 2007 are as follows:

Exercise Price	Number of Shares	Remaining Life	Intrinsic Value (In-the-money) Warrants
1.35	558,172	7.8 years	$	385,139
1.85	324,324	2.8 years		61,622
2.65	900,000	3.2 years		—
	1,782,496		$	446,761

Subsequent to the year ended December 31, 2007, option holders exercised 50,000 stock options on a cashless basis for 35,212 shares of common stock. This transaction resulted in an increase in common stock of $35 and a reduction in paid-in capital of $35. Dune received no cash consideration in this transaction.

NOTE 8—INCOME TAXES

The income tax provision differs from the amount of income tax determined by applying the Federal Income Tax Rate to pre-tax income from continuing operations for the years ended December 31, 2007, 2006 and 2005 due to the following:

	Year ended December 31,
	2007			2006			2005
	(in thousands)
Computed "expected" tax benefit	$	(15,293	)	$	(18,773	)	$	(555	)
Non-deductible expenses		6			—			—
State taxes, net of benefit		—			—			—
Other		(6	)		—			—
Valuation allowance		—			18,773			555
Income Tax expense (benefit)	$	(15,293	)	$	—		$	—

F-23

DUNE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Deferred tax assets at December 31, 2007 and 2006 are comprised primarily of net operating loss carryforwards and book impairment from write downs of assets. Deferred tax liabilities consist primarily of the difference between book and tax basis depreciation, depletion and amortization (DD&A). Book basis in excess of tax basis for oil and gas properties and equipment primarily results from differing methodologies for recording property costs and depreciation, depletion and amortization under United States generally accepted accounting principles and income tax reporting. Additionally, upon the acquisition of the stock of Goldking, deferred tax liabilities have resulted for the difference in fair market value of the oil and gas properties relative to their historical tax basis.

Following is a summary of deferred tax assets and liabilities:

	Year ended December 31,
	2007			2006
	(in thousands)
Current deferred tax assets:
State taxes	$	95		$	—
Unrealized gains/losses		1,501			12
Derivative instruments		674			—
Total current deferred tax assets		2,270			12
Noncurrent deferred tax assets:
Derivative instruments		1,351			—
Oil and gas property and equipment (Book DD&A)		20,285			1,880
Asset retirement obligation		2,341			120
Book impairment of assets		16,137			15,019
Share based compensation		2,699			—
Loss carry forwards		78,227			14,338
Other oil and gas property related		1,637			826
Other		171			—
Total noncurrent deferred tax assets		122,848			32,183
Total deferred tax assets		125,118			32,195
Current deferred tax liability		—			—
Noncurrent deferred tax liabilities:
Property and equipment (Tax DD&A)		25,914			1,933
Deferred tax on acquisition		72,309			—
Deferred state tax obligation		—			—
Oil and gas exploration and development operations		54,627			10,241
Asset retirement obligation		2,032			—
Other		165			—
Total noncurrent deferred tax liabilities		155,047			12,174
Total deferred tax liabilities		155,047			12,174
Net deferred tax assets (liabilities)		(29,929	)		20,021
Valuation allowance		—			(20,021	)
Net deferred income tax asset (liability)	$	(29,929	)	$	—

At December 31, 2007, the Company has U.S. tax loss carryforwards of approximately $223.5 million which will expire in various amounts beginning in 2020 and ending in 2027.

F-24

DUNE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

We have determined that as a result of the acquisition of all the outstanding stock of Goldking, a change of control pursuant to limitations set forth in Section 382 of the IRS rules and regulations occurred at the Goldking level. As a result, we will be limited to utilizing approximately $13.5 million of Goldking’s U.S. net operating losses (NOL’s”) to offset taxable income generated by us during the tax year ended December 31, 2007, and expect similar dollar limits in future years until our U.S. NOL’s are either completely used or expire.

NOTE 9—ASSET RETIREMENT OBLIGATION

Changes in the Company’s asset retirement obligations were as follows:

	Year Ended December 31,
	2007		2006		2005
Asset retirement obligations, beginning of period	$	377,249	$	78,682	$	—
Fair value of liabilities assumed in acquisitions		4,764,294		—		—
Liabilities related to property sales		—		—		—
Revisions in estimated liabilities		2,736,915		273,719		76,509
Accretion expense		887,344		24,848		2,173
Asset retirement obligations, end of period	$	8,765,802	$	377,249	$	78,682

The Company maintains an escrow agreement that has been established for the purpose of assuring maintenance and administration of a performance bond which secures certain plugging and abandonment obligations assumed by the Company in the acquisition of oil and gas properties from EnerVest. At December 31, 2007, 2006 and 2005, the amount of the escrow account totaled $2,220,574, $2,123,707 and $2,034,392, respectively.

NOTE 10—QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)

	Quarter Ended
2007 (3)	March 31			June 30			Sept 30			Dec 31
	(as adjusted) (4)
	(thousands of dollars, except per share)
Revenues	$	2,994		$	14,012		$	27,510		$	39,818
Operating income (loss) (1)		(5,095	)		(7,545	)		(3,958	)		5,251
Net earnings (loss)		(8,511	)		(22,231	)		(13,129	)		1,699
Net earnings (loss) per share; Basic and diluted (2)	$	(0.14	)	$	(0.31	)	$	(0.17	)	$	0.02
	Quarter Ended
2006	March 31			June 30			Sept 30			Dec 31
	(as adjusted) (4)			(as adjusted) (4)			(as adjusted) (4)			(as adjusted) (4)
	(thousands of dollars, except per share)
Revenues	$	1,301		$	1,236		$	1,634		$	3,409
Operating income (loss) (1)		(1,794	)		(1,458	)		(1,944	)		(33,318	)
Net loss		(2,924	)		(2,370	)		(4,726	)		(35,535	)
Net loss per share; Basic and diluted (2)	$	(0.05	)	$	(0.04	)	$	(0.08	)	$	(0.61	)

(1) Operating income (loss) is computed as revenues less lease operating expenses and production taxes, exploration expense, G&A expense, bad debt expense, loss on impairment of investment, impairment of oil and gas properties, depletion, and accretion.

(2) Available to common shareholders.

(3) For a discussion of the Goldking acquisition see NOTE 4 of the Company’s audited financial statements.

(4) Amounts have been adjusted to reflect the change in accounting for oil and gas properties from full cost to successful efforts. See NOTE 1 of the Company’s audited financial statements.

F-25

DUNE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

NOTE 11—SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. Crude oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.

The Company retained Degolyer and MacNaughton, independent third-party reserve engineers, to perform an independent evaluation of proved reserves as of December 31, 2007. Results of drilling, testing and production subsequent to the date of the estimates may justify revision of such estimates. Accordingly, reserve estimates are often different from the quantities of crude oil and natural gas that are ultimately recovered. All of the Company’s reserves are located in the United States.

Proved Reserves

The following reserve schedule was developed by the Company’s reserve engineers and sets forth the changes in estimated quantities for proved reserves of the Company during each of the periods presented:

	Year Ended December 31,
	2007				2006				2005
PROVED RESERVES AS OF:	Oil (MBbls)		Gas (MMcf)		Oil (MBbls)		Gas (MMcf)		Oil (MBbls)		Gas (MMcf)
Beginning of the period	440		26,764		578		26,047		1,309		5,534
Revisions of previous estimates	375		5,326		(191	)	(11,625	)	(794	)	2,570
Extensions, discoveries and other additions	1,308		30,164		2		56		—		—
Production	(580	)	(5,539	)	(35	)	(880	)	(12	)	(364	)
Purchase of minerals in place	8,088		60,849		86		13,166		75		18,307
End of period	9,631		117,564		440		26,764		578		26,047

Oil and Gas Operations

Aggregate results of operations, in connection with the Company’s crude oil and natural gas producing activities, for each of the periods are shown below:

	Year Ended December 31,
	2007		2006			2005
	(in thousands)
Revenues	$	84,334	$	7,580		$	3,724
Production Costs (1)		32,416		2,011			719
Exploration expenses		383		2,024			817
DD&A and valuation provision		36,264		5,799			1,551
Accretion expense		887		25			2
Impairment of oil and gas properties		—		31,411			—
Income before income taxes		14,384		(33,690	)		635
Income tax benefit		5,034		—			—
Results of operations from oil and natural gas producing activities	$	19,418	$	(33,690	)	$	635

(1) Production costs consist of oil and gas operations expense, production and ad valorem taxes, plus general and administrative expense supporting the Company’s oil and gas operations.

F-26

DUNE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Costs incurred in Oil and Gas Activities

Costs incurred in connection with the Company’s crude oil and natural gas acquisition, exploration and development activities for each of the years are shown below:

	Year Ended December 31,
	2007		2006		2005
	(in thousands)
Property acquisition costs	$	391,438	$	36,528	$	29,531
Unproved prospects		455		391		—
Exploration costs		383		2,024		817
Development costs		148,161		363		13,557
Asset retirement obligation		2,737		274		76
Total consolidated operations	$	543,174	$	39,580	$	43,981
Asset retirement obligation (non-cash)	$	2,737	$	274	$	76

Aggregate Capitalized Costs

Aggregate capitalized costs relating to the Company’s crude oil and natural gas producing activities, including asset retirement costs and related accumulated depreciation, depletion and amortization are as follows:

	Year Ended December 31,
	2007			2006
	(in thousands)
Proved oil and gas properties	$	628,087		$	84,913
Accumulated DD&A		(74,887	)		(39,033	)
Net capitalized costs	$	553,200		$	45,880

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following information is based on the Company’s best estimate of the required data for the Standardized Measure of Discounted Future Net Cash Flows as of December 31, 2007 and 2006 in accordance with SFAS No. 69, “Disclosures About Oil and Gas Producing Activities” which requires the use of a 10% discount rate. This information is not the fair market value, nor does it represent the expected present value of future cash flows of the Company’s proved oil and gas reserves.

	Year Ended December 31,
	2007			2006
	(in thousands)
Future cash inflows	$	1,753,426		$	174,385
Future production costs (1)		412,634			59,908
Future development costs		200,444			42,705
Future income tax expense		143,196			2,961
Future net cash flows		997,152			68,811
10% annual discount for estimated timing of cash flows		(360,001	)		(35,175	)
Standardized measure of discounted future net cash flows at the end of the year	$	637,151		$	33,636

(1) Production costs include oil and gas operations expense, production ad valorem taxes, transportation costs and general and administrative expense supporting the Company’s oil and gas operations.

F-27

DUNE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Future cash inflows are computed by applying year-end prices, adjusted for location and quality differentials on a property-by-property basis, to year-end quantities of proved reserves, except in those instances where fixed and determinable price changes are provided by contractual arrangements at year-end. The discounted future cash flow estimates do not include the effects of the Company’s derivative instruments. See the following table for average prices:

	December 31,
	2007		2006
Average crude oil price (per Bbl)	$	92.66	$	59.53
Average natural gas price (per Mcf)	$	7.32	$	5.54

Future production and development costs, which include dismantlement and restoration expense, are computed by estimating the expenditures to be incurred in developing and producing the Company’s proved crude oil and natural gas reserves at the end of the year, based on the year-end costs, and assuming continuation of existing economic conditions.

Future development costs include $88.5 million, $35.7 million and $3.2 million – that the Company expects to spend in 2008, 2009 and 2010, respectively, to develop proved non-producing and proved undeveloped reserves.

Future income tax expenses are computed by applying the appropriate year-end statutory tax rates to the estimated future pretax net cash flows relating to the Company’s proved crude oil and natural gas reserves, less the tax basis of the properties involved. The future income tax expenses give effect to tax credits and allowances, but do not reflect the impact of general and administrative costs and exploration expenses of ongoing operations relating to the Company’s proved crude oil and natural gas reserves.

Sources of Changes in Discounted Future Net Cash Flows

Principal changes in the aggregate standardized measure of discounted future net cash flows attributable to the Company’s proved crude oil and natural gas reserves, as required by SFAS No. 69, at year end are set forth in the table below:

	Year Ended December 31,
	2007			2006			2005
Standardized measure of discounted future net cash flows at the beginning of the year	$	33,636			95,476			37,190
Extensions, discoveries and improved recovery		123,375			347			—
Revisions of previous quantity estimates		13,005			(25,147	)		(10,347	)
Net change in timing		—			(28,668	)		(2,130	)
Changes in estimated future development costs		(176,996	)		5,708			(2,947	)
Purchases of minerals in place		391,438			3,442			48,326
Net changes in prices and production costs		239,131			(38,710	)		18,836
Accretion of discount		26,815			9,681			3,719
Sales of oil and gas produced, net of production costs		(51,918	)		(5,569	)		(3,005	)
Development costs incurred during the period		148,161			—			—
Net Change in income taxes		(109,496	)		17,076			5,834
Standardized measure of discounted future net cash flows at the end of the year	$	637,151		$	33,636		$	95,476

F-28

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	DUNE ENERGY, INC.
Date: March 10, 2008	By:	/S/    JAMES A. WATT
		James A. Watt
		Chief Executive Officer

In accordance with the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities indicated below on March 10, 2008.

Signature and Title

/S/    JAMES A. WATT        

James A. Watt

Chief Executive Officer and Director

/S/    FRANK T. SMITH, JR.        

Frank T. Smith, Jr.

Chief Financial Officer

/S/    ALAN GAINES        

Alan Gaines

Chairman of the Board

/S/    RICHARD M. COHEN        

Richard M. Cohen

Director and Secretary

/S/    STEVEN BARRENECHEA        

Steven Barrenechea

Director

/S/    ALAN D. BELL        

Alan D. Bell

Director

/S/    WILLIAM E. GREENWOOD        

William E. Greenwood

Director

/S/    STEVEN M. SISSELMAN        

Steven M. Sisselman

Director