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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, 2010

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 001-32497

 

 

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		None

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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ¨    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  ¨

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

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, 2010, the aggregate market value of the voting and non-voting 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 $4,502,046 based upon a closing sale price of $0.11.

As of February 23, 2011, the registrant had outstanding 46,968,621 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 under the Securities Exchange Act of 1934 within 120 days after the end of the Registrant’s fiscal year covered by this Form 10-K.

 

 

 

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TABLE OF CONTENTS

 

Cautionary Notice Regarding Forward-Looking Statements			1
PART I			2
Item 1. and Item 2. Business and Properties			2
Item 1A. Risk Factors			15
Item 1B. Unresolved Staff Comments			25
Item 3. Legal Proceedings			25
Item 4. Removed and Reserved			25
PART II			26
Item  5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			26
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			29
Item 8. Financial Statements and Supplementary Data			38
Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure			38
Item 9A. Controls and Procedures			38
Item 9B. Other Information			40
PART III			40
PART IV			41
Item 15. Exhibits and Financial Statement Schedules			41
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

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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 under “Item 1A. Risk Factors” and elsewhere in this annual report. 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, without limitation, those described herein) 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 “Item 1A. 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., a Delaware corporation (“Dune,” the “Company” or “we”), is an independent energy company based in Houston, Texas. We were formed in 1998 and since May of 2004, we have been engaged in the exploration, development, acquisition and exploitation of crude oil and natural gas properties, with interests along the Louisiana/Texas Gulf Coast. Our properties cover over 85,000 gross acres across 22 producing oil and natural gas fields.

Our total proved reserves as of December 31, 2010 were 82.7 Bcfe, consisting of 48.6 Bcf of natural gas and 5.7 Mmbbls of oil. The PV-10 of our proved reserves at year end was $214.5 million based on the average of the beginning of each month prices for 2010 of $76.05/bbl and $4.38/mcf. During 2010, we sold 12.8 Bcfe and produced 7.8 Bcfe. In addition, we experienced a net downward revision of (2.2) Bcfe.

Employees

As of December 31, 2010, we had 38 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.

Our Business Strategy

We intend to use our competitive strengths to increase 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. Our primary focus will continue to be the development and exploration efforts in our Gulf Coast properties. We believe that our properties and acreage position will allow us to grow organically through low risk drilling in the near term, as this property set continues to present attractive opportunities to expand our reserve base through workovers and recompletions, field extensions, delineating deeper formations within existing fields and higher risk/higher reward exploratory drilling. In addition, we will constantly review, rationalize and “high-grade” our properties in order to optimize our existing asset base.

Actively Manage the Risks and Rewards of Our Drilling Program. Our strategy is to increase our oil and natural 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 higher risk/higher 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.

Maintain and Utilize State of the Art Technological Expertise. We expect to maintain and 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 employ technical advancements, including 3-D seismic data and Pre-Stack depth and Reverse-Time migration to identify and exploit new opportunities in our asset base. We also employ the latest directional drilling, completion and fracturing technology in our wells to enhance recoverability and accelerate cash flows.

 

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Pursue Opportunistic Acquisitions of Underdeveloped Properties. We continually review opportunities to acquire producing properties, leasehold acreage and drilling prospects that are in core operating areas and require a minimum of initial upfront capital. We are also seeking to acquire operational control of properties that we believe have a solid proved reserves base coupled with significant exploitation and exploration potential. Nevertheless, while we will continue to evaluate acquisition opportunities that we believe will further enhance our operations and reserves in a cost effective manner, our principal efforts in 2011 will be on exploiting our existing asset base.

2011 Budget. For 2011 we have targeted an initial capital budget of approximately $25 million, primarily focused on our Garden Island Bay projects. The capital program will include several maintenance projects in addition to field exploitation within Garden Island Bay.

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, 2010, our proved oil and gas reserves were concentrated in 22 producing fields along the Texas and Louisiana Gulf Coast. The fields tend to have stacked multiple producing horizons with production typically between 4,000 and 13,000 feet. Some of the fields have numerous available wellbores capable of providing workover and recompletion opportunities. Additionally, new 3-D seismic data allows definition of numerous updip proved undeveloped locations throughout the fields. The characteristics of these fields allow the Company to record significant proved behind pipe and proved undeveloped reserves in the annual year-end reserve report. At year end 2010, our proved developed producing (PDP) reserves of 29.7 Bcfe were 36% of our total oil and natural gas reserves, the proved developed non-producing (PDNP) of 24.7 Bcfe were 30% of the total oil and natural gas reserves and the proved undeveloped (PUD) of 28.3 Bcfe were 34% of the total proved reserves.

Three of our fields, Garden Island Bay, Leeville and Bateman Lake have large acreage positions surrounding piercement salt domes. These fields account for 39% of our total proved oil and gas reserves. We maintain an active workover and recompletion program in each of these fields and have drilled several development wells in the fields since we acquired them. These workovers, recompletions and development wells are designed to maintain or enhance the production rates in each of the fields. Most of these fields have had minimal drilling below 15,000 feet or below the salt layers which provides significant exploratory upside for the Company. 3-D seismic technology and directional drilling techniques developed in the offshore shelf and deep water environments provide the Company with several high reserve potential opportunities to drill in 2011 and beyond.

At Garden Island Bay, we completed a new Kirchoff Depth and Reverse Time migration project and depth converted our 3-D seismic data. The Company has entered into a partnership arrangement with two private entities to drill an exploratory test well below the salt in this high reserve potential area. Dune will have a 15% working interest in this well before payout and a 26% working interest after payout. Payout is defined as gross 3 MMboe of production. The well will spud in March 2011 and is expected to take 80–120 days to drill and test.

In addition, Dune began drilling the SL 214 #916 in late January. This is a 14,000 foot test in the north flank of the same Garden Island Bay field as the deep test but is above salt. This prospect is one of 17 prospects and approximately 40 separate well locations identified using a recently completed depth migrated 3-D data set within the field. Dune will maintain a 100% working interest in this prospect. Success on these projects could lead to further exploratory or development drilling later in 2011 within the field.

 

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At the Leeville and Bateman Lake fields, we have formed and maintained private company partnerships to drill new wells in which Dune can elect to participate at varied working interests or carry for the full cost of the well while maintaining an overriding royalty in the resultant production. The deeper potential at Leeville is relatively unexplored and we intend to develop partnerships to explore this potential in the next year or two.

The Chocolate Bayou, Comite, North Broussard and Live Oak fields comprise our next four largest properties and consist of 38% of our total reserves. These assets are typically characterized as having fewer wellbores than the salt dome fields but present numerous opportunities for new fault blocks containing unproved reserves that have been identified with new 3-D seismic data. As of December 31, 2010, approximately 52% of our PUDs requiring new wellbores are contained in these fields.

The remaining 15 fields contain approximately 23% of our total proved oil and gas reserves and are characterized by occasional new drilling wells and workovers, but typically do not have the upside opportunities demonstrated in the other fields.

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, future income tax expense or 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 the average of oil and natural gas sales prices on the first day of each of the twelve months during 2010. Estimated quantities of proved reserves and their present value are affected by changes in oil and natural gas prices. The arithmetic average reference prices utilized for the purpose of estimating our proved reserves and the present value of proved reserves as of December 31, 2010 were $76.05 per barrel of oil and $4.38 per Mcf of natural gas.

 

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The following table sets forth our estimated net total oil and natural gas reserves and the PV-10 value of such reserves as of December 31, 2010. The reserve data and the present value as of December 31, 2010 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, 2010, 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 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 reserves, see Note 12 of Notes to Consolidated Financial Statements.

 

		Oil				Natural Gas				Total				Undiscounted Future Net Revenue				Present value of Reserves Discounted at 10% (1)
		Mbbl				Mmcf				Mmcfe				$ (thousands)				$ (thousands)
Proved:
Developed Producing			2,406.0				15,298.0				29,734.0				96,100.5				68,404.4
Developed Nonproducing			1,309.1				16,835.5				24,690.1				102,634.7				47,921.2
Proved Undeveloped			1,976.5				16,419.8				28,278.8				144,733.6				98,204.0
Total Proved			5,691.6				48,553.3				82,702.9				343,468.8				214,529.6
Probable:
Developed Producing			62.5				644.5				1,019.5				7,319.8				6,746.1
Developed Nonproducing			65.9				1,496.8				1,892.2				7,173.9				3,653.7
Undeveloped			336.4				582.2				2,600.6				24,039.5				11,526.6
Total Probable			464.8				2,723.5				5,512.3				38,533.2				21,926.4
Possible:
Undeveloped			1.0				3,257.0				3,263.0				5,775.1				2,524.8
Total Possible			1.0				3,257.0				3,263.0				5,775.1				2,524.8

 

(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 natural 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.

 

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

 

		As of December 31, 2010
		(dollars in thousands)
PV-10		$	214,530
Future income taxes, discounted at 10%			—
Standardized income of discounted future net cash flows		$	214,530

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 from continuing operations for the two years ended December 31, 2010 and 2009.

 

		Year Ended December 31,
		2010				2009
Net Production:
Oil (Bbl)			584,919				572,497
Natural Gas (Mcf)			3,793,486				4,351,260
Natural Gas Equivalent (Mcfe)			7,303,000				7,786,242
Oil and Natural Gas Sales (dollars in thousands):
Oil		$	45,408			$	33,294
Natural Gas			18,781				18,951
Total		$	64,189			$	52,245
Average Sales Price:
Oil ($ per Bbl)		$	77.62			$	58.21
Natural Gas ($ per Mcf)			4.95				4.36
Natural Gas Equivalent ($ per Mcfe)		$	8.79			$	6.71
Oil and Natural Gas Costs (dollars in thousands):
Lease operating expenses		$	18,822			$	19,064
Production taxes			2,767				4,073
Other operating expenses			4,024				5,290
Average production cost per Mcfe		$	3.51			$	3.65

 

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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,
		2010				2009
		(in thousands)
Unproved prospects		$	—			$	477
Development costs			8,755				13,543
ARO costs			1,617				594
Total consolidated operations			10,372				14,614
Asset Retirement Obligations (non-cash)		$	(5,010	)		$	1,256

Drilling Activity

The following table sets forth our drilling activity during the twelve month period ended December 31, 2010 and 2009 (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,
		2010								2009
		Gross				Net				Gross				Net
Development wells
Productive			1.0				0.2				1.0				0.5
Non-productive			1.0				1.0				—				—
Exploratory wells
Productive			1.0				0.5				1.0				0.8
Non-productive			2.0				0.2				—				—

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, 2010. Productive wells are wells that are capable of producing natural gas or oil in economic quantities.

 

		Company Operated								Non-operated								Total
		Gross				Net				Gross				Net				Gross				Net
Oil			38				41				21				7				59				48
Natural gas			48				28				184				7				232				35
Total			86				69				205				14				291				83

 

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Acreage Data

The following table summarizes our gross and net developed and undeveloped oil and natural gas acreage under lease as of December 31, 2010.

 

		Developed acres								Undeveloped acres
		Gross				Net				Gross				Net
Gulf Coast Properties (1)			84,925				57,569				1,484				404
Other (2)			—				—				19,513				5,047
Total			84,925				57,569				20,997				5,451

 

(1)	Undeveloped acreage includes acreage located in Bayou Couba, Los Mogotes and Pearsall fields.

(2)	Other includes Delaware Deep acreage in 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.

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:

 

2010:
Texon LP			68	%
Upstream Energy Services			14	%
Crosstex Gulf Coast Marketing LTD			10	%
2009:
Texon LP			64	%
Upstream Energy Services			15	%

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.

 

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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 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.

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 (“FERC”) regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. Interstate oil pipeline rates are typically set based on a cost of service methodology (“Cost-Based Rates”); however, they may also be set based on the competitive market (“Market-Based Rates”) or by agreement between the pipeline and its shippers (“Settlement Rates”). Some oil pipeline rates may be increased pursuant to an index methodology, whereby the pipeline may increase its rates up to a ceiling set by reference to the Producer Price Index for Finished Goods (unless the rate increase is shown to be substantially in excess of the actual cost increases incurred by the pipeline). 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.

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 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

 

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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.

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 not currently regulated under RCRA or state hazardous waste provisions though our operations may produce waste that do not fall within this exemption. However, these oil and gas production wastes may be regulated as solid waste under state law or RCRA. 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

 

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substances and wastes or released petroleum, remediate contaminated property or perform remedial plugging or pit closure operations to prevent future contamination.

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 third parties. However, federal and sate regulators have determined Dune is the responsible party for clean up of this area. Dune had maintained a passive maintenance of this site since it was first discovered after Hurricane Katrina. Costs to date of approximately $1.1 million have been covered by the Company’s insurance minus the standard deductibles. The Company still feels other parties have the primary responsibility for this occurrence but is committed to working with various state and federal authorities on resolution of this issue. At this time no estimate of the final cost of remediation or the method of remediation preferred of this site can be determined. The Company’s insurance will continue to cover clean up costs up to $1 million total. At this time the Company can not be certain insurance will cover costs above this level or if the Company can be successful in proving the other parties should be primarily responsible for the cost of remediation.

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.

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.

Climate Change

In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because emissions of such gases are contributing to warming of the earth’s atmosphere and other climatic changes, the EPA had adopted regulations under existing provisions of the federal Clean Air Act that would require a reduction in emissions of GHGs, from motor vehicles and, also, could trigger permit review for GHG emissions from certain stationary sources. The EPA has asserted that the motor vehicle GHG emission standards triggered Clean Air Act construction and operating permit requirements for stationary sources, commencing when the motor vehicle standards took effect on January 2, 2011. The EPA published its

 

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final rule to address the permitting of GHG emissions from stationary sources under the PSD and Title V permitting programs. This rule “tailors” these permitting programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. It is widely expected that facilities required to obtain PSD permits for their GHG emissions also will be required to reduce those emissions according to “best available control technology” standards for GHG that have yet to be developed. With regards to the monitoring and reporting of GHGs, on November 30, 2010, the EPA published a final rule expanding its existing GHG emissions reporting rule published in October 2009 to include onshore oil and natural gas production activities, which may include certain of our operations. In addition, both houses of Congress have actively considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. The adoption and implementation of any legislation or regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas we produce. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic event; if any such effects were to occur, they could have an adverse effect on our exploration and production operations.

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 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.

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

 

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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 shareholders for the fiscal years ended December 31, 2009 and 2010 were $95.9 million and $101.9 million, respectively. Our revenues for the fiscal years ended December 31, 2009 and 2010 were $52.2 million and $64.1 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.

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

We have a substantial amount of debt. As of December 31, 2010, we had total debt of $335.2 million, $295.2 million of which was our 10-1/2% senior secured notes due 2012 (the “Senior Notes”). We also had $40.0 million outstanding under our amended and restated $40 million term loan credit facility (“Amended and Restated Credit Facility”) at year-end. 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 Amended and Restated Credit Facility bear interest at 15%.

We may not be able to generate sufficient cash flow to meet our debt service obligations and other obligations due to events beyond our control. Any failure to meet our debt obligations could harm our business, financial condition, results of operations or cash flows.

Our ability to generate cash flows from operations and to make scheduled payments on our indebtedness, including the Senior Notes and Amended and Restated Credit Facility, 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 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, we will be forced to adopt an alternative

 

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strategy that may include actions such as reducing or delaying acquisitions and capital expenditures and selling assets. 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 Amended and Restated 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 and our Amended and Restated 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 cash 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;

 

•

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 Amended and Restated Credit Facility contains customary representations and warranties by the Company as well as typical restrictive covenants whereby Dune has agreed, among other things, to limitations to incurrence of additional indebtedness, declaration of dividends, issuance of capital stock, sale of assets, granting of certain liens, prepaying a subordinated debt and corporate reorganizations.

The restrictions contained in the indenture governing the Senior Notes, the certificate of designations relating to the preferred stock and our Amended and Restated 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 could result in a default under our Amended and Restated Credit Facility.

If a default occurs, the lenders under our Amended and Restated 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. If the borrowings under our Amended and Restated 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.

 

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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.

Recent economic conditions in the credit market may adversely affect our financial condition.

The disruption experienced in U.S. and global credit markets since the latter half of 2008 has resulted in instability in demand for oil and natural gas, resulting in varying in energy prices, and has affected the availability and cost of capital. In addition, capital and credit markets have experienced unprecedented volatility and disruption and continue to be unpredictable. Given the current levels of market volatility and disruption, the availability of funds from those markets has diminished substantially. Prolonged negative changes in domestic and global economic conditions or disruptions of either or both of the financial and credit markets may have a material adverse effect on our results from operations, financial condition and liquidity. At this time, it is unclear whether and to what extent the actions taken by the U.S. government will mitigate the effects of the financial market turmoil. The impact of the current difficult conditions on our ability to obtain, and the cost and terms of, any financing in the future is equally unclear. Any inability to obtain adequate financing under our existing credit facility or to fund on acceptable terms could deter or prevent us from meeting our future capital needs to finance our development program, adversely affect the satisfaction or replacement of our debt obligations and result in a deterioration of our financial condition.

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, but are not limited to:

 

•

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 in 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.

Our estimated reserves are based on many assumptions that may prove inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

No one can measure underground accumulations of oil and natural gas in an exact way. Oil and natural gas reserve engineering requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels, and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves which could adversely affect our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

Further, the present value of future net cash flows from our proved reserves may not be the current market value of our estimated natural gas and oil reserves. [In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on the 12-month average oil and gas index prices, calculated as the un-weighted arithmetic average for the first-day-of-the-month price for each month and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties.] Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. In addition, the 10% discount factor we use when calculating discounted future net cash flows for reporting requirements in compliance with the FASB in Accounting Standards Codification (“ASC”) 932 may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general.

A substantial percentage of our proved reserves consist of undeveloped reserves.

As of the end of our 2010 fiscal year, approximately 34% of our proved reserves were classified as proved 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.

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, but not limited to:

 

•

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;

 

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•

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, 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.

Furthermore, if either Mr. Watt or Mr. Smith ceases to be involved in the day to day operations and management of our business, this will constitute a “Change of Control” and a resulting event of default under our Amended and Restated Credit Facility. As stated above, such an event of default could accelerate the amounts due under our Amended and Restated Credit facility, cause a cross default under our other debt instruments or have other adverse effects on our ability to continue to obtain debt financing. Therefore the loss of either Mr. Watt or Mr. Smith could have an adverse effect on our business, financial condition, and results of operations.

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.

 

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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 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.

Certain federal income tax deductions currently available with respect to oil and natural gas drilling and development may be eliminated as a result of future legislation.

President Obama’s Proposed Fiscal Year 2012 Budget includes proposals that would, if enacted into law, make significant changes to United States tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could increase the taxable income allocable to our unitholders and negatively impact the value of an investment in our units.

 

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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 in the areas where we operate has resulted in escalating insurance costs and less favorable coverage terms.

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, the operator for the prospect maintains insurance of various types to cover our operations with policy limits and retention liability customary in the industry. We believe the coverage and types of insurance are adequate. The occurrence of a significant adverse event that is not fully covered by insurance could result in the loss of our total investment in a particular prospect which could have a material adverse effect on our financial condition and results of operations.

The financial condition of our operators could negatively impact our ability to collect revenues from operations.

We operate 96% of the properties in which we have working interests. In the event that an operator of the other 4% of our properties experiences financial difficulties, this may negatively impact our ability to receive payments for our share of net production to which we are entitled 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 may 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 may enter 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 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

 

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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.

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. 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;

 

•

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.

 

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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 have 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.

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;

 

•

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.

A substantial number of shares of our common stock are 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 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

 

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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.

 

Item 4.

(Removed and Reserved).

 

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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 July 16, 2010, our common stock has been traded on the OTC Bulletin Board. The following table sets forth, for the periods indicated, the high and low bid information of our common stock on the OTC Bulletin Board for the period from July 16, 2010 through December 31, 2010 and the high and low sales prices of our common stock on the NYSE Amex from January 1, 2009 though July 15, 2010. Prices set forth below for period prior to December 2, 2009 have not been adjusted for the 1-for-5 reverse split that was effective on December 2, 2009.

 

2010:		High				Low
Quarter ended December 31, 2010		$	0.45			$	0.10
Quarter ended September 30, 2010		$	0.18			$	0.08
Quarter ended June 30, 2010		$	0.40			$	0.09
Quarter ended March 31, 2010		$	0.34			$	0.16
2009:		High				Low
Quarter ended December 31, 2009		$	0.45			$	0.07
Quarter ended September 30, 2009		$	0.25			$	0.10
Quarter ended June 30, 2009		$	0.25			$	0.11
Quarter ended March 31, 2009		$	0.32			$	0.11

The last sales price of our common stock on the OTC Bulletin Board on December 31, 2010 was $0.40 per share. As of February 22, 2011, the closing sale price of a share of our common stock was $0.99. As of February 22, 2011, there were approximately 196 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 60,299 common shares repurchased in 2010, and 27,603 common shares repurchased in the fourth quarter of 2010. All shares repurchased were associated with the payment of taxes by employees upon the vesting of stock awarded pursuant to the Dune Energy, Inc. 2007 Stock Incentive Plan (the “Plan”)

During the fourth quarter of 2010, the Company awarded a total of 943,345 shares of Restricted Stock to employees and non-employee directors of the Company, pursuant to the Plan.

 

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Securities Authorized for Issuance Under Equity Compensation Plans

The following table provides information as of December 31, 2010 about our equity compensation plans and arrangements.

Equity Compensation Plan Information—December 31, 2010

 

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			60,000	(1)(2)		$	9.70				884,072	(3)
Equity compensation plans not approved by security holders			441,635	(4)(5)		$	10.27				—
Total			501,635			$	10.20				884,072

 

(*)	The number of shares and any exercise prices with respect to awards and equity issuances made prior to December 1, 2009 have been adjusted to give effect to the 1-for-5 reverse stock split adopted, effective as of December 2, 2009.

(1)

Consists of options issued to our directors pursuant to our 2005 Non-Employee Director Incentive Plan (the “2005 Plan”) on January 24, 2007 to purchase up to 60,000 shares of our common stock at an exercise price of $9.70 per share, which expires on January 24, 2012. The 2005 Plan, which authorized the issuance of up to 400,000 shares in stock awards and options, was approved by stockholders on May 30, 2006.

(2)

Excludes the following shares of restricted stock awarded pursuant to our 2007 Stock Incentive Plan, as amended on December 1, 2009 (as amended, the “2007 Plan”): (i) 622,700 shares of restricted stock awarded to employees during fiscal year 2008, which shares vest equally over the three years from grant date; (ii) 573,780 shares of restricted stock awarded to employees, officers and non-employee directors during fiscal year 2009, which shares vest equally over the three years from grant date; (iii) 450,000 shares of restricted stock awarded to certain executive officers during fiscal year 2009, of which 301,500 shares vest equally over the three years from grant date and 148,500 shares vest in accordance with certain performance-based criteria; (iv) 938,900 shares of restricted stock awarded to employees, officers and non-employee directors during fiscal year 2010, which shares vest equally over three years from the grant date; and (v) 4,445 shares issued on December 30, 2010 in lieu of cash for a portion of their respective bonuses. The amendment to the 2007 Plan was approved by stockholders on November 30, 2009 and authorizes the issuance of up to 3,200,000 shares in stock awards and options. The initial 2007 Plan was approved by stockholders on May 30, 2006.

(3)

Includes 340,000 shares available under the 2005 Plan and 544,072 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)	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, 2010.

(5)	Excludes 407,702 shares of restricted stock awarded in fiscal year 2009 to non-employee directors having elected to receive shares in lieu of cash for a portion of their annual retainer and fees.

 

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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 441,635 shares of our Common Stock included in the chart above were issuable as of December 31, 2010:

 

•

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 180,000 shares of our Common Stock at a warrant exercise price of $13.25 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 10,000 shares of our Common Stock at an exercise price of $7.50 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 100,000 shares of our Common Stock at a warrant exercise price of $6.75 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 40,000 shares of our Common Stock at an exercise price of $9.70 per share;

 

•

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 100,000 shares of our Common Stock at an exercise price of $9.35 per share; and

 

•

Warrants issued April 17, 2007 to our former lender in accordance with anti-dilutive protection contained in the September 26, 2006 warrant agreement with our former lender, resulting in the issuance of additional warrants expiring in April 2012 and exercisable to purchase up to 11,635 shares of our Common Stock at a warrant exercise price of $6.75 per share.

 

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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.

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 total reserves are classified as proved, possible and probable. 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. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves and when probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable estimates. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves and when probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed proved plus probable plus possible reserve estimates.

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 total oil and gas reserves attributable to a specific property. Our total 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 total reserves will be produced, the timing and ultimate recovery can be affected by a

 

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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 or 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. Oil and condensate prices were calculated for each property using differentials to an average for the year of the first of the month ConocoPhillips WTI price of $76.05 per barrel and were held constant for the lives of the property. The weighted average price over the lives of the properties was $78.34 per barrel. Gas prices were calculated for each property using the differentials to an average for the year of the first of the month Henry Hub Louisiana Onshore price of $4.38 per million British thermal units and were held constant for the lives of the properties. The weighted average price over the lives of the properties was $4.71 per thousand cubic feet. The standardized measure is based on the average of the beginning of the month pricing for 2010. 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 2010 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 magnitude of dry holes, quarterly and annual net income can vary dramatically.

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 developed 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

 

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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 continued capitalization of the well and its reclassification as a well containing proved reserves.

Asset Retirement Obligation

The Company follows FASB ASC 410—Asset Retirement and Environmental 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. A five percent market risk premium was included in the Company’s asset retirement obligation fair value estimate. 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 retirement 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 FASB ASC 815—Derivatives and Hedging. 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 derivatives 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,

 

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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, continued to be reported in accumulated other comprehensive loss through December 31, 2009 and were charged to loss as the volumes underlying the cash flow hedges were realized. Beginning January 1, 2008, the gain or loss on derivatives was recognized currently in earnings.

Associated with the Wayzata Credit Agreement dated December 7, 2010, the Company was no longer required to hedge and settled all hedged balances.

Stock-based compensation

The Company follows the provisions of FASB ASC 718 – Stock Compensation. The statement 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 on the date of the grant. Due to significant declines in the price of Dune’s stock since the issuance of many employee grants, stock-based compensation amounts are high compared to current values.

Business Strategy

Dune is an independent energy company engaged in the exploration, development, acquisition and exploitation of natural gas and crude oil properties, with interest along the Gulf Coast. On May 15, 2007, we closed the Stock Purchase and Sale Agreement to acquire all of the capital stock of 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 85,000 gross acres across 22 oil and natural gas fields onshore and in state waters along the Texas and Louisiana Gulf Coast.

Grow Through Exploitation, Development, and Exploration of Our Properties. Our primary focus will continue to be the development and exploration efforts in our Gulf Coast properties. We believe that our properties and acreage position will allow us to grow organically through low risk drilling in the near term, as this property set continues to present attractive opportunities to expand our reserve base through workovers and recompletions, field extensions, delineating deeper formations within existing fields and higher risk/higher reward exploratory drilling. In addition, we will constantly review, rationalize and “high-grade” our properties in order to optimize our existing asset base.

Maintain and Utilize State of the Art Technological Expertise. We expect to maintain and 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 and pre-stack depth and reverse-time migration to identify and exploit new opportunities in our asset base. We also plan to employ the latest drilling, completion and fracturing technology in our wells to enhance recoverability and accelerate cash flows associated with these wells.

Pursue Opportunistic Acquisitions of Underdeveloped Properties. We continually review opportunities to acquire producing properties, leasehold acreage and drilling prospects that are in core operating areas and require a minimum of initial upfront capital. We are seeking to acquire operational control of properties that we believe

 

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have a solid proved reserves base coupled with significant exploitation and exploration potential. Nevertheless, while we will continue to evaluate acquisition opportunities that we believe will further enhance our operations and reserves in a cost effective manner, our principal efforts in 2011 will be on exploiting our existing asset base.

Actively Manage the Risks and Rewards of Our Drilling Program. 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 higher risk/higher 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 2010 we invested $8.8 million in oil and gas properties. We produced 7.8 Bcfe during the year. Revisions of previous estimates were 2.2 Bcfe negative, mainly reflecting the Company’s decision not to sidetrack the Exxon Fee #5 located in the Bayou Couba field.

 

Capital costs ($000):		Year Ended 2010				Year Ended 2009
Acquisitions—unproved		$	—			$	477
Development			8,755				13,543
Total CAPEX before ARO			8,755				14,020
ARO costs			1,617				594
Total CAPEX including ARO		$	10,372			$	14,614
Asset retirement obligation (non-cash)		$	(5,010	)		$	1,256
Proved Reserves (Mmcfe):
Beginning			105,475				132,998
Production			(7,788	)			(9,522	)
Purchases			—				—
Sale of reserves			(12,822	)			(2,205	)
Discoveries and extensions			—				5,508
Revisions			(2,162	)			(21,304	)
Ending reserves			82,703				105,475
Reserve additions before revisions (Mmcfe)			—				5,508
Reserve additions after revisions (Mmcfe)			(2,162	)			(15,796	)

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, bank debt and equity offerings as discussed below in Liquidity and Capital Resources.

Liquidity and Capital Resources

During fiscal 2010 compared to fiscal 2009, net cash flow provided by operating activities improved by $1.7 million to ($9.4) million. This improvement was primarily attributable to higher average oil and gas prices for 2010 of $77.62/Bbl and $4.95/Mcf compared to $58.21/Bbl and $4.36/Mcf for 2009.

Our current assets were $51.8 million on December 31, 2010. Cash on hand comprised approximately $39.4 million of this amount, which included $15.8 million escrowed in restricted cash accounts. This compared to $15.1

 

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million at December 31, 2009. Accounts payable have been reduced from $11.8 million at December 31, 2009 to $7.0 million at December 31, 2010.

The consolidated financial statements continue to reflect a much reduced but ongoing drilling and facilities upgrade program which amounted to $8.8 million during 2010. This reduced spending reflected our efforts to conserve cash. Our capital program is designed to maintain production from recompletions and workovers within our fields and exploit the upside potential through joint venture programs. This strategy will involve industry partners in these efforts so as to reduce our upfront cash requirements and reduce risk dollars expended. This represents a decrease of $5.2 million under our $14.0 million of capital investment in 2009.

During the fourth quarter of 2010, Dune replaced its $40 million revolving credit facility with Wells Fargo Capital Finance, Inc. (formerly Wells Fargo Foothill) with a new $40 million term loan facility from Wayzata Opportunities Fund II, L.P. The new facility matures on March 15, 2012 and provides for Wells Fargo Foothill to remain as agent for the facility. The Company has received all of the funds associated with the facility and has placed $23.7 million in escrow to cash collateralize $8.0 million of P&A bonds and provide $15.7 million for the June 2011 bond interest payment. The Company plans to utilize the funds from the new term loan and available cash flow from operations to cover anticipated drilling and recompletion projects in 2011. Additionally, all hedging contracts were settled in 2010 and the Company no longer hedges its oil and gas production.

Semi-annual interest of $15.7 million on our 10  ¹/2% Senior Secured Notes due 2012 was paid on December 1, 2010 and is due on June 1 and December 1 thereafter. The principal on the Senior Secured Notes is not due until 2012. Additionally, as a requirement of the Wayzata Credit Agreement, the $15.7 million interest payment due June 1, 2011 was escrowed and reflected as restricted cash at December 31, 2010.

Shares of our Senior Redeemable Convertible Preferred Stock are not redeemable until the later of December 1, 2012, the repayment in full of all senior secured debt or upon a change in control. Dividends are payable quarterly 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.

Our primary sources of liquidity are cash provided by operating activities, debt financing, sales of non-core properties and access to capital markets. We believe the strength of our current cash position puts us in a favorable position to meet our financial obligations and ongoing capital programs in the current commodity price environment.

The exact amount of capital spending for 2011 will depend upon individual well performance results, cash flow and, where applicable, partner negotiations on the timing of drilling operations. In addition, we expect to offer participations in our drilling program to industry partners over this time frame, thus potentially reducing our capital requirements.

The following table summarizes our contractual obligations and commercial commitments as of December 31, 2010:

 

		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		$	391,875			$	37,500			$	354,375			$	—			$	—
Office lease			609				609				—				—				—
Total		$	392,484			$	38,109			$	354,375			$	—			$	—

 

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Results of Operations

Comparison of 2010 and 2009

Year-over-year production decreased from 7,783 Mmcfe in 2009 to 7,303 Mmcfe in 2010. This decrease was caused by normal reservoir declines and a very limited capital reinvestment program.

The following table reflects the increase (decrease) in oil and gas sales revenue due to changes in price and volume:

 

		2010				% Increase (Decrease)				2009				% Increase (Decrease)				2008
Oil production volume (Mbbls)			585				2	%			572				-22	%			735
Oil sales revenue ($000)		$	45,408				36	%		$	33,294				-55	%		$	73,363
Price per Bbl		$	77.62				33	%		$	58.21				-42	%		$	99.81
Increase (decrease) in oil sales revenue due to:
Change in production volume		$	757							$	(16,269	)
Change in prices			11,357								(23,800	)
Total increase (decrease) in oil sales revenue		$	12,114							$	(40,069	)
Gas production volume (Mmcf)			3,793				-13	%			4,351				-13	%			5,029
Gas sales revenue ($000)		$	18,781				-1	%		$	18,951				-61	%		$	48,577
Price per Mcf		$	4.95				14	%		$	4.36				-55	%		$	9.66
Increase (decrease) in gas sales revenue due to:
Change in production volume		$	(2,433	)						$	(6,549	)
Change in prices			2,263								(23,077	)
Total increase (decrease) in gas sales revenue		$	(170	)						$	(29,626	)
Total production volume (Mmcfe)			7,303				-6	%			7,783				-18	%			9,439
Total revenue		$	64,189				23	%		$	52,245				-57	%		$	121,940
Price per Mcfe		$	8.79				31	%		$	6.71				-48	%		$	12.92
Increase (decrease) in revenue due to:
Change in production volume		$	(3,221	)						$	(21,396	)
Change in prices			15,165								(48,299	)
Total increase (decrease) in total revenue		$	11,944							$	(69,695	)

Revenues

Revenues from continuing operations for the year ended December 31, 2010 totaled $64.2 million as compared to $52.2 million for the year ended December 31, 2009 representing a $12.0 million increase. Production volumes for 2010 were 585 Mbbls of oil and 3.8 Bcf of natural gas or 7.3 Bcfe. This compares to 572 Mbbls of oil and 4.4 Bcf of natural gas or 7.8 Bcfe for 2009 representing a modest reduction in production volumes. In 2010, the average sales price per barrel of oil was $77.62 per barrel and $4.95 per Mcf for natural gas as compared to $58.21 per barrel and $4.36 per Mcf, respectively for 2009. These results indicate that the increase in revenue is primarily attributable to the increase in commodity prices as the average price received per Mcfe produced was $8.79 in 2010 versus $6.71 in 2009 representing an increase of 31%.

 

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Operating expenses

Lease operating expense and production taxes

The following table presents the major components of Dune’s lease operating expense for the last two years on a per Mcfe basis:

 

		Years Ending December 31,
		2010								2009
		Total				Per Mcfe				Total				Per Mcfe
Direct operating expense		$	18,822			$	2.58			$	19,064			$	2.45
Production taxes			2,767				0.38				4,073				0.52
Ad Valorem taxes			1,143				0.16				974				0.13
Transportation			1,491				0.20				2,509				0.32
Workovers			1,390				0.19				1,807				0.23
		$	25,613			$	3.51			$	28,427			$	3.65

Lease operating expense and production taxes from continuing operations for the year ended December 31, 2010 totaled $25.6 million versus $28.4 million for the year ended December 31, 2009. This translated to a decrease of $0.14/Mcfe on a volume basis. This reduction reflects Dune’s efforts to reduce overall field operating expenses and a significant recoupment of production taxes resulting from drilling incentives.

Accretion of asset retirement obligation

Accretion expense for asset retirement obligations increased by $0.2 million for 2010 compared to 2009. This increase is the result of reevaluating abandonment cost at year end.

Depletion, depreciation and amortization (DD&A)

For the year ended December 31, 2010, the Company recorded DD&A expense of $27.1 million ($3.70/Mcfe) compared to $30.0 million ($3.85/Mcfe) for the year ended December 31, 2009 representing a decrease of $2.9 million ($0.15/Mcfe). This reduction reflects the impact of the 2010 impairment on the Company’s oil and gas properties of $34.6 million which directly impacts the depletable base for DD&A purposes.

General and administrative expense (G&A expense)

G&A expense for the year ended December 31, 2010 decreased $3.1 million from the year ended December 31, 2009 to $11.2 million. Cash G&A expense for 2010 fell $0.8 million (8%) from 2009 to $9.4 million. These decreases resulted primarily from a $0.5 million (7%) reduction in personnel expense and a $2.4 million (57%) drop in share-based compensation.

Loss on Impairment of oil and gas properties

Dune recorded an impairment of oil and gas properties of $34.6 million for the year ended December 31, 2010 compared to an impairment of $2.9 million for the year ended December 31, 2009. The increase consists primarily of expired leasehold costs on the Murphy Lake field of $5.3 million, expired drilling and leasehold costs of $18.5 million on the Bayou Couba field and $10.8 million split among 5 fields which did not perform as anticipated in 2010.

 

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Other income (expense)

Interest income

Interest income has been minimal as a result of using our cash balances to support working capital.

Interest expense

Interest expense for the year ended December 31, 2010 amounted to $37.4 million compared to $35.2 million in 2009. This increase reflects additional interest expense attributable to increased borrowings under the Company’s Revolver Commitment and Term Loan. Additionally, the Company expensed $1.2 million associated with the Company’s replacement of the Revolver Commitment.

Gain (loss) on derivative liabilities

The Company recognized a gain on derivatives of $1.4 million for the year ended December 31, 2010, composed of an unrealized gain on change in mark-to-market valuation of $1.6 million and a realized loss on cash settlements of ($0.2) million. This compares to a loss of ($2.8) million, composed of an unrealized loss on change in mark-to-market valuation of ($9.5) million and a realized gain on cash settlements of $6.7 million, for the year ended December 31, 2009. Additionally, associated with the Wayzata Credit Agreement, all hedging requirements were eliminated and all hedged balances settled.

Income (loss) on discontinued operations

Associated with the sale of the South Florence Properties, the Company has reflected all activity for these assets as discontinued operations. For the year ended December 31, 2009, the Company reclassified $3.8 million as income from discontinued operations.

For the year ended December 31, 2010, the Company generated income of $1.5 million. This income was offset by an impairment of $5.0 million to write down the related carrying amounts to their fair value less cost to sell. Consequently, the Company reflected a loss on discontinued operations for the year ended December 31, 2010 of ($3.5) million.

Net Loss available to common shareholders

For the year ended December 31, 2010, net loss available to common shareholders increased $6.0 million from the comparable period of 2009. This increase reflects the impact of a $12.0 million increase in revenues, a $2.8 million decrease in lease operating expense, a $10.3 million decrease in Preferred Stock dividends, a $3.1 million decrease in G&A expense and a $4.1 million increase in the gain on derivative liabilities partially offset by a ($31.7) million increase in the impairment of oil and gas properties and a ($7.3) million increase in loss on discontinued operations.

New Accounting Pronouncements

In January 2010, the FASB issued FASB Accounting Standards Update (ASU) No. 2010-03 Oil and Gas Estimations and Disclosures (ASU 2010-03). This update aligns the current oil and natural gas reserve estimation and disclosure requirements of the Extractive Industries Oil and Gas topic of the FASB Accounting Standards Codification (ASC Topic 932) with the changes required by the SEC final rule ASC 2010-03, as discussed above. ASU 2010-03 expands the disclosures required for equity method investments, revises the definition of oil and natural gas-producing activities to include nontraditional resources in reserves unless not intended to be upgraded into synthetic oil or natural gas, amends the definition of proved oil and natural gas reserves to require 12-month average pricing in estimating reserves, amends and adds definitions in the Master Glossary that is used in estimating proved oil and natural gas quantities and provides guidance on geographic area with respect to

 

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disclosure of information about significant reserves. ASU 2010-03 must be applied prospectively as a change in accounting principle that is inseparable from a change in accounting estimate and is effective for entities with annual reporting periods ending on or after a change in accounting estimate and is effective for entities with annual reporting periods ending on or after December 31, 2009. The impact on the Company’s operating results, financial position and cash flows has been recorded in the consolidated financial statements.

 

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, 2010. 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, 2010, 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. The Company’s internal control over financial reporting is designed to provide reasonable assurance to the Company’s Management and Directors regarding the reliability of financial reporting and the preparation of published financial statements. 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.

 

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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, 2010. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal 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, 2010.

(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 fourth quarter ended December 31, 2010 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

 

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(d) Report of Independent Registered Public Accounting Firm

 

Item 9B.

Other Information.

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.

 

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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, dated May 7, 2003 (1)
3.1.1*		Certificate of Amendment of Amended and Restated Certificate of Incorporation, dated May 7, 2003
3.1.2		Certificate of Amendment of Certificate of Incorporation, dated May 5, 2004 (2)
3.1.3*		Certificate of Amendment of Certificate of Incorporation, dated June 12, 2007
3.1.4*		Certificate of Amendment of Certificate of Incorporation, dated December 14, 2007
3.1.2		Certificate of Amendment of Amended and Restated Certificate of Incorporation, dated December 1, 2009 (3)
3.2		Amended and Restated By-Laws (4)
4.1		Certificate of Designations, dated May 15, 2007, for 10% Senior Redeemable Convertible Preferred Stock of the Company (5)
4.1.1		Certificate of Correction to Certificate of Designations, dated February 26, 2008 (11)
4.2		Form of Placement Agent Warrant (6)
4.3		Form of Investor Registration Rights Agreement (6)
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 (7)
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 (5)
4.6		First Supplement to Indenture dated as of December 30, 2008 (12)
4.7		Form of Global 10 1/2% Senior Secured Exchange Note due 2012 (11)
10.1		Employment Agreement, dated April 17, 2007, between the Company and James A. Watt (8)
10.1.1		Amended and Restated Employment Agreement, dated as of December 30, 2008 between the Company and James A. Watt (12)
10.1.2		Employment Agreement, dated as of October 1, 2009, between the Company and James A. Watt (13)
10.2		Employment Agreement, dated as of February 16, 2010, between the Company and Alan Gaines (15)
10.3		Restricted Stock Agreement, dated April 17, 2007, between the Company and James A. Watt (8)
10.3.1		Restricted Stock Agreement (Performance Based), dated October 1, 2009, between the Company and James A. Watt (14)
10.3.2		Restricted Stock Agreement (Time-Vesting), dated October 1, 2009, between the Company and James A. Watt (14)
10.4		Restricted Stock Agreement, dated April 17, 2007, between the Company and Alan Gaines (8)
10.5		Restricted Stock Agreement, dated April 17, 2007, between the Company and Frank T. Smith, Jr. (8)
10.5.1		Restricted Stock Agreement (Performance Based), dated October 1, 2009, between the Company and Frank T. Smith, Jr. (14)
10.5.2		Restricted Stock Agreement (Time-Vesting), dated October 1, 2009, between the Company and Frank T. Smith, Jr. (15)
10.6		Dune Energy, Inc. 2007 Stock Incentive Plan (21)
10.7*		Form of Grant Agreement under Dune Energy, Inc. 2007 Stock Incentive Plan

 

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Exhibit Nos.		Description
10.8		Stock Purchase and Sale Agreement dated effective April 13, 2007 between the Company and Goldking Energy Holdings, L.P. (8)
10.9		Form of Registration Rights Agreement (8)
10.10		Purchase Agreement dated as of May 1, 2007 between the Company and Jefferies & Company, Inc. (10)
10.11		Notes Registration Rights Agreement, dated May 15, 2007, between the Company and Jefferies & Company, Inc. (5)
10.12		Preferred Stock Registration Rights Agreement, dated May 15, 2007, between the Company and Jefferies & Company, Inc. (5)
10.13		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 (5)
10.14		Intercreditor Agreement, dated May 15, 2007, among Wells Fargo Foothills, Inc., The Bank of New York and the Company, among others named therein (5)
10.15		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 (5)
10.16		First Amendment to Credit Agreement dated as of August 4, 2008 (13)
10.17		Second Amendment to Credit Agreement, dated as of July 7, 2009 (17)
10.18		Third Amendment to Credit Agreement, dated as of March 23, 2010 (18)
10.19*		Fourth Amendment to Credit Agreement, dated as of May 21, 2010
10.20		Fifth Amendment to Credit Agreement, dated as of June 25, 2010 (16)
10.21		Sixth Amendment to Credit Agreement, dated as of September 30, 2010 (19)
10.22		Amended and Restated Credit Agreement, dated December 7, 2010, by and among Dune Energy, Inc. and each of its subsidiaries that are identified o the signature pages thereto as borrowers, as Borrowers, each of its subsidiaries that are identified in the signature pages thereto as guarantors, as Guarantors, the lenders that are signatories thereto, as the Lenders and Wells Fargo Capital Finance, Inc., as Administrative Agent. (20)
10.22.1*		First Amendment to Amended and Restated Credit Agreement and Waiver dated as of December 7, 2010
10.23		1992 ISDA Master Agreement, together with Schedule, dated May 15, 2007 among Wells Fargo Foothill, Inc. and the Company (5)
10.24		Purchase and Sale Agreement, dated as of May 28, 2010, between Dune Properties, Inc., as Seller, and Texas Petroleum Investment Company, as Buyer(16)
14.1		Code of Conduct and Ethics(11)
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.

 

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(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 December 1, 2009, and incorporated by reference herein.

(4)	Previously filed as an exhibit to the Company’s Report on Form 8-K, filed on July 12, 2010, and incorporated by reference herein.

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

(6)	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.

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

(8)	Previously filed as an exhibit to the Company’s Report on Form 8-K, filed April 18, 2007, 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.

(11)	Previously filed as an exhibit to the Company’s Report on Form 10-K filed on March 10, 2008, and incorporated by reference herein.

(12)	Previously filed as an exhibit to the Company’s Report on Form 8-K filed on December 30, 2008, and incorporated by reference herein.

(13)	Previously filed as an exhibit to the Company’s Report on Form 10-Q for the quarterly period ended June 30, 2008, and incorporated by reference herein.

(14)	Previously filed as an exhibit to the Company’s Report on Form 8-K filed on October 5, 2009, and incorporated by reference herein.

(15)	Previously filed as an exhibit to the Company’s Report on Form 8-K filed on February 18, 2010, and incorporated by reference herein.

(16)	Previously filed as an exhibit to the Company’s Report on Form 8-K filed on June 30, 2010, and incorporated by reference herein.

(17)	Previously filed as an exhibit to the Company’s Report on Form 8-K filed on July 9, 2009, and incorporated by reference herein.

(18)	Previously filed as an exhibit to the Company’s Annual Report on Form 10-K filed on March 25, 2010, and incorporated by reference herein.

(19)	Previously filed as an exhibit to the Company’s Report on Form 8-K filed on October 15, 2010, and incorporated by reference herein.

(20)	Previously filed as an exhibit to the Company’s Report on Form 8-K filed on December 10, 2010, and incorporated by reference herein.

(21)	Previously filed as Exhibit B to the Company’s Information Statement on Schedule 14C filed on November 20, 2001, and incorporated by reference herein.

 

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DUNE ENERGY INC.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

 

		PAGE
Dune Energy, Inc.—
Report of Independent Registered Public Accounting Firm			F-2
Consolidated Balance Sheets at December 31, 2010 and 2009			F-3
Consolidated Statements of Operations for the Years Ended December 31, 2010 and 2009			F-4
Consolidated Statements of Cash Flows for the Years Ended December 31, 2010 and 2009			F-5
Consolidated Statements of Changes in Stockholders’ Equity (Deficit) for the Years Ended December 31, 2010 and 2009			F-6
Notes to Consolidated Financial Statements			F-7

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders 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, 2010 and 2009, and the related consolidated statements of operations, shareholders’ equity (deficit), and cash flows for the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Dune Energy, Inc as of December 31, 2010 and 2009 and the results of its operations and cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

/s/ MaloneBailey, LLP

www.malonebailey.com

Houston, Texas

March 3, 2011

 

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Dune Energy, Inc.

Consolidated Balance Sheets

 

		December 31,
		2010				2009
ASSETS
Current assets:
Cash		$	23,670,192			$	15,053,571
Restricted cash			15,753,441				—
Accounts receivable			9,862,849				15,026,945
Assets held for resale			—				36,526,883
Prepayments and other current assets			2,542,624				2,724,666
Total current assets			51,829,106				69,332,065
Oil and gas properties, using successful efforts accounting—proved			526,760,643				541,705,920
Less accumulated depreciation, depletion, amortization and impairment			(294,566,739	)			(245,531,157	)
Net oil and gas properties			232,193,904				296,174,763
Property and equipment, net of accumulated depreciation of $2,817,158 and $2,247,220			527,357				1,215,123
Deferred financing costs, net of accumulated amortization of $1,456,592 and $1,565,280			786,087				1,026,445
Other assets			12,049,829				4,427,826
			13,363,273				6,669,394
TOTAL ASSETS		$	297,386,283			$	372,176,222
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
Current liabilities:
Accounts payable		$	6,953,863			$	11,760,370
Accrued liabilities			13,367,402				21,656,922
Derivative liability			—				1,596,545
Short-term debt			1,395,237				1,579,308
Preferred stock dividend payable			2,206,000				1,985,000
Total current liabilities			23,922,502				38,578,145
Long-term debt, net of discount of $4,781,310 and $7,737,553			335,218,690				316,262,447
Other long-term liabilities			12,548,062				17,640,000
Total liabilities			371,689,254				372,480,592
Commitments and contingencies			—				—
Redeemable convertible preferred stock, net of discount of $4,964,014 and $7,205,812, liquidation preference of $1,000 per share, 750,000 shares designated, 207,912 and 192,050 shares issued and outstanding			202,947,986				184,844,188
STOCKHOLDERS’ EQUITY (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, 41,912,723 and 39,801,796 shares issued and outstanding			41,912				39,802
Treasury stock, at cost (128,388 and 68,089 shares)			(62,920	)			(48,642	)
Additional paid-in capital			81,040,691				97,600,721
Accumulated deficit			(358,270,640	)			(282,740,439	)
Total stockholders’ equity (deficit)			(277,250,957	)			(185,148,558	)
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)		$	297,386,283			$	372,176,222

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

 

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Dune Energy, Inc.

Consolidated Statements of Operations

 

		For the Year Ended December 31,
		2010				2009
Revenues		$	64,188,647			$	52,244,513
Operating expenses:
Lease operating expense and production taxes			25,612,598				28,426,868
Accretion of asset retirement obligation			1,822,959				1,599,555
Depletion, depreciation and amortization			27,054,118				30,039,263
General and administrative expense			11,156,379				14,321,383
Impairment of oil and gas properties			34,562,104				2,874,000
Total operating expense			100,208,158				77,261,069
Operating loss			(36,019,511	)			(25,016,556	)
Other income(expense):
Interest income			4,067				45,054
Interest expense			(37,424,038	)			(35,192,809	)
Gain (loss) on derivative liabilities			1,382,938				(2,780,933	)
Total other income(expense)			(36,037,033	)			(37,928,688	)
Loss on continuing operations			(72,056,544	)			(62,945,244	)
Income (loss) on discontinued operations			(3,473,657	)			3,813,803
Net loss			(75,530,201	)			(59,131,441	)
Preferred stock dividend			(26,418,537	)			(36,727,085	)
Net loss available to common shareholders		$	(101,948,738	)		$	(95,858,526	)
Net loss per share:
Basic and diluted from continuing operations		$	(2.43	)		$	(3.58	)
Basic and diluted from discontinued operations			(0.09	)			0.14
Total basic and diluted		$	(2.52	)		$	(3.44	)
Weighted average shares outstanding:
Basic and diluted			40,457,296				27,846,561
Comprehensive loss:
Net loss		$	(75,530,201	)		$	(59,131,441	)
Other comprehensive income			—				3,709,177
Comprehensive loss		$	(75,530,201	)		$	(55,422,264	)

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

 

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Dune Energy, Inc.

Consolidated Statements of Cash Flows

 

		For the Year Ended December 31,
		2010				2009
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss		$	(75,530,201	)		$	(59,131,441	)
Adjustments to reconcile net loss to net cash used in operating activities:
Loss (income) from discontinued operations			3,473,657				(3,813,803	)
Depletion, depreciation and amortization			27,054,118				30,039,263
Amortization of deferred financing costs and debt discount			5,060,064				3,250,872
Stock-based compensation			1,766,880				4,145,712
Impairment of oil and gas properties			34,562,104				2,874,000
Accretion of asset retirement obligation			1,822,959				1,599,555
Loss (gain) on derivative liabilities			(1,596,545	)			9,506,580
Changes in:
Accounts receivable			5,906,957				(774,980	)
Prepayments and other assets			182,042				931,379
Payments made to settle asset retirement obligations			(1,617,300	)			(594,476	)
Accounts payable and accrue liabilities			(13,302,050	)			(8,261,725	)
NET CASH PROVIDED BY (USED IN) CONTINUING OPERATIONS			(12,217,315	)			(20,229,064	)
NET CASH PROVIDED BY DISCONTINUED OPERATIONS			2,857,240				9,172,706
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES			(9,360,075	)			(11,056,358	)
CASH FLOWS FROM INVESTING ACTIVITIES
Investment in proved and unproved properties			(1,950,956	)			(12,932,109	)
Increase in restricted cash			(23,753,441	)			—
Purchase (disposal) of furniture and fixtures			2,651				(4,452	)
Decrease in other assets			377,997				1,077,419
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES— CONTINUING OPERATIONS			(25,323,749	)			(11,859,142	)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES—DISCONTINUED OPERATIONS			29,347,980				(1,088,070	)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES			4,024,231				(12,947,212	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt			40,000,000				24,000,000
Proceeds from short-term debt			15,594,556				2,030,539
Increase in loan costs			(1,863,464	)			—
Payments on short-term debt			(39,778,627	)			(2,464,930	)
NET CASH PROVIDED BY FINANCING ACTIVITIES			13,952,465				23,565,609
NET CHANGE IN CASH BALANCE			8,616,621				(437,961	)
Cash balance at beginning of period			15,053,571				15,491,532
Cash balance at end of period		$	23,670,192			$	15,053,571
SUPPLEMENTAL DISCLOSURES
Interest paid		$	32,093,632			$	31,881,106
Income taxes paid			—				—
NON-CASH INVESTING AND FINANCING DISCLOSURES
Redeemable convertible preferred stock dividends		$	24,176,739			$	34,752,970
Asset retirement obligation revision			(5,010,246	)			1,256,447
Accretion of discount on preferred stock			2,241,800				1,974,115
Common stock issued for conversion of preferred stock			8,016,000				71,547,000

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

 

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Dune Energy, Inc.

Consolidated Statements of Changes in Stockholders’ Equity (Deficit)

Years ended December 31, 2010 and 2009

 

																		Additional Paid-In Capital				Accumulated Other Comprehensive Loss				Accumulated Deficit				Total Stockholders’ Equity (Deficit)
		Common Stock								Treasury Stock
		Shares				Amount				Shares				Amount
Balance at December 31, 2008			19,225,816			$	19,226				(6,802	)		$	(8,332	)		$	50,232,715			$	(3,709,177	)		$	(223,608,998	)		$	(177,074,566	)
Conversion of preferred stock			19,167,799				19,169												71,527,831												71,547,000
Purchase of treasury stock											(61,287	)			(40,310	)															(40,310	)
Amortization and reclass of OCI																							3,709,177								3,709,177
Restricted stock issued			1,431,480				1,430												(1,430	)											—
Restricted stock cancelled			(23,299	)			(23	)											23												—
Stock-based compensation																			4,145,712												4,145,712
Preferred stock dividends																			(26,330,015	)											(26,330,015	)
Accretion of discount on preferred stock																			(1,974,115	)											(1,974,115	)
Net loss																											(59,131,441	)			(59,131,441	)
Balance at December 31, 2009			39,801,796				39,802				(68,089	)			(48,642	)			97,600,721				—				(282,740,439	)			(185,148,558	)
Conversion of preferred stock			1,341,316				1,341												8,014,659												8,016,000
Purchase of treasury stock											(60,299	)			(14,278	)															(14,278	)
Restricted stock issued			943,345				943												(943	)											—
Restricted stock cancelled			(173,734	)			(174	)											174												—
Stock-based compensation																			1,766,880												1,766,880
Preferred stock dividends																			(24,099,000	)											(24,099,000	)
Accretion of discount on preferred stock																			(2,241,800	)											(2,241,800	)
Net loss																											(75,530,201	)			(75,530,201	)
Balance at December 31, 2010			41,912,723			$	41,912				(128,388	)		$	(62,920	)		$	81,040,691			$	—			$	(358,270,640	)		$	(277,250,957	)

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

 

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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.

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.

Reclassifications and Adjustments

Certain prior year amounts in the consolidated financials statements have been reclassified to conform to the fiscal 2010 presentation. All historical share and per share data in the consolidated financial statements and notes thereto have been restated to give retroactive recognition of the 1-for-5 reverse stock split. In the consolidated statements of stockholders’ equity, for all periods presented, the par value of the reduced shares was reclassified to additional paid-in-capital from common stock. See Note 4 for additional information regarding the reverse stock split.

Oil and gas properties

Dune follows the successful efforts method of accounting for its investment in 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 developed 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 $26,369,002, and $29,173,192 for the years ended December 31, 2010 and 2009, 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 and costs, considering all available evidence at the date of review. The impairment evaluation triggers include a significant long-term decrease in current and projected prices or reserve volumes, an accumulation of project costs

 

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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 years ended December 31, 2010 and 2009, the Company impaired its oil and gas properties by $34,562,104 and $2,874,000, respectively, which are reflected in the accompanying consolidated statements of operations. The 2009 impairment was primarily isolated to one non-core Wyoming field which did not perform as anticipated when the well was completed. The 2010 impairment consists primarily of expired drilling and leasehold costs on two fields and poor performance on four other fields.

Properties not subject to amortization consist of exploration and development costs which are evaluated on a property-by-property basis. There were no material costs not subject to amortization as of December 31, 2010 and 2009.

Asset Retirement Obligation

The Company follows FASB ASC 410 – Asset Retirement and Environmental 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. This standard requires the Company to record a liability for the fair value of the dismantlement and plugging and abandonment costs excluding salvage values. 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.

Concentrations of credit risk and allowance

Substantially all of the Company’s receivables are due from oil and natural gas purchasers. The Company sold 82% of its oil and natural gas production to two customers in 2010 and 79% of its oil and natural gas production to two customers in 2009. 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 American Natural Energy Corp. (“ANEC”) of $396,629 in 2007. This balance was included in a transaction with ANEC during 2009 and is no longer reserved. 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 $250,000 in 2010 and 2009. At December 31, 2010 and December 31, 2009, the Company had approximately $47,671,278 and $16,666,103, 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, 2010 or 2009.

 

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Cash and cash equivalents

Cash and cash equivalents include cash in banks and highly liquid investments which mature within three months of the date of purchase.

Restricted cash

Restricted cash balances include money held in escrow and originated on December 7, 2010 in association with the Wayzata Credit Agreement. It includes $8 million to cash collateralize P&A bonds through a bonding agent which is classified as other assets in the consolidated financial statements. There is also $15.75 million held in escrow to cover the June 2011 bond interest payment which is recorded as a current asset in the consolidated financial statements.

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 incurs fees recorded as deferred financing costs. These costs are 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.

During 2010, the Company incurred additional fees associated with the WF Agreement of $1.6 million. These fees along with unamortized deferred financing costs related to the WF Agreement were expensed as a result of the December 7, 2010 Amended and Restated Credit Agreement with Wayzata. Additionally, financing costs of $229,803 were incurred in conjunction with the new agreement and are being amortized over the life of the loan.

Amortization expense of deferred financing costs and debt discount for the year ended December 31, 2010 and 2009 amounted to $5,060,064 and $3,250,872, 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

 

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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.

Derivatives

The Company follows the provisions of FASB ASC 815—Derivatives and Hedging. The statement requires the accounting recognition of all derivative instruments as either assets or liabilities at fair value. Under the provisions of the statement, the Company may or may not elect to designate a derivative instrument as a hedge against changes in the fair value of an asset or a liability (“a fair value hedge”) or against exposure to variability in expected future cash flows (a “cash flow hedge”).

Effective January 1, 2008, the Company discontinued, prospectively, the designation of its derivatives as cash flow hedges. The net derivative loss related to discontinued cash flow hedges, as of December 31, 2007, continued to be reported in accumulated other comprehensive loss through December 31, 2009 and were charged to loss as the volumes underlying the cash flow hedges were realized. Associated with the Wayzata Credit Agreement dated December 7, 2010, the Company was no longer required to hedge and all hedge balances were settled.

Stock-based compensation

The Company follows the provisions of FASB ASC 718 – Stock Compensation. The statement 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 on the date of grant.

Income taxes

Dune accounts for income taxes pursuant to FASB ASC 740 – 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 the financial statements or tax returns. The Company provides 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.

FASB ASC-740 establishes a more-likely-than-not threshold for recognizing the benefits of tax return positions in the financial statements. Also, the statement 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 Company files tax returns in the US and states in which it has operations and is subject to taxation. Tax years subsequent to 2006 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 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.

 

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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 approximates fair value due to the relationship between the interest rate on long-term debt and the Company’s incremental risk adjusted borrowing rate.

Impact of recently issued accounting standards

In January 2010, the FASB issued FASB Accounting Standards Update (ASU) No. 2010-03 Oil and Gas Estimations and Disclosures (ASU 2010-03). This update aligns the current oil and natural gas reserve estimation and disclosure requirements of the Extractive Industries Oil and Gas topic of the FASB Accounting Standards Codification (ASC Topic 932) with the changes required by the SEC final rule ASC 2010-03, as discussed above. ASU 2010-03 expands the disclosures required for equity method investments, revises the definition of oil and natural gas-producing activities to include nontraditional resources in reserves unless not intended to be upgraded into synthetic oil or natural gas, amends the definition of proved oil and natural gas reserves to require 12-month average pricing in estimating reserves, amends and adds definitions in the Master Glossary that is used in estimating proved oil and natural gas quantities and provides guidance on geographic area with respect to disclosure of information about significant reserves. ASU 2010-03 must be applied prospectively as a change in accounting principle that is inseparable from a change in accounting estimate and is effective for entities with annual reporting periods ending on or after a change in accounting estimate and is effective for entities with annual reporting periods ending on or after December 31, 2009. The impact on the Company’s operating results, financial position and cash flows has been recorded in the financial statements.

NOTE 2—DEBT FINANCING

Wells Fargo Foothill Credit Agreement

On May 15, 2007, Dune entered into a credit agreement among it, each of Dune’s subsidiaries named therein as borrowers, each of Dune’s subsidiaries named therein as guarantors, certain lenders and Wells Fargo Capital Finance, Inc. formerly Wells Fargo Foothill (“Wells Fargo”), as arranger and administrative agent (the “WF Agreement”). On December 7, 2010, Wells Fargo assigned to Wayzata Opportunities Fund II, L.P. (“Wayzata”) its rights, obligations and commitment under this Credit Agreement with Dune. In connection with this assignment, the Company as a borrower entered into the Amended and Restated Credit Agreement (the “Credit Agreement”) with Wayzata as the sole lender and Wells Fargo as the administrative agent. The Credit Agreement is a $40 million term loan facility which will mature on March 15, 2012. Pursuant to the Credit Agreement, (i) interest is 15% per annum which is due and payable, in arrears, on the first day of each month at any time that obligations are outstanding and (ii) if any or all of the $40 million term loan is prepaid (whether mandatory or voluntary prepayment) on or prior to November 15, 2011, the Company shall owe a prepayment premium equal to 10% of the principal amount prepaid.

As security for its obligations under the Credit Agreement, Dune and certain of its operating subsidiaries continue to grant Agent a security interest in and a first priority lien on all of its oil and gas properties and certain deposit accounts. In addition, its subsidiary, Dune Operating Company has guaranteed the obligations.

The Credit Agreement also continues to contain various covenants that limit the Company’s ability to: incur indebtedness; dispose of assets; grant certain liens; enter into certain swaps; make certain investments; prepay any subordinated debt; merge, consolidate, recapitalize, consolidate or allow any material change in the character of our business; enter into farm-out agreements; enter into forward sales; enter into agreements which (i) warrant production of hydrocarbons (other than permitted hedges) and (ii) shall not allow gas imbalances, take-or-pay or other prepayment with respect to its oil and gas properties; and enter into certain marketing activities.

The Credit Agreement modifies the definition of Change in Control to mean (i) that any “person” or “group”, other than Permitted Holders or Wayzata and its Affiliates, becomes the beneficial owner, directly or

 

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indirectly, of 35%, or more, of the stock of the Company having the right to vote for the election of members of the Board of Directors, (ii) that a majority of the members of the Board of Directors do not constitute continuing Directors, (iii) that the Company ceases to own and control, directly or indirectly, 100% of the outstanding Stock of each other Loan Party, (iv) either James Watt or Frank Smith shall cease to be involved in the day to day operations and management of the business of the Company, and a successor reasonably acceptable to Agent and Lenders is not appointed on terms reasonably acceptable to Agent and Lenders within 60 days of such cessation of involvement, or (v) any “Change of Control” or similar term, as defined in the Second Secured Debt Documents.

The Credit Agreement no longer contains covenants relating to minimum EBITDA and net hydrocarbon production, as well as no requirement to hedge. Instead, the Credit Agreement has a new financial covenant that requires Dune to maintain the following ratio: the total present value of future net revenues discounted at 10% of the proved developed reserves must be greater than two (2) times the value of the face amount of the term loan.

If an event of default exists under the Credit Agreement, the Lenders will be able to accelerate the maturity of the Credit Agreement and exercise other rights and remedies. Each of the following would continue to be an event of default: failure to pay any principal when due or any reimbursement amount, interest, fees or other amount within certain grace periods; a representation or warranty is proven to be incorrect when made; failure to perform or otherwise comply with the covenants, including, but not limited to maintenance of (i) required cash management activities and (ii) the Interest reserve account, or conditions contained in the Credit Agreement or other loan documents, subject, in certain instances, to certain grace periods; default by the Company on the payment of any other indebtedness or results in the third party’s right to accelerate the maturity of such indebtedness; bankruptcy or insolvency events involving the Company or any of its subsidiaries; the loan documents cease to be in full force and effect; our failing to create a valid lien, except in limited circumstances; the occurrence of a Change in Control; the entry of, and failure to pay or have stayed pending appeal, one or more adverse judgments in excess of an aggregate amount of $5.0 million or more.

Prior to the December 7, 2010 assignment, the Company’s activities under the Credit Agreement included an outstanding balance under the Revolver Commitment of $24 million at December 31, 2009. These borrowings were repaid in the second quarter of 2010. Additional borrowings of $8 million were incurred and repaid in the fourth quarter of 2010. Interest rates on these borrowings ranged from 2% to 8.25%.

Additionally, prior to the December 7, 2010 assignment, standby letters of credit for P&A bonds were issued amounting to $8.5 million at December 31, 2009. Fees associated with these letters of credit ranged from 1.75% to 3.5%. As a result of the December 7, 2010 assignment, these standby letters of credit were taken down as the Company cash collateralized these obligations through a bonding agent and reduced the obligation to $8 million at December 31, 2010.

On March 1, 2011, the Amended and Restated Credit Agreement dated December 7, 2010 was amended, effective as of December 7, 2010, to permit “the repurchase or other acquisition by Parent of shares of common Stock of Parent from employees, former employees, directors or former directors of Parent or its Subsidiaries or permitted transferees of such employees, former employees, directors or former directors), in each case pursuant to the terms of the agreements (including employment agreements) or plans (or amendments thereto) or other arrangements approved by the Board of Directors of the Parent under which such shares were granted, issued or sold; provided, that (A) no Default or Event of Default has occurred and is continuing or would exist after giving effect to such repurchase or other acquisition, and (B) the aggregate amount of all such repurchases and other acquisitions following the Restatement Date shall not exceed $500,000.” This amendment also waived any misrepresentation that may have inadvertently arisen as a result of such repurchases prior to the date of the amendment.

Senior Secured Notes

On May 15, 2007, Dune sold to Jefferies & Company, Inc. $300 million aggregate principal amount of 10 ¹/2% Senior Secured Notes due 2012 (“Senior Secured Notes”) at a purchase price of $285 million. The Senior Secured Notes, bearing interest at the rate of 10 ¹/2 % per annum, were issued under that certain indenture, dated

 

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May 15, 2007, among Dune, the guarantors named therein, and The Bank of New York Trust Company NA, as trustee (the “Indenture”). The Indenture contains customary representations and warranties by the Company as well as typical restrictive covenants whereby Dune has agreed, among other things, to limitations to 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) 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 (ii) 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 the Company 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 Dune’s operating subsidiaries. The Senior Secured Notes are unconditionally guaranteed on a senior secured basis by each of Dune’s existing and future domestic subsidiaries. The collateral securing the Senior Secured Notes is subject to, and made subordinate to, the lien granted to Wayzata under the Credit Agreement.

The debt discount is being amortized over the life of the notes using the effective interest method. Amortization expense associated with the debt discount amounted to $2,956,243 and $2,655,660 and is included in interest expense in the consolidated statements of operations for the years ended December 31, 2010 and 2009, respectively.

NOTE 3—REDEEMABLE CONVERTIBLE PREFERRED STOCK

During the quarter ended June 30, 2007, Dune sold to Jefferies and Company, Inc. pursuant to the Purchase Agreement dated May 1, 2007, 216,000 shares of its Senior Redeemable Convertible Preferred Stock (“Preferred Stock”) for gross proceeds of $216 million less a discount of $12.3 million yielding net proceeds of $203.7 million. As provided in the Certificate of Designations, the Preferred Stock has a liquidation preference of $1,000 per share and a dividend at a rate of 12% per annum, payable quarterly, at the option of Dune, in additional shares of Preferred Stock, shares of common stock (subject to the satisfaction of certain conditions) or cash.

The conversion price of the Preferred Stock is subject to adjustment and may be adjusted upon the occurrence of a fundamental change as defined in the Certificate of Designations. In the event a holder of Dune’s Preferred Stock elected to convert such shares prior to June 1, 2010, then such holder was 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 (as defined in the Certificate of Designations). Dune could elect to pay this amount in cash or shares of its common stock. Should the Company elect to make such payment in shares of its common stock, then such share will be valued at a 10% discount to the volume weighted average price of the Company’s common stock for the 10 trading days preceding any such conversion. The equity ownership of holders of Dune’s common stock could be significantly diluted. The Preferred Stock is redeemable at the option of the holder on December 1, 2012 and subject to the terms of any of the Company’s indebtedness or upon a change of control. In the event Dune fails 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. The Company analyzed the adjustment of the conversion right and the make whole premium for derivative accounting under FASB ASC 815—Derivatives and Hedges and determined that it was not applicable to either provision.

The Preferred Stock discount is deemed a Preferred Stock dividend and is being amortized over five years using the effective interest method and is charged to additional paid-in capital as the Company has a deficit balance in retained earnings. Charges to additional paid-in capital for the years ended December 31, 2010 and 2009 amounted to $2,241,798 and $1,974,115, respectively.

 

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During the years ended December 31, 2010 and 2009, holders of 8,016 and 71,547 shares of the Preferred Stock converted their shares into 1,341,316 and 19,167,921 shares of common stock, respectively. This amount includes 425,206 and 10,990,849 shares, respectively that the Company elected to issue to pay make whole premiums. Shares issued to satisfy the make whole premiums were deemed a Preferred Stock dividend for accounting purposes and increased the Preferred Stock dividend by $77,739 and $8,422,953, respectively.

During the years ended December 31, 2010 and 2009, Dune paid dividends on the Preferred Stock in the amount of $23,878,000 and $26,792,000, respectively. In lieu of cash, the Company elected to issue 23,878 and 26,792 additional shares of Preferred Stock, respectively.

NOTE 4 —REVERSE STOCK SPLIT

On November 30, 2009, the Company’s stockholders approved a 1-for-5 reverse stock split. The reverse stock split was effective at the opening of trading on December 2, 2009. As a result of the reverse stock split, every five shares of the Company that a stockholder owned were converted into one share of the Company, thus reducing the number of outstanding shares of common stock from approximately 185.5 million shares to 37.1 million shares as of the close of business on December 1, 2009. Following the reverse stock split, the Company continues to have 300 million authorized shares of common stock. Notwithstanding the reverse stock split, each shareholder continued to hold the same percentage of the Company’s outstanding common shares immediately following the reverse stock split as was held immediately prior to the split, except for fractional shares. Fractional shares created as a result of the reverse stock split were rounded up to the nearest whole share.

All share and per share amounts were restated to reflect the 1-for-5 reverse stock split. This reverse stock split resulted in the reduction of 148.4 million issued and outstanding shares of common stock. It was accounted for by the transfer of $148,400 from common stock to additional paid-in capital, which is the amount equal to the par value of the reduced shares affected by the reverse stock split.

NOTE 5—HEDGING ACTIVITIES

In accordance with a requirement of the WF Agreement, Dune and its operating subsidiaries entered into a Swap Agreement with Wells Fargo. The WF Agreement provided that Dune 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 Dune and its subsidiaries with respect to each of crude oil and natural gas.

Effective January 1, 2008, the Company discontinued, prospectively, the designation of its derivatives as cash flow hedges. The net derivative loss related to discontinued cash flow hedges, as of December 31, 2007, continued to be reported in accumulated other comprehensive loss through December 31, 2009 and were charged to loss as the volumes underlying the cash flow hedges were realized.

Associated with the Credit Agreement dated December 7, 2010, the Company is no longer required to hedge and all hedge balances were settled. Prior to this event, Dune accounted for its production hedge derivative instruments as defined in FASB ASC 815-Derivatives and Hedging. Accordingly, the Company designated derivative instruments as fair value hedges and recognized gain or losses in current earnings.

For the year ended December 31, 2010, Dune recorded a gain on the derivatives of $1,382,938, composed of an unrealized gain on changes in mark-to-market valuations of $1,596,544 and a realized loss on cash settlements of ($213,606). For the year ended December 31, 2009, Dune recorded a loss on derivatives of ($2,780,933), composed of an unrealized loss on changes in mark-to-market of ($9,506,580) and a realized gain on cash settlements of $6,725,647.

NOTE 6—COMMITMENTS AND CONTINGENCIES

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.

 

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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. Dune maintains insurance coverage, which it believes is customary in the industry, although Dune is not fully insured against all environmental risks.

In connection with the acquisition of Goldking Energy Holdings L.P., the Company inherited an environmental contingency which after conducting its due diligence and subsequent testing believes is the responsibility of third parties. However, federal and state regulators have determined Dune is the responsible party for clean up of this area. Dune has maintained a passive maintenance of this site since it was first discovered after Hurricane Katrina. Costs to date of approximately $1,100,000 have been covered by the Company’s insurance minus the standard deductibles. The Company still feels other parties have the primary responsibility for this occurrence but is committed to working with various state and federal authorities on resolution of this issue. At this time no estimate of the final cost of remediation of this site can be determined or if the Company’s insurance will continue to cover clean up costs or if the Company can be successful in proving the other parties should be primarily responsible for the cost of remediation.

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 build out allowance that is being amortized to expense over the term of the lease. In October 2007, the Company amended its lease agreement to expand the leased office space. The lease term for the additional space also expires on September 30, 2011. Rent expense for the years ended December 31, 2010 and 2009 was $0.8 million and $0.8 million, respectively.

Minimum rentals for each of the five years subsequent to December 31, 2010 are as follows (in thousands):

 

		Amount
2011		$	609
2012			—
2013			—
2014			—
2015			—
		$	609

NOTE 7—RESTRICTED STOCK, 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 $1,766,880 and $4,145,712 for the years ended December 31, 2010 and 2009, respectively.

The 2007 Stock Incentive Plan, which was approved by Dune’s shareholders, authorizes the issuance of up to 3,200,000 shares of common stock for issuance to employees, officers and non-employee directors. The Plan is administered by Dune’s Compensation Committee. The following is a description of restricted stock awards under the plan at December 31, 2010:

 

•

248,591 shares awarded on December 17, 2007 to employees and non-employee directors, which shares are fully vested.

 

•

105,412 shares awarded on March 13, 2008 to certain officers having elected to receive shares in lieu of cash for a portion of their respective bonuses, which shares are fully vested.

 

•

622,700 shares awarded on August 1, 2008 to employees and non-employee directors, which shares vest over the three years from grant date.

 

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•

450,000 shares awarded on October 1, 2009 to certain executive officers of which 301,500 shares vest of three years from grant date and 148,500 shares vest in accordance with certain performance-based criteria.

 

•

573,780 shares awarded on December 31, 2009 to employees, officers and non-employee directors, which shares vest over the three years from grant date.

 

•

938,900 shares awarded on November 18, 2010 to employees, officers and non-employee directors, which shares vest over the three years from grant date.

 

•

4,445 shares awarded on December 30, 2010 to certain employees having elected to receive shares in lieu of cash for a portion of their respective bonuses, which vested on the grant date.

The following table reflects the vesting activity associated with the restricted stock awards as of December 31, 2010:

 

Grant Date		Shares Awarded				Shares Cancelled				Shares Vested				Shares Unvested
December 17, 2007			248,591				(71,471	)			(177,120	)			—
March 13, 2008			105,412				—				(105,412	)			—
August 1, 2008			622,700				(106,829	)			(374,006	)			141,865
October 1, 2009			450,000				—				(100,499	)			349,501
December 31, 2009			573,780				(109,600	)			(163,921	)			300,259
November 18, 2010			938,900				—				—				938,900
December 30, 2010			4,445				—				(4,445	)			—
			2,943,828				(287,900	)			(925,403	)			1,730,525

Common shares available to be awarded at December 31, 2010 are as follows:

 

Total shares authorized			3,200,000
Total shares issued			(2,943,828	)
Total shares cancelled			287,900
Total shares available			544,072

A summary of stock option transactions follows:

 

		Options				Weighted Average Price
Outstanding as of December 31, 2008			556,000				10.50
Granted			—				—
Cancelled			(5,000	)			(4.25	)
Exercised			—				—
Outstanding as of December 31, 2009			551,000				10.56
Granted			—				—
Cancelled			(341,000	)			(11.26	)
Exercised			—				—
Outstanding as of December 31, 2010			210,000			$	9.43

 

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Options outstanding and exercisable at December 31, 2010 are as follows:

 

Exercise Price		Number of Shares				Remaining Life				Intrinsic Value (In-the-money) Options
7.50			10,000				.7 years				—
9.35			100,000				1.3 years				—
9.70			100,000				1.1 years				—
			210,000							$	—

A summary of stock warrant transactions follows:

 

		Warrants				Weighted Average Price
Outstanding as of December 31, 2008			356,500				11.20
Granted			—				—
Cancelled			—				—
Exercised			—				—
Outstanding as of December 31, 2009			356,500				11.20
Granted			—				—
Cancelled			(64,865	)			(9.25	)
Exercised			—				—
Outstanding as of December 31, 2010			291,635			$	10.76

Warrants outstanding and their relative exercise price at December 31, 2010 are as follows:

 

Exercise Price		Number of Shares				Remaining Life				Intrinsic Value (In-the-money) Warrants
6.75			111,635				4.8 years			$	—
13.25			180,000				.1 years				—
			291,635							$	—

NOTE 8—INCOME TAXES

Dune operates through its various subsidiaries in the United States (“U.S.”); accordingly, federal and state income taxes have been provided based upon the tax laws and rates of the U.S. as they apply to Dune’s current ownership structure.

Dune accounts for income taxes pursuant to Accounting Standards Codification No. 740, 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 Dune’s financial statements or tax returns. Dune provides 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.

Dune adopted FASB ASC 740-10, effective January 1, 2007. Dune recognizes interest and penalties related to unrecognized tax benefits within the provision for income taxes on continuing tax benefits. There are no unrecognized tax benefits that if recognized would affect the tax rate. There was no interest or penalties

 

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recognized as of the date of adoption or for the twelve months ended December 31, 2010. The Company files tax returns in the U.S. and states in which it has operations and is subject to taxation. Tax years subsequent to 2006 remain open to examination by taxing authorities.

Dune’s effective tax rate for continuing operations for the twelve months ended December 31, 2010 and 2009 was approximately 0% and 0%, respectively. The decrease in the tax rate is due primarily to the impairment of assets and the establishment of a valuation allowance, as further described below.

Prior to 2007, the Company’s taxes were subject to a full valuation allowance. During 2007 the Company acquired the stock of Goldking and was required to step-up the book basis of its oil and gas properties while using carryover cost basis for tax purposes. As a result, the Company has significant deferred tax liabilities in excess of its deferred tax assets. At that time, management determined that a valuation allowance was not necessary as the realization of its acquired deferred tax assets was more likely than not.

During the twelve months ended December 31, 2010 and 2009, the Company incurred a significant impairment loss of its oil and gas properties. As a result, the Company is in a position of cumulative reporting losses for the current and preceding reporting periods. The volatility of energy prices and uncertainty of when energy prices may rebound is uncertain and not readily determinable by our management. At this date, this general fact pattern does not allow us to project sufficient sources of future taxable income to offset our tax loss carry forwards and net deferred tax assets in the U.S. for both federal and state taxes. Under the current circumstances, it is management’s opinion that the realization of these tax attributes does not reach the “more likely than not criteria” under ASC 740. Accordingly, the Company has established a valuation allowance of $67,222,621 and $46,965,106 at December 31, 2010 and 2009, respectfully against its U.S. net deferred tax assets relating to continuing operations.

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, 2010 and 2009 due to the following:

 

		Year ended December 31,
		2010				2009
		(in thousands)
Computed “expected” tax expense (benefit)		$	(26,436	)		$	(20,696	)
Non-deductible expenses			5				3
State taxes, net of benefit			—				—
Return to accrual adjustment			(6,173	)			(182	)
Other			—				1,299
Valuation allowance			32,604				19,576
Income tax expense (benefit)		$	—			$	—

Deferred tax assets at December 31, 2010 and 2009 are comprised primarily of net operating loss carry forwards 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.

 

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Following is a summary of deferred tax assets and liabilities:

 

		Year ended December 31,
		2010				2009
		(in thousands)
Current deferred tax assets:
State taxes		$	—			$	—
Unrealized gains/losses			—				—
Accrued Compensation			—				—
Loss on sale of Discontinued Operations			—				—
Derivative instruments			—				—
Total current deferred tax assets			—				—
Noncurrent deferred tax assets:
Oil and gas property and equipment (Book DD&A)			62,000				52,501
Asset retirement obligation			1,019				1,585
Book impairment of assets			73,236				61,136
Share based compensation			6,574				5,956
Loss carry forwards			114,892				113,105
Other oil and gas property related			2,517				2,532
Deferred state tax benefit			—				28
Unrealized gain/losses			51				50
Other			—				32
Total noncurrent deferred tax assets			260,289				236,925
Total deferred tax assets			260,289				236,925
Current deferred tax liability			—				—
Noncurrent deferred tax liabilities:
Property and equipment (Tax DD&A)			50,421				45,620
Deferred tax on acquisition			72,239				72,309
Deferred state tax obligation			—				—
Unrealized Gains/Losses			—				—
Oil and gas exploration and development operations			68,374				70,070
Loss on Discontinued Operations			—				—
Asset retirement obligation			2,032				2,032
Other			—				—
Total noncurrent deferred tax liabilities			193,066				190,031
Total deferred tax liabilities			193,066				190,031
Net deferred tax assets (liabilities)			67,223				46,894
Valuation allowance			(67,223	)			(46,894	)
Net deferred income tax asset (liability)		$	—			$	—

At December 31, 2010 the Company has U.S. tax loss carry forwards of approximately $328.3 which will expire in various amounts beginning in 2020 through 2030.

 

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The Company has determined that as a result of the acquisition of all the outstanding stock of Goldking, a change of control pursuant to Section 382 of the Internal Revenue Code of 1986 occurred at the Goldking level. As a result, the Company 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 the Company during the tax year ended December 31, 2010, and expects similar dollar limits in future years until the acquired U.S. NOL’s are either completely exhausted or expire unutilized.

NOTE 9—ASSET RETIREMENT OBLIGATION

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

 

		Year Ended December 31,
		2010				2009
Asset retirement obligations, beginning of period		$	17,552,762			$	15,239,967
Liabilities related to property sales			(200,113	)			—
Revisions in estimated liabilities			(5,010,246	)			1,307,716
Abandonment costs			(1,617,300	)			(594,476	)
Accretion expense			1,822,959				1,599,555
Asset retirement obligations, end of period		$	12,548,062			$	17,552,762

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, Ltd. At December 31, 2010 and 2009, the amount of the escrow account totaled $2,252,352 and $2,252,352, respectively and included with other assets.

NOTE 10—DISCONTINUED OPERATIONS

On June 30, 2010, Dune consummated the sale of the South Florence field located in Vermilion Parish, Louisiana. The disposition of the South Florence Properties allowed the Company to repay all outstanding borrowings under the WF Agreement and to invest in new assets or fund maintenance, repair or improvement of existing properties and assets. The effective date of the sale was May 1, 2010.

Consideration received by the Company for the South Florence Properties aggregated $29,189,243, consisting of the purchase price of $30 million, as adjusted to account for the sale of hydrocarbons and various related costs, expenses and charges incurred between the execution and the Purchase and Sale Agreement and completion of the sale.

In conjunction with the sale of these assets, the Company recognized a loss of $5,014,397 to write down the related carrying amounts to their fair value plus the cost to sell. The assets of the discontinued operations, consisting of net oil and gas properties, are presented separately under the caption “Assets held for sale” in the accompanying consolidated financial statements at December 31, 2009.

 

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Pursuant to accounting rules for discontinuing operations, Dune has classified 2010 and prior reporting periods to present the activity related to the South Florence Properties as a discontinued operation. Discontinued operations for the years ended December 31, 2010 and 2009 are summarized as follows:

 

		Year ended December 31,
		2010				2009
Revenues		$	4,372,648			$	12,628,742
Costs and expenses:
Lease operating expense			1,329,475				3,456,036
Depletion, depreciation and amortization			1,502,433				5,358,903
Impairment on asset			5,014,397				—
Total operating expense			7,846,305				8,814,939
Income (loss) from discontinued operations		$	(3,473,657	)		$	3,813,803
Production:
Oil (bbl)			38,474				151,642
Gas (mcf)			254,537				826,057
Total (mcfe)			485,381				1,735,909

NOTE 11—FAIR VALUE MEASUREMENTS

Dune follows FASB ASC 820-10-05—Fair Value Measurements and Disclosures for financial assets and liabilities measured on a recurring basis. The statement applies to all financial assets and financial liabilities that are being measured and reported on a fair value basis. As defined in the statement, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The statement requires disclosure that establishes a framework for measuring fair value and expands disclosure about fair value measurements. It requires fair value measurements be classified and disclosed in one of the following categories:

 

Level 1

Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. We consider active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

 

Level 2

Quoted prices in markets that are not active or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that we value using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange traded derivatives such as over-the-counter commodity price swaps, investments and interest rate swaps.

 

Level 3

Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e. supported by little or no market activity). Our valuation models are primarily industry-standard models that consider various inputs including: (a) quoted forward prices for commodities, (b) time value, (c) volatility factors and (d) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Level 3 instruments primarily include derivative instruments, such as basic swaps, commodity price collars and floors, as well as investments. Although we utilize third party broker quotes to assess the reasonableness of our prices and valuation techniques, we do not have sufficient corroborating market evidence to support classifying these assets and liabilities as Level 2.

 

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As required by FASB ASC 820-10-05, financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

As a result of the Company liquidating its hedge positions on December 7, 2010, there are no significant financial assets or liabilities that require fair value measurement disclosure at December 31, 2010.

The following table summarizes the valuation of our investments and financial instruments by FASB ASC 820-10-05 pricing levels as of December 31, 2009:

 

		Fair Value Measurements at December 31, 2009 Using
		Level 1				Level 2				Level 3				Total
Oil and gas derivative assets		$	—			$	—			$	—			$	—
Oil and gas derivative liabilities			—				(1,596,545	)			—				(1,596,545	)
Total		$	—			$	(1,596,545	)		$	—			$	(1,596,545	)

NOTE 12—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, possible and probable reserves as of December 31, 2010. 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.

Reserves

Total reserves are classified by degree of proof as proved, probable, or possible. These classifications are in accordance with the reserves definitions of Rules 4-10(a) (1)-(32) of Regulation S-X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. A description of reserve classifications are as follows:

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

Probable reserves—Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

 

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Possible reserves—Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

The following reserve schedule was developed by the Company’s reserve engineers and sets forth the changes in estimated quantities for total reserves of the Company during the year ended December 31, 2010 and 2009:

 

		Year Ended December 31,
		2010												2009
TOTAL RESERVES AS OF:		Oil (Mbbls)				Gas (Mmcf)				Total Mmcfe				Oil (Mbbls)				Gas (Mmcf)				Total Mmcfe
Beginning of the period			7,187				62,355				105,475				8,199				83,807				132,998
Revisions of previous estimates			433				(4,761	)			(2,162	)			(394	)			(18,941	)			(21,304	)
Extensions and discoveries			—				—				—				455				2,779				5,508
Production			(623	)			(4,048	)			(7,788	)			(724	)			(5,177	)			(9,522	)
Sale of minerals in place			(1,305	)			(4,992	)			(12,822	)			(349	)			(113	)			(2,205	)
Total proved reserves			5,692				48,554				82,703				7,187				62,355				105,475
Total probable reserves			465				2,723				5,512				425				4,041				6,591
Total possible reserves			1				3,257				3,263				44				6,779				7,043
Total reserves			6,158				54,534				91,478				7,656				73,175				119,109
Total proved developed reserves			3,715				32,134				54,424				4,940				42,504				72,144

Revisions of previous estimates consist of:

 

		2010												2009
		Oil (Mbbls)				Gas (Mmcf)				Total (Mmcfe)				Oil (Mbbls)				Gas (Mmcf)				Total (Mmcfe)
Price changes			630				7,132				10,912				(30	)			(297	)			(477	)
Performance changes			(197	)			(11,893	)			(13,074	)			(364	)			(18,644	)			(20,827	)
			433				(4,761	)			(2,162	)			(394	)			(18,941	)			(21,304	)

Significant reserve changes were noted in certain categories and are explained below:

 

•

Revisions of previous estimates:

2010—The major component of the downward revision of 2.2 Bcfe in reserves pertains to the Bayou Couba field. In 2010, the Company decided not to sidetrack the Exxon Fee #5 and 4.6 Bcfe in reserves were written off. The remaining 2.4 Bcfe of upward revisions occurred across several fields consisting of positive and negative revisions on individual wells.

2009—There were two major components of the downward revisions of 21.3 Bcfe in reserves. First, the Chocolate Bayou field experienced an 8.3 Bcfe negative revision due to unexpected water breakthrough on the Wieting #30. Second, the North Broussard field declined 10.6 Bcfe due to revisions in PUD’s from 3D seismic interpretation. The remaining 2.4 Bcfe of negative revisions occurred across several fields consisting of positive and negative revisions on individual wells.

Proved Undeveloped Reserves

The Company’s proved undeveloped reserves decreased from 2009 to 2010 by 306 Mbbls of oil and 3,451 Mmcf of gas primarily associated with the decision not to sidetrack the Exxon Fee #5 well. As a result of this decision the acreage associated with the well expired and the PUD reserves and value were eliminated. The

 

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percentage of proved undeveloped reserves increased to 34% in 2010 from 32% in 2009. During 2010 the Company invested in PUD conversions in the Chocolate Bayou field and the Live Oak field with an investment of $1.8 million and $1.4 million, respectively.

The Company intends to continue investing in converting its inventory of PUD locations to proved developed locations.

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,
		2010				2009
		(in thousands)
Unproved property costs		$	—			$	477
Development costs			8,755				13,543
ARO Costs			1,617				594
Total consolidated operations		$	10,372			$	14,614
Asset retirement obligation (non-cash)		$	(5,010	)		$	1,256

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,
		2010				2009
		(in thousands)
Proved oil and gas properties		$	526,761			$	541,706
Accumulated DD&A			(294,567	)			(245,531	)
Net capitalized costs		$	232,194			$	296,175

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, 2010 and 2009 in accordance with FASB ASC 932—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,
		2010				2009
		(in thousands)
Future cash inflows		$	674,756			$	675,053
Future production costs (1)			(244,185	)			(238,961	)
Future development costs			(87,102	)			(100,112	)
Future income tax expense			—				—
Future net cash flows			343,469				335,980
10% annual discount for estimated timing of cash flows			(128,939	)			(123,679	)
Standardized measure of discounted future net cash flows at the end of the year		$	214,530			$	212,301

 

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

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,
		2010				2009
Average crude oil price (per Bbl)		$	76.05			$	58.05
Average natural gas price (per Mcf)		$	4.38			$	4.14

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 $22.9 million, $14.3 million and $7.7 million – that the Company expects to spend in 2011, 2012 and 2013, 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 FASB ASC 932-235, at year end are set forth in the table below:

 

		Year Ended December 31,
		2010				2009
Standardized measure of discounted future net cash flows at the beginning of the year		$	212,301			$	283,636
Extensions, discoveries and improved recovery			—				14,391
Revisions of previous quantity estimates			(33,726	)			(55,660	)
Changes in estimated future development costs			1,648				12,350
Sale of minerals in place			(24,581	)			(3,719	)
Net changes in prices and production costs			83,469				(38,807	)
Accretion of discount			10,559				13,902
Sales of oil and gas produced, net of production costs			(41,619	)			(32,991	)
Development costs incurred during the period			6,479				9,653
Net Change in income taxes			—				9,546
Standardized measure of discounted future net cash flows at the end of the year		$	214,530			$	212,301

 

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NOTE 13—SUBSEQUENT EVENT

Pursuant to FASB ASC 855, we have evaluated all events or transactions that occurred from January 1, 2011 through March 3, 2011, the date of issuance of the audited consolidated financial statements. During this period we did not have any material recognizable subsequent events, except as disclosed below:

Subsequent to December 31, 2010, holders of 44,239 shares of Preferred Stock converted their shares into approximately 5,055,898 shares of common stock.

 

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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 3, 2011				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 2, 2011.

 

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