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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, 2011

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: None

 

Securities registered pursuant to section 12(g) of the Act:

 

Title of each class
Common Stock, $0.001 par value

 

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  x    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K  ¨

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, 2011, 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 others holding more than 5% of the outstanding shares of the class) was $30,838,185 based upon a closing sales price of $63.00, as adjusted to account for the effect of the 1-for-100 reverse stock split effective as of December 22, 2011.

As of March 16, 2012, the registrant had outstanding 38,579,630 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
Glossary of Oil and Gas Terms			1
PART I			3
Item 1. and Item 2. Business and Properties			3
Item 1A. Risk Factors			16
Item 1B. Unresolved Staff Comments			25
Item 3. Legal Proceedings			25
Item 4. Mine Safety Disclosures			25
PART II			26
Item  5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			26
Item 6. Selected Financial Data			28
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 MaloneBailey, LLP, independent registered public accounting firm
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 with respect to terms such as “Dune”, “we,” “our,” “us” 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 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 a 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 report. Our actual results, performance or achievements could differ materially from historical results as well as those expressed in or 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 are made 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 that 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.

Glossary of Oil and Gas Terms

The following are abbreviations and definitions of certain terms commonly used in the oil and gas industry and this report:

Bbl.    One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.

Bcf.    One billion cubic feet of gas.

Bcfe.    One billion cubic feet of natural gas equivalent, using the ratio of one barrel of crude oil, condensate or natural gas liquids to 6 Mcf of natural gas.

Boe.    One barrel of oil equivalent, using the ratio of one barrel of crude oil, condensate or natural gas liquids to 6 Mcf of natural gas.

Btu.    British thermal unit. One British thermal unit is the amount of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

Developed oil and gas reserves.    Developed oil and gas reserves are reserves of any category that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

 

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Development well.    A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

Differential.    An adjustment to the price of oil or gas from an established spot market price to reflect differences in the quality or location of oil or gas.

Exploratory well.    A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well or a stratigraphic test well.

Extension well.    An extension well is a well drilled to extend the limits of a known reservoir.

Gas.    Natural gas.

MBbl.    One thousand barrels of crude oil or other liquid hydrocarbons.

Mcf.    One thousand cubic feet of gas.

Mcfe.    One thousand cubic feet of gas equivalent, using the ratio of one barrel of crude oil, condensate or natural gas liquids to 6 Mcf of natural gas.

Mmbbls.    One million barrels of crude oil or other liquid hydrocarbons.

Mmbtu.    One million Btus.

Mmcf.    One million cubic feet of gas.

MMcfe.    One million cubic feet of gas equivalent.

Oil.    Crude oil, condensate and natural gas liquids.

Operator.    The individual or company responsible for the exploration or production of an oil or gas well or lease.

 

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PART I

Items 1 and 2. Business and Properties.

Overview

Dune Energy, Inc., a Delaware corporation, 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 86,000 gross acres across 22 producing oil and natural gas fields.

Our total proved reserves as of December 31, 2011 were 79.4 Bcfe, consisting of 45.5 Bcf of natural gas and 5.7 Mmbbls of oil. The PV-10 of our proved reserves at year end was $249.9 million based on the average of the oil and natural gas sales prices on the first day of each of the twelve months during 2011, which was $92.81 per bbl of oil and $4.12 per mcf of natural gas. During 2011, we added 3.0 Bcfe through extensions and discoveries and produced 5.8 Bcfe. In addition, we experienced a net downward revision of 0.4 Bcfe.

Financial Restructuring

On December 22, 2011, Dune completed a financial restructuring, including the consummation of the exchange of $297,012,000 in aggregate principal amount of its 10.5% Senior Secured Notes due 2012 for:

 

•

shares of its newly issued common stock and shares of a new series of preferred stock that have been converted into common stock, which in the aggregate constitute approximately 97.2% of Dune’s common stock on a post-restructuring basis; and

 

•

approximately $49.5 million aggregate principal amount of newly issued Floating Rate Senior Secured Notes due 2016, or the New Notes.

The notes exchanged in the exchange offer constituted 99% of Dune’s senior notes outstanding prior to closing of the restructuring.

As a component of the restructuring, and with the requisite consent of such preferred stockholders, all of Dune’s 10% Senior Redeemable Convertible Preferred Stock was converted into $4 million in cash and shares of common stock constituting approximately 1.5% of Dune’s common stock on a post-restructuring basis.

Completion of the restructuring resulted in Dune’s pre-restructuring common stockholders holding approximately 1.3% of Dune’s common stock on a post-restructuring basis.

After the restructuring, percentage ownership of Dune’s common stock will continue to be subject to dilution through issuance of equity compensation pursuant to Dune’s equity compensation arrangements.

As part of its overall financial restructuring, Dune has also entered into a new $200.0 million senior secured revolving credit facility pursuant to a credit agreement, dated as of December 22, 2011, by and among Dune, Bank of Montreal, CIT Capital Securities LLC and the lenders party thereto, or the New Credit Agreement, with an initial borrowing base limit of up to $63.0 million. At December 31, 2011, $39 million was borrowed under this facility.

In addition, as part of its restructuring, Dune implemented a 1-for-100 reverse stock split, which was effective on December 22, 2011. After the restructuring and the reverse stock split, there were approximately 38.6 million shares of Dune’s common stock outstanding.

Employees

As of December 31, 2011, we had 34 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.

 

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Our Business Strategy

We intend to use our competitive strengths to increase reserves, production and cash flow in order to maximize value for our 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 Mcfe basis) competitive with our industry peers. We expect to 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, 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 stimulation technology in our wells to enhance recoverability and accelerate cash flows.

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 reserve base coupled with significant exploitation and exploration potential. We will evaluate acquisition opportunities that we believe will further enhance our operations and reserves in a cost-effective manner.

2012 Budget. For 2012, we have targeted an initial capital budget of approximately $38 million to $40 million (including dry-hole costs), primarily focused on our Garden Island Bay and Leeville field projects. The capital program will include several maintenance projects in addition to field exploitation within Garden Island Bay and Leeville.

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, 2011, 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, or PUD, locations throughout the fields. We expect the characteristics of these fields to allow us to record significant proved behind pipe and PUD reserves in the annual year-end reserve

 

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report. At year end 2011, our proved developed producing, or PDP, reserves of 29.9 Bcfe were 38% of our total oil and natural gas reserves, our proved developed non-producing, or PDNP, reserves of 21.7 Bcfe were 27% of our total oil and natural gas reserves and our PUD reserves of 27.9 Bcfe were 35% of our total oil and natural gas reserves.

Three of our fields, Garden Island Bay, Leeville and Bateman Lake, have large acreage positions surrounding piercement salt domes. Approximately 39% of our total proved oil and gas reserves are located in these fields. 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. We intend to complete 2 to 4 workovers in these fields in 2012 along with 3 to 5 new drilling opportunities. 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. Three dimensional, or 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 2012 and beyond.

At Garden Island Bay, in 2011 we participated in a partnership arrangement with two oil and gas companies to drill an exploratory test well below the salt layers in this high-reserve potential area. We held a 15% working interest in this well before payout and a 26% working interest after payout. Drilling ceased at the targeted depth and the well was temporarily abandoned with 9 ⁷/8 inch casing set at 17,500 feet. The well can be reentered for either a sidetrack or deepening operation. While commercially recoverable reserves were not found at this level, geologic indications suggest that there are other areas of high potential that can be reached from this depth. We will continue to evaluate this opportunity and the potential for further exploration of deep sub-salt targets within this field.

In addition, Dune began drilling the SL 214 #916 in late January 2011. 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 the salt layers. 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 maintains a 100% working interest in this prospect. We made the decision to temporarily halt drilling this well just short of the objective as a result of the Company’s limited financial resources during the year. During 2012, we intend to re-enter this well bore and continue drilling to the original target horizons. Success on these projects could lead to further exploratory or development drilling later in 2012 within this field.

At the Leeville field, we have formed a joint venture to drill new wells in which Dune can elect to participate, typically at a 40% working interest. The initial well drilled in the field under this joint venture was completed in November 2011 and is producing at approximately 4 Mmcf / day on a gross basis. We anticipate drilling 3 to 4 additional wells in this field in 2012. At our Bateman Lake field, we are evaluating the potential of establishing a joint venture program for additional drilling in the field.

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, 2011, 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

 

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value are based on various assumptions, including those prescribed by the U.S. Securities and Exchange Commission, or the SEC, and are inherently imprecise. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates. Also, the use of a 10% discount factor for reporting purposes may not necessarily represent the most appropriate discount factor, given actual interest rates and risks to which our business or the oil and natural gas industry in general are subject.

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 2011. 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, 2011 were $92.81 per barrel of oil and $4.12 per Mmbtu of natural gas.

The reserve data and the present value as of December 31, 2011 were prepared by Dune’s Senior Vice-President of Operations. He is the technical person primarily responsible for overseeing the preparation of reserve estimates. He attended Texas A&M University for his undergraduate studies in Petroleum Engineering and has over 30 years of industry experience with positions of increasing responsibility in engineering and reservoir evaluations.

In this regard, management has established, and is responsible for, internal controls designed to provide reasonable assurance that our reserve estimation is compared and reported in accordance with rules and regulations promulgated by the SEC as well as established industry practices used by independent engineering firms and our peers. These internal controls include, but are not limited to, (i) documented process workflow timeline, (ii) verification of economic data inputs to information supplied by our internal operations accounting, regional production and operations, land, and marketing groups, and (iii) senior management review of internal reserve estimations prior to publication.

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, 2011.

 

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Summary of Oil and Natural Gas Reserves as of Fiscal-Year End Based on Average Fiscal-Year Prices

 

		Oil				Natural Gas				Total				Undiscounted Future Net Revenue				Present Value of Reserves Discounted at 10% (1)
		Mbbl				Mmcf				Mmcfe				$ (thousands)				$ (thousands)
Proved:
Developed Producing			2,341				15,833				29,879				142,410				96,211
Developed Nonproducing			1,179				14,610				21,685				111,716				42,767
Undeveloped			2,134				15,079				27,884				169,235				110,947
Total Proved			5,654				45,522				79,448				423,361				249,925
Probable:
Developed Producing			165				1,704				2,694				22,518				18,846
Developed Nonproducing			66				1,430				1,826				7,766				4,010
Undeveloped			298				515				2,303				28,964				13,500
Total Probable			529				3,649				6,823				59,248				36,356
Possible:
Undeveloped			1				3,657				3,663				6,032				2,367
Total Possible			1				3,657				3,663				6,032				2,367

 

(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 accounting principles that are generally accepted in the United States, or GAAP, nor is it intended to represent the current market value of the estimated oil and natural gas reserves owned by us. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP.

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

 

		As of December 31, 2011
		$(thousands)
PV-10		$	249,925
Future income taxes, discounted at 10%			—
Standardized measure of discounted future net cash flows		$	249,925

 

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Oil and Natural Gas Volumes, Prices and Operating Expense

The following tables set forth certain information regarding the production volumes, revenue, average prices received and average production costs associated with our sale of oil and natural gas from continuing operations for the three years ended December 31, 2011, 2010 and 2009.

 

		Year Ended December 31,
		2011				2010				2009
Net Production:
Oil (Mbbl)			482				585				572
Natural gas (Mmcf)			2,928				3,793				4,351
Natural gas equivalent (Mmcfe)			5,820				7,303				7,783
Oil and Natural Gas Sales (dollars in thousands):
Oil		$	49,473			$	45,408			$	33,294
Natural gas			13,419				18,781				18,951
Total		$	62,892			$	64,189			$	52,245
Average Sales Price:
Oil ($ per Bbl)		$	102.72			$	77.62			$	58.21
Natural gas ($ per Mcf)			4.58				4.95				4.36
Natural gas equivalent ($ per Mcfe)		$	10.81			$	8.79			$	6.71
Oil and Natural Gas Costs (dollars in thousands):
Lease operating expenses		$	18,298			$	18,822			$	19,064
Production taxes			4,923				2,767				4,073
Other operating expenses			2,863				4,024				5,290
Total		$	26,084			$	25,613			$	28,427
Average production cost per Mcfe		$	4.48			$	3.51			$	3.65
Average production cost per Boe		$	26.88			$	21.06			$	21.20

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,
		2011				2010
		(in thousands)
Unproved prospects		$	—			$	—
Development costs			19,302				8,755
ARO costs			744				1,617
Total consolidated operations			20,046				10,372
Asset retirement obligations (non-cash)		$	—			$	(5,010	)

 

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Drilling Activity

The following table sets forth our drilling activity during the twelve-month periods ended December 31, 2011, 2010 and 2009 (excluding wells in progress at the end of such 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,
		2011								2010								2009
		Gross				Net				Gross				Net				Gross				Net
Development wells
Productive			1.0				0.4				1.0				0.2				1.0				0.5
Non-productive			—				—				1.0				1.0				—				—
Exploratory wells
Productive			1.0				0.5				1.0				0.5				1.0				0.8
Non-productive			1.0				0.2				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, 2011. 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			30				27				17				8				47				35
Natural gas			30				22				185				16				215				38
Total			60				49				202				24				262				73

Acreage Data

The following table summarizes our gross and net developed and undeveloped oil and natural gas acreage under lease as of December 31, 2011.

 

		Developed acres								Undeveloped acres
		Gross				Net				Gross				Net
Gulf Coast Properties (1)			84,925				57,569				1,484				404
Other (2)			—				—				7,224				2,926
Total			84,925				57,569				8,708				3,330

 

(1)	Undeveloped acreage includes rental tracts at Broussard South.

(2)	Other includes the Delaware Deep acreage in Sweetwater County, Wyoming, which was released in 2011.

As is customary in the oil and natural gas industry, we can generally retain our interest in undeveloped acreage by carrying out 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.

 

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Major Customers

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

 

2011:
Texon LP			49	%
Texon Crude Oil LLC			23	%
Upstream Energy Services LP			14	%
2010:
Texon LP			68	%
Upstream Energy Services			14	%
Crosstex Gulf Coast Marketing LTD			10	%

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

Competition

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

Marketing

Our production is marketed to third parties consistent with industry practices. Typically, oil is sold at the wellhead at field-posted prices plus an oil-quality differential 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. 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 the Oil and Natural Gas Industry

The oil and natural gas industry is subject to extensive regulation by federal, state and local authorities. Legislation affecting the oil and natural gas industry is frequently amended or reinterpreted, and may increase the regulatory burden on our industry and our company. In addition, numerous federal and state agencies are authorized by statute to issue rules, regulations and policies that are binding on the oil and natural gas industry and its individual participants. Some of these rules and regulations authorize the imposition of substantial penalties for failures to comply. The regulatory burden on the oil and natural gas industry increases the cost of doing business and, consequently, our profitability. However, this regulatory burden generally does not affect us any differently or to a greater or lesser extent than it affects other companies in the oil and natural gas industry with similar types, quantities and locations of oil and natural gas production.

 

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Regulation of Sales and Transportation of Oil

Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, the United States Congress, or 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 by common carrier pipelines is subject to rate regulation. The Federal Energy Regulatory Commission, or the FERC, regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. Interstate oil pipeline rates must be just and reasonable and may not be unduly discriminatory or confer undue preference upon any shipper. Rates generally are cost-based, although rates may be market-based or may be the result of settlement, if agreed to by all shippers. Some oil pipeline rates may be increased pursuant to an indexing methodology, whereby the pipeline may increase its rates up to a prescribed ceiling that changes annually based on the change from year to year in the Producer Price Index for Finished Goods. 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. Common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. 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 Sales, Transportation and Gathering of Natural Gas

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. Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938, or the NGA, the Natural Gas Policy Act of 1978 and regulations enacted under those statutes by the FERC. The 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. In general, the interstate pipelines’ traditional roles as wholesalers of natural gas have been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open-access basis to others who buy and sell natural gas. Although the FERC’s orders generally do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry. Failure to comply with the FERC’s regulations, policies and orders may result in substantial penalties. Under the Energy Policy Act of 2005, the FERC has civil authority under the NGA to impose penalties for violations of up to $1 million per day per violation.

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 pro-competitive regulatory approach 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.

Intrastate natural gas transportation is subject to regulation by state regulatory agencies. 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 intrastate natural gas transportation in the states in which

 

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we operate 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.

Gathering, which is distinct from transportation, is regulated by state regulatory authorities and is not subject to regulation by the FERC. Under certain circumstances, the FERC will reclassify jurisdictional transportation facilities as non-jurisdictional gathering facilities. This reclassification tends to increase our costs of getting natural gas to point-of-sale locations.

Regulation of Production

The production of oil and natural gas is subject to and affected by 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 of wells, drilling bonds and reports concerning operations. Each 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 the plugging and abandonment of wells. The effect of these regulations may be 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.

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;

 

•

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, the United States 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.

 

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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 the EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of crude oil or natural gas are currently exempted from regulation under RCRA or state hazardous waste provisions, though our operations may produce waste that does 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 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, the Company believes is the responsibility of a third party. However, federal and state regulators have determined Dune is the responsible party for cleanup of this area. Dune has maintained a passive maintenance of this site since it was first discovered after Hurricane Katrina. Cost to date of approximately $1,200,000 has been covered by the Company’s insurance minus the standard deductibles. The Company still believes another party has the primary responsibility for this occurrence but is committed to working with the various state and federal authorities on resolution of this issue. Plans for testing and analysis of various containment products and remediation procedures by third party consultants are being reviewed and will be presented to the federal and state authorities for consideration. The possible cost of an acceptable containment product, assuming potential remediation programs are viable and acceptable to all

 

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involved parties, may be as much as $2,500,000 to $3,000,000. At this time, it is not known if the Company’s insurance will continue to cover the cleanup costs or if the Company can be successful in proving another party 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 the 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 to OPA 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, the 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 greenhouse gases, or 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 Federal 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 final rule to address the permitting of GHG emissions from stationary sources under the prevention of significant deterioration, or 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 GHGs 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

 

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regional GHG cap and trade programs. The adoption and implementation of any legislation or regulations imposing reporting obligations with respect to, 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 the 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, or 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 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 has occurred, private parties or landowners may bring lawsuits against oil and gas companies under state law. The plaintiffs may seek property damages, personal injury damages, remediation costs or injunctions to require remediation or restoration of contaminated property, soil, groundwater or surface water. In some cases, oil and gas operations are located near populated areas and emissions or accidental releases could affect the surrounding properties and population.

 

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Item 1A.

Risk Factors.

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

We have had operating losses and limited revenues to date.

We have operated at a loss each year since inception. Net losses applicable to common stockholders for the fiscal years ended December 31, 2010 and 2011 were $101.9 million and $80.6 million, respectively. Our revenues for the fiscal years ended December 31, 2010 and 2011 were $64.2 million and $62.9 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 if or when we might become profitable.

Our New Credit Agreement imposes significant operating and financial restrictions on us that may prevent us from pursuing certain business opportunities and restrict our ability to operate our business.

Our New Credit Agreement contains covenants that restrict our ability and the ability of certain of our subsidiaries to take various actions, such as:

 

•

have a leverage ratio of greater than 4.0 to 1.0;

 

•

have a current ratio of less than 1.0 to 1.0;

 

•

incur additional debt;

 

•

make distributions or other restricted payments;

 

•

make investments;

 

•

change its business;

 

•

enter into leases;

 

•

use the proceeds of loans other than as permitted by the New Credit Agreement;

 

•

sell receivables;

 

•

merge or consolidate or sell, transfer, ease or otherwise dispose of its assets;

 

•

sell properties and terminate hedges in excess of 5% of the borrowing base then in effect;

 

•

enter into transactions with affiliates of the Company;

 

•

organize subsidiaries;

 

•

agree to limit its ability to grant liens or pay dividends;

 

•

incur gas imbalances or make prepayments;

 

•

enter into hedge agreements in excess of agreed limits;

 

•

modify its organizational documents; and

 

•

engage in certain types of hyrocarbon marketing activities.

The New Credit Agreement also contains other customary covenants that, subject to certain exceptions, include, among other things: maintenance of existence; maintenance of insurance; compliance with laws; delivery of certain information; maintenance of properties; keeping of books and records; preservation of organizational existence; and further assurances requirements.

 

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The restrictions contained in the New Credit Agreement 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.

We have substantial capital requirements that, if not met, may hinder our 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 our new credit facility pursuant to the New Credit Agreement 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, which will in turn negatively affect our business, financial condition and results of operations.

Recent economic conditions in the credit markets 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 volatile 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 the financial or 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 new 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;

 

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•

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.

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 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

 

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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 and to the extent that others in the industry do not have the financial resources or choose not to participate in our exploration activities, we will be adversely affected.

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 and financial condition.

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 unweighted 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 FASB 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 2011 fiscal year, approximately 35% 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;

 

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•

our ability to acquire additional 3-D seismic data;

 

•

our ability to identify and acquire new exploratory prospects;

 

•

our ability to develop existing prospects;

 

•

our ability to continue to retain and attract skilled personnel;

 

•

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

 

•

the results of our drilling program;

 

•

hydrocarbon prices; and

 

•

our access to capital.

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

Our business may suffer if we lose key personnel.

We depend to a large extent on the services of certain key management personnel, including James A. Watt, our President and Chief Executive Officer, Frank T. Smith, Jr., our Senior Vice President and Chief Financial Officer, and our other executive officers and key employees. The loss of Mr. Watt, Mr. Smith or other key management personnel could have a material adverse effect on our business, financial condition and results of operations. 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. We do not maintain key-man life insurance with respect to any of our employees. Our success will be dependent on our ability to continue to employ and retain skilled technical personnel.

We face strong competition from other natural gas and oil companies.

We encounter competition from other natural gas and oil companies in all areas of our operations, including the acquisition of exploratory prospects and 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.

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

 

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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 parties 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 Fiscal Year 2013 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) increasing 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 our tax liability and negatively impact our financial results.

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.

 

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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 the majority of the properties in which we have working interests. In the event that an operator of our remaining 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 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. In addition, our hedging arrangements may apply only to 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 adversely 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 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 that make us vulnerable to risks associated with operating in one major contiguous geographic area, including, but not limited to, 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

 

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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.

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.

 

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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 could be subject to large fluctuations in response to a variety of events or conditions, including, but not limited 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; and

 

•

changes in government regulations.

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 do so in the foreseeable future. We are currently restricted from paying dividends on our common stock by the indenture governing our New Notes and by our New Credit Agreement. 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, or the DGCL, contain provisions that may have the effect of delaying, deferring or preventing a change of control of the Company. These provisions, among other things, authorize the Company’s board of directors to set the terms of preferred 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 our board of directors.

Substantial sales of our common stock could adversely affect our stock price.

Sales of a substantial number of shares of our common stock, or the perception that such sales could occur, could adversely affect the market price of our common stock by introducing a large number of sellers to the market. Such sales could cause the market price of our common stock to decline. We cannot predict whether future sales of our common stock, or the availability of our common stock for sale, will adversely affect the market price for our common stock or our ability to raise capital by offering equity securities.

We may issue shares of preferred stock that could adversely affect holders of shares of our common stock.

Our board of directors is authorized to issue additional classes or series of shares of preferred stock without any action on the part of the holders of shares of our common stock, subject to the limitations of our certificate of incorporation and the DGCL. Our board of directors also has the power, without approval of the holders of shares

 

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of our common stock and subject to the terms of our certificate of incorporation and the DGCL, to set the terms of any such classes or series of shares of preferred stock that may be issued, including voting rights, dividend rights, conversion features, preferences over shares of our common stock with respect to dividends or if we liquidate, dissolution or winding-up of our business and other terms. If we issue shares of preferred stock in the future that have a preference over shares of our common stock with respect to the payment of dividends or upon our liquidation, dissolution or winding up, or if we issue shares of preferred stock with voting rights that dilute the voting power of shares of our common stock, the rights of holders of shares of our common stock or the trading price of shares of our common stock could be adversely affected.

 

Item 1B.

Unresolved Staff Comments.

Not applicable.

 

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, our management does not expect these matters to have a materially adverse effect on our financial position or results of operations.

 

Item 4.

Mine Safety Disclosures.

Not applicable.

 

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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, 2011 and the high and low sales prices of our common stock on the NYSE Amex from January 1, 2010 through July 15, 2010. Prices set forth below for periods prior to December 31, 2011 have been adjusted for the 1-for-100 reverse split that was effective on December 22, 2011.

 

2011:		High				Low
Quarter ended December 31, 2011		$	10.00			$	2.00
Quarter ended September 30, 2011		$	71.00			$	9.00
Quarter ended June 30, 2011		$	135.00			$	40.50
Quarter ended March 31, 2011		$	131.00			$	39.50
2010:		High				Low
Quarter ended December 31, 2010		$	45.00			$	10.00
Quarter ended September 30, 2010		$	18.00			$	8.00
Quarter ended June 30, 2010		$	40.00			$	9.00
Quarter ended March 31, 2010		$	34.00			$	16.00

The last sales price of our common stock on the OTC Bulletin Board on December 30, 2011 was $2.75 per share. As of March 16, 2012, the closing sales price of a share of our common stock was $3.60. As of March 16, 2012, there were approximately 325 stockholders 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 the DGCL and other restrictions under our existing or future debt instruments. 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 indenture governing our New Notes and our New Credit Agreement contain significant restrictions on our ability to pay dividends on our common stock.

There were 1,146 common shares repurchased in 2011, and 189 common shares repurchased in the fourth quarter of 2011. 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, as amended on December 1, 2009, or the 2007 Plan.

No shares of restricted stock were awarded to employees, officers or non-employee directors during fiscal year 2011.

 

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Securities Authorized for Issuance Under Equity Compensation Plans

The following table provides information as of December 31, 2011 about our equity compensation plans and arrangements.

Equity Compensation Plan Information—December 31, 2011(*)

 

Plan category		(a) Number of securities to be issued upon exercise of outstanding options, warrants and rights				(b) Weighted-average exercise price of outstanding options, warrants and rights				(c) Number of securities remaining available for future issuance  under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by security holders			600	(1)(2)		$	970.00				9,965	(3)
Equity compensation plans not approved by security holders			2,517	(4)(5)		$	825.18				—
Total			3,117			$	1,795.18				9,965

 

(*)	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, and the 1-for-100 reverse stock split effective December 22, 2011.

(1)

Consists of options issued to directors pursuant to our 2005 Non-Employee Director Incentive Plan, or the 2005 Plan, on January 24, 2007 to purchase up to 600 shares of our common stock at an exercise price of $970.00 per share, which expired on January 24, 2012. None of these options were exercised. The 2005 Plan, which authorized the issuance of up to 4,000 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 the 2007 Plan: (i) 6,227 shares of restricted stock awarded to employees during fiscal year 2008, which shares vest equally over the three years from grant date; (ii) 5,738 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) 4,500 shares of restricted stock awarded to certain executive officers during fiscal year 2009, of which 3,015 shares vest equally over the three years from grant date and 1,485 shares vest in accordance with certain performance-based criteria; (iv) 9,389 shares of restricted stock awarded to employees, officers and non-employee directors during fiscal year 2010, which shares vest equally over three years from grant date; and (v) 45 shares issued on December 30, 2010 in lieu of cash for a portion of two employees’ respective bonuses. The amendment to the 2007 Plan was approved by stockholders on November 30, 2009 and authorizes the issuance of up to 32,000 shares in stock awards and options. The initial 2007 Plan was approved by stockholders on May 30, 2006.

(3)

Includes 3,400 shares available under the 2005 Plan and 6,565 shares available under the 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 SEC under the Securities Exchange Act of 1934, as amended) as of December 31, 2011.

(5)	Excludes 4,078 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 2,517 shares of our common stock included in the chart above were issuable as of December 31, 2011:

 

•

Warrant issued September 26, 2006 to a consultant in consideration of services performed on our behalf, which warrant expires September 25, 2015 and is currently exercisable to purchase up to 1,000 shares of our common stock at an exercise price of $675.00 per share;

 

•

Option granted January 24, 2007 to a former officer in consideration of services performed on our behalf, which option expired January 23, 2012 and was exercisable to purchase up to 400 shares of our common stock at an exercise price of $970.00 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 an aggregate of 1,000 shares of our common stock at an exercise price of $935.00 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 on September 25, 2015 and exercisable to purchase up to 117 shares of our common stock at an exercise price of $675.00 per share.

 

Item 6.

Selected Financial Data.

The Company qualifies as a smaller reporting company and is not required to provide information pursuant to this item.

 

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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 the 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, or 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, probable and possible. Proved reserves are classified as either proved developed or proved undeveloped. Proved developed reserves are those reserves that 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.

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 U.S. Securities and Exchange Commission, or the SEC. The evaluation of our reserves by the 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 (i) already available geologic, reservoir or production data or (ii) 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 $92.81 per barrel and were held constant for the lives of the property. The weighted average price over the lives of the properties was $108.17 per barrel. Gas prices were calculated for each property using differentials to an average for the year of the first-of-the-month Henry Hub Louisiana Onshore price of $4.12 per Mmbtu and were held constant for the lives of the properties. The weighted average price over the lives of the properties was $4.45 per Mcf. The standardized measure is based on the average of the first-of-the-month pricing for 2011. 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, or 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. We employ the successful efforts method of accounting.

It is typical for companies that drill exploration wells to incur dry hole costs. Our primary activities have focused on mainly development wells and our exploratory drilling activities were limited. However, we anticipate we will selectively expand our exploration drilling in the future. It is impossible to accurately predict specific dry holes. Because we cannot 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 fields rather than one pool of costs. In addition, under the successful efforts method, we assess our fields 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

 

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or units produced and asset costs are known and while the proved reserves have a high probability of recoverability, they are based on estimates that are subject to some variability. The factors that 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

 

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statement of operations when the hedged item affects earnings. If the derivative is not designated as a hedge, changes in the fair value are recognized in other expense. Ineffective portions of changes in the fair value of cash flow hedges are also recognized in loss on derivative liabilities.

Beginning January 1, 2008, the gain or loss on derivatives was recognized currently in earnings and treated as fair value hedges. Associated with the Wayzata Credit Agreement dated December 7, 2010, the Company was no longer required to hedge and settled all hedged balances. However, in accordance with the requirements of the financial restructuring, the Company entered into hedge agreements in January 2012.

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.

Business Strategy

Dune is an independent energy company engaged in the exploration, development, acquisition and exploitation of natural gas and crude oil properties, with interests along the Louisiana/Texas 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., or Goldking. 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 86,000 gross acres across 22 producing 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.

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 Mcfe basis) competitive with our industry peers. We expect to 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 this report.

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, 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 stimulation technology in our wells to enhance recoverability and accelerate cash flows associated with these wells.

 

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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. We will evaluate acquisition opportunities that we believe will further enhance our operations and reserves in a cost effective manner.

In 2011 we invested $19.3 million in oil and gas properties (excluding dry-hole costs of $6.1 million). We produced 5.8 Bcfe during the year. Revisions of previous estimates were 0.4 Bcfe negative.

 

Capital costs (in thousands):		Year Ended 2011				Year Ended 2010
Acquisitions—unproved		$	—			$	—
Development			19,302				8,755
Total CAPEX before ARO			19,302				8,755
ARO costs			744				1,617
Total CAPEX including ARO		$	20,046			$	10,372
Asset retirement obligation (non-cash)		$	—			$	(5,010	)
Proved Reserves (Mmcfe):
Beginning			82,703				105,475
Production			(5,820	)			(7,788	)
Purchases			—				—
Sale of reserves			—				(12,822	)
Discoveries and extensions			3,019				—
Revisions			(454	)			(2,162	)
Ending reserves			79,448				82,703
Reserve additions before revisions (Mmcfe)			3,019				—
Reserve additions after revisions (Mmcfe)			2,565				(2,162	)

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 year 2011 compared to fiscal year 2010, net cash flow provided by (used in) operating activities improved by $10.7 million to $1.3 million. This improvement was primarily attributable to higher average oil prices for 2011 of $102.64/Bbl compared to $77.62/Bbl for 2010. The average price received for natural gas fell slightly year-over-year from $4.95/Mcf in 2010 to $4.58/Mcf for 2011.

Our current assets were $31.1 million on December 31, 2011. Cash on hand comprised approximately $20.4 million of this amount. This compared to cash of $39.4 million at December 31, 2010, which included $15.8 million escrowed in restricted cash accounts. Accounts payable have been reduced slightly from $7.0 million at December 31, 2010 to $6.8 million at December 31, 2011.

The consolidated financial statements reflect an exploration program in 2011 and a more active drilling program compared to the previous year, as well as ongoing drilling and facilities upgrade program. As mentioned previously, these investments were equal to $19.3 million (excluding dry-hole costs) in 2011 versus $8.8 million

 

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in 2010 (and no dry-hole costs). 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 involved industry partners in these efforts so as to reduce our upfront cash requirements and reduce risk dollars expended.

On December 22, 2011, Dune completed a financial restructuring, including the consummation of the exchange of $297,012,000 in aggregate principal amount of its 10.5% Senior Secured Notes due 2012 for:

 

•

shares of its newly issued common stock and shares of a new series of preferred stock that have been converted into common stock, which in the aggregate constitute approximately 97.2% of Dune’s common stock on a post-restructuring basis; and

 

•

approximately $49.5 million aggregate principal amount of newly issued Floating Rate Senior Secured Notes due 2016, or the New Notes.

The notes exchanged in the exchange offer constituted 99% of Dune’s senior notes outstanding prior to closing of the restructuring.

As a component of the restructuring, and with the requisite consent of such preferred stockholders, all of Dune’s 10% Senior Redeemable Convertible Preferred Stock was converted into $4 million in cash and shares of common stock constituting approximately 1.5% of Dune’s common stock on a post-restructuring basis.

Completion of the restructuring resulted in Dune’s pre-restructuring common stockholders holding approximately 1.3% of Dune’s common stock on a post-restructuring basis.

After the restructuring, percentage ownership of Dune’s common stock will continue to be subject to dilution through issuance of equity compensation pursuant to Dune’s equity compensation arrangements.

As part of its overall financial restructuring, Dune has entered into a new $200.0 million senior secured revolving credit facility pursuant to a credit agreement, dated as of December 22, 2011, by and among Dune, Bank of Montreal, CIT Capital Securities LLC and the lenders party thereto, or the New Credit Agreement, with an initial borrowing base limit of up to $63.0 million. At December 31, 2011, $39 million was borrowed under this facility.

In addition, as part of its restructuring, Dune implemented a 1-for-100 reverse stock split, which was effective on December 22, 2011. After the restructuring and the reverse stock split, there were approximately 38.6 million shares of Dune’s common stock outstanding.

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 and remaining availability under our borrowing arrangements put 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 2012 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. However, we have targeted an initial capital budget of approximately $38 million to $40 million (including dry-hole costs), primarily focused on our Garden Island Bay and Leeville field projects. The capital program will include several maintenance projects in addition to field exploitation within Garden Island Bay and Leeville.

 

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The following table summarizes our contractual obligations and commercial commitments as of December 31, 2011:

 

		Payments Due By Period
		Total				1 year				2 - 3 years				4 - 5 years				After 5 years
		(in thousands)
Contractual obligations:
Debt and interest		$	131,937			$	9,162			$	18,062			$	104,713			$	—
Office lease			2,860				495				990				1,051				324
Total		$	134,797			$	9,657			$	19,052			$	105,764			$	324

Results of Operations

Comparison of 2011 and 2010

Year-over-year production decreased from 7,303 Mmcfe in 2010 to 5,820 Mmcfe in 2011. 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 between fiscal years 2009, 2010 and 2011 due to changes in prices and production volumes:

 

		2011				% Increase (Decrease)				2010				% Increase (Decrease)				2009
Oil production volume (Mbbls)			482				-18	%			585				2	%			572
Oil sales revenue ($000)		$	49,472				9	%		$	45,408				36	%		$	33,294
Price per Bbl		$	102.64				32	%		$	77.62				33	%		$	58.21
Increase (decrease) in oil sales revenue due to:
Change in production volume		$	(7,995	)						$	757
Change in prices			12,059								11,357
Total increase (decrease) in oil sales revenue		$	4,064							$	12,114
Gas production volume (Mmcf)			2,928				-23	%			3,793				-13	%			4,351
Gas sales revenue ($000)		$	13,419				-29	%		$	18,781				-1	%		$	18,951
Price per Mcf		$	4.58				-7	%		$	4.95				14	%		$	4.36
Increase (decrease) in gas sales revenue due to:
Change in production volume		$	(4,282	)						$	(2,433	)
Change in prices			(1,080	)							2,263
Total increase (decrease) in gas sales revenue		$	(5,362	)						$	(170	)
Total production volume (Mmcfe)			5,820				-20	%			7,303				-6	%			7,783
Total revenue ($000)		$	62,891				-2	%		$	64,189				23	%		$	52,245
Price per Mcfe		$	10.81				23	%		$	8.79				31	%		$	6.71
Increase (decrease) in revenue due to:
Change in production volume		$	(13,036	)						$	(3,221	)
Change in prices			11,738								15,165
Total increase (decrease) in total revenue		$	(1,298	)						$	11,944

Revenues

Revenues from continuing operations for the year ended December 31, 2011 totaled $62.9 million as compared to $64.2 million for the year ended December 31, 2010, representing a $1.3 million decrease.

 

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Production volumes for 2011 were 482 Mbbls of oil and 2.9 Bcf of natural gas, or 5.8 Bcfe. This compares to 585 Mbbls of oil and 3.8 Bcf of natural gas, or 7.3 Bcfe, for 2010, representing a 20% reduction in production volumes. In 2011, the average sales price of oil was $102.64 per barrel and the average sales price of natural gas was $4.58 per Mcf as compared to $77.62 per barrel of oil and $4.95 per Mcf of natural gas in 2010. These results indicate that the modest decrease in revenue was attributable to the decrease in production volumes of 20%, which was not completely offset by the increase in commodity prices from $8.79 per Mcfe to $10.81 per Mcfe in 2011, representing a 23% increase.

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 in total (in thousands) and on a per Mcfe basis:

 

		Years Ending December 31,
		2011								2010
		Total				Per Mcfe				Total				Per Mcfe
Direct operating expense		$	18,298			$	3.14			$	18,822			$	2.58
Production taxes			4,924				0.85				2,767				0.38
Ad valorem taxes			656				0.11				1,143				0.16
Transportation			1,232				0.21				1,491				0.20
Workovers			974				0.17				1,390				0.19
		$	26,084			$	4.48			$	25,613			$	3.51

Lease operating expense and production taxes from continuing operations for the year ended December 31, 2011 totaled $26.1 million versus $25.6 million for the year ended December 31, 2010. This translated to an increase of $0.97/Mcfe on a volume basis. This increase reflects the impact of the significant recoupment of production taxes resulting from drilling incentives that occurred in 2010. Additionally, all other components of lease operating expense (i.e., direct operating expense, ad valorem taxes, transportation and workovers) experienced a reduction from 2010 to 2011.

Accretion of asset retirement obligation

Accretion expense for asset retirement obligations decreased by $0.5 million for 2011 compared to 2010. This decrease is the result of reevaluating abandonment cost at year end.

Depletion, depreciation and amortization (DD&A)

For the year ended December 31, 2011, the Company recorded DD&A expense of $22.1 million ($3.80/Mcfe) compared to $27.1 million ($3.70/Mcfe) for the year ended December 31, 2010, representing a decrease of $5.0 million ($0.10/Mcfe). This reduction reflects the impact of the 2011 impairment on the Company’s oil and gas properties of $18.1 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, 2011 decreased $1.6 million (14%) from the year ended December 31, 2010 to $9.6 million. Cash G&A expense for 2011 fell $0.3 million (3%) from 2010 to $9.1 million. These decreases resulted primarily from a $0.4 million (70%) reduction in professional fees that were capitalized in connection with the restructuring and a $1.2 million (71%) drop in share-based compensation.

 

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Impairment of oil and gas properties

Dune recorded an impairment of oil and gas properties of $18.1 million for the year ended December 31, 2011 compared to an impairment of $34.6 million for the year ended December 31, 2010. The 2011 impairment is attributable to the Company’s decision not to drill proved undeveloped wells in the Toro Grande field of $13.5 million and $4.6 million split among four fields that did not perform as anticipated in 2011. The 2010 impairment 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.

Exploration expense

In 2011, the Company, as a party to a joint venture, drilled an exploratory well. Although the Company will continue to evaluate future options associated with the well, it has determined that the costs incurred should be expensed. Consequently, $6.1 million was expensed during the year ended December 31, 2011.

Loss on settlement of asset retirement obligation liability

As a result of the Company’s plugging and abandonment commitment, Dune was required to plug and abandon 16 wells located in the Chocolate Bayou and Garden Island Bay fields. As these costs were scheduled to occur several years into the future, the Company recognized a loss of $0.5 million on the settlement of these plugging costs, representing the present value of these future costs.

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, 2011 was equal to $39.6 million compared to $37.4 million in 2010. This increase reflects additional interest expense attributable to increased borrowings under the Credit Agreement (as defined in Note 3). Additionally, it should be noted that $17.4 million of the interest expensed in 2011 was cancelled in connection with the restructuring in December 2011.

Gain 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. In connection with the Company’s entry into the Credit Agreement in December 2010, all hedging requirements were eliminated and all hedged balances settled. There was no hedge activity in 2011.

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, 2010, the Company generated income of $1.5 million in connection with these assets. 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. There were no discontinued operations activities in 2011.

 

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Net loss available to common stockholders

For the year ended December 31, 2011, net loss available to common stockholders decreased $21.4 million from the comparable period of 2010. This decrease reflects the impact of a $5.0 million reduction in DD&A, a $16.3 million reduction in impairment of oil and gas properties, a $3.5 million reduction in loss on discontinued operations and a $6.2 million reduction in preferred stock dividends. These reductions were offset by a ($6.1) million increase in exploration expense, a ($2.1) million increase in interest expense and a ($1.4) million reduction in gain on derivative liability.

 

Item 8.

Financial Statements and Supplementary Data.

The response to this item is included in Item 15—Financial Statements and is incorporated into this Item 8 by reference.

 

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, or the SEC, under the Securities Exchange Act of 1934, as amended, or 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, or CEO, and Chief Financial Officer, or 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, 2011. 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, 2011, 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 deterioration in the degree of compliance with the policies or procedures.

Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2011. 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, 2011.

This report does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting due to an exemption provided by the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, enacted into law in July 2010. The Dodd-Frank Act provides smaller public companies and debt-only issuers with a permanent exemption from the requirement to obtain an external audit on the effectiveness of internal financial reporting controls provided in Section 404(b) of the Sarbanes-Oxley Act. Dune is a smaller reporting company and is eligible for this exemption under the Dodd-Frank Act.

(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, 2011 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

 

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Item 9B.

Other Information.

None.

PART III

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

 

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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 No.		Description
3.1		Amended and Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Registrant’s Form 10-KSB (File No. 001-32497) for the year ended December 31, 2002).
3.1.1		Certificate of Amendment of Amended and Restated Certificate of Incorporation, dated May 7, 2003 (incorporated by reference to Exhibit 3.1.1 to the Registrant’s Form 10-K (File No. 001-32497) for the year ended December 31, 2010).
3.1.2		Certificate of Amendment of Certificate of Incorporation, dated May 5, 2004 (incorporated by reference to Exhibit 3.1 to the Registrant’s Form 10-Q (File No. 001-32497) for the period ended March 31, 2007).
3.1.3		Certificate of Amendment of Certificate of Incorporation, dated June 12, 2007 (incorporated by reference to Exhibit 3.1.3 to the Registrant’s Form 10-K (File No. 001-32497) for the year ended December 31, 2010).
3.1.4		Certificate of Amendment of Certificate of Incorporation, dated December 14, 2007 (incorporated by reference to Exhibit 3.1.4 to the Registrant’s Form 10-K (File No. 001-32497) for the year ended December 31, 2010).
3.1.5		Certificate of Amendment of Amended and Restated Certificate of Incorporation, dated December 1, 2009 (incorporated by reference to Exhibit 3.1.2 to the Registrant’s Current Report on Form 8-K (File No. 001-32497) filed on December 1, 2009).
3.1.6		Certificate of Amendment of Amended and Restated Certificate of Incorporation, dated December 22, 2011 (incorporated by reference to Exhibit 3.2 to the Registrant’s Form 8-K (File No. 001-32497) filed on December 27, 2011).
3.2		Amended and Restated By-Laws (incorporated by reference to Exhibit 3.1 to the Registrant’s Report on Form 8-K (File No. 001-32497) filed on July 12, 2010).
4.1		Registration Rights Agreement, dated January 10, 2012, between Dune Energy, Inc. and TPG Opportunity Fund I, L.P., TPG Opportunity Fund III, L.P., West Face Long Term Opportunities Global Master L.P., Strategic Value Master Fund, Ltd., Strategic Value Special Situations Master Fund, L.P., BlueMountain Credit Alternatives Master Fund, LP, BlueMountain Distressed Master Fund, LP, BlueMountain Long/Short Credit Master Fund, LP, BlueMountain Strategic Master Fund, LP and BlueMountain Timberline, Ltd., (incorporated by reference to Exhibit 4.1 to the Registrant’s Form 8-K (File No. 001-32497) filed on January 10, 2012).
4.2		Indenture, dated December 22, 2011, by and among Dune Energy, Inc., the guarantors named therein and U.S. Bank National Association (incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K (File No. 001-32497) filed on December 27, 2011).
4.3		Collateral Agreement, dated December 22, 2011, by and among Dune Energy, Inc., the grantors named therein and U.S. Bank National Association (incorporated by reference to Exhibit 4.3 to the Registrant’s Current Report on Form 8-K (File No. 001-32497) filed on December 27, 2011).
4.4		Second-Lien Mortgage, Deed of Trust, Assignment of as Extracted Collateral, Security Agreement, Fixture Filing and Financing Statement, dated as of December 22, 2011, from Dune Properties, Inc. to U.S. Bank National Association as trustee (incorporated by reference to Exhibit 4.4 to the Registrant’s Current Report on Form 8-K (File No. 001-32497) filed on December 27, 2011).

 

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Exhibit No.		Description
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 (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K (File No. 001-32497) filed on May 21, 2007).
4.6		First Supplemental Indenture, dated December 30, 2008, by and among Dune Energy, Inc, the guarantors signatory thereto and The Bank of New York Mellon (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K (File No. 001-32497) filed on December 30, 2008).
4.7		Second Supplemental Indenture, dated as of December 21, 2011, by and among Dune Energy, Inc., the guarantors signatory thereto and The Bank of New York Mellon (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K (File No. 001-32497) filed on December 27, 2011).
10.1		Employment Agreement, dated as of October 1, 2009, between Dune Energy, Inc. and James A. Watt (incorporated by reference to Exhibit 99.1 to the Registrant’s Form 8-K (File No. 001-32497) filed on October 5, 2009).
10.2		Employment Agreement, dated as of October 1, 2009, between Dune Energy, Inc. and Frank T. Smith, Jr. (incorporated by reference to Exhibit 99.2 to the Registrant’s Form 8-K (File No. 001-32497) filed on October 5, 2009).
10.3		Restricted Stock Agreement (Performance Based) dated as of October 1, 2009, between Dune Energy, Inc. and James A. Watt (incorporated by reference to Exhibit 99.3 to the Registrant’s Form 8-K (File No. 001-32497) filed on October 5, 2009).
10.4		Restricted Stock Agreement (Performance Based) dated as of October 1, 2009, between Dune Energy, Inc. and Frank T. Smith, Jr. (incorporated by reference to Exhibit 99.4 to the Registrant’s Form 8-K (File No. 001-32497) filed on October 5, 2009).
10.5		Restricted Stock Agreement (Time Vesting Based) dated as of October 1, 2009, between Dune Energy, Inc. and James A. Watt (incorporated by reference to Exhibit 99.5 to the Registrant’s Form 8-K (File No. 001-32497) filed on October 5, 2009).
10.6		Restricted Stock Agreement (Time Vesting Based) dated as of October 1, 2009, between Dune Energy, Inc. and Frank T. Smith, Jr. (incorporated by reference to Exhibit 99.6 to the Registrant’s Form 8-K (File No. 001-32497) filed on October 5, 2009).
10.7		2005 Non-Employee Director Incentive Plan (incorporated by reference to Exhibit A to the Registrant’s Definitive Proxy Statement on Schedule 14A (File No. 001-32497) filed on May 30, 2006).
10.8		Dune Energy, Inc. 2007 Stock Incentive Plan (incorporated by reference to Exhibit B to the Registrant’s Preliminary Information Statement on Schedule 14C (File No. 001-32497) filed on November 9, 2007).
10.9		Form of Grant Agreement under Dune Energy, Inc. 2007 Stock Incentive Plan (incorporated by reference to Exhibit 10.7 to the Registrant’s Form 10-K (File No. 001-32497) for the year ended December 31, 2010).
10.10		Amended and Restated Credit Agreement, dated as of December 22, 2011, among Dune Energy, Inc., Bank of Montreal, CIT Capital Securities LLC and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (File No. 001-32497) filed on December 27, 2011).
10.11		Amended and Restated Guarantee and Collateral Agreement, dated as of December 22, 2011, by and among Dune Energy, Inc., the grantors named therein and Bank of Montreal (incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K (File No. 001-32497) filed on December 27, 2011).

 

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Exhibit No.		Description
10.12		Amended and Restated Mortgage, Deed of Trust, Assignment of as Extracted Collateral, Security Agreement, Fixture Filing and Financing Statement, dated as of December 22, 2011, from Dune Properties, Inc. to Bank of Montreal as administrative agent. (incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K (File No. 001-32497) filed on December 27, 2011).
10.13		Master Assignment of Note and Liens, dated as of December 22, 2011, by and among Dune Energy, Inc., Dune Properties, Inc., Dune Operating Company, Wells Fargo Capital Finance, Inc., Wayzata Opportunities Fund II, L.P., Bank of Montreal and other lender parties thereto (incorporated by reference to Exhibit 10.4 to the Registrant’s Current Report on Form 8-K (File No. 001-32497) filed on December 27, 2011).
10.14		Intercreditor Agreement, dated as of December 22, 2011, by and among Dune Energy, Inc., its subsidiaries, Bank of Montreal and U.S. Bank National Association (incorporated by reference to Exhibit 10.5 to the Registrant’s Current Report on Form 8-K (File No. 001-32497) filed on December 27, 2011).
10.15		1992 ISDA Master Agreement, together with Schedule, dated May 15, 2007 among Wells Fargo Foothill, Inc., Dune Energy, Inc. and certain subsidiaries of Dune Energy, Inc. (incorporated by reference to Exhibit 10.6 to the Registrant’s Current Report on Form 8-K (File No. 001-32497) filed on May 21, 2007).
10.16		Purchase and Sale Agreement, dated as of May 28, 2010, between Dune Properties, Inc., as Seller, and Texas Petroleum Investment Company, as Buyer (incorporated by reference to Exhibit 99.1 to the Registrant’s Current Report on Form 8-K (File No. 001-32497) filed on June 30, 2010).
21.1*		List of subsidiaries.
23.1*		Consent of MaloneBailey, LLP.
23.2*		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.
101.INS		XBRL Instance Document.
101.SCH		XBRL Taxonomy Extension Schema Document.
101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF		XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB		XBRL Taxonomy Extension Label Linkbase Document.
101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document.

 

*	Indicates filed herewith

 

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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.

 

Date: March 23, 2012

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities and on the dates indicated.

 

Date		Signature and Title
March 23, 2012		/S/ JAMES A. WATT Name: James A. Watt Title: Chief Executive Officer and Director (principal executive officer)
March 23, 2012		/S/ FRANK T. SMITH, JR. Name: Frank T. Smith, Jr. Title: Chief Financial Officer (principal financial and accounting officer)
March 23, 2012		/S/ MICHAEL R. KEENER Name: Michael R. Keener Title: Director
March 23, 2012		/S/ STEPHEN P. KOVACS Name: Stephen P. Kovacs Title: Director
March 23, 2012		/S/ ALEXANDER A. KULPECZ, JR. Name: Alexander A. Kulpecz, Jr. Title: Director
March 23, 2012		/S/ EMANUEL R. PEARLMAN Name: Emanuel R. Pearlman Title: Director
March 23, 2012		/S/ ROBERT A. SCHMITZ Name: Robert A. Schmitz Title: Director
March 23, 2012		/S/ ERIC R. STEARNS Name: Eric R. Stearns Title: Director

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Index to Financial Statements

Index to Financial Statements

Dune Energy, Inc.

Report of Independent Registered Public Accounting Firm			F-2
Consolidated Balance Sheets			F-3
Consolidated Statements of Operations			F-4
Consolidated Statements of Cash Flows			F-5
Consolidated Statements of Changes in Stockholders’ Equity (Deficit)			F-6
Notes to Consolidated Financial Statements			F-7

 

F-1

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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, 2011 and 2010, 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 the 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, 2011 and 2010, 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 23, 2012

 

F-2

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Index to Financial Statements

Dune Energy, Inc.

Consolidated Balance Sheets

 

		Successor Company						Predecessor Company
		December 31,
		2011						2010
ASSETS
Current assets:
Cash		$	20,393,672					$	23,670,192
Restricted cash			17,184						15,753,441
Accounts receivable			8,107,009						9,862,849
Prepayments and other current assets			2,556,373						2,542,624
Total current assets			31,074,238						51,829,106
Oil and gas properties, using successful efforts accounting—proved			210,199,348						526,760,643
Less accumulated depreciation, depletion, amortization and impairment			—						(294,566,739	)
Net oil and gas properties			210,199,348						232,193,904
Property and equipment, net of accumulated depreciation of $- and $2,817,158			230,074						527,357
Deferred financing costs, net of accumulated amortization of $- and $1,456,592			2,915,229						786,087
Other assets			3,006,564						12,049,829
			6,151,867						13,363,273
TOTAL ASSETS		$	247,425,453					$	297,386,283
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
Current liabilities:
Accounts payable		$	6,759,073					$	6,953,863
Accrued liabilities			10,042,683						13,367,402
Current maturities of long-term debt (see note 3)			4,557,857						1,395,237
Preferred stock dividend payable			—						2,206,000
Total current liabilities			21,359,613						23,922,502
Long-term debt, net of discount of $- and $4,781,310 (see note 3)			88,503,991						335,218,690
Other long-term liabilities			12,630,676						12,548,062
Total liabilities			122,494,280						371,689,254
Commitments and contingencies			—						—
Redeemable convertible preferred stock, net of discount of $- and $4,964,014, liquidation preference of $1,000 per share, 750,000 shares designated, 0 and 207,912 shares issued and outstanding			—						202,947,986
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, 4,200,000,000 shares authorized, 38,579,630 and 419,127 shares issued			38,580						419
Treasury stock, at cost (235 and 1,284 shares)			(552	)					(62,920	)
Additional paid-in capital			124,893,145						81,082,184
Accumulated deficit			—						(358,270,640	)
Total stockholders’ equity (deficit)			124,931,173						(277,250,957	)
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)		$	247,425,453					$	297,386,283

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

 

F-3

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Index to Financial Statements

Dune Energy, Inc.

Consolidated Statements of Operations

 

		Predecessor Company
		For the Year Ended December 31,
		2011				2010
Revenues		$	62,891,627			$	64,188,647
Operating expenses:
Lease operating expense and production taxes			26,084,239				25,612,598
Accretion of asset retirement obligation			1,317,516				1,822,959
Depletion, depreciation and amortization			22,076,347				27,054,118
General and administrative expense			9,602,222				11,156,379
Impairment of oil and gas properties			18,087,128				34,562,104
Exploration expense			6,119,943				—
Loss on settlement of asset retirement obligation liability			497,647				—
Total operating expense			83,785,042				100,208,158
Operating loss			(20,893,415	)			(36,019,511	)
Other income (expense):
Interest income			45,156				4,067
Interest expense			(39,566,366	)			(37,424,038	)
Gain on derivative liabilities			—				1,382,938
Total other income (expense)			(39,521,210	)			(36,037,033	)
Loss on continuing operations			(60,414,625	)			(72,056,544	)
Loss on discontinued operations			—				(3,473,657	)
Net loss			(60,414,625	)			(75,530,201	)
Preferred stock dividend			(20,212,916	)			(26,418,537	)
Net loss available to common shareholders		$	(80,627,541	)		$	(101,948,738	)
Net loss per share:
Basic and diluted from continuing operations		$	(166.79	)		$	(243.40	)
Basic and diluted from discontinued operations			—				(8.59	)
Total basic and diluted		$	(166.79	)		$	(251.99	)
Weighted average shares outstanding:
Basic and diluted			483,413				404,573

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

 

F-4

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Index to Financial Statements

Dune Energy, Inc.

Consolidated Statements of Cash Flows

 

		Predecessor Company
		For the Year Ended December 31,
		2011				2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss		$	(60,414,625	)		$	(75,530,201	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Loss from discontinued operations			—				3,473,657
Depletion, depreciation and amortization			22,076,347				27,054,118
Amortization of deferred financing costs and debt discount			3,833,870				5,060,064
Stock-based compensation			506,210				1,766,880
Impairment of oil and gas properties			18,087,128				34,562,104
Accretion of asset retirement obligation			1,317,516				1,822,959
Loss on settlement of asset retirement obligation liability			497,647				—
Gain on derivative liabilities			—				(1,596,545	)
Changes in:
Accounts receivable			1,743,725				5,906,957
Prepayments and other assets			(13,425	)			182,042
Payments made to settle asset retirement obligations			(743,611	)			(1,617,300	)
Accounts payable and accrued liabilities			14,412,362				(13,302,050	)
NET CASH PROVIDED BY (USED IN) CONTINUING OPERATIONS			1,303,144				(12,217,315	)
NET CASH PROVIDED BY DISCONTINUED OPERATIONS			—				2,857,240
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES			1,303,144				(9,360,075	)
CASH FLOWS FROM INVESTING ACTIVITIES
Investment in proved and unproved properties			(18,302,410	)			(1,950,956	)
Decrease (increase) in restricted cash			15,736,258				(23,753,441	)
Purchase (disposal) of furniture and fixtures			(85,004	)			2,651
Decrease in other assets			705,682				377,997
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES—CONTINUING OPERATIONS			(1,945,474	)			(25,323,749	)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES—DISCONTINUED OPERATIONS			—				29,347,980
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES			(1,945,474	)			4,024,231
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt			—				40,000,000
Proceeds from short-term debt			2,018,387				15,594,556
Payments on long-term debt issuance costs			(3,098,232	)			(1,863,464	)
Payments on short-term debt			(1,869,448	)			(39,778,627	)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES			(2,949,293	)			13,952,465
NET CHANGE IN CASH BALANCE			(3,591,623	)			8,616,621
Cash balance at beginning of period			23,670,192				15,053,571
Cash balance at end of period		$	20,078,569			$	23,670,192
SUPPLEMENTAL DISCLOSURES
Interest paid		$	20,734,335			$	32,093,632
Income taxes paid			—				—
NON-CASH INVESTING AND FINANCIAL DISCLOSURES
Redeemable convertible preferred stock dividends		$	17,852,000			$	24,176,739
Asset retirement obligation revision			—				(5,010,246	)
Accretion of discount on preferred stock			2,360,916				2,241,800
Common stock issued for conversion of preferred stock			62,288,000				8,016,000

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

 

F-5

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Index to Financial Statements

Dune Energy, Inc.

Consolidated Statements of Changes in Stockholders’ Equity (Deficit)

Years ended December 31, 2011 and 2010

 

		Common Stock								Treasury Stock								Additional Paid-In Capital				Accumulated Deficit				Total Stockholders’ Equity (Deficit)
		Shares				Amount				Shares				Amount
Balance at December 31, 2009			398,018			$	398				(681	)		$	(48,642	)			97,640,125			$	(282,740,439	)		$	(185,148,558	)
Conversion of preferred stock			13,413				14												8,015,986								8,016,000
Purchase of treasury stock											(603	)			(14,278	)											(14,278	)
Restricted stock issued			9,433				9												(9	)							—
Restricted stock cancelled			(1,737	)			(2	)											2								—
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			419,127			$	419				(1,284	)		$	(62,920	)		$	81,082,184			$	(358,270,640	)		$	(277,250,957	)
Conversion of preferred stock			71,186				71												62,287,929								62,288,000
Purchase of treasury stock											(1,146	)			(12,115	)											(12,115	)
Restricted stock issued																											—
Restricted stock cancelled			(1,124	)			(1	)											1								—
Stock-based compensation																			506,210								506,210
Preferred stock dividends																			(17,852,000	)							(17,852,000	)
Accretion of discount on preferred stock																			(2,360,916	)							(2,360,916	)
Net loss																							(60,414,625	)			(60,414,625	)
Equity adjustment due to debt restructure			(489,189	)			(489	)			2,430				75,035				(123,663,408	)			418,685,265				295,096,403
Balance at December 31, 2011			—			$	—				—			$	—			$	—			$	—			$	—
Successor Company:
Purchase of treasury stock											(235	)			(552	)											(552	)
Equity adjustment due to debt restructure			38,579,630				38,580												124,893,145								124,931,725
			38,579,630			$	38,580				(235	)		$	(552	)		$	124,893,145			$	—			$	124,931,173

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

 

F-6

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DUNE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1—FINANCIAL RESTRUCTURING

On December 22, 2011, Dune Energy, Inc., a Delware corporation (“Dune” or the “Company”), completed its financial restructuring (the “Restructuring”), including the consummation of the exchange of $297,012,000 in aggregate principal amount of its 10.5% Senior Secured Notes due 2012 for:

 

•

an aggregate 2,485,516 shares of its newly issued common stock and 247,506 shares of a new series of preferred stock that have been converted into 35,021,098 shares of its newly issued common stock, which in the aggregate constitute approximately 97.2% of Dune’s common stock on a post-restructuring basis; and

 

•

approximately $49.5 million aggregate principal amount of newly issued Floating Rate Senior Secured Notes due 2016.

The notes exchanged in the exchange offer constituted 99% of Dune’s senior notes outstanding prior to closing of the Restructuring.

As a component of the Restructuring, and with the requisite consent of such preferred stockholders, all of Dune’s 10% Senior Redeemable Convertible Preferred Stock was converted into an aggregate of $4 million in cash and approximately 584,338 shares of common stock constituting approximately 1.5% of Dune’s common stock on a post-restructuring basis.

Completion of the Restructuring resulted in Dune’s pre-restructuring common stockholders holding approximately 487,678 shares, or approximately 1.3%, of Dune’s common stock on a post-restructuring basis.

After the Restructuring, percentage ownership of Dune’s common stock continues to be subject to dilution through issuance of equity compensation pursuant to Dune’s equity compensation plan.

As part of the Restructuring, Dune entered into a new $200.0 million senior secured revolving credit facility (the “New Credit Facility”) with an initial borrowing base limit of up to $63.0 million, with BMO Capital Markets Corp. as Sole Lead Arranger and Sole Bookrunner, Bank of Montreal as Administrative Agent and CIT Capital Securities LLC as Syndication Agent.

In addition, as part of its Restructuring, Dune implemented a 1-for-100 reverse stock split, which was effective on December 22, 2011. After the restructuring and the reverse stock split, there are approximately 38.6 million shares of Dune’s common stock outstanding.

The Restructuring was accounted for as a purchase and was effective December 22, 2011. However, due to the immateriality of the nine day activity period from December 23, 2011 through December 31, 2011, the Restructuring will be treated for accounting purposes as effective December 31, 2011. The Restructuring resulted in a new basis of accounting reflecting estimated fair values for assets and liabilities at December 22, 2011. Accordingly, the financial statements for the periods subsequent to December 31, 2011 are expected to be presented on the Company’s new basis of accounting, while the results of operations for prior periods reflect the historical results of the predecessor company. Vertical lines are presented to separate the financial statements of the predecessor company and the successor company. The “Successor Company” refers to the period from December 31, 2011 and forward. The “Predecessor Company” refers to the period prior to December 31, 2011.

The aggregate value of the total equity consideration for the Restructuring was approximately $127 million. The table below summarizes the allocation of the Restructuring’s purchase price based on the acquisition date fair values of the assets acquired and the liabilities assumed.

 

F-7

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Index to Financial Statements

		(In thousands)
Current assets, including cash of $20,394		$	31,074
Oil and gas properties			210,199
Other assets			6,152
Current liabilities			(21,359	)
Other long-term liabilities			(12,630	)
Long-term debt			(88,504	)
Equity restructuring costs			2,382
		$	127,314

Additionally, there were four transactions that occurred between December 22, 2011 and December 31, 2011 that had a material impact on the Successor Company’s financial statements. These transactions included the payment on long-term debt of $7,700,000, the receipt of escrowed balances of $8,000,000, the receipt of net cash proceeds from borrowings of $69,152 and the payment of interest on long-term debt of $54,049.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of operations and organization

The Company is an independent energy company that was formed in 1998. Since May 2004, Dune has been engaged in the exploration, development, acquisition and exploitation of crude oil and natural gas properties. 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 financial statements have been reclassified to conform to the fiscal 2011 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-100 reverse stock split. See Note 5 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 $21,694,060, and $26,369,002 for the years ended December 31, 2011 and 2010, 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

 

F-8

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Index to Financial Statements

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 significantly in excess of the amount originally expected and historical and current 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, 2011 and 2010, the Company impaired its oil and gas properties by $18,087,128 and $34,562,104, respectively, which are reflected in the accompanying consolidated statements of operations. The 2010 impairment consists primarily of expired drilling and leasehold costs on two fields and poor performance on four other fields. The 2011 impairment consists primarily of the Company’s decision not to pursue two proved undeveloped locations on the Toro Grande field.

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, 2011 and 2010.

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 86% of its oil and natural gas production to three customers in 2011 and 82% of its oil and natural gas production to two customers in 2010. 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. Management believes that there are no trade receivables that require an allowance for doubtful accounts.

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”) for up to $250,000 in 2011 and 2010. At December 31, 2011 and December 31, 2010, the Company had bank deposit accounts with approximately $21,694,737 and $47,671,278, respectively, in excess of FDIC insured limits. The Company has not experienced any losses in such accounts.

 

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Index to Financial Statements

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, 2011 or 2010.

Cash and cash equivalents

Cash and cash equivalents include cash in banks and highly liquid investments that 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 Credit Agreement (as defined in Note 3). It includes $8 million to cash collateralize P&A bonds through a bonding agent, which were classified as other assets in the consolidated financial statements at December 31, 2010. This amount was received in December 2011, leaving a balance of $17,184, classified as a current asset, which represents accrued interest received in January 2012. There was also $15.75 million held in escrow at December 31, 2010 to cover the June 2011 interest payment on the senior secured notes, which was recorded as a current asset in the consolidated financial statements at December 31, 2010. This amount was paid out and the account was closed in June 2011.

Use of estimates

The preparation of these financial statements in conformity with generally accepted accounting principles 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 Dune makes 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 Dune’s 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 fees associated with the WF Agreement (as defined in Note 3) 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 2010 in conjunction with the new agreement and were being amortized over the life of the loan.

 

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Index to Financial Statements

In 2011, associated with the Restructuring, the Company incurred debt issuance costs of $3,098,232. Of this amount, $717,178 was deferred and is being amortized over the life of the applicable debt. The remaining $2,381,054 was offset against additional paid-in capital in the Successor Company. Additional financing costs of $2,217,500 were incurred by the Successor Company and these amounts will be amortized over the life of the applicable debt. Finally, unamortized deferred loan costs of $215,447 attributable to the Credit Agreement and Senior Secured Notes were written-off as part of the Restructuring.

Amortization expense of deferred financing costs and debt discount for the year ended December 31, 2011 and 2010 amounted to $3,833,870 and $5,060,064, respectively.

Long-lived assets

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

Derivatives

The Company follows the provisions of FASB ASC 815—Derivatives and Hedging, which 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 elect to designate a derivative instrument as a hedge against changes in the fair value of an asset or a liability or against exposure to variability in expected future cash flows.

Associated with the Credit Agreement dated December 7, 2010, the Company was no longer required to hedge and all hedge balances were settled. However, in accordance with the requirements of the New Credit Agreement (as defined in Note 3) entered into in connection with the Restructuring, the Company entered into hedge agreements in January 2012.

Stock-based compensation

The Company follows the provisions of FASB ASC 718 – Stock Compensation, which 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

The Company 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 that 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 U.S. and states in which it has operations and is subject to taxation. Tax years subsequent to 2007 remain open to examination by U.S. federal and state tax jurisdictions.

 

F-11

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Index to Financial Statements

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.

NOTE 3—DEBT FINANCING

Long-term debt consists of:

 

		Successor Company						Predecessor Company
		December 31, 2011						December 31, 2010
Term loan		$	—					$	40,000,000
Revolving credit loan			39,000,000						—
Insurance Note Payable			1,569,857						1,395,237
Floating Rate Senior Secured Notes due 2016			49,503,991						—
Senior Secured Notes, net of discount of $- and $4,781,310			—						295,218,690
Senior Notes			2,988,000						—
Total long-term debt			93,061,848						336,613,927
Less: current maturities			(4,557,857	)					(1,395,237	)
Long-term debt, net of current maturities		$	88,503,991					$	335,218,690

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 the WF Agreement. In connection with this assignment, Dune, 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 was a $40 million term loan facility that would have matured on March 15, 2012. Pursuant to the Credit Agreement, (i) interest was 15% per annum, which was due and payable, in arrears, on the first day of each month at any time that obligations were outstanding and (ii) if any or all of the $40 million term loan was prepaid (whether mandatory or voluntary prepayment) on or prior to November 15, 2011, Dune would 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 continued to grant Wayzata a security interest in and a first priority lien on all of their oil and gas properties and deposit accounts. In addition, Dune’s subsidiary, Dune Operating Company, guaranteed the obligations under the Credit Agreement.

The Credit Agreement also contained various covenants that limit Dune’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 its 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) would not allow gas imbalances, take-or-pay or other prepayment with respect to its oil and gas properties; and enter into certain marketing activities. Additionally, the Credit Agreement modified the definition of “Change of Control”.

 

F-12

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Table of Contents

Index to Financial Statements

The amended Credit Agreement had a new financial covenant requiring that the total present value of future net revenues discounted at 10% of Dune’s proved developed reserves must be greater than two times the value of the face amount of the term loan.

If an event of default existed under the Credit Agreement, the lenders under the Credit Agreement were able to accelerate the maturity of the Credit Agreement and exercise other rights and remedies. Each of the following continued 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 contained in the Credit Agreement, 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 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; the Company’s 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.

In connection with entering into the Credit Agreement on December 7, 2010, standby letters of credit equal to $8.5 million were taken down as the Company cash collateralized these obligations through a bonding agent and reduced the obligation to $8 million in 2011. This obligation was $- at December 31, 2011.

On March 1, 2011, the Credit Agreement 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 any such repurchase prior to the date of the amendment. This amount was paid in full as a result of the Restructuring.

On June 1, 2011, in connection with the liquidation of the escrow balance of $15.7 million established for the June 2011 interest payment on the Senior Secured Notes (as defined below), the Company applied the remaining escrow balance of $25,680 to the term loan facility, reducing the balance to $39,974,320. Additionally, a 10% prepayment premium of $2,568 was made in accordance with the terms of the Credit Agreement, as amended. This amount was paid in full as a result of the Restructuring.

Amended and Restated Credit Agreement

On December 22, 2011, Wayzata assigned to Bank of Montreal its rights and obligations under the Credit Agreement pursuant to an agreement, by and among the Company and Dune Properties, Inc., as borrowers, Dune Operating Company, as guarantor, and Wells Fargo and Wayzata, as agents and lenders. In connection with such assignment, on December 22, 2011, the Company entered into the Amended and Restated Credit Agreement, dated as of December 22, 2011 (the “New Credit Agreement”), among the Company, as borrower, Bank of Montreal, as administrative agent, CIT Capital Securities LLC, as syndication agent, and the lenders party thereto (the “Lenders”).

The New Credit Agreement will mature on December 22, 2015. The Lenders have committed to provide up to $200 million of loans and up to $10 million of letters of credit, provided that the sum of the outstanding loans and the face amount of the outstanding letters of credit cannot exceed $200 million at any time and further provided that the availability of loans under the New Credit Agreement will be limited by a borrowing base

 

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Index to Financial Statements

(initially set at $63 million) as in effect from time to time, which is determined by the Lenders in their discretion based upon their evaluation of the Company’s oil and gas properties. The principal balance of the loans may be prepaid at any time, in whole or in part, without premium or penalty, except for losses incurred by the Lenders as a consequence of such prepayment. Amounts repaid under the New Credit Agreement may be reborrowed.

The Company must use the letters of credit and the proceeds of the loans only for funding the cash portion of the Restructuring, for the acquisition and development of oil and natural gas properties and for general corporate purposes. The Company’s obligations under the New Credit Agreement are guaranteed by its domestic subsidiaries.

As security for its obligations under the New Credit Agreement, the Company and its domestic subsidiaries have granted to the administrative agent (for the benefit of the Lenders) a first-priority lien on substantially all of their assets, including liens on not less than 85% of the total value of proved oil and gas reserves and not less than 90% of the total value of proved developed and producing reserves.

Generally, outstanding borrowings under the New Credit Agreement are priced at LIBOR plus a margin or, at the Company’s option, a domestic bank rate plus a margin. The LIBOR margin is 2.75 percent if usage is greater than 75 percent and steps down to 2.25 percent if usage is 50 percent or less and the domestic rate margin is 1.75 percent if usage is greater than 75 percent and steps down to 1.25 percent if usage is 50 percent or less. The Company is charged the above LIBOR margin plus an additional fronting fee of 0.25 percent on outstanding letters of credit, which are considered usage of the revolving credit facility, plus a nominal administrative fee. The Company is also required to pay a commitment fee equal to 0.50 percent of the average daily amount of unborrowed funds.

The New Credit Agreement contains various affirmative and negative covenants as well as other customary representations and warranties and events of default.

Borrowings under the New Credit Agreement equalled $46.7 million and $2 million of letters of credit as of December 22, 2011. Of this amount, $40.4 million was used to pay off the Credit Agreement principal and interest balance, $4 million was paid to cash settle the Senior Redeemable Convertible Preferred Stock and $2.3 million to pay loan fees. The Company repaid $7.7 million on December 30, 2011, yielding an outstanding balance of $39 million at December 31, 2011.

Senior Secured Notes

On May 15, 2007, Dune sold to Jefferies & Company, Inc. $300 million aggregate principal amount of 10¹/₂% 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 10¹/₂ % per annum, were issued under that certain indenture, dated May 15, 2007, among Dune, the guarantors named therein, and The Bank of New York Trust Company NA, as trustee (the “Indenture”). The Indenture contained typical restrictive covenants whereby Dune agreed, among other things, to limitations on restricted payments, limitations to incurrence of additional indebtedness, limitations on transactions with affiliates, issuance of capital stock of subsidiaries, limitations on sale of assets and limitations on mergers, consolidations and sales of substantially all assets.

The Senior Secured Notes are subject to redemption by Dune after June 1, 2011, at a repurchase price equal to 100% of the aggregate principal amount plus accrued and unpaid interest. Holders of the Senior Secured Notes could 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 domestic subsidiaries. The collateral securing the Senior Secured Notes is subject to, and made subordinate to, the lien granted to Wayzata and Bank of Montreal under the New Credit Agreement.

 

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Index to Financial Statements

The debt discount was being amortized over the life of the Senior Secured Notes using the effective interest method. Amortization expense associated with the debt discount amounted to $3,243,781 and $2,956,243 for the years ended December 31, 2011 and 2010, respectively, and is included in interest expense in the consolidated statements of operations.

On December 22, 2011, the Company completed its restructuring, which included the consummation of the exchange of $297,012,000 aggregate principal amount, or approximately 99%, of the Senior Secured Notes for 2,486,516 shares of the Company’s newly issued common stock, 247,506 shares of a new series of preferred stock that mandatorily converted into 35,021,098 shares of the Company’s newly issued common stock and approximately $49.5 million aggregate principal amount of newly issued Floating Rate Senior Secured Notes due 2016 (the “New Notes”). In addition to completing the exchange offer for the Senior Secured Notes, the Company completed a consent solicitation of the holders of the Senior Secured Notes, in which it procured the requisite consent of the holders of approximately 99% of the aggregate principal amount of the Senior Secured Notes to eliminate all the restrictive covenants and certain events of default in the Indenture.

The New Notes were issued pursuant to an indenture, dated December 22, 2011 (the “New Notes Indenture”), by and among the Company, the guarantors named therein and U.S. Bank National Association, as trustee and collateral agent. The New Notes will mature on December 15, 2016. The Company did not receive any proceeds from the issuance of the New Notes.

Interest on the New Notes is payable quarterly in arrears on March 15, June 15, September 15 and December 15 of each year, beginning on March 15, 2012. Subject to applicable law, interest accrues on the New Notes at a variable rate per annum equal to 13% plus the greater of 1.5% and Three-Month LIBOR, determined as of two London banking days prior to the original issue date and reset quarterly on each interest payment date. Such interest consists of (a) a mandatory cash interest component (that shall accrue at a fixed rate of 3% per annum and be payable solely in cash) and (b) a component that shall accrue at a variable rate and be payable in either cash or by accretion of principal.

The New Notes rank (i) equal in right of payment to indebtedness under the New Credit Facility, but effectively junior to such indebtedness to the extent of the value of the collateral securing such credit facility, (ii) equal in right of payment to all of the Company’s existing and future senior unsecured indebtedness but effectively senior to such indebtedness to the extent of the value of the collateral securing the New Notes, and (iii) senior in right of payment to all of the Company’s future subordinated indebtedness, if any.

The New Notes are jointly, severally, fully and unconditionally guaranteed by each of the Company’s domestic subsidiaries. Each of the guarantees of the New Notes is a general senior obligation of each guarantor and, with respect to each guarantor, ranks (i) equal in right of payment with any existing and future senior indebtedness of such guarantor, (ii) effectively junior to obligations of such guarantor under the New Credit Facility to the extent of the value of the assets of the guarantor constituting collateral securing such credit facility, (iii) effectively senior to any existing and future unsecured indebtedness of such guarantor to the extent of the value of the assets of the guarantor constituting collateral securing the New Notes, and (iv) senior in right of payment to any existing and future subordinated indebtedness of such guarantor.

Pursuant to a Collateral Agreement, dated as of December 22, 2011, by and among the Company, the grantors named in such agreement and U.S. Bank National Association, as collateral agent, and a Second-Lien Mortgage, Deed of Trust, Assignment of As-Extracted Collateral, Security Agreement, Fixture Filing and Financing Statement, dated as of December 22, 2011, from Dune Properties, Inc. to U.S. Bank National Association as trustee, the New Notes and the guarantees are secured by liens, subject to permitted liens, on substantially all of the Company’s assets and substantially all of the assets of the subsidiary guarantors that secure the Company’s New Credit Facility. Pursuant to an Intercreditor Agreement, dated as of December 22, 2011 (the “Intercreditor Agreement”), by and among the Company, its subsidiaries, Bank of Montreal and U.S. Bank National Association, such liens are contractually subordinated to liens securing indebtedness under the

 

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Index to Financial Statements

New Credit Facility. The Intercreditor Agreement governs the rights of the Company’s creditors under the New Credit Facility vis-à-vis the rights of holders of the New Notes and their collateral agent with respect to the collateral securing obligations under the New Credit Facility and the New Notes, and includes provisions relating to lien subordination, turnover obligations with respect to the proceeds of collateral, restrictions on exercise of remedies, releases of collateral, restrictions on amendments to junior lien documentation, bankruptcy-related provisions and other intercreditor matters.

The Company may redeem the New Notes, in whole or in part, at its option, upon not less than 30 nor more than 60 days’ notice at a redemption price equal to 100% of the principal amount of New Notes redeemed, plus accrued and unpaid interest, if any, to, but not including, the redemption date (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date that is on or prior to the redemption date).

If a change of control (as defined in the New Notes Indenture) occurs, each holder of New Notes may require the Company to repurchase all or a part of its New Notes for cash at a price equal to not less than 101% of the aggregate principal amount of such New Notes, plus any accrued and unpaid interest to the date of purchase (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date).

The New Notes Indenture contains a number of covenants that, among other things, restrict, subject to certain important exceptions, the Company’s and its restricted subsidiaries’ ability to:

 

•

pay dividends, redeem subordinated debt or make other restricted payments;

 

•

create liens;

 

•

transfer or sell assets; and

 

•

merge, consolidate or sell substantially all of the Company’s assets.

In addition, the New Notes Indenture imposes certain requirements as to future subsidiary guarantors. The New Notes Indenture also contains certain customary events of default.

In connection with the consent solicitation with respect to the Senior Secured Notes, on December 21, 2011, the Company entered into a second supplemental indenture (the “Second Supplemental Indenture”) among the Company, the guarantors named therein and The Bank of New York Mellon, as trustee and collateral agent (the “Senior Secured Notes Trustee”), amending the Indenture, as amended and supplemented by the first supplemental indenture, dated December 30, 2008, among the Company, the guarantors named therein and the Senior Secured Notes Trustee (the “First Supplemental Indenture” and together with the Indenture, the “Old Notes Indenture”). The Second Supplemental Indenture amended the Old Notes Indenture by, among other things, eliminating all of the restrictive covenants in the Old Notes Indenture (other than the covenant to pay interest and premium, if any, on, and principal of, the Senior Secured Notes when due), certain events of default with respect to the Old Notes and certain other provisions contained in the Old Notes Indenture and the Senior Secured Notes. The Second Supplemental Indenture also terminated the security documents that secure the obligations under the Senior Secured Notes and the related intercreditor agreement, thus turning the Senior Secured Notes into the Senior Notes.

The amendments to the Old Notes Indenture contained in the Second Supplemental Indenture were effective as of December 21, 2011. Such amendments became operative when the Company accepted for purchase validly tendered Senior Secured Notes representing at least 75% in aggregate principal amount of the Senior Secured Notes outstanding pursuant to the Company’s exchange offer for any and all Senior Secured Notes, which closed on December 22, 2011.

The remaining Senior Notes balance of $2,988,000 is due on June 1, 2012 and is classified as current maturities on long-term debt in the financial statements.

 

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NOTE 4—PREFERRED STOCK

Redeemable Convertible Preferred Stock

During the quarter ended June 30, 2007, Dune sold to Jefferies & Company, Inc., pursuant to the Purchase Agreement dated May 1, 2007, 216,000 shares of its Senior Redeemable Convertible Preferred Stock (the “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 for the Preferred Stock (the “Certificate of Designations”), the Preferred Stock had a liquidation preference of $1,000 per share and a dividend 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 was subject to adjustment pursuant to customary anti-dilution provisions and could also be adjusted upon the occurrence of a fundamental change as defined in the Certificate of Designations. The Preferred Stock was 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.

The Preferred Stock discount was deemed a preferred stock dividend and was amortized over five years using the effective interest method and charged to additional paid-in capital as the Company had a deficit balance in retained earnings. Charges to additional paid-in capital for the years ended December 31, 2011 and 2010 were equal to $2,360,916 and $2,241,800, respectively.

During the year ended December 31, 2011, holders of 62,288 shares of the Preferred Stock converted their shares into 71,186 shares of common stock.

During the year ended December 31, 2011 and 2010, Dune paid dividends on the Preferred Stock in the amount of $18,904,000 and $23,878,000, respectively, with the Company electing to issue 18,904 and 23,878 additional shares of preferred stock, respectively in lieu of cash.

On November 23, 2011, the Company received the consent of the holders of the Preferred Stock to mandatorily convert all shares of the Preferred Stock into an aggregate of approximately $4 million in cash and approximately 584,338 shares of the Company’s common stock. Such conversion took place on December 22, 2011 as part of the consummation of the Restructuring.

Additionally, all accrued preferred stock dividends associated with the Preferred Stock, which was equal to $1,154,000 as of December 22, 2011, were eliminated in association with the Restructuring.

Series C Preferred Stock

As part of the Restructuring, the board of directors of the Company designated a total of 247,506 shares of convertible preferred stock, per value $.001 per share, as Series C Preferred Stock. Shares of the Series C Preferred Stock were issued pursuant to the terms of an offer to exchange any and all of the Company’s outstanding Senior Secured Notes. On December 22, 2011, in accordance with the mandatory conversion of the Series C Preferred Stock, each share of Series C Preferred Stock was converted into 14,149 shares of the Company’s newly issued common stock for a total of 35,021,098 shares of common stock. All Series C Preferred Shares that were reacquired by the Company were subsequently cancelled by the board of directors of the Company and retired, not subject to reissuance.

NOTE 5—REVERSE STOCK SPLIT

On December 22, 2011, the Company amended its certificate of incorporation to effect a 1-for-100 reverse stock split. The reverse stock split was effective on December 22, 2011. As a result of the reverse stock split, every one hundred shares of common stock of the Company that a stockholder owned prior to December 22, 2011 were converted into one share of common stock of the Company, thus reducing the number of outstanding shares of common stock from approximately 3,858 million shares to 38.6 million shares as of the close of

 

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Index to Financial Statements

business on December 22, 2011. Following the reverse stock split, the Company continues to have 4,200 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 stock 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-100 reverse stock split. Significant common stock activity has been restated as detailed below:

 

		Post-Split Activity
Balance at December 31, 2010			419,127
Conversion of preferred stock			71,186
Stock grants cancelled			(1,124	)
Treasury stock cancelled			2,430
Common stock to Preferred Stock			584,338
Common stock to Senior Secured Notes			2,486,516
Common stock to Series C Preferred Stock			35,021,098
Other			(3,941	)
Balance at December 31, 2011			38,579,630

NOTE 6—HEDGING ACTIVITIES

As a result of entering into the Credit Agreement on December 7, 2010, the Company was 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 gains 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 valuation of $1,596,544 and a realized loss on cash settlements of ($213,606).

In accordance with the requirements of the New Credit Agreement entered into in connection with the Restructuring, the Company entered into hedge agreements in January 2012.

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 $506,210 and $1,766,880 for the years ended December 31, 2011 and 2010, respectively.

 

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Index to Financial Statements

The 2007 Stock Incentive Plan, which was approved by Dune’s stockholders, authorizes the issuance of up to 32,000 shares of common stock to employees, officers and non-employee directors. The Plan is administered by the Compensation Committee of Dune’s board of directors. The following table reflects the vesting activity associated with restricted stock awards at December 31, 2011:

 

Grant Date		Shares Awarded				Shares Canceled				Shares Vested				Shares Unvested
December 17, 2007			2,486				(715	)			(1,771	)			—
March 13, 2008			1,054				—				(1,054	)			—
August 1, 2008			6,227				(1,114	)			(5,113	)			—
October 1, 2009			4,500				—				(2,010	)			2,490
December 31, 2009			5,738				(1,505	)			(2,986	)			1,247
November 11, 2010			9,389				(669	)			(2,946	)			5,774
December 30, 2010			44				—				(44	)			—
			29,438				(4,003	)			(15,924	)			9,511

Common shares available to be awarded at December 31, 2011 are as follows:

 

Total shares authorized			32,000
Total shares issued			(29,438	)
Total shares canceled			4,003
Total shares available			6,565

The Company has 2,000 stock options outstanding at December 31, 2011 that expire in the first quarter of 2012 with no intrinsic value. Additionally, the Company has 1,116 stock warrants outstanding at December 31, 2011 that expire in 2015 with no intrinsic value.

Pursuant to a unanimous written consent dated March 5, 2012, the board of directors of the Company authorized the adoption of the Dune Energy, Inc. 2012 Stock Incentive Plan (the “2012 Plan”), to become effective immediately. The 2012 Plan is administered by the Compensation Committee of Dune’s board of directors. As defined under the 2012 Plan, the Compensation Committee may grant any one or a combination of incentive options, non-qualified stock options, restricted stock, stock appreciation rights and phantom stock awards, as well as purchased stock, bonus stock and other performance awards.

Pursuant to the consent of the Company’s board of directors, the board of directors approved grants to nonemployee directors of nonqualified options to purchase an aggregate of 600,000 shares. Additionally, the Committee approved the issuance of 834,500 restricted shares to employees, including an aggregate of 327,700 restricted shares to the Company’s four executive officers.

NOTE 8 – INCOME TAXES

Dune operates through its various subsidiaries in the United States; 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. Tax years subsequent to 2007 remain open to examination by taxing authorities.

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 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.

 

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Index to Financial Statements

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 recognized as of the date of adoption or for the twelve months ended December 31, 2011. The Company files tax returns in the U.S. and states in which it has operations and is subject to taxation.

Prior to 2007, the Company’s taxes were subject to a full valuation allowance. During 2007, the Company acquired the stock of Goldking Energy Holdings, L.P., or 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, 2011 and 2010, 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 the Company’s management. At this date, this general fact pattern does not allow the Company to project sufficient sources of future taxable income to offset the Company’s 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 FASB ASC 740. Accordingly, the Company has established a valuation allowance of $89,447,220 and $67,222,621 at December 31, 2011 and 2010, respectively, 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, 2011 and 2010 due to the following:

 

		Year ended December 31,
		2011				2010
		(in thousands)
Computed “expected” tax expense (benefit)		$	(21,145	)		$	(26,436	)
State taxes, net of benefit			(1,963	)			—
Return to accrual adjustment			7,122				(6,173	)
Other			3				5
Valuation allowance			15,983				32,604
Income tax expense (benefit)		$	—			$	—

Deferred tax assets at December 31, 2011 and 2010 are comprised primarily of net operating loss carryforwards and book impairment from write-downs of assets. Deferred tax liabilities consist primarily of the difference between book and tax basis depreciation, depletion and amortization (DD&A). Book basis in excess of tax basis for oil and gas properties and equipment primarily results from differing methodologies for recording property costs and depreciation, depletion and amortization under U.S. 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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Index to Financial Statements

Following is a summary of deferred tax assets and liabilities:

 

		Successor						Predecessor
		Year ended December 31,  2011						Year ended December 31,  2010
		(in thousands)
Current deferred tax assets		$	—					$	—
Noncurrent deferred tax assets:
Loss carryforwards			143,804						114,892
Other			7,991						10,161
Total noncurrent deferred tax assets			151,795						125,053
Total deferred tax assets			151,795						125,053
Current deferred tax liabilities			—						—
Noncurrent deferred tax liabilities:
Book-tax difference in oil and gas property and equipment			62,348						57,830
Total noncurrent deferred tax liabilities			62,348						57,830
Total deferred tax liabilities			62,348						57,830
Net deferred tax assets (liabilities)			89,447						67,223
Valuation allowance			(89,447	)					(67,223	)
Net deferred tax asset (liabilities)		$	—					$	—

At December 31, 2011, the Company has U.S. tax loss carryforwards of approximately $376 million, which will expire in various amounts beginning in 2020 through 2031.

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, as amended, 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, 2011 and expects similar dollar limits in future years until the acquired U.S. NOL’s are either completely exhausted or expire unutilized.

During 2011, the Company negotiated a workout of certain debt obligations and as a result, a change of control pursuant to Section 382 of the Internal Revenue Code of 1986, as amended, occurred. Accordingly, the Company will be limited to utilizing a portion of the NOL’s to offset taxable income generated by the Company during the tax year ended December 31, 2011 and future years until the NOL’s are completely exhausted or expire unutilized. The amount of the limitation is estimated to be less that $1 million annually.

 

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Index to Financial Statements

NOTE 9—ASSET RETIREMENT OBLIGATION

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

 

		Predecessor Company
		Year Ended December 31, 2011				Year Ended December 31, 2010
Asset retirement obligations, beginning of period		$	12,548,062			$	17,552,762
Liabilities related to property sales			—				(200,113	)
Revisions in estimated liabilities			—				(5,010,246	)
Abandonment costs			(245,964	)			(1,617,300	)
Accretion expense			1,317,516				1,822,959
Adjustment due to debt restructure			(13,619,614	)			—
Asset retirement obligations, end of period		$	—			$	12,548,062
Successor Company:
Asset retirement obligations, end of period		$	12,630,676			$	—

The Company maintains an escrow agreement that has been established for the purpose of assuring maintenance and administration of a performance bond that secures certain plugging and abandonment obligations assumed by the Company in the acquisition of oil and gas properties from EnerVest, Ltd. At December 31, 2011 and 2010, the amount of the escrow account totaled $2,252,352 and $2,252,352, respectively, and is included with other assets. Additionally, the Company incurred accretion expense of $1,317,516 and $1,822,959 at December 31, 2011 and 2010, respectively.

NOTE 10—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. 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, the Company inherited an environmental contingency, which after conducting its due diligence and subsequent testing, the Company believes is the responsibility of a third party. However, federal and state regulators have determined Dune is the responsible party for cleanup of this area. Dune has maintained a passive maintenance of this site since it was first discovered after Hurricane Katrina. Cost to date of approximately $1,200,000 has been covered by the Company’s insurance minus the standard deductibles. The Company still believes another party has the primary responsibility for this occurrence but is committed to working with the various state and federal authorities on resolution of this issue. Plans for testing and analysis of various containment products and remediation procedures by third party consultants are being reviewed and will be presented to the federal and state authorities for consideration. The possible cost of an acceptable containment product, assuming potential remediation programs are viable and acceptable to all involved parties, may be as much as $2,500,000 to $3,000,000. At this time, it is not known if the Company’s insurance will continue to cover the cleanup costs or if the Company can be successful in proving another party should be primarily responsible for the cost of remediation.

NOTE 11—SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

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

 

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Index to Financial Statements

The Company performed an evaluation of proved, probable or possible reserves as of December 31, 2011. 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. 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.

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.

Historically, Dune has had a third-party engineer prepare its year-end reserve report and Dune has completed the mid-year report on an internal basis. For the Restructuring, Dune had the third-party reserve engineer, DeGolyer & MacNaughton, prepare a mid-year 2011 report. We intend to have a third-party engineer prepare these reports each subsequent mid-year with the year-end report prepared by our internal engineering staff. This will result in the Company providing semi-annual reserve updates to its investors. The following reserve schedule was developed by the Company’s internal reserve engineers and sets forth the changes in estimated quantities for total reserves of the Company during the year ended December 31, 2011 and 2010:

 

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Index to Financial Statements

		Year Ended December 31,
		2011												2010
TOTAL RESERVES AS OF:		Oil (Mbbls)				Gas (Mmcf)				Total (Mmcfe)				Oil (Mbbls)				Gas (Mmcf)				Total (Mmcfe)
Beginning of the period			5,692				48,554				82,703				7,187				62,355				105,475
Revisions of previous estimates			267				(2,055	)			(454	)			433				(4,761	)			(2,162	)
Extensions and discoveries			177				1,951				3,019				—				—				—
Production			(482	)			(2,928	)			(5,820	)			(623	)			(4,048	)			(7,788	)
Sale of minerals in place			—				—				—				(1,305	)			(4,992	)			(12,822	)
Total proved reserves			5,654				45,522				79,448				5,692				48,554				82,703
Total probable reserves			529				3,649				6,823				465				2,723				5,512
Total possible reserves			1				3,657				3,663				1				3,257				3,263
Total reserves			6,184				52,828				89,934				6,158				54,534				91,478
Total proved developed reserves			3,520				30,433				51,564				3,715				32,134				54,424

Revisions of previous estimates consist of:

 

		2011												2010
		Oil (Mbbls)				Gas (Mmcf)				Total (Mmcfe)				Oil (Mbbls)				Gas (Mmcf)				Total (Mmcfe)
Price changes			24				18				162				630				7,132				10,912
Performance changes			243				(2,073	)			(616	)			(197	)			(11,893	)			(13,074	)
			267				(2,055	)			(454	)			433				(4,761	)			(2,162	)

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

 

•

Extensions and discoveries:

2011—The major components of the increase in extensions and discoveries pertain to the addition of proved undeveloped reserves in the Bateman Lake and Leeville fields as well as proved developed producing reserves in the Leeville field.

 

•

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.

Proved Undeveloped Reserves

The Company’s proved undeveloped reserves decreased from 2010 to 2011 by 38 Mbbls of oil and 3,032 Mmcf of gas primarily as a result of the Company’s decision not to drill two proved undeveloped locations in the Toro Grande field.

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

 

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Index to Financial Statements

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,
		2011				2010
		(in thousands)
Unproved property costs		$	—			$	—
Development costs			19,302				8,755
ARO costs			744				1,617
Total consolidated operations		$	20,046			$	10,372
Asset retirement obligations (non-cash)		$	—			$	(5,010	)

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:

 

		Successor Company						Predecessor Company
		Year Ended December 31, 2011						Year Ended December 31, 2010
		(in thousands)						(in thousands)
Proved oil and gas properties		$	210,199					$	526,761
Accumulated DD&A			—						(294,567	)
Net capitalized costs		$	210,199					$	232,194

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, 2011 and 2010 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.

 

		Successor Company						Predecessor Company
		Year Ended December 31, 2011						Year Ended December 31, 2010
		(in thousands)						(in thousands)
Future cash inflows		$	814,306					$	674,756
Future production costs (1)			(283,194	)					(244,185	)
Future development costs			(107,751	)					(87,102	)
Future income tax expense			—						—
Future net cash flows			423,361						343,469
10% annual discount for estimated timing of cash flows			(173,436	)					(128,939	)
Standardized measure of discounted future net cash flows at the end of the year		$	249,925					$	214,530

 

(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.

 

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Index to Financial Statements

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,
		2011				2010
Average crude oil price (per Bbl)		$	92.81			$	76.05
Average natural gas price (per Mmbtu)		$	4.12			$	4.38

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 $48.5 million, $12.6 million and $5.7 million that the Company expects to spend in 2012, 2013 and 2014, 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,
		2011				2010
		(In thousands)
Standardized measure of discounted future net cash flows at the beginning of the year		$	214,530			$	212,301
Extensions, discoveries and improved recovery			16,908				—
Revisions of previous quantity estimates			(1,852	)			(33,726	)
Changes in estimated future development costs			(32,945	)			1,648
Sale of minerals in place			—				(24,581	)
Net changes in prices and production costs			43,458				83,469
Accretion of discount			21,453				10,559
Sales of oil and gas produced, net of production costs			(36,807	)			(41,619	)
Development costs incurred during the period			20,046				6,479
Net change in income taxes			—				—
Changes in timing and other			5,134				—
Standardized measure of discounted future net cash flows at the end of the year		$	249,925			$	214,530

 

F-26