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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

For the fiscal year ended December 31, 2013

or

For the transition period from             to

Commission file number 000-27897

DUNE ENERGY, INC.

(Exact name of registrant as specified in its charter

(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:

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 (§ 232.405 of this chapter) 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):

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, 2013, 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 10% of the outstanding shares of the class) was $26,512,653 based upon a closing sales price of $1.60.

As of March 7, 2014, the registrant had outstanding 72,152,555 shares of common stock.

DOCUMENTS INCORPORATED BY REFERENCE

Certain of 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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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 74,000 gross acres across 15 producing oil and natural gas fields.

Our total proved reserves as of December 31, 2013 were 93.1 Bcfe, consisting of 50.1 Bcf of natural gas and 7.2 Mmbbls of oil. The PV-10 of our proved reserves at year end was $311.7 million based on the average of the oil and natural gas sales prices on the first day of each of the twelve months during 2013, which was $93.39 per bbl of oil and $3.66 per mcf of natural gas. During 2013, we added 7.7 Bcfe through extensions and discoveries and produced 4.5 Bcfe. In addition, we experienced a net downward revision of 0.1 Bcfe.

Our wholly-owned subsidiaries are Dune Operating Company and Dune Properties, Inc., each a Texas corporation.

Employees

As of December 31, 2013, 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.

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

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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.

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.

2014 Budget. For 2014, we have targeted an initial capital budget of approximately $52 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. We intend to finance our 2014 capital expenditure plan primarily from cash flows from operations and our credit facility. Approximately $17 million will be expended in the first half of 2014. Success on these programs will provide cash flow and availability under our credit facility to conduct a drilling program across several fields in the second half of the year.

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, 2013, our proved oil and gas reserves were concentrated in 15 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 each annual year-end and mid-year reserve report. At year-end 2013, our proved developed producing, or PDP, reserves of 23.6 Bcfe were 25.3% of our 93.1 Bcfe of total proved oil and natural gas reserves, our proved developed non-producing, or PDNP, reserves of 25.5 Bcfe were 27.4% of our total proved oil and natural gas reserves and our PUD reserves of 44.1 Bcfe were 47.3% of our total proved 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 58% 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 and exploratory wells in the fields since we acquired them. These workovers, recompletions, development and exploratory wells are designed to maintain or enhance the production rates in each of the fields. We intend to complete 4 to 6 workovers in these fields in 2014 along with 8 to 14 drilling opportunities both PUD and exploration locations. 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 provide the Company with several high reserve potential opportunities to drill in 2014 and beyond.

At Garden Island Bay, in 2013 we drilled the 913 572 (Kappa) PUD location and successfully completed the well as an oil producer. The initial 913 well, prior to being sidetracked, tested the Epsilon prospect but did not encounter commercial hydrocarbons. This program along with a 3 to 5 well workover program kept production essentially flat in the field for the year at approximately 760 Boe per day. In Garden Island Bay Field, we control 16 prospects and approximately 40 separate well locations identified using a recently completed depth-migrated

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3-D data set within the field. Dune maintains a 100% working interest in these prospects. We intend to drill two or three of these projects in 2014. Success on these projects could lead to further exploratory or development drilling later in 2014 within this field.

At the Leeville field, we participate with a 40% working interest as a non-operator in a shallow drilling program encompassing 5 to 10 primarily PUD locations per year. In 2013, we completed several wells in this program. We also drilled a deep exploratory well with a 20% working interest. This well was junked and abandoned at approximately 19,000 feet without reaching its objective. We expect the well to be redrilled in 2014; however, we will only be responsible for our 20% of the costs below 19,000 feet as the costs of redrilling to this level will be reimbursed by insurance proceeds. We recompleted several older wells in the field in 2013 and expect that program will continue in 2014.

At our Bateman Lake field, we continue evaluating investments in drilling opportunities. However, the reserves attributed to this field are 90% natural gas and as a result of low gas prices, we conducted no new drilling in this field in 2013. With gas price recovery we anticipate a more active program in 2014 of at least one PUD location in addition to 2 to 3 workovers.

The Chocolate Bayou, Comite, and Live Oak fields comprise our next three largest properties and consist of 26% of our total proved reserves. These assets are typically characterized as having fewer wellbores than the salt dome fields but present numerous opportunities for PUD drilling and fault blocks containing unproved reserves that have been identified with new 3-D seismic data.

The remaining fields contain approximately 16% of our total proved oil and gas reserves and are characterized by occasional new drilling wells and workovers, but typically do not have the upside opportunities demonstrated in the other fields.

Natural Gas and Oil Reserves.

Due to the inherent uncertainties and the limited nature of reservoir data, proved reserves are subject to change as additional information becomes available. The estimates of reserves, future cash flows and present value are based on various assumptions, including those prescribed by the 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 2013. 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, 2013 were $93.39 per barrel of oil and $3.66 per Mmbtu of natural gas.

The reserve data and the present value as of December 31, 2013 were prepared by our 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

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over 32 years of industry experience with positions of increasing responsibility in engineering and reservoir evaluations. We also have Degolyer and MacNaughton, a nationally recognized petroleum engineering firm, prepare a complete analysis of our reserves at mid-year. Such a report was completed as of June 30, 2013. This report is provided to our banks for calculation of our borrowing base under our revolver along with the year-end report prepared by our internal reservoir engineering staff.

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.

During 2013 we drilled one PUD location at Garden Island Bay field and added one new PUD location based on recent drilling and 3-D seismic evaluations. PUD reserves in Garden Island Bay increased to 1.976 Bcfe from 1.326 Bcfe at the beginning of the year. In our Leeville field we increased PUD reserves from 17.1 Bcfe year-end 2012 to 19.1 Bcfe at year-end 2013 based on a several well drilling program and an extensive 3-D mapping incorporating all existing well data. Leeville now accounts for approximately 43% of our current PUD volumes and 51% of the current PV-10 value. We commenced a drilling program on these new PUD locations late in 2012 and we expect the program to continue into 2014. The remaining PUD locations on our books at year end 2012 remained booked at year-end 2013 and the majority are anticipated to be evaluated as part of the 2014 drilling program. Even with very limited capital the Company has maintained a program of evaluating all PUD locations in a timely manner.

Our proved undeveloped reserves increased from 2012 to 2013 by 493 Mbbls of oil and 1,251 Mmcf of gas or 4.21 Bcfe as a result of drilling activity and new interpretations of reservoirs within our Chocolate Bayou, Garden Island Bay and Leeville fields. We intend to continue investing in converting our inventory of PUD locations to proved developed locations within a five year time-frame. In 2013, approximately 70% of our $50 million budget was expended on development drilling and completions designed to move reserves from PUD and PDNP to PDP reserves.

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, 2013.

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

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

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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 operations for the three years ended December 31, 2013, 2012 and 2011.

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.

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Drilling Activity

The following table sets forth our drilling activity during the twelve-month periods ended December 31, 2013, 2012 and 2011 (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.

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, 2013. Productive wells are wells that are capable of producing natural gas or oil in economic quantities.

Acreage Data

The following table summarizes our gross and net developed and undeveloped oil and natural gas acreage under lease as of December 31, 2013.

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:

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

The oil and gas industry is highly competitive. 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, more advanced technologies and greater capital resources than we do. There is also competition for the hiring of experienced personnel. 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.

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.

Additionally, our sales of crude oil is subject, in certain states, to what are generally referred to as common purchaser statutes and related regulations, which, in general, require that purchasers in a field purchase and take ratably and without discrimination from all producers in that field selling to that purchaser. Accordingly, we believe that the impact of common purchaser statutes and related regulations 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

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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 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.

Further, our sales of natural gas is subject, in certain states, to what are generally referred to as common purchaser statutes and related regulations, which, in general, require that purchasers in a field purchase and take ratably and without discrimination from all producers in that field selling to that purchaser. Accordingly, we believe that the impact of common purchaser statutes and related regulations will not affect our operations in any way that is of material difference from those of our competitors.

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.

Further, any impact of the common purchaser statutes and related regulations discussed above is manifested, if at all, on our production of crude oil and natural gas in relation to other producers in the fields in which we operate. Accordingly, we believe that the impact of common purchaser statutes and related regulations will not affect our operations in any way that is of material difference from those of our competitors.

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:

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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. Further in recent years, oil and gas exploration and production operations have been subject to increasing scrutiny and regulation from environmental authorities. The Environmental Protection Agency (EPA) has identified environmental compliance by the energy extraction sector as one of its enforcement initiatives for 2014-2016.

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 a site where a release occurred. 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.

Although CERCLA generally exempts “petroleum” from the definition of hazardous substances, 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

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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 Energy Holdings, L.P. or Goldking, we inherited a remediation contingency, which after conducting its due diligence and subsequent testing, we believe is the responsibility of a third party. However, federal and state regulators have determined that we are the responsible party for cleanup of this area. We have maintained a passive maintenance of this site since it was first discovered after Hurricane Katrina. Plans for testing and analysis of various containment products and remediation procedures by third party consultants have been approved and in the third quarter of 2013, the Company recorded a liability of $4,586,000. Costs of $1,224,157 have been incurred during the year resulting in a $3,361,843 balance of which $582,843 is included in accrued liabilities and $2,779,000 is included in other long-term liabilities in the consolidated balance sheets at December 31, 2013.

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. The CWA also prohibits the discharge of fill materials to regulated waters, including wetlands, without a permit. 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, and can seek injunctive relief which could require the Company to forego construction, modification or operation of certain air emissions sources. 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.

On April 17, 2012, the EPA issued final rules to subject oil and gas operations to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAPS, programs under the CAA, and to impose new and amended requirements under both programs. The EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells. Before January 1, 2015, these standards require owners/operators to reduce VOC emissions from natural gas not sent to the

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gathering line during well completion either by flaring using a completion combustion device or by capturing the natural gas using green completions with a completion combustion device. Beginning January 1, 2015, operators must capture the natural gas and make it available for use or sale, which can be done through the use of green completions. The standards are applicable to new hydraulically fractured wells and also existing wells that are refractured. Further, the finalized regulations also establish specific new requirements, effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. These rules may require changes to our operations, including the installation of new equipment to control emissions.

Climate Change

More stringent laws and regulations relating to climate change and greenhouse gases (“GHGs”) may be adopted in the future and could cause us to incur material expenses in complying with them. The EPA has adopted rules under the Clean Air Act (“CAA”) for the permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. The EPA has adopted a multi-tiered approach or “tailored” approach to this permitting, 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.

With regards to the monitoring and reporting of GHGs, on November 30, 2010, the EPA published a final rule expanding its GHG emissions reporting rule to include onshore oil and natural gas production activities, which may include certain of our operations.

In addition, both houses of Congress have actively considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. The adoption and implementation of any legislation or regulations imposing reporting obligations 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

The Endangered Species Act (“ESA”) was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory

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Bird Treaty Act. The U.S. Fish and Wildlife Service must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development. If the Company were to have a portion of its leases designated as critical or suitable habitat, it may adversely impact the value of the affected leases.

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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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 or uncertainties 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, 2012 and 2013 were $7.9 million and $47.0 million, respectively. Our revenues for the fiscal years ended December 31, 2012 and 2013 were $52.1 million and $55.5 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:

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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.

The restrictions contained in the New Credit Agreement could:

We may not be able to generate enough cash flow to meet our debt obligations.

We expect our earnings and cash flow to vary significantly from year to year due to the nature of our industry. As a result, the amount of debt that we can manage in some periods may not be appropriate for us in other periods. Additionally, our future cash flow may be insufficient to meet our debt obligations and other commitments. Any insufficiency could negatively impact our business. A range of economic, competitive, business and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flow from operations and to pay our debt obligations. Many of these factors, such as oil and gas prices, economic and financial conditions in our industry and the global economy and initiatives of our competitors, are beyond our control. If we do not generate enough cash flow from operations to satisfy our debt obligations, we may have to undertake alternative financing plans, such as:

If for any reason we are unable to meet our debt service and repayment obligations, we would be in default under the terms of the agreements governing our debt, which would allow our creditors at that time to declare all outstanding indebtedness to be due and payable. If amounts outstanding under our revolving credit facility or our notes were to be accelerated, we cannot be certain that our assets would be sufficient to repay in full the money owed to the lenders or to our other debt holders.

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.

Any additional capital raised through the sale of equity may dilute the ownership percentage of our stockholders. Raising any such capital could also result in a decrease in the nominal fair market value of our equity securities because our assets would be owned by a larger pool of outstanding equity. The terms of securities we issue in future capital transactions may be more favorable to new investors and may include preferences, superior voting rights and the issuance of other derivative securities, all of which may have a dilutive effect to existing investors.

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Our ability to obtain financing, if and when necessary, may be impaired by such factors as the capital markets (both generally and in the oil and gas industry in particular), the location of our oil and gas properties, prices of oil and gas on the commodities markets (which will impact the amount of asset-based financing available to us) and the departure of key employees. Further, if oil or gas prices decline, our revenues will likely decrease and such decreased revenues may increase our requirements for capital. If the amount of capital we are able to raise from financing activities, together with revenues from our operations, are not sufficient to satisfy our capital needs (even if we reduce our operations), we may be required to cease operations, divest our assets at unattractive prices or obtain financing on unattractive terms.

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:

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.

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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:

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 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.

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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.

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.

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

As of the end of our 2013 fiscal year, approximately 47% 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.

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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:

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.

We may be unable to integrate successfully the operations of any acquisitions with our operations and we may not realize all the anticipated benefits of the recent acquisitions or any future acquisition.

Failure to successfully assimilate any acquisitions could adversely affect our financial condition and results of operations. Acquisitions involve numerous risks, including:

Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. If we consummate any future acquisition, our capitalization and results of operation may change significantly, and you may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in evaluating future acquisitions.

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We rely on our senior management team and the loss of a single member could adversely affect our operations.

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.

Competitive industry conditions may negatively affect our ability to conduct operations.

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. There is also competition for contracting for drilling equipment and the hiring of experienced personnel. Factors that affect our ability to compete in the marketplace include:

Our competitors include major integrated natural gas and oil companies and substantial independent energy companies, many of which possess greater financial, technological, personnel and other resources than we do. 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 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

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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.

Cyber-attacks targeting systems and infrastructure used by the oil and gas industry may adversely impact our operations.

Our business has become increasingly dependent on digital technologies to conduct certain exploration, development, production and financial activities. We depend on digital technology to estimate quantities of oil and gas reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third party partners. Unauthorized access to our seismic data, reserves information or other proprietary information could lead to data corruption, communication interruption or other operational disruptions in our exploration or production operations. Also, computers control nearly all of the oil and gas distribution systems in the United States and abroad, which are necessary to transport our production to market. A cyber-attack directed at oil and gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for production and settle transactions. While we have not experienced cyber-attacks, there is no assurance that we will not suffer such attacks and resulting losses in the future. Further, as cyber-attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber-attacks.

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 U.S. 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.

In recent years, the current U.S. government’s budget proposals and other proposed legislation have included the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production. If enacted into law, these proposals would eliminate certain tax preferences applicable to taxpayers engaged in the exploration or production of natural resources. 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 paid or incurred in connection with the exploration for or development of, oil and gas within the United States. It is

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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 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 oil and natural gas prices are unstable, we may reduce our exposure to the volatility of oil and natural gas prices by hedging a portion of our production, by entering into price risk management transactions such as swaps, collars, futures and options. 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. Hedging also prevents us from receiving the full advantage of increases in oil or natural gas prices above the maximum fixed amount specified in the hedge agreement. Conversely, hedging may limit our ability to realize cash flows from commodity price increases. In a typical hedge transaction, we have the right to receive from the hedge counterparty the excess of the maximum fixed price specified in the hedge agreement over a floating price based on a market index, multiplied by the quantity hedged. If the floating price exceeds the maximum fixed price, we must pay the counterparty this difference multiplied by the quantity hedged even if we had insufficient production to cover the quantities specified in the hedge agreement. Accordingly, if we have less production than we have hedged when the floating price exceeds the fixed price, we must make payments against which there are no offsetting sales of production. If these payments become too large, the remainder of our business may be adversely affected.

In addition, hedging agreements expose us to risk of financial loss if the counterparty to a hedging contract defaults on its contract obligations. This risk of counterparty performance is of particular concern given the disruptions that occurred in the financial markets that lead to sudden changes in a counterparty’s liquidity and hence their ability to perform under the hedging contract.

The adoption of derivatives legislation by the U.S. Congress could have an adverse effect on the Company’s ability to use derivative instruments to reduce the effect of commodity price, interest rate, and other risks associated with its business.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd Act”), signed into law in 2010, establishes, among other provisions, federal oversight and regulation of the over-the-counter derivatives market and entities, such as the Company, that participate in that market. The Dodd Act required the Commodities Futures Trading Commission (“CFTC”) and the SEC to promulgate rules and regulations implementing the new legislation; although the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas and the scope of relevant definitions and/or exemptions still remain to be finalized. In its rulemaking under the Dodd Act, the CFTC has issued a final rule on position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents; the CFTC’s final rule was set aside by the U.S. District Court for the District of Columbia on September 28, 2012 and remanded to the CFTC to resolve ambiguity as to whether statutory requirements for such limits to be determined necessary and appropriate were satisfied. The

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CFTC appealed this ruling, but subsequently withdrew its appeal. On November 5, 2013, the CFTC approved a Notice of Proposed Rulemaking to implement new position limits regulation which would be published later in a final rule. Certain bona fide hedging transactions or positions are exempt from these position limits. While it is not possible at this time to predict when the CFTC will finalize the position limit rule or other related rules and regulations, depending on our classification, these rules and regulations may require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities. The Dodd Act may also require the counterparties to derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The Dodd Act and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts and reduce the availability of derivatives to protect against risks we encounter. Finally, the Dodd Act was intended, in part, to reduce the volatility of oil and natural-gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd Act and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our ability to hedge risks and on our consolidated financial position, results of operations, or cash flows.

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 and climate changes.

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

In an interpretative guidance on climate change disclosures, the SEC indicates that climate change could have an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland, and water availability and quality. If such effects were to occur, our exploration and production operations have the potential to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low-lying areas, disruption of our production activities either because of climate-related damages to our facilities in our costs of operation potentially arising from such climatic effects, less efficient or non-routine operating practices necessitated by climate effects or increased costs for insurance

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coverages in the aftermath of such effects. Significant physical effects of climate change could also have an indirect affect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change.

Unexpected subsurface conditions and other unforeseen operating hazards may adversely impact our oil and gas activities.

The oil and gas business involves a variety of operating risks, including fire, explosions, blow-outs, pipe failure, casing collapse, abnormally pressured formations and environmental hazards such as oil spills, gas leaks, ruptures and discharges of toxic gases, underground migration and surface spills or mishandling of fracture fluids including chemical additives, the occurrence of any of which could result in substantial losses to us due to injury and loss of life, severe damage to and destruction of property, natural resources and equipment, pollution and other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. The impact that any of these risks may have upon us is increased due to the low number of producing properties we own.

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

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

Oil and natural gas operations are subject to particular hazards incident to the drilling and production of oil and natural gas, such as blowouts, cratering, explosions, uncontrollable flows of oil, natural gas or well fluids, fires and pollution and other environmental risks. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operation. We do not operate all of the properties in which we have an interest. In the projects in which we own a non-operating interest directly, the operator for the prospect maintains insurance of various types to cover our operations with policy limits and retention liability customary in the industry. We believe the coverage and types of insurance are adequate. The occurrence of a significant adverse event that is not fully covered by insurance could result in the loss of our total investment in a particular prospect, which could have a material adverse effect on our financial condition and results of operations.

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

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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.

Additionally, the price and terms for access to pipeline transportation in the U.S. remain subject to extensive federal and state regulation. If these regulations change, or if rate increase requests are approved, we could face higher transmission costs for our production and, possibly, reduced access to transmission capacity. Various proposals and proceedings that might affect the petroleum industry are pending before Congress, the Federal Energy Regulatory Commission, or FERC, various state legislatures, and the courts. The industry historically has been heavily regulated and we can offer you no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue nor can we predict what effect such proposals or proceedings may have on our operations.

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

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

The market price of our common stock may be volatile.

The trading price of our common stock and the price at which we may sell common stock in the future could be subject to large fluctuations in response to a variety of events or conditions, including, but not limited to, any of the following:

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.

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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 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.

Not applicable.

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.

In connection with the acquisition of Goldking, we inherited a remediation contingency, which after conducting its due diligence and subsequent testing, we believe is the responsibility of a third party. However, federal and state regulators have determined that we are the responsible party for cleanup of this area. We have maintained a passive maintenance of this site since it was first discovered after Hurricane Katrina. Plans for testing and analysis of various containment products and remediation procedures by third party consultants have been approved and in the third quarter of 2013, the Company recorded a liability of $4,586,000. Costs of $1,224,157 have been incurred during the year resulting in a $3,361,843 balance of which $582,843 is included in accrued liabilities and $2,779,000 is included in other long-term liabilities in the consolidated balance sheets at December 31, 2013.

See additional disclosures in Note 8 of our consolidated financial statements and related notes included elsewhere in this report.

Not applicable.

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PART II

Market for Our Common Stock

Our common stock is currently traded under the symbol “DUNR” on the OTCQB tier of the OTC Markets Group Inc. From July 16, 2010 to January 21, 2014, our common stock 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 for the period from January 1, 2012 through December 31, 2013.

The last sales price of our common stock on the OTC Bulletin Board on December 31, 2013 was $1.30 per share. As of February 11, 2014, the closing sales price of a share of our common stock was $1.04 and there were approximately 279 stockholders of record.

There were 144,214 common shares repurchased in 2013. All shares repurchased were associated with the payment of taxes by employees upon the vesting of stock awarded pursuant to the Dune Energy, Inc. 2007 Stock Incentive Plan (the “2007 Plan”), as amended on December 1, 2009, and the Dune Energy, Inc. 2012 Stock Incentive Plan (the “2012 Plan”).

1,187,487 shares of restricted stock were awarded to employees, officers or non-employee directors during fiscal year 2013.

Dividends

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.

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Securities Authorized for Issuance Under Equity Compensation Plans

The following table provides information as of December 31, 2013 about our equity compensation plans and arrangements. Please refer to Note 5 to the consolidated financial statements for additional information on stock based compensation.

Equity Compensation Plan Information—December 31, 2013(*)

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 1,116 shares of our common stock included in the chart above were issuable as of December 31, 2013:

Recent Sales of Unregistered Securities

On December 21, 2012, we issued 18,749,997 shares of its common stock to the Company’s major stockholders (the “Investors”), pursuant to a Stock Purchase Agreement (collectively the “Stock Purchase Agreements” and such transaction the “Financing”) between the Company and each such stockholder, resulting in gross proceeds to the Company of $30,000,000. Upon our election, and subject to our meeting certain

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performance objectives, we could conduct two additional closings with the Investors prior to December 31, 2013 (each a “Subsequent Closing”). In each Subsequent Closing, we would issue up to 6,250,000 shares of our common stock at a purchase price of $1.60 per share or a total purchase price of up to $10,000,000. The Investors could also elect to require us to conduct a closing in which we will issue the remaining shares to be issued in the Financing, upon the occurrence of certain events specified in the Stock Purchase Agreements. In the Financing, each of the Investors received a “Preemptive Right” to purchase such investor’s pro rata percentage of new stock or new debt financings (excluding certain reserve based revolver financings) undertaken by the Company, on substantially the same terms as offered to any outside investor.

On May 8, 2013, pursuant to the terms of the Stock Purchase Agreements, the Company conducted a Subsequent Closing with the Investors in which the Company issued 6,249,996 shares of its common stock, resulting in gross proceeds to the Company of $10,000,000.

On June 28, 2013, pursuant to the terms of the Stock Purchase Agreements, the Company conducted the final Subsequent Closing with the Investors in which the Company issued 6,249,996 shares of its common stock, resulting in gross proceeds to the Company of $10,000,000.

The shares of common stock were issued in reliance on an exemption from registration under Section 4(2) of the Securities Act. The proceeds from the sale of common stock will be used to fund working capital and repay indebtedness.

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

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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 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

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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 $93.39 per barrel and were held constant for the lives of the property. The weighted average price over the lives of the properties was $103.91 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 $3.66 per Mmbtu and were held constant for the lives of the properties. The weighted average price over the lives of the properties was $3.91 per Mcf. The standardized measure is based on the average of the first-of-the-month pricing for 2013. 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 are 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 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.

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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 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 negative operating losses. Although we evaluate future oil and gas prices as part of the impairment analysis, we do not view short-term decreases in prices, even if significant, as impairment triggering events.

During the years ended December 31, 2013 and 2012, the Company impaired its oil and gas properties by $31,370,000 and $0, respectively, which are reflected in the accompanying consolidated statements of operations. The 2013 impairment resulted from the impact of lower expected future oil prices on the economic life of the Garden Island Bay field proved reserves. The application of this non-cash accounting assessment was triggered by the publication of the mid-year and year-end Reserve Report which reflected the backwardation of the published strip price by WTI oil on the effective date of the report.

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

We follow 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 our 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 us 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 our 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

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hedge, the changes in the fair value of the derivative and of the hedged item attributable to the hedged risk are recognized in earnings. If the derivative is designated as a cash flow hedge, the effective portions of changes in the fair value of the derivatives are recorded in other comprehensive income or loss and are recognized in the statement of operations when the hedged item affects earnings. If the derivative is not designated as a hedge, 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.

In accordance with the requirements of the financial restructuring, we entered into hedge agreements in January 2012. The gain or loss on these derivatives is recognized currently in earnings and treated as fair value hedges.

Stock-based compensation

We follow the provisions of FASB ASC 718—Stock Compensation. The statement requires all stock-based payments to employees and non-employee directors, including grants of stock options, to be recognized in the financial statements based on their fair values on the date of the grant.

Business Strategy

We are 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 74,000 gross acres across 15 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 2013 we invested $49.5 million in oil and gas properties. We produced 4.5 Bcfe during the year. Extensions and discoveries were 7.7 Bcfe and revisions of previous estimates were 0.2 Bcfe negative.

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.” We expect to have substantial capital needs as a result of our exploration and development program. Without additional capital resources, we may be forced to limit our planned capital expenditure program.

Liquidity and Capital Resources

During fiscal 2013 compared to fiscal 2012, net cash flow provided by operating activities reflected an increase of $9.3 million to $18.3 million. This increase is primarily attributable to the fluctuation in accounts payable and accrued liabilities between periods as well as a build-up of prepayments and other assets.

Our current assets were $11.9 million on December 31, 2013. Cash on hand comprised approximately $3.3 million of this amount compared to $22.8 million in cash at December 31, 2012. Accounts payable have increased from $6.9 million at year end 2012 to $10.1 million at December 31, 2013. This increase in payables and decreases in cash on hand from the calendar year 2012 reflects the impact of additional capital spending during 2013.

Our capital investments and exploration costs year-to-date reflect our ongoing drilling and facilities upgrade program which amounted to $49.5 million during 2013, up from $27.3 million spent during the same period of 2012. The increased spending reflected continued drilling activity at Garden Island Bay and Leeville fields. This

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represented $22.2 million increase over our capital investment and exploration costs in 2012. Our capital program is designed to maintain production from recompletions and workovers within our fields and fully develop both existing PUD locations and evaluate potential field extension wells through joint venture programs. This strategy involved industry partners in these efforts so as to reduce our upfront cash requirements and dollars expended.

In mid-2013, we conducted two Subsequent Closings with certain investors in which we issued an aggregate of 12,499,992 shares of our common stock, resulting in gross proceeds of $20,000,000.

However, our primary sources of liquidity are cash provided by operating activities, debt financing, sales of non-core properties and access to capital markets. The Total Debt to EBITDAX covenant in our current revolving credit agreement controls access to the “undrawn” amount of borrowing availability from quarter to quarter and is based on the trailing 12 month total. As a result, any given month within the 12 month calculation period, such as that experienced during the first two months of 2013, will have a lingering impact on future quarterly EBITDAX determinations until those months are no longer included. For the fourth quarter of 2013 and the first quarter of 2014, the EBITDAX covenant stipulates that the ratio of Total Debt to EBITDAX be less than 5.0 to 1.0. On June 30, 2014, and thereafter, the ratio of total Debt to EBITDAX must be less than 4.0 to 1.0. The Total Debt to EBITDAX for the 12 months ended December 31, 2013 is 4.1 to 1.0, within the 5.0 to 1.0 requirement. Current indications suggest that the Company should remain in compliance with this covenant for the coming year. However, any operational delays or failures that impact expected production volumes or timing may have an adverse effect on our ability to meet this calculation. We monitor our financial progress very carefully and attempt to adjust our available projects in order to meet all of the covenants of the credit agreement.

The exact amount of capital spending for 2014 will depend upon individual well performance results; cash flow; availability and scheduling of drilling operations; and partner agreement on timing and planning of joint drilling obligations. Currently, we expect that a significant portion of our first half of 2014 budget will be dedicated to our Leeville field. Should our partners decide to pursue a drilling schedule that is more aggressive than currently presumed, the resulting AFE’s for our share of the expenditures may force us to either forfeit our interest in future programs or delay our drilling activity at Garden Island Bay. As Leeville has been a successful venture thus far, delaying Garden Island Bay projects would likely occur. In the meantime, we are targeting a total capital budget of approximately $50 to $52 million in calendar 2014, which is below our 2013 forecast of $73 million. The less ambitious target is set so as to ensure that the Company stays within the covenant restrictions of our credit agreement where we have opportunities to increase production volumes for relatively low overall investments. As always, gains in production volumes will significantly drive EBITDAX increases, which should then provide for increased borrowing availability under our revolver.

Our operating cash flows, both in the short-term and long-term, are impacted by highly volatile oil and natural gas prices. Significant deterioration in commodity prices negatively impacts our revenues, earnings and cash flows, and our liquidity if spending does not trend downward as well. Sales volumes and costs also impact cash flows; however, these historically have not been as volatile and have less impact than commodity prices in the short-term. Our long-term operating cash flows are dependent on reserve replacement and the level of costs required for ongoing operations. Our business, as with other extractive industries, is a depleting one which each barrel produced must be replaced or the Company and its reserves, a critical source of future liquidity, will shrink. Cash investments are required to fund activity necessary to offset the inherent declines in production and proved crude oil and natural gas reserves. Future success in maintaining and growing reserves and production is highly dependent on the success of our exploration and development activities and our ability to acquire additional reserves at reasonable costs.

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The following table summarizes our contractual obligations and commercial commitments as of December 31, 2013:

Results of Operations

Comparison of 2013 and 2012

Year-over-year production decreased by 14.0% from 5,261 Mmcfe in 2012 to 4,529 Mmcfe in 2013. This decrease was caused by normal reservoir declines which were not offset by increased production in the Garden Island Bay and Leeville fields.

The following table reflects the increase (decrease) in oil and gas sales revenue between fiscal years 2012 and 2013 due to changes in prices and production volumes:

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Revenues

Oil and gas revenue

Oil and gas revenues for the year ended December 31, 2013 totaled $53.6 million as compared to $52.0 million for the year ended December 31, 2012, representing a $1.6 million increase. Production volumes for 2013 were 436 Mbbls of oil and 1.9 Bcf of natural gas, or 4.5 Bcfe. This compares to 407 Mbbls of oil and 2.8 Bcf of natural gas, or 5.3 Bcfe, for 2012, representing a 14% reduction in production volumes. In 2013, the average sales price of oil was $105.22 per barrel and the average sales price of natural gas was $4.03 per Mcf as compared to $105.54 per barrel of oil and $3.20 per Mcf of natural gas in 2012. These results indicate that the increase in revenue was attributable to the increase in natural gas prices of 26% which were able to offset the 14% decrease in overall production.

Other revenues

During the year ended December 31, 2013, the Company sold volatile organic compound emission credits to purchasers for $1.9 million. Sales of these credits totaled $0.2 million in 2012.

Operating expenses

Lease operating expense and production taxes

The following table presents the major components of our lease operating expense for the last two years in total (in thousands) and on a per Mcfe basis:

Lease operating expense and production taxes for the year ended December 31, 2013 totaled $24.9 million versus $25.9 million for the year ended December 31, 2012. This translated to a 4% reduction in total lease operating expense and production taxes for the year even though there was a 12% increase year-over-year on a sales volume basis from $4.93 to $5.51 as declining production had an adverse impact on field economies of scale.

Accretion of asset retirement obligation

Accretion expense for asset retirement obligations increased by $0.3 million for 2013 compared to 2012. This increase is the result of reevaluating abandonment cost at year end.

Depletion, depreciation and amortization (DD&A)

For the year ended December 31, 2013, we recorded DD&A expense of $16.8 million ($3.71/Mcfe) compared to $14.1 million ($2.67/Mcfe) for the year ended December 31, 2012, representing an increase of $2.7 million ($1.04/Mcfe). This increase reflects the impact of a $22.2 million increase in capital investment during 2013.

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