UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
| x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2008
or
| ¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission file number 001-32497
DUNE ENERGY, INC.
(Exact name of registrant as specified in its charter
| | |
| Delaware | | 95-4737507 |
(State or other jurisdiction of incorporation or organization) | | (I.R.S. Employer Identification No.) |
| |
Two Shell Plaza, 777 Walker Street, Suite 2300 Houston, Texas | | 77002 |
| (Address of principal executive offices) | | (Zip Code) |
(713) 229-6300
Registrant’s telephone number, including area code
Securities registered pursuant to Section 12(b) of the Act:
| | |
Title of each class | | Name of each exchange on which registered |
| Common Stock, $0.001 par value | | NYSE Alternext US |
Securities registered pursuant to section 12(g) of the Act: None (Title of class)
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No x
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
| | |
| Large accelerated filer ¨ | | Accelerated filer ¨ |
| Non-accelerated filer x (Do not check if a smaller reporting company) | | Smaller reporting company ¨ |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No x
As of June 30, 2008, the aggregate market value of the common stock of the registrant held by non-affiliates (excluding shares held by directors, officers and other holding more than 5% of the outstanding shares of the class) was $37,402,176, based upon a closing sale price of $1.03.
As of February 27, 2009, the registrant had outstanding 98,377,224 shares of common stock.
DOCUMENTS INCORPORATED BY REFERENCE
The information required by Part III will be incorporated by reference into this Form 10-K from the Registrant’s Definitive Proxy Statement to be filed pursuant to Regulation 14A within 120 days after the end of the Registrant’s fiscal year covered by this Form 10-K.
TABLE OF CONTENTS
Cautionary Notice Regarding Forward Looking Statements
Dune Energy, Inc. (referred to herein as “Dune”, “we” or the “Company”) desires to take advantage of the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. This report contains a number of forward-looking statements that reflect management’s current views and expectations with respect to our business, strategies, future results and events and financial performance. All statements made in this Annual Report other than statements of historical fact, including statements that address operating performance, events or developments that management expects or anticipates will or may occur in the future, including statements related to revenues, cash flow, profitability, adequacy of funds from operations, statements expressing general optimism about future operating results and non-historical information, are forward looking statements. In particular, the words “believe,” “expect,” “intend,” “anticipate,” “estimate,” “may,” “will,” variations of such words, and similar expressions identify forward-looking statements, but are not the exclusive means of identifying such statements and their absence does not mean that the statement is not forward-looking. These forward-looking statements are subject to certain risks and uncertainties, including those discussed below. Our actual results, performance or achievements could differ materially from historical results as well as those expressed in, anticipated or implied by these forward-looking statements.
Readers should not place undue reliance on these forward-looking statements, which are based on management’s current expectations and projections about future events, are not guarantees of future performance, are subject to risks, uncertainties and assumptions (including those described below) and apply only as of the date of this report. Our actual results, performance or achievements could differ materially from the results expressed in, or implied by, these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those discussed below in “Risk Factors” as well as those discussed elsewhere in this report, and the risks discussed in our press releases and other communications to stockholders issued by us from time to time which attempt to advise interested parties of the risks and factors that may affect our business. Except as may be required under the federal securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.
1
PART I
Items 1 and 2. Business and Properties.
Overview
Dune Energy, Inc. (“Dune, the “Company” or “we”) is an independent energy company based in Houston, Texas. Since May of 2004, we have been engaged in the exploration, development, acquisition and exploitation of natural gas and crude oil properties, with interests along the Louisiana/Texas Gulf Coast. Our properties cover 100,000 gross acres across 23 producing oil and natural gas fields.
Our total proved reserves as of December 31, 2008 were 132.9 Bcfe, consisting of 83.8 Bcf of natural gas and 8.2 MMbbls of oil. The SEC PV-10 of our proved reserves at year end was $293.2 million based on year end prices of $40.41/Bbl and $6.07/Mcfe. During 2008, we sold 33.5 Bcfe in connection with the disposition of our Barnett Shale properties, added 13.5 Bcfe through extensions and discoveries and produced 12.8 Bcfe including 1.4 Bcfe of Barnett Shale production prior to its sale. In addition, we experienced a downward revision of 11.0 Bcfe largely as a result of unsuccessful completion attempts in the Comite field in Louisiana.
Employees
As of December 31, 2008, we had 52 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 continue increasing reserves, production and cash flow in order to maximize value for stockholders. The following are key elements of this strategy:
Grow Through Exploitation, Development and Exploration of Our Properties. 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 gas reserves and production while keeping our finding and development costs and operating costs (on a per Mcf equivalent (Mcfe) basis) competitive with our industry peers. We will implement this strategy through drilling exploratory and development wells from our inventory of available prospects that we have evaluated for geologic and mechanical risk and future reserve or resource potential. Our drilling program will contain some higher risk/higher reserve potential opportunities as well as some lower risk/lower reserve potential opportunities in order to achieve a balanced program of reserve and production growth.
Maintain and Utilize State of the Art Technological Expertise. We expect to maintain and utilize our technical and operations teams’ knowledge of salt-dome structures and multiple stacked producing zones common in the Gulf Coast to enhance our growth prospects and reserve potential. We will employ technical advancements, including 3-D seismic data, pre-stack depth migration and directional drilling to identify and exploit new opportunities in our asset base. We also plan to employ the latest drilling, completion and fracturing technology in all of our wells to enhance recoverability and accelerate cash flows associated with these wells.
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. We are seeking to acquire operational control of properties that we believe have a solid proved reserves base coupled
2
with significant exploitation and exploration potential. We intend to continue to evaluate acquisition opportunities and make acquisitions that we believe will further enhance our operations and reserves in a cost effective manner.
2009 Budget. For 2009 we have targeted a capital budget of approximately $38 million. While we will focus primarily on our development drilling program, we also intend to exploit certain exploration opportunities. Our budget will be carefully managed to stay within our available cash, cash flow and line of credit.
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, 2008, our proved reserves were concentrated in 23 producing fields along the Texas and Louisiana Gulf Coast. Almost all fields are characterized as legacy fields discovered by major companies in the mid 1900’s. The fields tend to have stacked multiple producing horizons with production typically between 4,000 and 13,000 feet. Most fields have numerous available wellbores capable of providing workover and recompletion opportunities. Additionally, new 3-D seismic allows definition of numerous updip proved undeveloped locations throughout the fields. The characteristics of these fields allow the Company to record significant proved behind pipe and proved undeveloped reserves in the annual year-end reserve report. At year end 2008, our proved producing reserves of 44.4 Bcfe were 33% of our total reserves, the proved developed behind pipe (PDNP) of 44.1 Bcfe were 33% of the total reserves and the proved undeveloped (PUD) of 44.5 Bcfe were 34% of the total reserves.
Four of our fields, Garden Island Bay, Bayou Couba, Leeville and Bateman Lake have large acreage positions surrounding piercement salt dome features. These fields account for 37% of our total reserves. We maintain an active workover and recompletion program in each of these fields and have drilled several development wells in the fields since we acquired them. These workovers, recompletions and development wells are designed to maintain or enhance the production rates in each of the fields. Most of these fields have had minimal drilling below 15,000 feet or below the salt layers which provides significant exploratory upside for the Company. 3-D seismic technology and directional drilling techniques perfected in the offshore shelf and deep water environments is providing the Company several high reserve potential opportunities to drill in 2009 and beyond.
At Garden Island Bay, we have recently completed a reverse time migration and depth conversion of our 3-D data and formed a partnership with a private entity to market these high potential prospects to industry partners. When drilled, Dune would retain a minimum of a 15% working interest in the prospects plus benefit from any marketing revenues or interests. We anticipate the initial test on this 4,900 acre joint venture late in 2009 or in 2010.
At Bayou Couba, we are in the process of converting the current 3-D data set to a depth migration in an effort to better define the high potential sub-salt opportunities. This project should be ready for drilling in 2010. We are currently seeking an industry partner in a deeper pool test on this dome where we have seismically defined a high potential amplitude related prospect. The Company intends to maintain a 20-40% working interest in this 13,000 foot test which will commence when we locate industry partners to share the risk of drilling.
At Leeville and Bateman Lake fields, we have formed private company partnerships to drill new wells in which Dune can elect to participate at varied working interests or be carried for the full cost of the well and maintain an overriding royalty in the resultant production. The deeper potential in each of these two fields is relatively unexplored and we intend to develop partnerships to explore this potential in the next year or two.
3
The Chocolate Bayou, South Florence, Comite, North Broussard and Live Oak fields consist of 46% of our total reserves and are characterized as fields with fewer wellbores than the salt dome fields but numerous opportunities for new fault blocks containing unproved reserves that have been identified with new 3-D seismic data. As of December 31, 2008, approximately 50% of our proved undeveloped reserves (PUDs) requiring new wellbores are contained in these fields.
The remaining 14 fields contain approximately 17% of our total reserves and are characterized by occasional new drilling wells and workovers, but typically do not have the upside opportunities demonstrated in the other fields.
Natural Gas and Oil Reserves.
Due to the inherent uncertainties and the limited nature of reservoir data, proved reserves are subject to change as additional information becomes available. The estimates of reserves, future cash flows and present value are based on various assumptions, including those prescribed by the Securities and Exchange Commission (“SEC”), and are inherently imprecise. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates. Also, the use of a 10% discount factor for reporting purposes may not necessarily represent the most appropriate discount factor, given actual interest rates and risks to which our business or the oil and natural gas industry in general are subject.
These calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with SEC financial accounting and reporting standards. The estimated present value of proved reserves does not include indirect expenses such as general and administrative expenses, debt service, future income tax expense or depletion, depreciation, and amortization.
In accordance with applicable financial accounting and reporting standards of the SEC, the estimates of our proved reserves and the present value of proved reserves set forth herein are made using oil and natural gas sales prices estimated to be in effect as of the date of such reserve estimates and are held constant throughout the life of the properties. Estimated quantities of proved reserves and their present value are affected by changes in oil and natural gas prices. The average prices utilized for the purpose of estimating our proved reserves and the present value of proved reserves as of December 31, 2008 were $40.41 per barrel of oil and $6.07 per Mcf of natural gas.
The following table sets forth our estimated net proved oil and natural gas reserves and the PV-10 value of such reserves as of December 31, 2008. The reserve data and the present value as of December 31, 2008 were prepared by DeGolyer and MacNaughton, independent petroleum engineers. For further information concerning our independent engineer’s estimates of our proved reserves as of December 31, 2008, see the reserve report filed as Exhibit 99.1 to this Annual Report on Form 10-K. The PV-10 value is not intended to represent the current market value of the estimated oil and natural gas reserves owned by us. For further information concerning the present value of future net revenues from these proved reserves, see Note 13 of Notes to Consolidated Financial Statements.
| | | | | | | | | | |
| | | Oil | | Natural
Gas | | Undiscounted
Future Net
Revenue | | Present
Value of
Proved
Reserves
Discounted at
10% (1) |
| | | (Mbbl) | | (Mmcf) | | ($ thousands) | | ($ thousands) |
Developed Producing | | 3,028.5 | | 26,255.5 | | $ | 134,105.1 | | $ | 106,861.1 |
Developed Nonproducing | | 3,017.5 | | 25,991.5 | | | 173,982.6 | | | 91,646.9 |
Proved Undeveloped | | 2,152.5 | | 31,559.8 | | | 158,669.1 | | | 94,671.9 |
| | | | | | | | | | |
Total Proved | | 8,198.5 | | 83,806.8 | | $ | 466,756.8 | | $ | 293,179.9 |
| | | | | | | | | | |
| (1) | Management believes that the presentation of PV-10 may be considered a non-GAAP financial measure as defined in Item 10(e) of Regulation S-K. Therefore we have included a reconciliation of the measure to the |
4
| | most directly comparable GAAP financial measure (standardized measure of discounted future net cash flows in the table immediately below). Management believes that the presentation of PV-10 value provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Because many factors that are unique to each individual company may impact the amount of future income taxes to be paid, the use of the pre-tax measure provides greater comparability when evaluating companies. It is relevant and useful to investors for evaluating the relative monetary significance of our natural gas and oil properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. Management also uses this pre-tax measure when assessing the potential return on investment related to its oil and gas properties and in evaluating acquisition candidates. The PV-10 value is not a measure of financial or operating performance under GAAP, nor is it intended to represent the current market value of the estimated oil and natural gas reserves owned by us. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP. |
The table below provides a reconciliation of PV-10 to the standardized measure of discounted future net cash flows:
| | | | |
| | | As of
December 31,
2008 | |
| | | (dollars in
thousands) | |
PV-10 | | $ | 293,180 | |
Future income taxes, discounted at 10% | | | (9,544 | ) |
| | | | |
Standardized income of discounted future net cash flows | | $ | 283,636 | |
| | | | |
Oil and Natural Gas Volumes, Prices and Operating Expense
The following tables set forth certain information regarding the production volumes, revenue, average prices received and average production costs associated with our sale of oil and natural gas from continuing operations for the three years ended December 31, 2008, 2007 and 2006.
| | | | | | | | | |
| | | Year Ended December 31, |
| | | 2008 | | 2007 | | 2006 |
Net Production: | | | | | | | | | |
Oil (Bbl) | | | 884,213 | | | 568,069 | | | 24,670 |
Natural Gas (Mcf) | | | 6,060,093 | | | 3,731,351 | | | 203,750 |
| | | | | | | | | |
Natural Gas Equivalent (Mcfe) | | | 11,365,371 | | | 7,139,765 | | | 351,770 |
| | | |
Oil and Natural Gas Sales (dollars in thousands): | | | | | | | | | |
Oil | | $ | 88,306 | | $ | 44,892 | | $ | 1,487 |
Natural Gas | | | 58,294 | | | 26,308 | | | 1,645 |
| | | | | | | | | |
Total | | $ | 146,600 | | $ | 71,200 | | $ | 3,132 |
| | | |
Average Sales Price: | | | | | | | | | |
Oil ($ per Bbl) | | $ | 99.87 | | $ | 79.04 | | $ | 60.26 |
Natural Gas ($ per Mcf) | | | 9.62 | | | 7.05 | | | 8.07 |
| | | | | | | | | |
Natural Gas Equivalent ($ per Mcfe) | | $ | 12.90 | | $ | 9.97 | | $ | 8.90 |
| | | |
Oil and Natural Gas Costs (dollars in thousands): | | | | | | | | | |
Lease operating expenses | | $ | 24,830 | | $ | 15,243 | | $ | 661 |
Production taxes | | | 10,710 | | | 6,061 | | | 77 |
| | | |
Average production cost per Mcfe | | $ | 3.13 | | $ | 2.98 | | $ | 2.10 |
5
Exploration, Development and Acquisition Capital Expenditures
The following table sets forth certain information regarding the gross costs incurred in the purchase of proved and unproved properties and in development and exploration activities.
| | | | | | | | | | | |
| | | Year Ended December 31, | |
| | | 2008 | | 2007 | | | 2006 | |
| | | (in thousands) | |
Property acquisition costs | | $ | — | | $ | 391,438 | | | $ | 36,528 | |
Unproved prospects | | | 1,571 | | | 455 | | | | 391 | |
Exploration costs | | | 115 | | | 383 | | | | 2,024 | |
Development costs | | | 51,064 | | | 148,161 | | | | 363 | |
ARO costs | | | 1,209 | | | — | | | | — | |
| | | | | | | | | | | |
Total consolidated operations | | | 53,959 | | | 540,437 | | | | 39,306 | |
Less: Barnett Shale costs | | | — | | | (47,246 | ) | | | (32,802 | ) |
| | | | | | | | | | | |
Total consolidated operations excluding Barnett Shale | | $ | 53,959 | | $ | 493,191 | | | $ | 6,504 | |
| | | | | | | | | | | |
Asset Retirement Obligation (non-cash) | | $ | 7,403 | | $ | 2,737 | | | $ | 274 | |
| | | | | | | | | | | |
Drilling Activity
The following table sets forth our drilling activity during the twelve month periods ended December 31, 2008, 2007 and 2006 (excluding wells in progress at the end of the period). In the table, “gross” refers to the total number of wells in which we have a working interest and “net” refers to gross wells multiplied by our working interest therein.
| | | | | | | | | | | | |
| | | Year Ended December 31, |
| | | 2008 | | 2007 | | 2006 |
| | | Gross | | Net | | Gross | | Net | | Gross | | Net |
Development wells | | | | | | | | | | | | |
Productive | | 10.0 | | 7.6 | | 31.0 | | 29.1 | | 32.0 | | 11.7 |
Non-productive | | — | | — | | 3.0 | | 3.0 | | 1.0 | | 0.9 |
| | | | | | |
Exploratory wells | | | | | | | | | | | | |
Productive | | 1.0 | | 0.3 | | — | | — | | 2.0 | | 0.5 |
Non-productive | | — | | — | | — | | — | | 1.0 | | 1.0 |
Productive Wells
The following table sets forth the number of productive oil and natural gas wells in which we owned an interest as of December 31, 2008. Productive wells are wells that are capable of producing natural gas or oil.
| | | | | | | | | | | | |
| | | Company Operated | | Non-operated | | Total |
| | | Gross | | Net | | Gross | | Net | | Gross | | Net |
Oil | | 94 | | 59.9 | | 5 | | 1.1 | | 99 | | 61.0 |
Natural Gas | | 39 | | 21.8 | | 110 | | 0.9 | | 149 | | 22.7 |
| | | | | | | | | | | | |
Total | | 133 | | 81.7 | | 115 | | 2.0 | | 248 | | 83.7 |
| | | | | | | | | | | | |
6
Acreage Data
The following table summarizes our gross and net developed and undeveloped oil and natural gas acreage under lease as of December 31, 2008.
| | | | | | | | |
| | | Developed acres | | Undeveloped acres |
| | | Gross | | Net | | Gross | | Net |
Gulf Coast Properties (1) | | 87,762.3 | | 43,442.6 | | 2,541.0 | | 2,541.0 |
Other (2) | | — | | — | | 14,250.0 | | 4,275.0 |
| | | | | | | | |
Total | | 87,762.3 | | 43,442.6 | | 16,791.0 | | 6,816.0 |
| | | | | | | | |
| (1) | Undeveloped acreage includes State Lease #19246 at Bayou Couba and rental tracts at Broussard South. |
| (2) | Other includes Delaware Deep acreage in Sweetwater County, Wyoming. |
As is customary in the oil and natural gas industry, we can generally retain our interest in undeveloped acreage by drilling activity that establishes commercial production sufficient to maintain the leases or by paying delay rentals during the remaining primary term of leases. The oil and natural gas leases in which we have an interest are for varying primary terms, and if production under a lease continues from our developed lease acreage beyond the primary term, we are entitled to hold the lease for as long as oil or natural gas is produced.
Our oil and natural gas properties consist primarily of oil and natural gas wells and our interests in leasehold acreage, both developed and undeveloped.
Major Customers
The Company sold oil and natural gas production representing more than 10% of its oil and natural gas revenues as follows:
| | | |
2008: | | | |
Texon LP | | 50.42 | % |
Upstream Energy Services | | 17.42 | % |
| |
2007: | | | |
Texon LP | | 52.08 | % |
| |
2006: | | | |
Targa North Texas LP (Dynegy) | | 19.16 | % |
Crosstex Gulf Coast Marketing Ltd. | | 18.07 | % |
North Central Oil Corp. | | 15.10 | % |
Jerry Hess Operating Co. | | 12.39 | % |
Because alternate purchasers of natural gas and oil are readily available, we believe that the loss of any of our purchasers would not have a material adverse effect on our financial results.
Competition
We encounter competition from other natural gas and oil companies in all areas of our operations, including the acquisition of exploratory prospects and proven properties. Many of our competitors are large, well-established companies that have been engaged in the natural gas and oil business for much longer than we have and possess substantially larger operating staffs and greater capital resources than we do. Our ability to explore for oil and natural gas reserves and to acquire additional properties in the future will be dependent upon our ability to conduct our operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. We believe that our technological expertise, our exploration, land, drilling and production capabilities and the experience of our management generally enable us to compete effectively.
7
Marketing
Our production is marketed to third parties consistent with industry practices. Typically, oil is sold at the wellhead at field-posted prices plus a bonus and natural gas is sold under contract at a negotiated price based upon factors normally considered in the industry, such as distance from the well to the pipeline, well pressure, estimated reserves, quality of natural gas and prevailing supply and demand conditions.
Our marketing objective is to receive the highest possible wellhead price for our product. We are aided by the presence of multiple outlets near our production in Texas and Louisiana onshore Gulf Coast area. We take an active role in determining the available pipeline alternatives for each property based on historical pricing, capacity, pressure, market relationships, seasonal variances and long-term viability.
Regulation of the Oil and Natural Gas Industry
Regulation of Transportation and Sale of Oil
Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.
Our sales of crude oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. The Federal Energy Regulatory Commission, or the FERC, regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors.
Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.
Regulation of Transportation and Sale of Natural Gas
Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and regulations issued under those Acts by the FERC. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future.
FERC regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Since 1985, the FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers. The interstate pipelines’ traditional role as wholesalers of natural gas has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. Although the FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.
8
We cannot accurately predict whether the FERC’s actions will achieve the goal of increasing competition in markets in which our natural gas is sold. Additional proposals and proceedings that might affect the natural gas industry are pending before the FERC and the courts. The natural gas industry historically has been very heavily regulated. Therefore, we cannot provide any assurance that the less stringent regulatory approach recently established by the FERC will continue. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers.
Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states on shore and in state waters. Although its policy is still in flux, FERC has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of getting natural gas to point of sale locations.
Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.
Regulation of Production
The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. All of the states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.
The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.
Environmental Matters and Other Regulation
General
Our operations are subject to stringent and complex federal, state and local laws and regulations governing environmental protection as well as the discharge of materials into the environment. These laws and regulations may, among other things:
| | • | | require the acquisition of various permits before drilling commences; |
| | • | | restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and natural gas drilling and production activities; |
| | • | | limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and |
9
| | • | | require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells. |
These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and gas industry could have a significant impact on our operating costs.
The following is a summary of some of the existing laws, rules and regulations to which our business operations are subject.
Waste Handling
The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the federal Environmental Protection Agency, or EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of crude oil or natural gas are currently regulated under RCRA or state non-hazardous waste provisions. Releases or spills of these regulated materials may result in remediation liabilities under these statutes. It is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position.
Comprehensive Environmental Response, Compensation, and Liability Act
The Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, also known as the Superfund Law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current or former owner or operator of the site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.
In the course of our operations, we generate wastes that may fall within CERCLA’s definition of hazardous substances. Further, we currently own, lease or operate properties that have been used for oil and natural gas exploration and production for many years. Hazardous substances or petroleum may have been released on, at or under the properties owned, leased or operated by us, or on, at or under other locations, including off-site locations, where such hazardous substances or other wastes have been taken for disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose handling, treatment and disposal of hazardous substances, petroleum, or other materials or wastes were not under our control. These properties and the substances or materials disposed or released on, at or under them may be subject to CERCLA, RCRA or analogous or other state laws. Under such laws, we could be required to remove previously disposed substances and wastes or released petroleum, remediate contaminated property or perform remedial plugging or pit closure operations to prevent future contamination.
10
Water Discharges
The Federal Water Pollution Control Act, or the Clean Water Act, and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances into waters of the United States or state waters. Under these laws, the discharge of pollutants into regulated waters is prohibited except in accordance with the terms of a permit issued by EPA or an analogous state agency. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.
The Oil Pollution Act of 1990, or OPA, which amends and augments the Clean Water Act, establishes strict liability for owners and operators of facilities that are the site of a release of oil into waters of the United States. In addition, OPA and regulations promulgated pursuant thereto impose a variety of regulations on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills. OPA also requires certain oil and natural gas operators to develop, implement and maintain facility response plans, conduct annual spill training for certain employees and provide varying degrees of financial assurance.
We are not aware of any environmental claims existing as of December 31, 2008, which have not been provided for, covered by insurance, or would otherwise have a material impact on our financial position or results of operations. There can be no assurance, however, that current regulatory requirements will not change, or past non-compliance with environmental laws will not be discovered on our properties.
Air Emissions
The Federal Clean Air Act and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, EPA has developed and continues to develop stringent regulations governing emissions of toxic air pollutants at specified sources. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the Federal Clean Air Act and associated state laws and regulations. Oil and gas operations may in certain circumstances and locations be subject to permits and restrictions under these statutes for emissions of air pollutants, including volatile organic compounds, nitrous oxides, and hydrogen sulfide.
National Environmental Policy Act
Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions that have the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay the development of oil and natural gas projects.
Endangered Species, Wetlands and Damages to Natural Resources
Various state and federal statutes prohibit certain actions that adversely affect endangered or threatened species and their habitat, migratory birds, wetlands, and natural resources. These statutes include the Endangered Species Act, the Migratory Bird Treaty Act, the Clean Water Act and CERCLA. Where takings of or harm to species or damages to wetlands, habitat, or natural resources occur or may occur, government entities or at times private parties may act to prevent oil and gas exploration or production or seek damages to species, habitat, or natural resources resulting from filling or construction or releases of oil, wastes, hazardous substances or other regulated materials.
11
OSHA and Other Laws and Regulations
We are subject to the requirements of the federal Occupational Safety and Health Act (OSHA) and comparable state statutes. The OSHA hazard communication standard, the Emergency Planning and Community Right to Know Act and similar state statutes require that we organize and/or disclose information about hazardous materials stored, used or produced in our operations.
Recent studies have indicated that emissions of certain gases may be contributing to warming of the Earth’s atmosphere. In response to these studies, many nations have agreed to limit emissions of “greenhouse gases” pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol.” Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of oil and natural gas, and refined petroleum products, are “greenhouse gases” regulated by the Kyoto Protocol. Although the United States is not participating in the Kyoto Protocol, several states have adopted legislation and regulations to reduce emissions of greenhouse gases. Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect our operations and demand for our products. Additionally, the U.S. Supreme Court has ruled, in Massachusetts, et al. v. EPA, that the U.S. Environmental Protection Agency abused its discretion under the Clean Air Act by refusing to regulate carbon dioxide emissions from mobile sources. This Supreme Court decision could result in federal regulation of carbon dioxide emissions and other greenhouse gases, and may affect the outcome of other climate change lawsuits pending in U.S. federal courts in a manner unfavorable to our industry. Currently, our operations are not adversely impacted by existing state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.
Private Lawsuits
In addition to claims arising under state and federal statutes, where a release or spill of hazardous substances, oil and gas or oil and gas wastes have occurred, private parties or landowners may bring lawsuits against oil and gas companies under state law. The plaintiffs may seek property damages, personal injury damages, remediation costs or injunctions to require remediation or restoration of contaminated property, soil, groundwater or surface water. In some cases, oil and gas operations are located near populated areas and emissions or accidental releases could affect the surrounding properties and population.
12
You should carefully consider each of the risks described below, together with all of the other information contained in this report, before deciding to invest in our securities. If any of the following risks develop into actual events, our business, financial condition or results of operations could be materially adversely affected and you may lose all or part of your investment.
We have had operating losses and limited revenues to date.
We have operated at a loss each year since inception. Net losses applicable to common shareholders for the fiscal years ended December 31, 2006, 2007 and 2008 were $45.6 million, $43.6 million and $241.7 million, respectively. Our losses in the fiscal years ended December 31, 2006 and 2008 were largely attributable to a proved property impairment expense as a result of a drop in commodity prices from the fiscal year ended 2005 to the fiscal year ended 2006 and from 2007 to 2008. Our revenues for the fiscal years ended December 31, 2006, 2007 and 2008 were $3.4 million, $71.2 million and $146.6 million, respectively. We may not be able to generate significant revenues in the future. In addition, we expect to incur substantial operating expenses in connection with our natural gas and oil exploration and development activities. As a result, we may continue to experience negative cash flow for at least the foreseeable future and cannot predict when, or even if, we might become profitable.
Our leverage and debt service obligations may adversely affect our cash flow.
We have a substantial amount of debt. As of December 31, 2008, we had total debt of $289.6 million, primarily consisting of our 10-1/2% senior secured notes due 2012 (the “Senior Notes”). There were borrowings of $0 under our $40 million revolving credit facility (“May 2007 Credit Facility”) at year-end, however, $8.8 million of letters of credit were issued against the commitment. Our substantial level of indebtedness could have important consequences to you, including the following:
| | • | | it may make it difficult for us to satisfy our obligations under our indebtedness and contractual and commercial commitments; |
| | • | | we must use a substantial portion of our cash flow from operations to pay interest on our indebtedness, which will reduce the funds available to us for other purposes; |
| | • | | our ability to obtain additional debt financing in the future for working capital, capital expenditures, acquisitions or general corporate purposes may be limited; |
| | • | | our flexibility in reacting to changes in the industry may be limited and we could be more vulnerable to adverse changes in our business or economic conditions in general; and |
| | • | | we may be at a competitive disadvantage to those of our competitors who operate on a less leveraged basis. |
Furthermore, all of our borrowings under our May 2007 Credit Facility will bear interest at variable rates. If these rates were to increase significantly, our ability to borrow additional funds may be reduced, our interest expense would significantly increase and the risks related to our substantial indebtedness would intensify.
Any failure to meet our debt obligations could harm our business, financial condition, results of operations or cash flows.
If our cash flow and capital resources are insufficient to fund our debt obligations, we may be forced to sell assets, seek additional equity or debt capital or restructure our debt. In addition, any failure to make scheduled payments of interest and principal on our outstanding indebtedness would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness on acceptable terms. Our cash flow and capital resources may be insufficient for payment of interest on and principal of our debt in the future and any such alternative measures may be unsuccessful or may not permit us to meet scheduled debt service obligations, which could cause us to default on our obligations and impair our liquidity.
13
The indenture governing the Senior Notes, the certificate of designations relating to our 10% Senior Redeemable Convertible Preferred Stock and our May 2007 Credit Facility impose significant operating and financial restrictions on us that may prevent us from pursuing certain business opportunities and restrict our ability to operate our business.
The indenture governing the Senior Notes, the certificate of designations relating to the our 10% senior redeemable convertible preferred stock and our May 2007 Credit Facility each contain covenants that restrict our ability and the ability of certain of our subsidiaries to take various actions, such as:
| | • | | incurring or generating additional indebtedness or issuing certain preferred stock; |
| | • | | paying dividends on our capital stock or redeeming, repurchasing or retiring our capital stock or subordinated indebtedness or making other restricted payments; |
| | • | | entering into certain transactions with affiliates; |
| | • | | creating or incurring liens on our assets; |
| | • | | transferring or selling assets; |
| | • | | incurring dividend or other payment restrictions affecting certain of our existing and future subsidiaries; and |
| | • | | consummating a merger, consolidation or sale of all or substantially all of our assets. |
In addition, our May 2007 Credit Facility contains customary representations and warranties by the Company as well as typical restrictive covenants whereby Dune has agreed, among other things, to limitations to incurrence of additional indebtedness, declaration of dividends, issuance of capital stock, sale of assets and corporate reorganizations.
The restrictions contained in the indenture governing the Senior Notes, the certificate of designations relating to the preferred stock and our May 2007 Credit Facility could:
| | • | | limit our ability to plan for or react to market conditions or meet capital needs or otherwise restrict our activities or business plans; and |
| | • | | adversely affect our ability to finance our operations, strategic acquisitions, investments or alliances or other capital needs or to engage in other business activities that would be in our interest. |
A breach of any of the restrictive covenants could result in a default under our May 2007 Credit Facility.
If a default occurs, the lenders under our May 2007 Credit Facility may elect to:
| | • | | declare all borrowings outstanding thereunder, together with accrued interest and other fees, to be immediately due and payable; |
| | • | | or prevent us from making payments on the Senior Notes; |
either of which (after the expiration of any applicable grace periods) would result in an event of default under the indenture governing the Senior Notes and could result in a cross default under our other debt instruments. The lenders would also have the right in these circumstances to terminate any commitments they have to provide us with further borrowings. If the borrowings under our May 2007 Credit Facility and the Senior Notes were to be accelerated, we cannot assure you that we would be able to repay in full the Senior Notes.
We may not be able to generate sufficient cash flow to meet our debt service and other obligations due to events beyond our control.
Our ability to generate cash flows from operations and to make scheduled payments on our indebtedness, including the Senior Notes, will depend on our future financial performance. Our future performance will be affected by a range of economic, competitive, legislative, operating and other business factors, many of which we
14
cannot control, such as general economic and financial conditions in our industry or the economy at large. A significant reduction in operating cash flows resulting from changes in economic conditions, increased competition, or other events could increase the need for additional or alternative sources of liquidity and could have a material adverse effect on our business, financial condition, results of operations and prospects and our ability to service our debt, including the Senior Notes, and other obligations. If we are unable to service our indebtedness, we will be forced to adopt an alternative strategy that may include actions such as reducing or delaying acquisitions and capital expenditures, selling assets, restructuring or refinancing our indebtedness or seeking equity capital. We cannot assure you that any of these alternative strategies could be effected on satisfactory terms, if at all, or that they would yield sufficient funds to make required payments on the Senior Notes and our other indebtedness.
We have substantial capital requirements that, if not met, may hinder operations.
We have and expect to continue to have substantial capital needs as a result of our active exploration, development, and acquisition programs. We expect that additional external financing will be required in the future to fund our growth. We may not be able to obtain additional financing, and financing under existing or new credit facilities may not be available in the future. Without additional capital resources, we may be forced to limit or defer our planned natural gas and oil exploration and development program and this will adversely affect the recoverability and ultimate value of our natural gas and oil properties, in turn negatively affecting our business, financial condition, and results of operations.
Recent economic conditions in the credit market may adversely affect our financial condition.
The disruption experienced in U.S. and global credit markets since the latter half of 2008 has resulted in projected decreases in demand for oil and natural gas, resulting in a sharp drop in energy prices, and has affected the availability and cost of capital. In addition, capital and credit markets have experienced unprecedented volatility and disruption and continue to be unpredictable. Given the current levels of market volatility and disruption, the availability of funds from those markets has diminished substantially. Prolonged negative changes in domestic and global economic conditions or disruptions of either or both of the financial and credit markets may have a material adverse effect on our results from operations, financial condition and liquidity. At this time, it is unclear whether and to what extent the actions taken by the U.S. government will mitigate the effects of the financial market turmoil. The impact of the current difficult conditions on our ability to obtain, and the cost and terms of, any financing in the future is equally unclear. Any inability to obtain adequate financing under our existing credit facility or to fund on acceptable terms could deter or prevent us from meeting our future capital needs to finance our development program, adversely affect the satisfaction or replacement of our debt obligations and result in a deterioration of our financial condition.
Natural gas and oil prices are highly volatile, and lower prices will negatively affect our financial results.
Our revenue, profitability, cash flow, oil and natural gas reserves value, future growth, and ability to borrow funds or obtain additional capital, as well as the carrying value of our properties, are substantially dependent on prevailing prices of natural gas and oil. Historically, the markets for natural gas and oil have been volatile, and those markets are likely to continue to be volatile in the future. It is impossible to predict future natural gas and oil price movements with certainty. Prices for natural gas and oil are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for natural gas and oil, market uncertainty, and a variety of additional factors beyond our control. These factors include:
| | • | | the level of consumer product demand; |
| | • | | the domestic and foreign supply of oil and natural gas; |
| | • | | overall economic conditions; |
| | • | | domestic and foreign governmental regulations and taxes; |
15
| | • | | the price and availability of alternative fuels; |
| | • | | political conditions in or affecting oil and natural gas producing regions; |
| | • | | the level and price of foreign imports of oil and liquefied natural gas; and |
| | • | | the ability of the members of the Organization of Petroleum Exporting Countries and other state controlled oil companies to agree upon and maintain oil price and production controls. |
Declines in natural gas and oil prices may materially adversely affect our financial condition, liquidity, and ability to finance planned capital expenditures and results of operations and may reduce the amount of oil and natural gas that we can produce economically.
Drilling for natural gas and oil is a speculative activity and involves numerous risks and substantial and uncertain costs that could adversely affect us.
Our success will be largely dependent upon the success of our drilling program. Our prospects are in various stages of evaluation, ranging from prospects that are ready to drill to prospects that will require substantial additional seismic data processing and interpretation and other types of technical evaluation. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects. Drilling for natural gas and oil involves numerous risks, including the risk that no commercially productive natural gas or oil reservoirs will be discovered. The cost of drilling, completing, and operating wells is substantial and uncertain, and drilling operations may be curtailed, delayed, or canceled as a result of a variety of factors beyond our control, including:
| | • | | unexpected or adverse drilling conditions; |
| | • | | elevated pressure or irregularities in geologic formations; |
| | • | | equipment failures or accidents; |
| | • | | adverse weather conditions; |
| | • | | compliance with governmental requirements; and |
| | • | | shortages or delays in the availability of drilling rigs, crews, and equipment. |
Even if drilled, our completed wells may not produce reserves of natural gas or oil that are economically viable or that meet our earlier estimates of economically recoverable reserves. A productive well may become uneconomic if water or other deleterious substances are encountered, which impair or prevent the production of oil and/or natural gas from the well. Our overall drilling success rate or our drilling success rate for activity within a particular project area may decline. Unsuccessful drilling activities could result in a significant decline in our production and revenues and materially harm our operations and financial condition by reducing our available cash and resources. Because of the risks and uncertainties of our business, our future performance in exploration and drilling may not be comparable to our historical performance.
We depend on successful exploration, development and acquisitions to maintain reserves and revenue in the future.
In general, the volume of production from natural gas and oil properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Except to the extent that we conduct successful
16
exploration and development activities or acquire properties containing proved reserves, or both, our proved reserves will decline as reserves are produced. Our future natural gas and oil production is, therefore, highly dependent on our level of success in finding or acquiring additional reserves. Additionally, the business of exploring for, developing, or acquiring reserves is capital intensive. Recovery of our reserves, particularly undeveloped reserves, will require significant additional capital expenditures and successful drilling operations. To the extent cash flow from operations is reduced and external sources of capital become limited or unavailable, our ability to make the necessary capital investment to maintain or expand our asset base of natural gas and oil reserves would be impaired. In addition, we are dependent on finding partners for our exploratory activity. To the extent that others in the industry do not have the financial resources or choose not to participate in our exploration activities, we will be adversely affected.
Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions could materially affect the quantities and present values of our reserves.
The process of estimating natural gas and oil reserves is complex. It requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves shown in our petroleum engineering reserve reports. In order to prepare these estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of this data can vary. The process also requires economic assumptions relating to matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Therefore, estimates of oil and natural gas reserves are inherently imprecise.
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from our estimates. A significant variance could materially affect the estimated quantities and pre-tax present value of the reserves shown in our petroleum engineering reserve reports. In addition, the 10% discount factor we use to calculate the net present value of future net cash flows for reporting purposes may not necessarily be the most appropriate discount factor. Further, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.
A substantial percentage of our proved reserves consist of undeveloped reserves.
As of the end of our 2008 fiscal year, approximately 33.4% of our proved reserves were classified as undeveloped reserves. These reserves may not ultimately be developed or produced. As a result, we may not find commercially viable quantities of oil and natural gas, which in turn may have a material adverse effect on our results of operations.
Our future acquisitions may yield revenues or production that varies significantly from our projections.
In acquiring producing properties we assess the recoverable reserves, future natural gas and oil prices, operating costs, potential liabilities and other factors relating to the properties. Our assessments are necessarily inexact and their accuracy is inherently uncertain. Our review of a subject property in connection with its acquisition assessment will not reveal all existing or potential problems or permit us to become sufficiently familiar with the property to assess fully its deficiencies and capabilities.
We may not inspect every well, and we may not be able to observe structural and environmental problems even when we do inspect a well. If problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of those problems. Any acquisition of property interests may
17
not be economically successful, and unsuccessful acquisitions may have a material adverse effect on our financial condition and future results of operations. We cannot assure you that:
| | • | | we will be able to identify desirable natural gas and oil prospects and acquire leasehold or other ownership interests in such prospects at a desirable price; |
| | • | | any completed, currently planned, or future acquisitions of ownership interests in natural gas and oil prospects will include prospects that contain proved natural gas or oil reserves; |
| | • | | we will have the ability to develop prospects which contain proven natural gas or oil reserves to the point of production; |
| | • | | we will have the financial ability to consummate additional acquisitions of ownership interests in natural gas and oil prospects or to develop the prospects which we acquire to the point of production; or |
| | • | | that we will be able to consummate such additional acquisitions on terms favorable to us. |
Seismic studies do not guarantee that hydrocarbons are present or if present will produce in economic quantities.
We rely on seismic studies to assist us with assessing prospective drilling opportunities on our properties, as well as on properties that we may acquire. Such seismic studies are merely an interpretive tool and do not necessarily guarantee that hydrocarbons are present or if present will produce in economic quantities.
We may experience difficulty in achieving and managing future growth.
Future growth may place strains on our resources and cause us to rely more on project partners and independent contractors, possibly negatively affecting our financial condition and results of operations. Our ability to grow will depend on a number of factors, including:
| | • | | our ability to obtain leases or options on properties for which we have 3-D seismic data; |
| | • | | our ability to acquire additional 3-D seismic data; |
| | • | | our ability to identify and acquire new exploratory prospects; |
| | • | | our ability to develop existing prospects; |
| | • | | our ability to continue to retain and attract skilled personnel; |
| | • | | our ability to maintain or enter into new relationships with project partners and independent contractors; |
| | • | | the results of our drilling program; |
| | • | | hydrocarbon prices; and |
We may not be successful in upgrading our technical, operations, and administrative resources or in increasing our ability to internally provide certain of the services currently provided by outside sources, and we may not be able to maintain or enter into new relationships with project partners and independent contractors. Our inability to achieve or manage growth may adversely affect our financial condition and results of operations.
Our business may suffer if we lose key personnel.
We depend to a large extent on the services of certain key management personnel, including James A. Watt, our President and Chief Executive Officer, Alan Gaines, the Chairman of our board of directors, Frank T. Smith, Jr., our Senior Vice President and Chief Financial Officer and our other executive officers and key employees.
18
These individuals have extensive experience and expertise in evaluating and analyzing producing oil and natural gas properties and drilling prospects, maximizing production from oil and natural gas properties, marketing oil and natural gas production and developing and executing financing and hedging strategies. The loss of any of these individuals could have a material adverse effect on our operations. We do not maintain key-man life insurance with respect to any of our employees. Our success will be dependent on our ability to continue to employ and retain skilled technical personnel.
We face strong competition from other natural gas and oil companies.
We encounter competition from other natural gas and oil companies in all areas of our operations, including the acquisition of exploratory prospects and proved properties. Our competitors include major integrated natural gas and oil companies and numerous independent natural gas and oil companies, individuals, and drilling and income programs. Many of our competitors are large, well-established companies that have been engaged in the natural gas and oil business much longer than we have and possess substantially larger operating staffs and greater capital resources than we do. These companies may be able to pay more for exploratory projects and productive natural gas and oil properties and may be able to define, evaluate, bid for, and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may be able to expend greater resources on the existing and changing technologies that we believe are and will be increasingly important to attaining success in the industry. We may not be able to conduct our operations, evaluate, and select suitable properties and consummate transactions successfully in this highly competitive environment.
We may not be able to keep pace with technological developments in our industry.
The natural gas and oil industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or competitive pressures may force us to implement those new technologies at substantial costs. In addition, other natural gas and oil companies may have greater financial, technical, and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition, and results of operations could be materially adversely affected.
Governmental regulation and liability for environmental matters may adversely affect our business, financial condition and results of operations.
Natural gas and oil operations are subject to various federal, state, and local government regulations that may change from time to time. Matters subject to regulation include discharge permits for drilling operations, plug and abandonment bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties, and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of natural gas and oil wells below actual production capacity in order to conserve supplies of natural gas and oil. Other federal, state, and local laws and regulations relating primarily to the protection of human health and the environment apply to the development, production, handling, storage, transportation, and disposal of natural gas and oil, by-products thereof, and other substances and materials produced or used in connection with natural gas and oil operations. In addition, we may be liable for environmental damages caused by previous owners of property we purchase or lease. Some environmental laws provide for joint and several strict liability for remediation of releases of hazardous substances, rendering a person liable for environmental damage without regard to negligence or fault on the part of such person. In addition, we may be subject to claims alleging personal injury or property damage as a result of alleged exposure to hazardous substances such as oil and natural gas related products. As a result, we may incur substantial liabilities to third parities or governmental entities and may be required to incur substantial remediation costs.
19
We also are subject to changing and extensive tax laws, the effects of which cannot be predicted. Compliance with existing, new, or modified laws and regulations could have a material adverse effect on our business, financial condition, and results of operations.
We may not have enough insurance to cover all of the risks we face and operators of prospects in which we participate may not maintain or may fail to obtain adequate insurance.
In accordance with customary industry practices, we maintain insurance coverage against some, but not all, potential losses in order to protect against the risks we face. We do not carry business interruption insurance. We may elect not to carry insurance if our management believes that the cost of available insurance is excessive relative to the risks presented. In addition, we cannot insure fully against pollution and environmental risks. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial condition and results of operations. The impact of recent hurricanes have 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 or own an equity interest in a limited partnership which in turn owns a non- operating interest, the operator for the prospect maintains insurance of various types to cover our operations with policy limits and retention liability customary in the industry. We believe the coverage and types of insurance are adequate. The occurrence of a significant adverse event that is not fully covered by insurance could result in the loss of our total investment in a particular prospect which could have a material adverse effect on our financial condition and results of operations.
We cannot control the activities on properties we do not operate and are unable to ensure their proper operation and profitability.
We do not operate all of the properties in which we have an interest. As a result, we have limited ability to exercise influence over, and control the risks associated with, operations of these properties. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements, or an operator’s failure to act in ways that are in our best interests could reduce our production and revenues. The success and timing of our drilling and development activities on properties operated by others depends upon a number of factors outside of our control, including the operator’s:
| | • | | timing and amount of capital expenditures; |
| | • | | expertise and financial resources; |
| | • | | inclusion of other participants in drilling wells; and |
The financial condition of our operators could negatively impact our ability to collect revenues from operations.
We do not operate all of the properties in which we have working interests. In the event that an operator of our properties experiences financial difficulties, this may negatively impact our ability to receive payments for our share of net production that we are entitled to under our contractual arrangements with such operator. While we seek to minimize such risk by structuring our contractual arrangements to provide for production payments to be made directly to us by first purchasers of the hydrocarbons, there can be no assurances that we can do so in all situations covering our non-operated properties.
20
We hedge the price risks associated with our production. Our hedge transactions may result in our making cash payments or prevent us from benefiting to the fullest extent possible from increases in prices for natural gas and oil.
Because natural gas and oil prices are unstable, we have entered into price-risk-management transactions such as swaps, collars, futures, and options to reduce our exposure to price declines associated with a portion of our natural gas and oil production and thereby to achieve a more predictable cash flow. The use of these arrangements will limit our ability to benefit from increases in the prices of natural gas and oil. Our hedging arrangements may apply to only a portion of our production, thereby providing only partial protection against declines in natural gas and oil prices. These arrangements could expose us to the risk of financial loss in certain circumstances, including instances in which production is less than expected, our customers fail to purchase contracted quantities of natural gas and oil, or a sudden, unexpected event materially impacts natural gas or oil prices.
If oil and natural gas prices decrease, we may be required to take write-downs of the carrying values of our oil and natural gas properties.
Certain accounting rules may require us to write down the carrying value of our properties when oil and natural gas prices decrease or when we have substantial downward adjustments of our estimated proved reserves, increases in our estimates of development costs or deterioration in our exploration results. Once incurred, a write-down of our oil and natural gas properties is not reversible at a later date. Any write-down would constitute a non-cash charge to earnings and could have a material adverse effect on our results of operations for the periods in which such charges are taken. For example, for the years ended December 31, 2006 and 2008, we incurred proved property impairment expenses of $6.9 million and $125.7 million, respectively, which reduced the carrying value of the properties, due to a drop in commodity prices from year end 2005 to year end 2006 and from year end 2007 to year end 2008.
Our producing properties are located in regions which make us vulnerable to risks associated with operating in one major contiguous geographic area, including the risk of damage or business interruptions from hurricanes.
Our properties are located onshore and in state waters along the Texas and Louisiana Gulf Coast region of the United States. As a result of this geographic concentration, we are disproportionately affected by any delays or interruptions in production or transportation in these areas caused by governmental regulation, transportation capacity constraints, natural disasters, regional price fluctuations or other factors. This is particularly true of our inland water drilling and offshore operations, which are susceptible to hurricanes and other tropical weather disturbances. Such disturbances have in the past and will in the future have any or all of the following adverse effects on our business:
| | • | | interruptions to our operations as we suspend production in advance of an approaching storm; |
| | • | | damage to our facilities and equipment, including damage that disrupts or delays our production; |
| | • | | disruption to the transportation systems we rely upon to deliver our products to our customers; and |
| | • | | damage to or disruption of our customers’ facilities that prevents us from taking delivery of our products. |
Our identified drilling locations are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
Our management has specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These scheduled drilling locations represent a significant component of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including oil and natural gas prices, the availability of capital, costs, drilling results, regulatory
21
approvals and other factors. Because of these uncertainties, we do not know if the potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.
Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.
Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of our reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of transport vessels, gathering systems, pipelines and processing facilities owned and operated by third parties under interruptible or short-term transportation agreements. Under the interruptible transportation agreements, the transportation of our natural gas may be interrupted due to capacity constraints on the applicable system, for maintenance or repair of the system, or for other reasons as dictated by the particular agreements. Our failure to obtain such services on acceptable terms could materially harm our business. We may be required to shut in wells due to lack of a market or the inadequacy or unavailability of natural gas pipeline or gathering system capacity. If that were to occur, we would be unable to realize revenue from those wells unless and until we made arrangements for delivery of their production to market.
Terrorist attacks aimed at our energy operations could adversely affect our business.
The continued threat of terrorism and the impact of military and other government action has led and may lead to further increased volatility in prices for oil and natural gas and could affect these commodity markets or the financial markets used by us. In addition, the U.S. government has issued warnings that energy assets may be a future target of terrorist organizations. These developments have subjected our oil and natural gas operations to increased risks. Any future terrorist attack on our facilities, those of our customers, the infrastructure we depend on for transportation of our products, and, in some cases, those of other energy companies, could have a material adverse effect on our business.
Conversion of shares of our 10% Senior Redeemable Convertible Preferred Stock prior to June 1, 2010, will require us to make certain make-whole payments, which payments may consist of shares of our common stock, resulting in the dilution of the equity ownership of holders of our common stock.
In the event a holder of our 10% senior redeemable convertible preferred stock elects to convert such shares prior to June 1, 2010, then such holder shall be entitled to a make whole premium consisting of the present value of all dividends on the preferred stock as if paid in cash from the date of conversion through June 10, 2010, computed using a discount rate equal to the Reinvestment Yield. Should we elect to pay this amount in shares of our common stock, the equity ownership of holders of our common stock could be significantly diluted.
The market price of our common stock may be volatile.
The trading price of our common stock and the price at which we may sell common stock in the future are subject to large fluctuations in response to any of the following:
| | • | | limited trading volume in our common stock; |
| | • | | quarterly variations in operating results; |
| | • | | our involvement in litigation; |
| | • | | general financial market conditions; |
| | • | | the prices of natural gas and oil; |
22
| | • | | announcements by us and our competitors; |
| | • | | our ability to raise additional funds; |
| | • | | changes in government regulations; and |
Sales of substantial amounts of shares of our common stock could cause the price of our common stock to decrease.
We have registered for resale a substantial number of shares of our common stock issuable upon conversion of our 10% senior redeemable convertible preferred stock and certain other securities convertible into or exercisable for shares of our common stock. Our stock price may decrease due to the additional amount of shares available in the market.
We do not intend to pay dividends on our common stock and our ability to pay dividends on our common stock is restricted.
We have not historically paid a dividend on our common stock, cash or otherwise, and do not intend to in the foreseeable future. We are currently restricted from paying dividends on common stock by our the indenture governing our Senior Notes, the agreement relating to our existing credit facility and, in some circumstances, by the terms of our 10% senior redeemable convertible preferred stock. Any future dividends also may be restricted by our then-existing debt agreements.
Provisions of Delaware law and our charter and bylaws may delay or prevent transactions that would benefit stockholders.
Our certificate of incorporation and bylaws and the Delaware General Corporation Law contain provisions that may have the effect of delaying, deferring or preventing a change of control of the company. These provisions, among other things, provide for a classified Board of Directors with staggered terms, restrict the ability of stockholders to take action by written consent, authorize the Board of Directors to set the terms of preferred stock and restrict our ability to engage in transactions with stockholders with 15% or more of outstanding voting stock.
Because of these provisions, persons considering unsolicited tender offers or other unilateral takeover proposals may be more likely to negotiate with our board of directors rather than pursue non-negotiated takeover attempts. As a result, these provisions may make it more difficult for our stockholders to benefit from transactions that are opposed by an incumbent board of directors.
| Item 1B. | Unresolved Staff Comments. |
None.
| Item 3. | Legal Proceedings. |
From time to time, we are party to certain legal actions and claims arising in the ordinary course of business. While the outcome of these events cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on our financial position or results of operations.
| Item 4. | Submission of Matters to Vote of Security Holders. |
No matters were submitted to the vote or consent of the holders of the outstanding shares of our common stock during the quarter ended December 31, 2008.
23
PART II
| Item 5. | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. |
Market for Our Common Stock
Since May 9, 2005, our common stock has been traded on the NYSE Alternext US LLC (“The Exchange”) under the symbol “DNE”. The following table sets forth, for the periods indicated, the high and low sales prices of our common stock on The Exchange.
| | | | | | |
2008: | | High | | Low |
Quarter ended December 31, 2008 | | $ | 0.75 | | $ | 0.12 |
Quarter ended September 30, 2008 | | $ | 1.11 | | $ | 0.576 |
Quarter ended June 30, 2008 | | $ | 1.85 | | $ | 0.94 |
Quarter ended March 31, 2008 | | $ | 2.05 | | $ | 1.40 |
| | |
2007: | | High | | Low |
Quarter ended December 31, 2007 | | $ | 2.30 | | $ | 1.65 |
Quarter ended September 30, 2007 | | $ | 2.45 | | $ | 2.08 |
Quarter ended June 30, 2007 | | $ | 2.98 | | $ | 1.75 |
Quarter ended March 31, 2007 | | $ | 2.51 | | $ | 1.65 |
The last sales price of our common stock on The Exchange on December 31, 2008 was $0.18 per share. As of February 27, 2009, the closing sale price of a share of our common stock was $0.14. As of February 27, 2009, there were approximately 305 holders of record of our common stock.
On December 15, 2008, we received notice from The Exchange indicating that the Company was not in compliance with certain conditions of The Exchange’s continued listing standards under Section 1003 of the Company Guide. Specifically, The Exchange noted the Company’s failure to comply with (a) Section 1003(a)(i) of the Company Guide relating to stockholders’ equity of less than $2,000,000 and losses from continuing operations and net losses in two out of its three most recent fiscal years; (b) Section 1003(a)(ii) of the Company Guide relating to stockholders’ equity of less than $4,000,000 and losses from continuing operations and net losses in three out of its four most recent fiscal years; and (c) Section 1003(a)(iii) of the Company Guide relating to stockholders’ equity of less than $6,000,000 and losses from continuing operations and net losses in its five most recent fiscal years. We submitted a plan of compliance on January 13, 2009 detailing the steps anticipated in order to regain compliance with the listing standards which was accepted on February 17, 2009. Accordingly, subject to periodic review by The Exchange, we have been granted an extension until June 15, 2010 to regain compliance with the continued listing requirements.
We have not paid any cash dividends to date, and have no intention of paying any cash dividends on our common stock in the foreseeable future. The declaration and payment of dividends is subject to the discretion of our Board of Directors and to certain limitations imposed under Delaware corporation law. The timing, amount and form of dividends, if any, will depend on, among other things, our results of operations, financial condition, cash requirements and other factors deemed relevant by our Board of Directors. The agreements and instruments that we entered into in 2007 in connection with our note and preferred stock financings, as well as our credit facility, contain significant restrictions on our ability to pay dividends on our common stock.
There were no repurchases of securities during the fourth quarter of 2008.
As previously reported by us in our Current Report on Form 8-K filed with the Securities and Exchange Commission on August 4, 2008, during the third quarter of 2008, the Company awarded a total of 3,113,500 shares of Restricted Stock to employees and non-employee directors of the Company, pursuant to the Dune Energy, Inc. 2007 Stock Incentive Plan (the “Plan”). Under the terms of the awards, the Restricted Stock will vest ratably in three equal installments on each of August 1, 2009, 2010 and 2011.
24
Securities Authorized for Issuance Under Equity Compensation Plans
The following table provides information as of December 31, 2008 about our equity compensation plans and arrangements.
Equity Compensation Plan Information—December 31, 2008
| | | | | | | | | |
Plan category | | (a)
Number of securities
to be issued upon
exercise of
outstanding options,
warrants and rights | | | (b)
Weighted-average
exercise price of
outstanding options,
warrants and rights | | (c)
Number of securities remaining
available for future issuance under
equity compensation plans
(excluding securities reflected in
column (a)) | |
Equity compensation plans approved by security holders | | 600,000 | (1)(2) | | $ | 2.15 | | 4,636,732 | (3)(4) |
Equity compensation plans not approved by security holders | | 3,962,496 | | | $ | 2.09 | | 2,025,000 | (6) |
| | | | | | | | | |
Total | | | | | $ | 2.10 | | | |
| | | | | | | | | |
| (1) | Represents options issued to our directors pursuant to our 2005 Non-Employee Director Incentive Plan (the “2005 Plan”) (i) on October 28, 2005 to purchase up to 300,000 shares of our common stock at an exercise price of $1.94 per share and (ii) on January 24, 2007 to purchase up to 300,000 shares of our common stock at an exercise price of $2.35 per share. The 2005 Plan, which authorized the issuance of up to 2,000,000 shares in stock awards and options, was approved by stockholders on May 30, 2006. |
(2) | Excludes the following shares of restricted stock awarded pursuant to our 2007 Stock Incentive Plan (the “2007 Plan”): (i) 1,242,946 shares of restricted stock awarded to employees during fiscal year 2007, which shares vest over the three years from grant date; (ii) 3,113,500 shares of restricted stock (net of 485,559 shares forfeited prior to being fully vested or otherwise withheld to cover applicable tax withholding obligations) awarded to employees during fiscal year 2008, which shares vest over the three years from grant date; (iii) 527,058 shares of restricted stock awarded in fiscal year 2008 to certain officers having elected to receive shares in lieu of cash for a portion of their respective bonuses, which shares vest one year from grant date; and (iv) 365,323 shares of restricted stock awarded to non-employee directors during fiscal year 2008, which shares vest one year from grant date. |
| (3) | Includes 1,400,000 shares available under the 2005 Plan and 2,236,732 shares available under our 2007 Plan. The following shares may return to the 2007 Plan or the 2005 Plan, as the case may be, and be available for issuance in connection with a future award: (i) shares covered by an award that expires or otherwise terminates without having been exercised in full; (ii) shares that are forfeited or repurchased by us prior to becoming fully vested; (iii) shares covered by an award that is settled in cash; (iv) shares withheld to cover payment of an exercise price or cover applicable tax withholding obligations; (v) shares tendered to cover payment of an exercise price; and (vi) shares that are cancelled pursuant to an exchange or repricing program. |
| (4) | Also includes an aggregate of 1,000,000 shares of restricted stock awarded but not yet vested pursuant to one of the two Restricted Stock Agreements dated April 17, 2007 entered into with two of our officers. The grant of the shares under the Restricted Stock Agreements was approved by stockholders holding a majority of our outstanding shares of common stock by written consent in lieu of a meeting of stockholders. An information statement pursuant to Regulation 14C reporting the authorization of the issuance of shares under the Restricted Stock Agreements was mailed to stockholders on May 21, 2007. |
| (5) | Consists of warrants and options granted to our employees, officers, directors and consultants, to the extent vested and exercisable (within the meaning of Rule 13d-3(d)(1) promulgated by the Commission under the Securities and Exchange Act of 1934, as amended) as of December 31, 2008. |
| (6) | Includes an aggregate of 2,025,000 shares of restricted stock awarded pursuant to Restricted Stock Agreements dated April 17, 2007 entered into with two of our officers, which shares vest over the next three years. |
25
Set forth below is a description of the individual compensation arrangements or equity compensation plans that were not required to be approved by our security holders pursuant to which the 3,962,496 shares of our Common Stock included in the chart above were issuable as of December 31, 2008:
| | • | | Option granted December 15, 2004 to director in consideration of services performed on our behalf, which option expires December 14, 2009 and is currently exercisable to purchase up to 25,000 shares of our Common Stock at an exercise price of $0.85 per share; |
| | • | | Option granted December 15, 2005 to a former officer and director in consideration of services performed on our behalf, which option expires December 14, 2010 and is currently exercisable to purchase up to 250,000 shares of our Common Stock at an exercise price of $1.25 per share; |
| | • | | Option granted May 12, 2005 to an officer and director in consideration of services performed on our behalf, which option expires May 11, 2010 and is currently exercisable to purchase up to an aggregate of 625,000 shares of our Common Stock at an exercise price of $2.44 per share; |
| | • | | Option granted May 12, 2005 to a former officer in consideration of services performed on our behalf, which option expires May 11, 2010 and is currently exercisable to purchase up to an aggregate of 500,000 shares of our Common Stock at an exercise price of $2.44 per share; |
| | • | | Option granted August 3, 2005 to employee in consideration of services performed on our behalf, which option expires August 2, 2010 and is currently exercisable to purchase up to 30,000 shares of our Common Stock at an exercise price of $2.54 per share; |
| | • | | Warrant issued September 30, 2005 to consultant in consideration of services performed on our behalf, which warrant expires September 29, 2010 and is currently exercisable to purchase up to 324,324 shares of our Common Stock at an warrant exercise price of $1.85 per share; |
| | • | | Warrant issued February 1, 2006 to consultant in consideration of services performed on our behalf, which warrant expires January 31, 2011 and is currently exercisable to purchase up to 900,000 shares of our Common Stock at an warrant exercise price of $2.65 per share; |
| | • | | Option granted August 28, 2006 to employee in consideration of services performed on our behalf, which option expires April 27, 2011 and is currently exercisable to purchase up to an aggregate of 50,000 shares of our Common Stock at an exercise price of $1.50 per share; |
| | • | | Warrant issued September 26, 2006 to consultant in consideration of services performed on our behalf, which warrant expires September 25, 2011 and is currently exercisable to purchase up to 500,000 shares of our Common Stock at a warrant exercise price of $1.35 per share; |
| | • | | Option granted January 24, 2007 to a former officer in consideration of services performed on our behalf, which option expires January 23, 2012 and is currently exercisable to purchase up to an aggregate of 200,000 shares of our Common Stock at an exercise price of $1.94 per share; |
| | • | | Options granted April 12, 2007 to consultants in consideration of services performed on our behalf, which options expire April 11, 2012 and are currently exercisable to purchase up to 500,000 shares of our Common Stock at an exercise price of $1.87 per share; and |
| | • | | Warrants issued April 17, 2007 to our former lender in accordance with anti-dilutive protection contained in the September 26, 2006 warrant agreement with our former lender, resulting in the issuance of additional warrants expiring in April 2012 and exercisable to purchase up to 58,172 shares of our Common Stock at a warrant exercise price of $1.35 per share. |
26
| Item 6. | Selected Financial Data. |
The following table sets forth selected financial data of the Company and its consolidated subsidiaries over the five-year period ended December 31, 2008, which information has been derived from the Company’s audited financial statements. This information should be read in connection with, and is qualified in its entirety by the more detailed information in the Company’s financial statements of Item 7 in this Form 10-K.
| | | | | | | | | | | | | | | | | | | | |
| | | As of or For the Year Ended December 31, | |
| | | 2008 | | | 2007 | | | 2006 (1) | | | 2005 (1) | | | 2004 (1) | |
| | | | | | | | | (as adjusted) | | | (as adjusted) | | | (as adjusted) | |
| | | (In thousands, except per share amounts) | |
Income Statement Data | | | | | | | | | | | | | | | | | | | | |
Total revenues | | $ | 146,600 | | | $ | 71,200 | | | $ | 3,360 | | | $ | 3,368 | | | $ | 1,022 | |
Loss from continuing operations | | $ | (108,728 | ) | | $ | (29,621 | ) | | $ | (21,665 | ) | | $ | (3,229 | ) | | $ | (2,945 | ) |
Loss from discontinued operations | | $ | (32,392 | ) | | $ | 1,220 | | | $ | (23,890 | ) | | $ | 200 | | | $ | — | |
Loss available to common shareholders | | | (241,717 | ) | | | (43,597 | ) | | | (45,555 | ) | | | (3,029 | ) | | | (2,945 | ) |
| | | | | |
Net loss per share: | | | | | | | | | | | | | | | | | | | | |
Basic and diluted from continuing operations | | | (2.36 | ) | | | (0.62 | ) | | | (0.37 | ) | | | (0.07 | ) | | | (0.10 | ) |
Basic and diluted from discontinued operations | | | (0.36 | ) | | | 0.02 | | | | (0.41 | ) | | | 0.01 | | | | — | |
| | | | | | | | | | | | | | | | | | | | |
Total basic and diluted | | | (2.72 | ) | | | (0.60 | ) | | | (0.78 | ) | | | (0.06 | ) | | | (0.10 | ) |
| | | | | |
Balance Sheet Data | | | | | | | | | | | | | | | | | | | | |
Total assets | | $ | 402,052 | | | $ | 616,432 | | | $ | 55,664 | | | $ | 55,257 | | | $ | 11,163 | |
Long-term debt | | | 289,607 | | | | 287,244 | | | | 55,239 | | | | 39,098 | | | | — | |
Redeemable convertible preferred stock | | | 227,625 | | | | 216,975 | | | | — | | | | — | | | | — | |
Shareholders’ equity (deficit) | | | (177,075 | ) | | | (30,161 | ) | | | (10,443 | ) | | | 11,611 | | | | 10,423 | |
Common shares outstanding | | | 96,129 | | | | 79,258 | | | | 59,430 | | | | 50,245 | | | | 45,597 | |
| (1) | Amounts have been adjusted to reflect the change in accounting for oil and gas properties from full cost to successful efforts |
| Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations. |
The following discussion will assist you in understanding our financial position, liquidity and results of operations. The information below should be read in conjunction with the consolidated financial statements and the related notes to consolidated financial statements. Our discussion contains both historical and forward-looking information. We assess the risks and uncertainties about our business, long-term strategy and financial condition before we make any forward-looking statements but we cannot guarantee that our assessment is accurate or that our goals and projections can or will be met. Statements concerning results of future exploration, exploitation, development and acquisition expenditures as well as expense and reserve levels are forward-looking statements. We make assumptions about commodity prices, drilling results, production costs, administrative expenses and interest costs that we believe are reasonable based on currently available information.
Critical Estimates and Accounting Policies
We prepare our consolidated financial statements in this report using accounting principles that are generally accepted in the United States (“GAAP”). GAAP represents a comprehensive set of accounting and disclosure rules and requirements. We must make judgments, estimates, and in certain circumstances, choices between acceptable GAAP alternatives as we apply these rules and requirements. The most critical estimate we make is the engineering estimate of proved oil and gas reserves. This estimate affects the application of the successful efforts method of accounting, the calculation of depreciation, depletion, and amortization of oil and
27
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 proved reserves are classified as either proved developed or proved undeveloped. Proved developed reserves are those reserves which can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves include reserves expected to be recovered from new wells from undrilled proven reservoirs or from existing wells where a significant major expenditure is required for completion and production.
Independent reserve engineers prepare the estimates of our oil and gas reserves presented in this report based on guidelines promulgated under GAAP and in accordance with the rules and regulations of the Securities and Exchange Commission. The evaluation of our reserves by the independent reserve engineers involves their rigorous examination of our technical evaluation and extrapolations of well information such as flow rates and reservoir pressure declines as well as other technical information and measurements. Reservoir engineers interpret these data to determine the nature of the reservoir and ultimately the quantity of proved oil and gas reserves attributable to a specific property. Our proved reserves in this report include only quantities that we expect to recover commercially using current prices, costs, existing regulatory practices and technology. While we are reasonably certain that the proved reserves will be produced, the timing and ultimate recovery can be 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 in the previously estimated volumes or proved reserves for existing fields due to evaluation of (1) already available geologic, reservoir or production data or (2) new geologic or reservoir data obtained from wells. Revisions can also include changes associated with significant changes in development strategy, oil and gas prices or production equipment/facility capacity.
Standardized measure of discounted future net cash flows
The standardized measure of discounted future net cash flows relies on these estimates of oil and gas reserves using commodity prices and costs at year-end. In our 2008 year-end reserve report, we used December 31, 2008 ConocoPhillips West Texas Intermediate posted price of $41.22 per Bbl and a Henry Hub Onshore price of $5.71 per MMbtu adjusted by property for energy content, quality, transportation fees and regional price differentials. The weighted average price over the lives of the properties was $40.41 per Bbl for oil and $6.07 per Mcf for gas. While we believe that future operating costs can be reasonably estimated, future prices are difficult to estimate since the market prices are influenced by events beyond our control. Future global economic and political events will most likely result in significant fluctuations in future oil prices.
Successful efforts method of accounting
Oil and gas exploration and production companies choose one of two acceptable accounting methods, successful efforts or full cost. The most significant difference between the two methods relates to the accounting treatment of drilling costs for unsuccessful exploration wells (“dry holes”) and exploration costs. Under the successful efforts method, exploration costs and dry hole costs (the primary uncertainty affecting this method) are recognized as expenses when incurred and the costs of successful exploration wells are capitalized as oil and gas properties. Entities that follow the full cost method capitalize all drilling and exploration costs including dry hole costs into one pool of total oil and gas property costs.
28
While it is typical for companies that drill exploration wells to incur dry hole costs, our primary activities during 2008 focused on development wells and our exploratory drilling activities were immaterial. Nevertheless, we will selectively expand our exploration drilling in the future. It is impossible to accurately predict specific dry holes. Because we can not predict the timing and magnitude of dry holes, quarterly and annual net income can vary dramatically.
The calculation of depreciation, depletion and amortization of capitalized costs under the successful efforts method of accounting differs from the full cost method in that the successful efforts method requires us to calculate depreciation, depletion and amortization expense on individual properties rather than one pool of costs. In addition, under the successful efforts method we assess our properties individually for impairment compared to one pool of costs under the full cost method.
Depreciation, Depletion and Amortization of Oil and Gas Properties
The unit-of-production method of depreciation, depletion and amortization of oil and gas properties under the successful efforts method of accounting is applied pursuant to the simple multiplication of units produced by the costs per unit on a field by field basis. Leasehold cost per unit is calculated by dividing the total cost by the estimated total proved oil and gas reserves associated with that field. Well cost per unit is calculated by dividing the total cost by the estimated total proved producing oil and gas reserves associated with that field. The volumes or units produced and asset costs are known and while the proved reserves have a high probability of recoverability, they are based on estimates that are subject to some variability. The factors which create this variability are included in the discussion of estimated proved oil and gas reserves above.
Impairment of Oil and Gas Properties
We test for impairment of our properties based on estimates of proved reserves. Proved oil and gas properties are reviewed for impairment whenever events or circumstances indicate that the carrying amount may not be recoverable. We estimate the future undiscounted cash flows of the affected properties to judge the recoverability of the carrying amounts. Initially this analysis is based on proved reserves. However, when we believe that a property contains oil and gas reserves that do not meet the defined parameters of proved reserves, an appropriately risk adjusted amount of these reserves may be included in the impairment evaluation. These reserves are subject to much greater risk of ultimate recovery. An asset would be impaired if the undiscounted cash flows were less than its carrying value. Impairments are measured by the amount by which the carrying value exceeds its fair value.
Impairment analysis is performed on an ongoing basis. In addition to using estimates of oil and gas reserve volumes in conducting impairment analysis, it is also necessary to estimate future oil and gas prices. The impairment evaluation triggers include a significant long-term decrease in current and projected prices, or reserve volumes, an accumulation of project costs significantly in excess of the amount originally expected and historical and current negative operating losses. Although we evaluate future oil and gas prices as part of the impairment analysis, we do not view short-term decreases in prices, even if significant, as impairment triggering events.
Exploratory Drilling Costs
The costs of drilling an exploratory well are capitalized as uncompleted wells pending the determination of whether the well has found proved reserves. If proved reserves are not found, these capitalized costs are charged to expense. On the other hand, the determination that proved reserves have been found results in continued capitalization of the well and its reclassification as a well containing proved reserves.
Asset Retirement Obligation
The Company follows SFAS No. 143, “Accounting for Asset Retirement Obligations,” which requires entities to record the fair value of a liability for legal obligations associated with the retirement obligations of
29
tangible long-lived assets in the period in which it is incurred. The fair value of asset retirement obligation liabilities has been calculated using an expected present value technique. Fair value, to the extent possible, should include a market risk premium for unforeseeable circumstances. A five percent market risk premium was included in the Company’s Asset Retirement Obligation fair value estimate. When the liability is initially recorded, the entity increases the carrying amount of the related long-lived asset. Over time, accretion of the liability is recognized each period, and the capitalized cost is amortized over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. This standard requires the Company to record a liability for the fair value of the dismantlement and plugging and abandonment costs, excluding salvage values.
Derivatives
Derivative financial instruments, utilized to manage or reduce commodity price risk related to Dune’s production, are accounted for under the provisions of SFAS No. 133, “Accounting for Derivative Instruments and for Hedging Activities”, and related interpretations and amendments. Under this statement, derivatives are carried on the balance sheet at fair value. If the derivative is designated as a fair value hedge, the changes in the fair value of the derivative and of the hedged item attributable to the hedged risk are recognized in earnings. If the derivative is designated as a cash flow hedge, the effective portions of changes in the fair value of the 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.
Effective January 1, 2008, the Company discontinued, prospectively, the designation of its derivatives as cash flow hedges. The net derivative loss related to the discontinued cash flow hedges, as of December 31, 2007, will continue to be reported in accumulated other comprehensive loss until such time that they are charged to income or loss as the volumes underlying the cash flow hedges are realized. Beginning January 1, 2008, the gain or loss on derivatives is being recognized currently in earnings.
Stock-based compensation
On January 1, 2006, dune adopted SFAS No. 123(R), “Share-Based Payment”. SFAS 123(R) replaced SFAS No. 123 and supersedes APB Opinion No. 25. SFAS 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values. The pro forma disclosures previously permitted under SFAS 123 are no longer an alternative to financial statement recognition. Dune adopted SFAS 123(R) using the modified prospective method which requires the application of the accounting standard as of January 1, 2006. Our Notes to Consolidated Financial Statements included in this report have additional discussion of our significant accounting policies.
Business Strategy
Dune is an independent energy company engaged in the exploration, development, acquisition and exploitation of natural gas and crude oil properties, with interest along the Gulf Coast. On May 15, 2007, we closed the Stock Purchase and Sale Agreement to acquire all of the capital stock of Goldking from Goldking Energy Holdings, L.P. Goldking was an independent energy company focused on the exploration, exploitation and development of natural gas and crude properties located onshore and in state waters along the Gulf Coast, The acquisition of Goldking substantially increased our proved reserves, provided significant drilling upside and increased our geographic and geological well diversification. Additionally, the acquisition of Goldking provided us with exploration opportunities within our core geographic area.
Our properties now cover over 100,000 gross acres across 23 oil and natural gas fields onshore and in state waters along the Texas and Louisiana Gulf Coast.
30
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. Consistent with this goal, during the second half of 2008, we closed the previously announced sale of our Barnett Shale assets, located in Denton and Wise Counties, Texas.
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 migration and directional drilling to identify and exploit new opportunities in our asset base. We also plan to employ the latest drilling, completion and fracturing technology in all of our wells to enhance recoverability and accelerate cash flows associated with these wells.
Pursue Opportunistic Acquisitions of Underdeveloped Properties.We review opportunities to acquire producing properties, leasehold acreage and drilling prospects. We are seeking to acquire operational control of properties that we believe have a solid proved reserves base coupled with significant exploitation and exploration potential. We intend to continue to evaluate acquisition opportunities and make acquisitions that we believe will further enhance our operations and reserves in a cost effective manner.
Actively Manage the Risks and Rewards of Our Drilling Program.Our strategy is to increase our oil and gas reserves and production while keeping our finding and development costs and operating costs (on a per Mcf equivalent (Mcfe) basis) competitive with our industry peers. We will implement this strategy through drilling exploratory and development wells from our inventory of available prospects that we have evaluated for geologic and mechanical risk and future reserve potential. Our drilling program will contain some higher risk/higher reserve potential opportunities as well as some lower risk/lower reserve potential opportunities in order to achieve a balanced program of reserve and production growth. Success of this strategy is contingent on various risk factors, as discussed elsewhere in the 10-K.
In 2008 we invested $61.8 million in oil and gas properties. Continuing operations accounted for $52.8 million of this total and $9 million was associated with the Barnett Shale properties sold during the second half of the year. The investment in continuing operations added 13.5 Bcfe through extensions and discoveries. We produced 12.8 Bcfe during the year including 1.4 Bcfe from discontinued operations in the Barnett Shale. Revisions of previous estimates were 11.0 Bcfe negative, mainly reflecting unsuccessful completion operations in the Cobb#1 well in the Comite field.
The Company sold its interest in the Barnett Shale assets which accounted for a 32.1 Bcfe year-over-year reduction in proved reserves. As of December 31, 2007, Dune’s Barnett Shale proved reserves totaled 33.5 Bcfe. 1.4 Bcfe was extracted and sold from the discontinued Barnett Shale properties during 2008 prior to the closing date of the sale.
31
| | | | | | | | | | | | | | | | |
Capital Costs ($000): | | Year
Ended
2008 | | | Year
Ended
2007 | | | Year
Ended
2006 | | | Three
Years
Ended
12/31/08 | |
Acquisitions—Proved | | $ | — | | | $ | 391,438 | | | $ | 36,528 | | | $ | 427,966 | |
Acquisitions—Unproved | | | 1,571 | | | | 455 | | | | 391 | | | | 2,417 | |
Exploration | | | 115 | | | | 383 | | | | 2,024 | | | | 2,522 | |
Development | | | 51,064 | | | | 148,161 | | | | 363 | | | | 199,588 | |
| | | | | | | | | | | | | | | | |
Total CAPEX before ARO | | | 52,750 | | | | 540,437 | | | | 39,306 | | | | 632,493 | |
ARO Costs | | | 1,209 | | | | — | | | | — | | | | 1,209 | |
| | | | | | | | | | | | | | | | |
Total CAPEX including ARO | | | 53,959 | | | | 540,437 | | | | 39,306 | | | | 633,702 | |
Barnett Shale CAPEX | | | — | | | | (47,246 | ) | | | (32,802 | ) | | | (80,048 | ) |
| | | | | | | | | | | | | | | | |
Total CAPEX including ARO and excluding Barnett Shale | | $ | 53,959 | | | $ | 493,191 | | | $ | 6,504 | | | $ | 553,654 | |
| | | | | | | | | | | | | | | | |
Asset Retirement Obligation (non-cash) | | $ | 7,403 | | | $ | 2,737 | | | $ | 274 | | | $ | 10,414 | |
| | | | | | | | | | | | | | | | |
| | | | |
Proved Reserves (Mmcfe): | | | | | | | | | | | | | | | | |
Beginning | | | 175,347 | | | | 29,404 | | | | 29,515 | | | | 29,515 | |
Production | | | (12,781 | ) | | | (9,022 | ) | | | (1,090 | ) | | | (22,893 | ) |
Purchases | | | — | | | | 109,377 | | | | 13,682 | | | | 123,059 | |
Barnett Shale Sale | | | (32,065 | ) | | | — | | | | — | | | | (32,065 | ) |
Discoveries & Extensions | | | 13,481 | | | | 38,012 | | | | 68 | | | | 51,561 | |
Revisions | | | (10,984 | ) | | | 7,576 | | | | (12,771 | ) | | | (16,179 | ) |
| | | | | | | | | | | | | | | | |
Ending Reserves | | | 132,998 | | | | 175,347 | | | | 29,404 | | | | 132,998 | |
| | | | | | | | | | | | | | | | |
Reserve Additions before Revisions (Mmcfe) | | | 13,481 | | | | 147,389 | | | | 13,750 | | | | 174,620 | |
Reserve Additions after Revisions (Mmcfe) | | | 2,497 | | | | 154,965 | | | | 979 | | | | 158,441 | |
The implementation of our strategy requires that we continually incur significant capital expenditures in order to replace current production and find and develop new oil and gas reserves. In order to finance our capital and exploration program, we depend on cash flow from operations or bank debt and equity offerings as discussed below in Liquidity and Capital Resources.
Hurricanes
As previously announced, during the third quarter we experienced two production disruptions by hurricanes Gustav and Ike resulting in production shut-ins. Many of our onshore Louisiana fields were flooded and incurred minor structural damage. Such damage did not exceed Dune’s deductibles for insurance claims. Production has been restored at all fields. In total, Dune estimates that production deferrals associated with the two hurricanes were approximately 0.5 Bcfe.
Liquidity and Capital Resources
During fiscal 2008 compared to fiscal 2007, net cash flow provided by all operating activities decreased by $30.7 million to $23.5 million. This decline was primarily attributable to our efforts to substantially reduce our accounts payable which had accumulated in 2007 as a result of our aggressive capital program.
Our current assets stood at $40.9 million on December 31, 2008. Cash on hand at year-end was $15.5 million, which compared to $16.8 million at the end of calendar year 2007. The Barnett Shale disposition, as mentioned earlier, facilitated the reduction in our accounts payable from $56.6 million at year end 2007 to $21.7 million at December 31, 2008.
The financial statements continue to reflect our active and ongoing drilling and facilities upgrade program which involved almost $59.4 million of capital investment in the fourth quarter of 2007 and another
32
$61.8 million during 2008. Expenditures in the discontinued Barnett Shale operations accounted for $9.0 million of the 2008 total. The hurricanes caused only minor damage to certain of our production operations and no material cash outlays were necessary to restore this capacity.
During 2008, the availability under our revolving line of credit was increased to $40 million. As of December 31, 2008 and 2007, there were no borrowings under our credit facility. This compared with $28.1 million outstanding at the end of the second quarter of 2008. Proceeds from the Barnett Shale asset sale, after customary purchase price adjustments, were utilized to eliminate borrowings outstanding under the revolver, and for general working capital.
Semi-annual interest of $15.75 million on our 10 1/2% Senior Secured Notes due 2012 was paid on December 31, 2008 and will be due semi-annually thereafter. The principal on the Senior Secured Notes is not due until 2012.
Shares of our Senior Redeemable Convertible Preferred Stock are not redeemable until December 1, 2012 or upon a change in control. Dividends are payable quarterly beginning September 1, 2007 with the Company having the option of paying any dividend on the Preferred Stock in shares of common stock, shares of Preferred Stock or cash.
Our primary sources of liquidity are cash provided by operating activities, debt financing, sales of non-core properties and access to capital markets. The strength of our current cash position and availability under our revolver put us in a favorable position to meet our financial obligations and ongoing capital programs even as commodity prices continue to decline from their mid-year record highs.
For 2009, capital spending will be targeted at between $35 million and $50 million. The exact amount will depend upon individual well performance results, cash flow and, where applicable, partner negotiations on the timing of drilling operations.
The following table summarizes our contractual obligations and commercial commitments as of December 31, 2008:
| | | | | | | | | | | | | | | |
| | | Payments Due By Period |
| | | Total | | Less than
1 year | | 1 - 3
years | | 4 - 5 years | | After 5 years |
| | | (in thousands) |
Contractual obligations: | | | | | | | | | | | | | | | |
Debt and interest | | $ | 407,625 | | $ | 31,500 | | $ | 63,000 | | $ | 313,125 | | $ | — |
Office Lease | | | 2,207 | | | 778 | | | 1,429 | | | — | | | — |
| | | | | | | | | | | | | | | |
Total | | $ | 409,832 | | $ | 32,278 | | $ | 64,429 | | $ | 313,125 | | $ | — |
| | | | | | | | | | | | | | | |
Changes in our working capital accounts from 2007 to 2008 include a $17 million decrease in our accounts receivable due to lower oil and gas prices, decreased production and decreased balances due from our joint interest participants. For essentially the same reasons, our accounts payable balance declined by $35 million.
On December 31, 2008, our current assets were less than our current liabilities by $5.3 million.
We believe our short-term and long-term liquidity augmented by sale of non-core properties, if needed, is adequate to fund operations, including capital expenditures, interest and repayment of debt maturities.
Results of Operations
Comparison of 2008 and 2007
Year-over-year production volumes were up significantly as a result of the Goldking acquisition and increased operating and drilling activities, rising from 7,139 Mmcfe for the twelve months of fiscal 2007 to
33
11,365 Mmcfe for the same period of 2008. Nevertheless, this increase was tempered partially by the adverse impact on production of hurricanes Gustav and Ike during the third quarter of 2008 and the completion of the sale of the Barnett Shale properties during the second half of the year.
The following table discloses the net oil and gas production volumes, sales, and sales prices for each of the two years ended December 31, 2008 and 2007:
| | | | | | | | | |
| | | 2008 | | % Increase
(Decrease) | | | 2007 |
Oil production volume (Mbbls) | | | 884 | | 56 | % | | | 568 |
Oil sales revenue ($000) | | $ | 88,306 | | 97 | % | | $ | 44,892 |
Price per Bbl | | $ | 99.87 | | 26 | % | | $ | 79.04 |
Increase in oil sales revenue due to: | | | | | | | | | |
Change in prices | | $ | 11,831 | | | | | | |
Change in production volume | | | 31,583 | | | | | | |
| | | | | | | | | |
Total increase (decrease) in oil sales revenue | | $ | 43,414 | | | | | | |
| | | | | | | | | |
| | | |
Gas production volume (Mmcf) | | | 6,060 | | 62 | % | | | 3,731 |
Gas sales revenue | | $ | 58,294 | | 122 | % | | $ | 26,308 |
Price per Mcf | | $ | 9.62 | | 36 | % | | $ | 7.05 |
Increase in gas sales revenue due to: | | | | | | | | | |
Change in prices | | $ | 9,589 | | | | | | |
Change in production volume | | | 22,397 | | | | | | |
| | | | | | | | | |
Total increase (decrease) in gas sales revenue | | $ | 31,986 | | | | | | |
| | | | | | | | | |
Revenues
Revenue from continuing operations for the year ended December 31, 2008 increased $75.4 million from the prior twelve month period ended December 31, 2007 to $146.6 million. This was the result of higher commodity prices, which averaged $12.90/Mcfe for the year versus $9.97 in 2007. However, production gains were tempered by the third quarter shut-ins caused by hurricanes Gustav and Ike and the completion of the Barnett Shale sale at the end of the third quarter of 2008.
Operating expenses
Lease operating expense and production taxes
Total lease operating expense for 2008 increased $14.9 million from the comparable 2007 period to $43.5 million. This translated to a decrease of $0.18/Mcfe to $3.82/Mcfe on a volume basis. The full-year’s effect of the Goldking acquisition and the concomitant increase in the number of operating properties made up the vast amount of this increase as direct operating expense rose $9.6 million to $24.8 million ($2.18/Mcfe). Production taxes accounted for the second largest cost of operations, increasing $4.6 million to $10.7 million ($0.94/Mcfe). A decline of $0.5 million in workover expense to $5.5 million partially offset these increases.
34
The following table presents the major components of our operating costs for the last three years on a per mcfe basis:
| | | | | | | | | | | | | | | | | | |
| | | Years Ending December 31, |
| | | 2008 | | 2007 | | 2006 |
| | | Total | | Per
Mcfe | | Total | | Per
Mcfe | | Total | | Per
Mcfe |
Direct operating expense | | $ | 24,830 | | $ | 2.18 | | $ | 15,243 | | $ | 2.13 | | $ | 661 | | $ | 1.88 |
Workovers | | | 5,456 | | $ | 0.48 | | | 5,975 | | $ | 0.84 | | | — | | $ | — |
Ad valorem taxes | | | 1,258 | | $ | 0.11 | | | 605 | | $ | 0.08 | | | 20 | | $ | 0.06 |
Production taxes | | | 10,710 | | $ | 0.94 | | | 6,061 | | $ | 0.85 | | | 77 | | $ | 0.22 |
Transportation | | | 1,247 | | $ | 0.11 | | | 719 | | $ | 0.10 | | | 10 | | $ | 0.03 |
| | | | | | | | | | | | | | | | | | |
| | $ | 43,501 | | $ | 3.82 | | $ | 28,603 | | $ | 4.00 | | $ | 768 | | $ | 2.18 |
| | | | | | | | | | | | | | | | | | |
Exploration Expenses
Exploration costs for the year ended 2008 totaled $0.1 million compared to $0.4 million in 2007. This reduction of $0.3 million is the result of the Company’s continuing focus on drilling development wells in order to convert proved undeveloped reserves to proved developed reserves.
Accretion of asset retirement obligation
Accretion expense for the year increased from $0.89 million in 2007 to $0.91 million in 2008 representing a $0.02 million increase. The modest increase is the result of the impact of reevaluating abandonment costs at year end 2008.
Depletion, depreciation and amortization (DD&A)
For 2008, the Company recorded DD&A expense of $56.7 million ($4.99/Mcfe) compared to $29.9 million ($4.19/Mcfe) for 2007 representing an increase of $26.8 million. The increase in DD&A year-over-year is primarily attributable to a full year’s depletion of oil and gas properties purchased in the Goldking acquisition in 2008 versus 7 1/2 months in 2007 and a downward revision in reserves on certain fields.
General and administrative expense (G&A expense)
G&A expense for 2008 declined by $3.6 million ($1.47/Mcfe) from the comparable 2007 period to $18.5 million ($1.63/Mcfe). The decrease was the result of a $2.8 million decline in stock-based compensation to $5.3 million as well as a reduction in cash G&A expenses of $0.8 million to $13.2 million ($1.16/Mcfe). Part of this decline is attributable to the $0.4 million of non-recurring one-time severance payments to former Goldking employees whose employment was terminated by Dune following the acquisition. Furthermore, G&A also reflected a reduction in total employees from 62 to 52.
Loss on impairment of oil and gas properties
The Company recorded $125.7 million or pre-tax, non-cash impairment charges associated with its oil and natural gas properties in the fourth quarter of 2008. This impairment primarily resulted from lower oil and natural gas prices. The Company’s bank covenants are not impacted by this non-cash charge.
Other income (expense)
Interest income
Interest income was $0.5 million for the year ended December 31, 2008 compared to $1.7 million in the comparable 2007 period. This was the result of using our cash balances in 2008 to support working capital and contribute to the capital program.
35
Interest expense
Interest expense on debt borrowing for 2008 amounted to $32.1 million compared to $24.0 million in 2007. The increase of $8.1 million is attributable in part to outstanding borrowings under the Revolver Commitment which reached a mid-year peak of $28.1 million and was paid off in August, 2008. The balance of the rise was the full-year’s impact of the interest on $300 million in Senior Secured Notes issued at the end of the second quarter of 2007.
Loss on derivative liabilities
Effective January 1, 2008, the Company discontinued, prospectively, the designation of its derivatives as cash flow hedges. The net derivative loss related to the discontinued cash flow hedges, as of December 31, 2007, will continue to be reported in accumulated other comprehensive loss until such time that they are charged to income or loss as the volumes underlying the cash flow hedges are realized. Beginning January 1, 2008, the loss on derivatives is being recognized currently in earnings. For the year ended December 31, 2008, the Company incurred a gain on derivatives of $4.1 million, composed of an unrealized gain of $13.4 million due to the change in the mark-to-market valuation partially offset by a realized loss of ($9.3) million for cash settlements. The comparable period ended December 31, 2007 yielded a loss on derivatives of ($1.9) million.
Income tax benefit
The Company’s 2006 taxes were subject to a full valuation allowance yielding $0 tax benefit. As a result of the Goldking acquisition in the second quarter of 2007, the Company has significant deferred tax liabilities in excess of its deferred tax assets. Management has determined that a valuation allowance is no longer necessary as the realization of its deferred tax assets is more likely than not. Consequently, in 2008 the Company has recorded an income tax benefit of $20.5 million for continuing operations and $9.4 million for discontinued operations.
Discontinued operations
Associated with the sale of the Barnett Shale Properties, the Company has reflected all activity for these assets as discontinued operations. For the year ended December 31, 2007, the Company reclassified $1.9 million as income from discontinued operations. An income tax expense of $0.7 million yielded net income for the year of $1.2 million.
For the year ended December 31, 2008, the Company generated a net gain from the operation of the Barnett Shale Properties of $2.1 million. This gain was added to a $43.9 million impairment to write down the related carrying amounts to their fair value less cost to sell. An income tax benefit of $9.4 million was added to this transaction yielding a $32.4 million loss on discontinued operations for 2008.
Net Loss
Net loss from continuing operations for 2008 reached $108.7 million, up from the comparable 2007 net loss from continuing operations of $29.6 million. Total net loss from continuing and discontinued operations for the year ended December 31, 2008 was $141.1 million versus $28.4 million for 2007.
Comparison of 2007 and 2006
A comparison of balances between 2006 to 2007 focuses on activity of the Company with 7 1/2 months of activity related to the Goldking acquisition in 2007 compared to a full year of activity without the Goldking acquisition in 2006. After reclassifying all of the activity related to the Barnett Shale assets as discontinued operations, the operating loss reflected a slight decrease of $0.3 million.
Other income (expense) reflected an increase of $24.3 million which was primarily attributable to the interest expense on the Senior Secured Notes issued in 2007.
36
A comparison of discontinued operations related to the Barnett Shale assets resulted in a $25.1 million increase from 2006 to 2007. This change is specifically attributable to the impairment of the Barnett Shale properties of $24.5 million in 2006.
In 2007, as a result of the Goldking acquisition, Dune recognized a deferred tax benefit of $15.3 million which was allocated between continued and discontinued operations. Prior to 2007, the net deferred tax asset had a valuation reserve and was not recognized in income.
Associated with the issuance of Preferred Stock in 2007, Dune recorded Preferred Stock dividends of $13.8 million. No Preferred Stock dividends were recorded in 2006.
The net impact of these various components was a decrease in the net loss available to shareholders from $45.6 million to $43.5 million.
New Accounting Pronouncements
On December 31, 2008, the Securities and Exchange Commission (SEC) issued the final rule, “Modernization of Oil and Gas Reporting” (“Final Rule”). The Final Rule adopts revisions to the SEC’s oil and gas reporting disclosure requirements and is effective for annual reports on Forms 10-K for years ending on or after December 31, 2009. The revisions are intended to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves to help investors evaluate their investments in oil and gas companies. The amendments are also designed to modernize the oil and gas disclosure requirements to align them with current practices and technological advances. Revised requirements in the Final Rule include, but are not limited to:
| | • | | Oil and gas reserves must be reported using a 12-month average of the closing prices on the first day of each of such months, rather than a single day year-end price: |
| | • | | Companies will be allowed to report, on a voluntary basis, probable and possible reserves, previously prohibited by SEC rules; and |
| | • | | Easing the standard for the inclusion of proved undeveloped reserves (PUDs) and requiring disclosure of information indicating any progress toward the development of PUDs. |
We are currently evaluating the potential impact of adopting the Final Rule. The SEC is discussing the Final Rule with the FASB and IASB staffs to align accounting standards with the Final Rule. These discussions may delay the required compliance date. Absent any change in such date, we will begin complying with the disclosure requirements in our annual report on Form 10-K for the year ended December 31, 2009. Voluntary early compliance is not permitted.
In June 2008, the FASB ratified the consensus reached by the EITF on Issue 07-5, “Determining Whether and Instrument (or Embedded Feature) Is Indexed to an Entity’s Own Stock” (Issue 07-5). Under Issue 07-5, an instrument (or embedded feature) would not be considered indexed to an entity’s own stock if its settlement amount is affected by variables other than those used to determine the fair value of a “plain vanilla” option or forward contract on equity shares, or if the instrument contains a feature (such as a leverage factor) that increases exposure to those variables. An equity-linked financial instrument (or embedded feature) would not be considered indexed to the entity’s own stock if the strike price is denominated in a currency other than the issuer’s functional currency. This Issue is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Early application is not permitted. The Company is currently evaluating the impact that EITF 07-5 will have on its consolidated financial position or result of operations.
In June 2008, FASB issued EITF Issue No. 08-4, “Transition Guidance for Conforming Changes to Issue No. 98-5 (“EITF No. 08-4”). The objective of EITF No. 08-4 is to provide transition guidance for conforming
37
changes made to EITF No. 98-5, “Accounting for Convertible Securities with Beneficial Conversion Features or Contingently Adjustable Conversion Ratios”, that result from EITF No. 00-27 “Application of Issue No. 98-5 to Certain Convertible Instruments”, and SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity”. This Issue is effective for financials statements issued for fiscal years ending after December 15, 2008. The adoption did not have a material impact on our financial statements.
In March 2008, the FASB issued SFAS 161, Disclosures about Derivative Instruments and Hedging Activities. SFAS 161 is effective beginning January 1, 2009 and required entities to provide expanded disclosures about derivative instruments and hedging activities including (1) the ways in which an entity uses derivatives, (2) the accounting for derivatives and hedging activities, and (3) the impact that derivatives have (or could have) on an entity’s financial position, financial performance, and cash flows. SFAS 161 requires expanded disclosures and does not change the accounting for derivatives. Dune is currently evaluating the impact of SFAS 161, but we do not expect the adoption of this standard to have a material impact on our financial results.
| Item 7A. | Quantitative and Qualitative Disclosures About Market Risk. |
Our primary exposure to market risk is the commodity pricing available to our oil and natural gas production. Realized commodity prices received for such production are primarily driven by the prevailing worldwide price for oil and spot prices applicable to natural gas. To mitigate some of this risk, we engage periodically in certain hedging activities, including price swaps, costless collars and, occasionally, put options, in order to establish some price floor protection (see Note 5 to financial statements). We also have some exposure to market risk consisting of changes in interest rates on borrowings under our credit agreement with our senior lender. An increase in interest rates would adversely affect our operating results and the cash flow available after debt service to fund operations. We manage exposure to interest rate fluctuations by optimizing the use of fixed and variable debt.
| Item 8. | Financial Statements and Supplementary Data. |
The response to this item is included in Item 15—Financial Statements.
| Item 9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. |
None.
| Item 9A. | Controls and Procedures. |
(a) Disclosure Controls and Procedures.
We maintain disclosure controls and procedures that are designed to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit to the Securities and Exchange Commission (“SEC”) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms, and that information is accumulated and communicated to our management, including our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), as appropriate to allow timely decisions regarding required disclosure.
In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our CEO and CFO, of the effectiveness of our disclosure controls and procedures as of December 31, 2008. As described below under Management’s Annual Report on Internal Control over Financial Reporting, our CEO and CFO have concluded that, as of December 31, 2008, our disclosure controls and procedures were effective to provide reasonable assurance that information
38
required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.
(b) Management’s Annual Report on Internal Control over Financial Reporting.
Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. The Company’s internal control over financial reporting includes those policies and procedures that:
| | 1. | pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; |
| | 2. | provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and |
| | 3. | provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that could have a material effect on the financial statements. |
Because of the inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2008. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission inInternal Control—Integrated Framework.Based on such assessment and those criteria, management believes that the Company maintained effective internal control over financial reporting as of December 31, 2008.
Malone & Bailey, P.C., our independent registered public accounting firm who also audited the Company’s consolidated financial statements, has issued its own attestation report on the effectiveness of the Company’s internal control over financial reporting as of December 31, 2008, which is filed herewith.
(c) Changes in Internal Control Over Financial Reporting. There have not been any changes in the Company’s internal control over financial reporting during the fiscal quarter ended December 31, 2008 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
39
(d) Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders of
Dune Energy, Inc.
Houston, Texas
We have audited Dune Energy, Inc.’s internal control over financial reporting as of December 31, 2008, based on criteria established inInternal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Dune Energy, Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Dune Energy, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Dune Energy, Inc. as of December 31, 2008 and 2007, and the related consolidated statements of operations, shareholders’ equity(deficit), and cash flows for each of the three years in the period ended December 31, 2008 and our report dated March 5, 2009 expressed an unqualified opinion thereon.
/s/ Malone & Bailey, PC
Houston, Texas
March 5, 2009
40
| Item 9B. | Other Information. |
None.
PART III
The information required by Part III will be incorporated by reference into this Form 10-K from the Registrant’s Definitive Proxy Statement to be filed pursuant to Regulation 14A within 120 days after the end of the Registrant’s fiscal year covered by this Form 10-K.
41
PART IV
| Item 15. | Exhibits, Financial Statement Schedules. |
(a)(1) Financial Statements
The response to this item is submitted in a separate section of this report.
(a)(3) Exhibits
| | |
Exhibit Nos. | | Description |
| 3.1 | | Amended and Restated Certificate of Incorporation (1) |
| 3.1.1 | | Certificate of Amendment of Certificate of Incorporation (2) |
| 3.2 | | Amended and Restated By-Laws (3) |
| 4.1 | | Certificate of Designations, dated May 15, 2007, for 10% Senior Redeemable Convertible Preferred Stock of the Company (4) |
| 4.1.1 | | Certificate of Correction to Certificate of Designations, dated February 26, 2008 (11) |
| 4.2 | | Form of Placement Agent Warrant (5) |
| 4.3 | | Form of Investor Registration Rights Agreement (5) |
| 4.4 | | Form of Warrant, dated as of September 26, 2006, from Company to Bernard National Senior Funding, Ltd. and Drawbridge Special Opportunities Fund LP (6) |
| 4.5 | | Indenture, dated May 15, 2007, among the Company, each of Dune Operating Company and Vaquero Partners LLC, as guarantors, and The Bank of New York, as trustee and collateral agent (4) |
| 4.6 | | First Supplement to Indenture dated as of December 30, 2008 (12) |
| 4.7 | | Form of Global 10 1/2% Senior Secured Exchange Note due 2012 (11) |
| 10.1 | | Employment Agreement, dated April 17, 2007, between the Company and James A. Watt (7) |
| 10.1.1 | | Amended and Restated Employment Agreement, dated as of December 30, 2008 between the Company and James A. Watt (12) |
| 10.2 | | Employment Agreement, dated April 17, 2007, between the Company and Alan Gaines (7) |
| 10.2.1 | | Amendment to Employment Agreement of Alan Gaines dated May 9, 2007 (2) |
| 10.2.2 | | Amended and Restated Employment Agreement, dated as of December 30, 2008 between the Company and Alan Gaines (12) |
| 10.3 | | EmploymentAgreement dated as of April 17, 2007, between the Company and Amiel David (7) |
| 10.3.1 | | Amendment to Employment Agreement of Amiel David dated May 9, 2007 (2) |
| 10.3.2 | | Amended and Restated Employment Agreement, dated as of December 30, 2008 between the Company and Amiel David (12) |
| 10.4 | | Restricted Stock Agreement, dated April 17, 2007, between the Company and James A. Watt (7) |
| 10.5 | | Restricted Stock Agreement, dated April 17, 2007, between the Company and Alan Gaines (7) |
| 10.6 | | Restricted Stock Agreement, dated April 17, 2007, between the Company and Frank T. Smith, Jr. (7) |
| 10.7 | | Exploration and Development Agreement between Company and American Natural Energy Corporation, dated effective as of August 26, 2005(8) |
| 10.8 | | Stock Purchase and Sale Agreement dated effective April 13, 2007 between the Company and Goldking Energy Holdings, L.P. (7) |
| 10.9 | | Form of Registration Rights Agreement (7) |
| 10.10 | | Purchase Agreement dated as of May 1, 2007 between the Company and Jefferies & Company, Inc. (10) |
| 10.11 | | Notes Registration Rights Agreement, dated May 15, 2007, between the Company and Jefferies & Company, Inc. (4) |
| 10.12 | | Preferred Stock Registration Rights Agreement, dated May 15, 2007, between the Company and Jefferies & Company, Inc. (4) |
| 10.13 | | Security Agreement, dated May 15, 2007, among The Bank of New York, as collateral agent, and each of the Company, Goldking Operating Company and Vaquero Partners LLC, as grantors, and Dune Operating Company and Goldking Energy Corporation, as guarantors (4) |
42
| | |
Exhibit Nos. | | Description |
| 10.14 | | Intercreditor Agreement, dated May 15, 2007, among Wells Fargo Foothills, Inc., The Bank of New York and the Company, among others named therein (4) |
| 10.15 | | Credit Agreement dated May 15, 2007 among the Company, its subsidiaries named therein as borrowers, its subsidiaries named therein as guarantors, certain lenders named therein and Wells Fargo Foothill, Inc., as arranger and administrative agent (4) |
| 10.16 | | First Amendment to Credit Agreement dated as of August 4, 2008 (13) |
| 10.17 | | Purchase and Sale Agreement, dated as of June 30, 2008 between the Company and Pioneer Natural Resources, Inc. (14) |
| 10.18 | | First Amendment to Purchase and Sale Agreement dated as of July 31, 2008 (13) |
| 10.19 | | 1992 ISDA Master Agreement, together with Schedule, dated May 15, 2007 among Wells Fargo Foothill, Inc. and the Company (4) |
| 14.1 | | Code of Conduct and Ethics(11) |
| 21.1* | | List of Subsidiaries |
| 23.1* | | Consent of DeGolyer and MacNaughton, independent petroleum engineers |
| 31.1* | | Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |
| 31.2* | | Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |
| 32.1* | | Certification pursuant to 18 U.S.C. 1350, adopted pursuant to Section 906 of the Sarbanes- Oxley Act of 2002, by Chief Executive Officer |
| 32.2* | | Certification pursuant to 18 U.S.C. 1350, adopted pursuant to Section 906 of the Sarbanes- Oxley Act of 2002, by Chief Financial Officer |
| 99.1* | | Reserve Report Of Independent Engineer |
| * | Indicates filed herewith |
| (1) | Previously filed as an exhibit to the Company’s Annual Report on Form 10-KSB for the year ended December 31, 2002, and incorporated by reference herein. |
| (2) | Previously filed as an exhibit to the Company’s Report on Form 10-Q for the quarterly period ended March 31, 2007, and incorporated by reference herein. |
| (3) | Previously filed as an exhibit to the Company’s Report on Form 8-K, filed on May 19, 2004, and incorporated by reference herein. |
| (4) | Previously filed as an exhibit to the Company’s Report on Form 8-K, filed May 21, 2007, and incorporated by reference herein. |
| (5) | Previously filed as an exhibit to the Company’s Annual Report on Form 10-KSB for year ended December 31, 2006, and incorporated by reference herein. |
| (6) | Previously filed as an exhibit to the Company’s Report on Form 8-K, filed on September 28, 2006, and incorporated by reference herein. |
| (7) | Previously filed as an exhibit to the Company’s Report on Form 8-K, filed April 18, 2007, and incorporated by reference herein. |
| (8) | Previously filed as an exhibit to the Company’s Report on Form 8-K, filed on October 24, 2005, and incorporated by reference herein. |
| (9) | Previously filed as an exhibit to the Company’s Report on Form 8-K filed on July 24, 2006, and incorporated by reference herein. |
| (10) | Previously filed as an exhibit to the Company’s Report on Form 8-K, filed May 4, 2007, and incorporated by reference herein. |
| (11) | Previously filed as an exhibit to the Company’s Report on Form 10-K filed on March 10, 2008, and incorporated by reference herein. |
| (12) | Previously filed as an exhibit to the Company’s Report on Form 8-K filed on December 30, 2008, and incorporated by reference herein. |
| (13) | Previously filed as an exhibit to the Company’s Report on Form 10-Q for the quarterly period ended June 30, 2008, and incorporated by reference herein. |
| (14) | Previously filed as an exhibit to the Company’s Report on Form 8-K filed on July 7, 2008, and incorporated by reference herein. |
43
DUNE ENERGY INC.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
F-1
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders of
Dune Energy, Inc
Houston, Texas
We have audited the accompanying consolidated balance sheets of Dune Energy, Inc (a Delaware Corporation) as of December 31, 2008 and 2007 and the related consolidated statements of operations, shareholders’ equity(deficit), and cash flows for each of the three years in the period ended December 31, 2008. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform an audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Dune Energy, Inc as of December 31, 2008 and 2007 and the results of operations and cash flows for each of the three years in the period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Dune Energy, Inc’s internal control over financial reporting as of December 31, 2008, based on criteria established inInternal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria), and our report dated March 5, 2009 expressed an unqualified opinion thereon.
/s/ Malone & Bailey, PC
Houston, Texas
March 5, 2009
F-2
Dune Energy, Inc.
Consolidated Balance Sheets
| | | | | | | | |
| | | December 31, | |
| | | 2008 | | | 2007 | |
ASSETS | | | | | | | | |
Current assets: | | | | | | | | |
Cash | | $ | 15,491,532 | | | $ | 16,771,726 | |
Accounts receivable, net of reserve for doubtful accounts of $396,629 and $396,629 | | | 14,477,918 | | | | 31,474,433 | |
Assets held for sale | | | — | | | | 76,492,464 | |
Prepayments and other current assets | | | 6,910,422 | | | | 6,764,741 | |
Derivative assets | | | 4,015,219 | | | | 837,664 | |
| | | | | | | | |
Total current assets | | | 40,895,091 | | | | 132,341,028 | |
| | | | | | | | |
Oil and gas properties, using successful efforts accounting—proved | | | 578,074,569 | | | | 518,036,814 | |
Less accumulated depreciation, depletion, amortization and impairment | | | (222,876,172 | ) | | | (41,529,191 | ) |
| | | | | | | | |
Net oil and gas properties | | | 355,198,397 | | | | 476,507,623 | |
| | | | | | | | |
Property and equipment, net of accumulated depreciation of $1,406,927 and $416,324 | | | 2,086,313 | | | | 2,632,400 | |
Deferred financing costs, net of accumulated amortization of $970,068 and $371,353 | | | 1,621,657 | | | | 2,220,372 | |
Deposit—related party | | | — | | | | 500,000 | |
Other assets | | | 2,250,868 | | | | 2,229,723 | |
| | | | | | | | |
TOTAL ASSETS | | $ | 402,052,326 | | | $ | 616,431,146 | |
| | | | | | | | |
LIABILITIES AND STOCKHOLDERS’ DEFICIT | | | | | | | | |
Current liabilities: | | | | | | | | |
Accounts payable | | $ | 21,662,965 | | | $ | 56,648,904 | |
Accrued liabilities | | | 20,038,900 | | | | 30,948,966 | |
Current debt | | | 2,013,699 | | | | 2,053,691 | |
Preferred stock dividend payable | | | 2,446,985 | | | | 1,899,330 | |
Derivative liabilities | | | — | | | | 4,131,078 | |
| | | | | | | | |
Total current liabilities | | | 46,162,549 | | | | 95,681,969 | |
Long-term debt, net of discount of $10,393,213 and $12,755,924 | | | 289,606,787 | | | | 287,244,076 | |
Deferred taxes | | | — | | | | 29,929,436 | |
Other long-term liabilities | | | 15,732,483 | | | | 16,762,462 | |
| | | | | | | | |
Total liabilities | | | 351,501,819 | | | | 429,617,943 | |
| | | | | | | | |
Commitments and contingencies | | | — | | | | — | |
Redeemable convertible preferred stock, net of discount of $9,179,927 and $10,943,172, liquidation preference of $1,000 per share, 750,000 shares designated, 236,805 and 227,918 shares issued and outstanding | | | 227,625,073 | | | | 216,974,828 | |
STOCKHOLDERS’ DEFICIT | | | | | | | | |
Preferred stock, $.001 par value, 1,000,000 shares authorized, 250,000 shares undesignated, no shares issued and outstanding | | | — | | | | — | |
Common stock, $.001 par value, 300,000,000 shares authorized, 96,129,047 and 79,258,174 shares issued and outstanding | | | 96,129 | | | | 79,258 | |
Treasury stock, at cost (34,009 and 0 shares) | | | 8,332 | | | | — | |
Additional paid-in capital | | | 50,139,148 | | | | 56,079,580 | |
Accumulated other comprehensive loss | | | (3,709,177 | ) | | | (3,831,228 | ) |
Accumulated deficit | | | (223,608,998 | ) | | | (82,489,235 | ) |
| | | | | | | | |
Total stockholders’ deficit | | | (177,074,566 | ) | | | (30,161,625 | ) |
| | | | | | | | |
TOTAL LIABILITIES AND STOCKHOLDERS’ DEFICIT | | $ | 402,052,326 | | | $ | 616,431,146 | |
| | | | | | | | |
See summary of significant accounting policies and notes to consolidated financial statements.
F-3
Dune Energy, Inc.
Consolidated Statements of Operations
| | | | | | | | | | | | |
| | | For the Year Ended December 31, | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | | | | | | | (As adjusted) | |
Revenues | | $ | 146,599,698 | | | $ | 71,199,940 | | | $ | 3,360,066 | |
| | | | | | | | | | | | |
Operating expenses: | | | | | | | | | | | | |
Lease operating expense and production taxes | | | 43,501,273 | | | | 28,603,072 | | | | 768,054 | |
Exploration expense | | | 114,950 | | | | 383,391 | | | | 2,024,431 | |
Accretion of asset retirement obligation | | | 911,012 | | | | 887,344 | | | | 24,848 | |
Depletion, depreciation and amortization | | | 56,692,441 | | | | 29,871,772 | | | | 3,430,909 | |
General and administrative expense | | | 18,470,758 | | | | 22,140,782 | | | | 4,823,582 | |
Bad debt expense | | | — | | | | 396,629 | | | | — | |
Loss on impairment of investment | | | — | | | | 3,192,250 | | | | — | |
Impairment of oil and gas properties | | | 125,694,000 | | | | — | | | | 6,911,697 | |
| | | | | | | | | | | | |
Total operating expense | | | 245,384,434 | | | | 85,475,240 | | | | 17,983,521 | |
| | | | | | | | | | | | |
Operating loss | | | (98,784,736 | ) | | | (14,275,300 | ) | | | (14,623,455 | ) |
| | | | | | | | | | | | |
Other income (expense): | | | | | | | | | | | | |
Interest income | | | 501,591 | | | | 1,672,459 | | | | 217,405 | |
Interest expense | | | (35,022,056 | ) | | | (31,070,721 | ) | | | (6,730,450 | ) |
Other expense | | | — | | | | — | | | | (494,458 | ) |
Gain (loss) on derivative liabilities | | | 4,071,507 | | | | (1,896,644 | ) | | | (33,733 | ) |
| | | | | | | | | | | | |
Total other income (expense) | | | (30,448,958 | ) | | | (31,294,906 | ) | | | (7,041,236 | ) |
| | | | | | | | | | | | |
Loss from continuing operations before income taxes | | | (129,233,694 | ) | | | (45,570,206 | ) | | | (21,664,691 | ) |
Income tax benefit | | | 20,505,873 | | | | 15,949,572 | | | | — | |
| | | | | | | | | | | | |
Loss from continuing operations | | | (108,727,821 | ) | | | (29,620,634 | ) | | | (21,664,691 | ) |
| | | | | | | | | | | | |
Discontinued operations: | | | | | | | | | | | | |
Income (loss) from operations of Barnett Shale Properties (including impairment of $43,895,525 in 2008 and $24,499,632 in 2006) | | | (41,815,505 | ) | | | 1,876,966 | | | | (23,890,677 | ) |
Income tax benefit (expense) | | | 9,423,563 | | | | (656,938 | ) | | | — | |
| | | | | | | | | | | | |
Income (loss) on discontinued operations | | | (32,391,942 | ) | | | 1,220,028 | | | | (23,890,677 | ) |
| | | | | | | | | | | | |
Net loss | | | (141,119,763 | ) | | | (28,400,606 | ) | | | (45,555,368 | ) |
Preferred stock dividend | | | (100,597,155 | ) | | | (15,196,346 | ) | | | — | |
| | | | | | | | | | | | |
Net loss available to common shareholders | | $ | (241,716,918 | ) | | $ | (43,596,952 | ) | | $ | (45,555,368 | ) |
| | | | | | | | | | | | |
Net loss per share: | | | | | | | | | | | | |
Basic and diluted from continuing operations | | $ | (2.36 | ) | | $ | (0.62 | ) | | $ | (0.37 | ) |
Basic and diluted from discontinued operations | | | (0.36 | ) | | | 0.02 | | | | (0.41 | ) |
| | | | | | | | | | | | |
Total basic and diluted | | $ | (2.72 | ) | | $ | (0.60 | ) | | $ | (0.78 | ) |
| | | | | | | | | | | | |
Weighted average shares outstanding: | | | | | | | | | | | | |
Basic and diluted | | | 88,818,086 | | | | 72,083,522 | | | | 58,583,932 | |
See summary of significant accounting policies and notes to consolidated financial statements.
F-4
Dune Energy, Inc.
Consolidated Statements of Cash Flows
| | | | | | | | | | | | |
| | | For the Year Ended December 31, | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | | | | | | | (As adjusted) | |
CASH FLOWS FROM OPERATING ACTIVITIES | | | | | | | | | | | | |
Net loss | | $ | (141,119,763 | ) | | $ | (28,400,606 | ) | | $ | (45,555,368 | ) |
Adjustments to reconcile net loss to net cash used in operating activities: | | | | | | | | | | | | |
Loss (income) from discontinued operations | | | 32,391,942 | | | | (1,220,028 | ) | | | 23,890,677 | |
Depletion, depreciation and amortization | | | 56,692,441 | | | | 29,871,772 | | | | 3,430,909 | |
Amortization of deferred financing costs and debt discount | | | 2,961,426 | | | | 7,030,353 | | | | 2,148,282 | |
Stock-based compensation | | | 5,282,671 | | | | 8,071,142 | | | | 1,324,714 | |
Realized gain on sale of investment | | | (146,210 | ) | | | | | | | | |
Loss on impairment of investment | | | — | | | | 3,192,250 | | | | — | |
Impairment of oil and gas properties | | | 125,694,000 | | | | — | | | | 6,911,697 | |
Exploration expense | | | 114,950 | | | | 383,390 | | | | 2,024,431 | |
Bad debt expense | | | — | | | | 396,629 | | | | — | |
Accretion of asset retirement obligation | | | 911,012 | | | | 887,344 | | | | 24,848 | |
Loss (gain) on derivative liabilities | | | (13,358,724 | ) | | | 2,948,403 | | | | 33,733 | |
Deferred tax benefit | | | (20,505,873 | ) | | | (15,949,572 | ) | | | — | |
Changes in: | | | | | | | | | | | | |
Accounts receivable | | | 16,082,845 | | | | (10,339,830 | ) | | | (2,253,961 | ) |
Prepayments and other assets | | | (2,448,783 | ) | | | (2,297,871 | ) | | | (27,515 | ) |
Payments made to settle asset retirement obligations | | | (1,208,920 | ) | | | — | | | | — | |
Accounts payable and accrue liabilities | | | (45,146,857 | ) | | | 51,364,642 | | | | 3,431,762 | |
| | | | | | | | | | | | |
NET CASH PROVIDED BY (USED IN) CONTINUING OPERATIONS | | | 16,196,157 | | | | 45,938,018 | | | | (4,615,791 | ) |
NET CASH PROVIDED BY DISCONTINUED OPERATIONS | | | 7,304,552 | | | | 8,269,090 | | | | 2,977,414 | |
| | | | | | | | | | | | |
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES | | | 23,500,709 | | | | 54,207,108 | | | | (1,638,377 | ) |
| | | | | | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES | | | | | | | | | | | | |
Acquisition of Goldking, net of $1,155,720 cash received | | | — | | | | (309,344,280 | ) | | | — | |
Investment in proved and unproved properties | | | (52,750,005 | ) | | | (105,357,440 | ) | | | (4,526,017 | ) |
Deposits | | | 500,000 | | | | | | | | | |
Proceeds from sale of investment | | | 424,098 | | | | | | | | | |
Purchase of furniture and fixtures | | | (546,886 | ) | | | (1,114,340 | ) | | | (23,640 | ) |
Increase in other assets | | | (21,145 | ) | | | (72,034 | ) | | | (500,000 | ) |
Increase in deposit—related party | | | — | | | | — | | | | (500,000 | ) |
| | | | | | | | | | | | |
NET CASH USED IN INVESTING ACTIVITIES—CONTINUING OPERATIONS | | | (52,393,938 | ) | | | (415,888,094 | ) | | | (5,549,657 | ) |
NET CASH USED IN INVESTING ACTIVITIES—DISCONTINUED OPERATIONS | | | 27,653,027 | | | | (47,246,404 | ) | | | (32,802,273 | ) |
| | | | | | | | | | | | |
NET CASH USED IN INVESTING ACTIVITIES | | | (24,740,911 | ) | | | (463,134,498 | ) | | | (38,351,930 | ) |
| | | | | | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES | | | | | | | | | | | | |
Proceeds from convertible preferred stock | | | — | | | | 203,677,812 | | | | — | |
Proceeds from long-term debt | | | 28,100,000 | | | | 356,909,062 | | | | 37,101,223 | |
Proceeds from short-term debt | | | 2,589,057 | | | | 3,038,007 | | | | — | |
Proceeds from sale of common stock, net | | | — | | | | — | | | | 22,103,232 | |
Proceeds from exercise of options | | | — | | | | — | | | | 100,000 | |
Payment on long-term debt issuance costs | | | — | | | | (6,286,413 | ) | | | (993,563 | ) |
Payment on preferred stock issuance costs | | | — | | | | (1,053,156 | ) | | | | |
Payments on long-term debt | | | (28,100,000 | ) | | | (104,771,263 | ) | | | (18,500,000 | ) |
Payments on long-term debt—related parties | | | — | | | | (27,423,932 | ) | | | — | |
Payments on short-term debt | | | (2,629,049 | ) | | | (1,965,706 | ) | | | — | |
| | | | | | | | | | | | |
NET CASH PROVIDED BY FINANCING ACTIVITIES | | | (39,992 | ) | | | 422,124,411 | | | | 39,810,892 | |
| | | | | | | | | | | | |
NET CHANGE IN CASH BALANCE | | | (1,280,194 | ) | | | 13,197,021 | | | | (179,415 | ) |
Cash balance at beginning of period | | | 16,771,726 | | | | 3,574,705 | | | | 3,754,120 | |
| | | | | | | | | | | | |
Cash balance at end of period | | $ | 15,491,532 | | | $ | 16,771,726 | | | $ | 3,574,705 | |
| | | | | | | | | | | | |
SUPPLEMENTAL DISCLOSURES | | | | | | | | | | | | |
Interest paid | | $ | 32,060,629 | | | $ | 21,340,567 | | | $ | 2,150,597 | |
Income taxes paid | | | — | | | | — | | | | — | |
NON-CASH DISCLOSURES | | | | | | | | | | | | |
Common stock issued for conversion of debt | | $ | — | | | $ | 2,692,250 | | | $ | — | |
Common stock issued for purchase of Goldking | | | — | | | | 18,000,000 | | | | — | |
Redeemable convertible preferred stock dividends | | | 98,833,909 | | | | 13,817,330 | | | | — | |
Asset retirement obligation revision | | | 7,402,701 | | | | 2,736,914 | | | | 273,719 | |
Deferred taxes associated with acquisition | | | — | | | | 45,222,070 | | | | — | |
Accretion of discount on preferred stock | | | 1,763,246 | | | | 1,379,016 | | | | — | |
Purchase price adjustment for asset retirement obligation | | | — | | | | 1,418,557 | | | | — | |
Common stock issued for conversion of preferred stock | | | 16,441,000 | | | | — | | | | — | |
Common stock issued for cashless exercise of options | | | 59 | | | | 73 | | | | — | |
See summary of significant accounting policies and notes to consolidated financial statements.
F-5
Dune Energy, Inc.
Consolidated Statements of Changes in Stockholders’ Equity (Deficit)
Years ended December 31, 2008, 2007 and 2006
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | Additional
Paid-In
Capital | | | Accumulated
Other
Comprehensive
Loss | | | Accumulated
Deficit | | | Total
Stockholders’
Equity (Deficit) | |
| | | Common Stock | | | Treasury Stock | | | | |
| | | Shares | | | Amount | | | Shares | | Amount | | | | |
| | | | | | | | | | | | | | | | | | | (As adjusted) | | | | |
Balance at December 31, 2005 | | 50,244,859 | | | $ | 50,244 | | | — | | $ | — | | $ | 20,093,671 | | | $ | — | | | $ | (8,533,261 | ) | | $ | 11,610,654 | |
Cash received for stock subscription | | 9,000,000 | | | | 9,001 | | | — | | | — | | | 23,840,999 | | | | — | | | | — | | | | 23,850,000 | |
Cash paid to consultant for stock subscription | | — | | | | — | | | — | | | — | | | (1,773,682 | ) | | | — | | | | — | | | | (1,773,682 | ) |
Cash received for exercise of stock options | | 133,333 | | | | 133 | | | — | | | — | | | 99,868 | | | | — | | | | — | | | | 100,001 | |
Stock issued for cashless exercise of stock options | | 51,980 | | | | 52 | | | — | | | — | | | (52 | ) | | | — | | | | — | | | | — | |
Stock-based compensation | | — | | | | — | | | — | | | — | | | 1,324,714 | | | | — | | | | — | | | | 1,324,714 | |
Net loss | | — | | | | — | | | — | | | — | | | — | | | | — | | | | (45,555,368 | ) | | | (45,555,368 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Balance at December 31, 2006 | | 59,430,172 | | | | 59,430 | | | — | | | — | | | 43,585,518 | | | | — | | | | (54,088,629 | ) | | | (10,443,681 | ) |
Stock issued for purchase of investment | | 1,380,641 | | | | 1,381 | | | — | | | — | | | 2,690,869 | | | | — | | | | — | | | | 2,692,250 | |
Stock issued for Goldking acquisition | | 10,055,866 | | | | 10,056 | | | — | | | — | | | 17,989,944 | | | | — | | | | — | | | | 18,000,000 | |
Unrealized loss on hedge contracts | | — | | | | — | | | — | | | — | | | — | | | | (3,831,228 | ) | | | — | | | | (3,831,228 | ) |
Restricted stock issued | | 8,317,946 | | | | 8,318 | | | — | | | — | | | 4,371,588 | | | | — | | | | — | | | | 4,379,906 | |
Stock issued for cashless exercise of stock options | | 73,549 | | | | 73 | | | — | | | — | | | (73 | ) | | | — | | | | — | | | | — | |
Stock-based compensation | | — | | | | — | | | — | | | — | | | 3,691,236 | | | | — | | | | — | | | | 3,691,236 | |
Preferred stock dividends | | — | | | | — | | | — | | | — | | | (13,817,330 | ) | | | — | | | | — | | | | (13,817,330 | ) |
Preferred stock issuance costs | | — | | | | — | | | — | | | — | | | (1,053,156 | ) | | | — | | | | — | | | | (1,053,156 | ) |
Accretion of discount on preferred stock | | — | | | | — | | | — | | | — | | | (1,379,016 | ) | | | — | | | | — | | | | (1,379,016 | ) |
Net loss | | — | | | | — | | | — | | | — | | | — | | | | — | | | | (28,400,606 | ) | | | (28,400,606 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Balance at December 31, 2007 | | 79,258,174 | | | | 79,258 | | | — | | | — | | | 56,079,580 | | | | (3,831,228 | ) | | | (82,489,235 | ) | | | (30,161,625 | ) |
Conversion of preferred stock | | 13,257,077 | | | | 13,258 | | | — | | | — | | | 16,427,742 | | | | — | | | | — | | | | 16,441,000 | |
Purchase of treasury stock | | — | | | | — | | | 34,009 | | | 8,332 | | | (8,332 | ) | | | — | | | | — | | | | — | |
Amortization and reclass of OCI | | — | | | | — | | | — | | | — | | | — | | | | 122,051 | | | | — | | | | 122,051 | |
Restricted stock issued | | 4,005,881 | | | | 4,006 | | | — | | | — | | | (4,006 | ) | | | — | | | | — | | | | — | |
Restricted stock cancelled | | (451,550 | ) | | | (452 | ) | | — | | | — | | | 452 | | | | — | | | | — | | | | — | |
Stock issued for cashless exercise of stock options | | 59,465 | | | | 59 | | | — | | | — | | | (59 | ) | | | — | | | | — | | | | — | |
Stock-based compensation | | — | | | | — | | | — | | | — | | | 5,282,672 | | | | — | | | | — | | | | 5,282,672 | |
Preferred stock dividends | | — | | | | — | | | — | | | — | | | (25,875,655 | ) | | | — | | | | — | | | | (25,875,655 | ) |
Accretion of discount on preferred stock | | — | | | | — | | | — | | | — | | | (1,763,246 | ) | | | — | | | | — | | | | (1,763,246 | ) |
Net loss | | — | | | | — | | | — | | | — | | | — | | | | — | | | | (141,119,763 | ) | | | (141,119,763 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Balance at December 31, 2008 | | 96,129,047 | | | $ | 96,129 | | | 34,009 | | $ | 8,332 | | $ | 50,139,148 | | | $ | (3,709,177 | ) | | $ | (223,608,998 | ) | | $ | (177,074,566 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
See summary of significant accounting policies and notes to consolidated financial statements.
F-6
DUNE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of operations and organization
Dune Energy, Inc., a Delaware corporation (“Dune” or the “Company”), is an independent energy company that was formed in 1998. Since May 2004, Dune has been engaged in the exploration, development, exploitation and production of oil and natural gas. Dune sells its oil and gas products primarily to domestic pipelines and refineries. Its operations are presently focused in the States of Texas and Louisiana.
On May 15, 2007, Dune completed the purchase of all of the issued and outstanding shares of common stock of Goldking Energy Corporation (“Goldking”) pursuant to a Stock Purchase and Sale Agreement (“SPSA”) dated effective April 13, 2007 with Goldking Energy Holdings, L.P. The accompanying consolidated financial statements include all activity for Goldking Energy Corporation from May 15, 2007 (date of acquisition). See Note 4 for discussion of the Goldking acquisition.
Consolidation
The accompanying consolidated financial statements include all accounts of Dune and its subsidiaries. All significant inter-company balances and transactions have been eliminated in consolidation.
Oil and gas properties
With the acquisition of Goldking, Dune elected to switch from full cost to successful efforts method of accounting for its investments in oil and gas properties, effective January 1, 2007. The successful efforts method is the preferable method of accounting for oil and gas properties. 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. The Company believes that, in light of the Goldking acquisition and its increased level of development and exploration activities, the successful efforts method of accounting provides a better matching of expenses to the period in which oil and gas production is realized. As a result, the Company believes that the change in accounting method was appropriate.
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 Dune to calculate depreciation, depletion and amortization expense on individual properties rather than one pool of costs. In addition, under the successful efforts method, Dune assesses its properties individually for impairment compared to one pool of costs under the full cost method.
The change in accounting method constituted a “Change in Accounting Principle,” requiring that all prior period financial statements be adjusted to reflect the results and balances that would have been reported had Dune been following the successful efforts method of accounting from its inception. The cumulative effect of the change in accounting method as of December 31, 2006 was to increase the balance of our net investment in oil and gas properties and retained earnings at that date by $4,805,966. The change in accounting method resulted in an increase (decrease) in the net loss of ($8,080,323) for the year ended December 31, 2006. The impact on earnings per share was ($.14) for the year ended December 31, 2006. The change in method of accounting had no impact on cash or working capital.
The unit-of-production method of depreciation, depletion and amortization of oil and gas properties under the successful efforts method of accounting is applied pursuant to the simple multiplication of units produced by
F-7
DUNE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
the costs per unit on a field by field basis. Leasehold cost per unit is calculated by dividing the total cost by the estimated total proved oil and gas reserves associated with that field. Well cost per unit is calculated by dividing the total cost by the estimated total proved developed oil and gas reserves associated with that field. The volumes or units produced and asset costs are known and while the proved reserves have a high probability of recoverability, they are based on estimates that are subject to some variability. Amortization expense from continuing operations amounted to $55,652,979, $29,330,321, and $3,297,424 for the years ended December 31, 2008, 2007 and 2006, respectively.
We test for impairment of our properties based on estimates of proved reserves. Proved oil and gas properties are reviewed for impairment whenever events or circumstances indicate that the carrying amount may not be recoverable. We estimate the future undiscounted cash flows of the affected properties to judge the recoverability of the carrying amounts. Initially this analysis is based on proved reserves. However, when we believe that a property contains oil and gas reserves that do not meet the defined parameters of proved reserves, an appropriately risk adjusted amount of these reserves may be included in the impairment evaluation. These reserves are subject to much greater risk of ultimate recovery. An asset would be impaired if the undiscounted cash flows were less than its carrying value. Impairments are measured by the amount by which the carrying value exceeds its fair value.
Impairment analysis is performed on an ongoing basis. In addition to using estimates of oil and gas reserve volumes in conducting impairment analysis, it is also necessary to estimate future oil and gas prices and costs, considering all available evidence at the date of review. The impairment evaluation triggers include a significant long-term decrease in current and projected prices or reserve volumes, an accumulation of project costs 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, 2008 and 2006, the Company impaired its oil and gas properties from continuing operations by $125,694,000 and $6,911,697, respectively, which are reflected in the accompanying Consolidated Statements of Operations. No impairment of oil and gas properties was recorded in 2007.
Properties not subject to amortization consist of exploration and development costs which are evaluated on a property-by-property basis. Amortization of these unproved property costs begins when the properties become proved or their values become impaired. Dune assesses the realizability of unproved properties on at least an annual basis or when there has been an indication that an impairment in value may have occurred. Impairment of unproved properties is assessed based on management’s intention with regard to future exploration and development of individually significant properties and the ability of Dune to obtain funds to finance such exploration and development. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is charged to expense. There was no impairment of unproved properties during the years ended December 31, 2008 and 2007. There were no material costs not subject to amortization as of December 31, 2008 and 2007.
Asset retirement obligation
The Company follows SFAS No. 143, “Accounting for Asset Retirement Obligations,” which requires entities to record the fair value of a liability for legal obligations associated with the retirement obligations of tangible long-lived assets in the period in which it is incurred. This standard requires the Company to record a liability for the fair value of the dismantlement and plugging and abandonment costs excluding salvage values. When the liability is initially recorded, the entity increases the carrying amount of the related long-lived asset.
F-8
DUNE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Over time, accretion of the liability is recognized each period, and the capitalized cost is amortized over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement.
Concentrations of credit risk and allowance
Substantially all of the Company’s receivables are due from oil and natural gas purchasers. The Company sold 68% of its oil and natural gas production to two customers in 2008, 52% to one customer in 2007, and 64% to four customers in 2006. Historically, credit losses incurred on receivables of the Company have not been significant.
The Company maintains an allowance for doubtful accounts on trade receivables equal to amounts estimated to be uncollectible. This estimate is based upon historical collection experience, combined with a specific review of each customer’s outstanding trade receivable balance. Dune established a reserve for doubtful accounts related to the revenue receivable from ANEC of $396,629 in 2007. Management believes that the allowance for doubtful accounts is adequate; however, actual write-offs may exceed the recorded allowance.
The Company maintains its cash in bank deposit accounts which, at times, may exceed federally insured limits. Accounts are guaranteed by the Federal Deposit Insurance Corporation (“FDIC”) up to $250,000 in 2008 and $100,000 in 2007. At December 31, 2008 and December 31, 2007, the Company had approximately $19,671,576 and $21,647,644, respectively, in excess of FDIC insured limits. The Company has not experienced any losses in such accounts.
Revenue recognition
Dune records oil and gas revenues following the entitlement method of accounting for production in which any excess amount received above Dune’s share is treated as a liability. If less than Dune’s share is received, the underproduction is recorded as an asset. Dune did not have an imbalance position in terms of volumes or values at December 31, 2008 or 2007.
Cash and cash equivalents
Cash and cash equivalents include cash in banks and highly liquid investments which mature within three months of the date of purchase.
Use of estimates
The preparation of these financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates.
The most critical estimate we make is the engineering estimate of proved oil and gas reserves. This estimate affects the application of the successful efforts method of accounting, the calculation of depreciation, depletion and amortization of oil and gas properties and the estimate of the impairment of our oil and gas properties. It also affects the estimated lives used to determine asset retirement obligations. In addition, the estimates of proved oil and gas reserves are the basis for the related standardized measure of discounted future net cash flows.
F-9
DUNE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Property and equipment
Property and equipment is valued at cost. Depreciation is computed using the straight-line method over estimated useful lives of 3 to 5 years. Additions are capitalized and maintenance and repairs are charged to expense as incurred. Gains and losses on dispositions of equipment are reflected in other income.
Deferred financing costs
In connection with debt financing, Dune paid $6,286,413 in fees for the year ended December 31, 2007. These fees were recorded as deferred financing costs and are being amortized over the life of the loans using the straight-line method which approximates the effective interest method as the principal amounts on the debt financings are due at maturity.
Amortization of deferred financing costs and debt discount for the years ended December 31, 2008, 2007 and 2006 amounted to $2,961,426, $7,030,353 and $2,148,282, respectively.
Long-lived assets
Long-lived assets including investments to be held and used or disposed of other than by sale are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. When required, impairment losses on assets to be held and used or disposed of other than by sale are recognized based on the fair value of the asset. Long-lived assets to be disposed of by sale are reported at the lower of the asset’s carrying amount or fair value less cost to sell.
During the year ended December 31, 2007, Dune acquired from parties unrelated to either entity, 8% Convertible Secured Debentures issued by American Natural Energy Corp. (“ANEC”), in the aggregate principal amount of $4,895,000. As consideration for the debentures, Dune issued a total of 1,380,641 shares of common stock valued at $1.95 per share, for aggregate consideration of $2,692,250 or 55% of the principal face amount of the debentures acquired by Dune. In 2006, Dune purchased $3 million of ANEC debentures from TransAtlantic Petroleum Corp. for a cash price of $0.5 million. Due to the poor financial condition of ANEC, Dune established a reserve for the impairment of the entire balance of the investment of $3,192,250 during the year ended December 31, 2007.
Deposit—related party
In 2006, Dune entered into a definitive contract with its largest shareholder, Itera Holdings, B.V. The terms call for the construction of and subsequent long-term contract for a drilling rig for the exclusive use on the Barnett Shale properties. The contract called for a $500,000 deposit which was to be applied to payments due at the end of the contract period. In the second quarter 2008, Dune released the drilling rig and the deposit with Itera Holdings, B.V. was forfeited due to early termination of the contract. Payments totaling $1,915,469, $7,053,700 and $1,517,744 were made during the years ended December 31, 2008, 2007 and 2006, respectively.
Derivatives
The Company follows the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities (“SFAS 133”). SFAS 133 requires the accounting recognition of all derivative instruments as either assets or liabilities at fair value. Under the provisions of SFAS 133, the Company may or may not elect to designate a derivative instrument as a hedge against changes in the fair value or an asset or a liability (a fair value hedge”) or against exposure to variability in expected future cash flows (a “cash flow hedge”).
F-10
DUNE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Effective January 1, 2008, the Company discontinued, prospectively, the designation of its derivatives as cash flow hedges. The net derivative loss related to discontinued cash flow hedges, as of December 31, 2007, will continue to be reported in accumulated other comprehensive loss until such time that they are charged to income or loss as the volumes underlying the cash flow hedges are realized.
Stock-based compensation
On January 1, 2006, Dune adopted SFAS No. 123(R), “Share-Based Payment”. SFAS 123(R) replaced SFAS No. 123 and supersedes APB Opinion No. 25. SFAS 123(R) requires all stock-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values. The pro forma disclosures previously permitted under SFAS 123 are no longer an alternative to financial statement recognition. Dune adopted SFAS 123(R) using the modified prospective method which requires the application of the accounting standard as of January 1, 2006.
Income taxes
We account for income taxes pursuant to SFAS No. 109, “Accounting for Income Taxes”, which requires recognition of deferred income tax liabilities and assets for the expected future tax consequences of events that have been recognized in our financial statements or tax returns. We provide for deferred taxes on temporary differences between the financial statements and tax basis of assets using the enacted tax rates that are expected to apply to taxable income when the temporary differences are expected to reverse.
In July 2006, the FASB issued “Accounting for Uncertainty in Income Taxes,” an interpretation of FAS 109 (“FIN 48”), effective for years beginning after December 15, 2006. FIN 48 establishes a more-likely-than-not threshold for recognizing the benefits of tax return positions in the financial statements. Also, FIN 48 implements a process for measuring those tax positions which meet the recognition threshold of being ultimately sustained upon examination by the taxing authorities. There are no uncertain tax positions taken by the Company on its tax returns and the adoption of FIN 48 had no material impact to the Company’s consolidated financial statements. The Company files tax returns in the US and states in which it has operations and is subject to taxation. Tax years subsequent to 2005 remain open to examination by U.S. federal and state tax jurisdictions.
Loss per share
Basic earnings per share amounts are calculated based on the weighted average number of shares of common stock outstanding during each period. Diluted earnings per share is based on the weighted average numbers of shares of common stock outstanding for the periods, including dilutive effects of stock options, warrants granted and convertible preferred stock. Dilutive options and warrants that are issued during a period or that expire or are canceled during a period are reflected in the computations for the time they were outstanding during the periods being reported. Since Dune has incurred losses for all periods, the impact of the common stock equivalents would be antidilutive and therefore are not included in the calculation.
Fair value of financial instruments
The Company’s financial instruments consist of cash, receivables, payables and long-term debt. The carrying amount of cash, receivables and payables approximates fair value because of the short-term nature of these items. The carrying amount of long-term debt approximates fair value due to the relationship between the interest rate on long-term debt and the Company’s incremental risk adjusted borrowing rate.
F-11
DUNE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Impact of recently issued accounting standards
On December 31, 2008, the Securities and Exchange Commission (SEC) issued the final rule, “Modernization of Oil and Gas Reporting” (“Final Rule”). The Final Rule adopts revisions to the SEC’s oil and gas reporting disclosure requirements and is effective for annual reports on Forms 10-K for years ending on or after December 31, 2009. The revisions are intended to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves to help investors evaluate their investments in oil and gas companies. The amendments are also designed to modernize the oil and gas disclosure requirements to align them with current practices and technological advances. Revised requirements in the Final Rule include, but are not limited to:
| | • | | Oil and gas reserves must be reported using a 12-month average of the closing prices on the first day of each of such months, rather than a single day year-end price: |
| | • | | Companies will be allowed to report, on a voluntary basis, probable and possible reserves, previously prohibited by SEC rules; and |
| | • | | Easing the standard for the inclusion of proved undeveloped reserves (PUDs) and requiring disclosure of information indicating any progress toward the development of PUDs. |
We are currently evaluating the potential impact of adopting the Final Rule. The SEC is discussing the Final Rule with the FASB and IASB staffs to align accounting standards with the Final Rule. These discussions may delay the required compliance date. Absent any change in such date, we will begin complying with the disclosure requirements in our annual report on Form 10-K for the year ended December 31, 2009. Voluntary early compliance is not permitted.
In June 2008, the FASB ratified the consensus reached by the EITF on Issue 07-5, “Determining Whether and Instrument (or Embedded Feature) Is Indexed to an Entity’s Own Stock” (Issue 07-5). Under Issue 07-5, an instrument (or embedded feature) would not be considered indexed to an entity’s own stock if its settlement amount is affected by variables other than those used to determine the fair value of a “plain vanilla” option or forward contract on equity shares, or if the instrument contains a feature (such as a leverage factor) that increases exposure to those variables. An equity-linked financial instrument (or embedded feature) would not be considered indexed to the entity’s own stock if the strike price is denominated in a currency other than the issuer’s functional currency. This Issue is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Early application is not permitted. The Company is currently evaluating the impact that EITF 07-5 will have on its consolidated financial position or result of operations.
In June 2008, FASB issued EITF Issue No. 08-4, “Transition Guidance for Conforming Changes to Issue No. 98-5 (“EITF No. 08-4”). The objective of EITF No. 08-4 is to provide transition guidance for conforming changes made to EITF No. 98-5, “Accounting for Convertible Securities with Beneficial Conversion Features or Contingently Adjustable Conversion Ratios”, that result from EITF No. 00-27 “Application of Issue No. 98-5 to Certain Convertible Instruments”, and SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity”. This Issue is effective for financials statements issued for fiscal years ending after December 15, 2008. The adoption did not have a material impact on our financial statements.
In March 2008, the FASB issued SFAS 161, Disclosures about Derivative Instruments and Hedging Activities. SFAS 161 is effective beginning January 1, 2009 and required entities to provide expanded disclosures about derivative instruments and hedging activities including (1) the ways in which an entity uses derivatives, (2) the accounting for derivatives and hedging activities, and (3) the impact that derivatives have (or
F-12
DUNE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
could have) on an entity’s financial position, financial performance, and cash flows. SFAS 161 requires expanded disclosures and does not change the accounting for derivatives. Dune is currently evaluating the impact of SFAS 161, but we do not expect the adoption of this standard to have a material impact on our financial results.
NOTE 2—DEBT FINANCING
Wells Fargo Foothill Credit Agreement
On May 15, 2007, Dune entered into a credit agreement among it, each of Dune’s subsidiaries named therein as borrowers, each of Dune’s subsidiaries named therein as guarantors, certain lenders and Wells Fargo Foothill, Inc. (“Wells Fargo”), as arranger and administrative agent (the “WF Agreement”). Subject to the satisfaction of a Borrowing Base formula (based on the proved producing and non-producing reserves of Dune and its operating subsidiaries), numerous conditions precedent and covenants, the WF Agreement provides for a revolving credit commitment of up to $20 million, which may be extended up to $40 million upon request by Dune so long as no Default or Event of Default exists or would exist at time of such request (the “Revolver Commitment”), with a sub-limit of $20 million for issuance of letters of credit. Effective February 29, 2008, Dune requested and received the extension up to $40 million under the Revolver Commitment. Unless earlier payment is required under the WF Agreement, advances under the Revolver Commitment must be paid on or before May 15, 2010. Under the WF Agreement, interest on advances accrues at either Wells Fargo’s Base Rate or the LIBOR rate, at Dune’s option, plus an applicable margin ranging from 0.25% to 2.0% based upon the ratio of outstanding advances and letters of credit usage under the WF Agreement to the Borrowing Base or Revolver Commitment, whichever is less. With respect to letters of credit issued under the WF agreement, fees accrue at a rate equal to the applicable margin for any LIBOR rate advances multiplied by the daily balance of the undrawn amount of all outstanding letters of credit. As of December 31, 2008, standby letters of credit were issued amounting to $8.8 million. There were no loans outstanding under the Revolver Commitment as of December 31, 2008.
As security for Dune’s obligations under the WF Agreement, Dune and certain of its operating subsidiaries granted Wells Fargo a security interest in and a first lien on all of Dune’s existing and after-acquired assets including, without limitation, the oil and gas properties and rights that Dune acquired in the Goldking acquisition. In addition, two of the Company’s subsidiaries have each guaranteed the Company’s obligations.
On August 4, 2008, Dune amended the WF agreement, pursuant to which the definitions of “Change of Control” and “Permitted Holders” were modified to provide that a Change of Control occurs when any group or person, other than Permitted Holders, becomes the beneficial owner, directly or indirectly, of 25% or more of Dune’s common stock.
Senior Secured Notes
On May 15, 2007, Dune sold to Jefferies & Company, Inc. $300 million aggregate principal amount of 10 1/2% Senior Secured Notes due 2012 (“Senior Secured Notes”) at a purchase price of $285 million. Net proceeds from the sale of the Senior Secured Notes together with the net proceeds from the sale of Dune’s Senior Redeemable Convertible Preferred Stock were used primarily to acquire all of the issued and outstanding capital stock of Goldking, to discharge outstanding indebtedness and for general working capital.
The Senior Secured Notes, bearing interest at the rate of 10 1/2% per annum, were issued under that certain indenture, dated May 15, 2007, among Dune, the guarantors named therein, and The Bank of New York Trust Company NA, as trustee (the “Indenture”). The Indenture contains customary representations and warranties by
F-13
DUNE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
the Company as well as typical restrictive covenants whereby Dune has agreed, among other things, to limitations to incurrence of additional indebtedness, declaration of dividends, issuance of capital stock, sale of assets and corporate reorganizations.
The Senior Secured Notes are subject to redemption by Dune (i) prior to June 1, 2010, in connection with equity offerings at a repurchase price equal to 110.5% of the aggregate principal amount plus accrued interest for up to 35% of the outstanding principal amount of the Senior Secured Notes, (ii) during the twelve-month period beginning June 1, 2010, at a repurchase price equal to 105.25% of the aggregate principal amount plus accrued interest, and (iii) after June 1, 2011, at a repurchase price equal to 100% of the aggregate principal amount plus accrued interest. Holders of the Senior Secured Notes may put such notes to the Company for repurchase, at a repurchase price of 101% of the principal amount plus accrued interest, upon a change in control as defined in the Indenture.
The Senior Secured Notes are secured by a lien on substantially all of Dune’s assets, including without limitation, those oil and gas leasehold interests located in Texas and Louisiana held by Dune’s operating subsidiaries. The Senior Secured Notes are unconditionally guaranteed on a senior secured basis by each of Dune’s existing and future domestic subsidiaries. The collateral securing the Senior Secured Notes is subject to, and made subordinate to, the lien granted to Wells Fargo under the WF Agreement.
The debt discount is being amortized over the life of the notes using the effective interest method. Amortization expense associated with the debt discount amounted to $2,362,711 and $1,805,084 and is included in interest expense in the Consolidated Statements of Operations for the years ended December 31, 2008 and 2007, respectively.
NOTE 3—REDEEMABLE CONVERTIBLE PREFERRED STOCK
During the quarter ended June 30, 2007, Dune sold to Jefferies & Company, Inc. pursuant to the Purchase Agreement dated May 1, 2007, 216,000 shares of its Senior Redeemable Convertible Preferred Stock (“Preferred Stock”) for gross proceeds of $216 million less a discount of $12.3 million yielding net proceeds of $203.7 million. As provided in the Certificate of Designations, the Preferred Stock has a liquidation preference of $1,000 per share and originally paid a dividend at a rate of 10% per annum, payable quarterly, at the option of Dune, in additional shares of Preferred Stock, shares of common stock (subject to the satisfaction of certain conditions) or cash. The Preferred Stock was initially convertible into shares of our common stock, based on an initial conversion price of $3.00 per share of the common stock. However, the Certificate of Designations provided a one-time adjustment to the conversion price in the event that, the volume weighted average price of the Company’s common stock for the 30 trading days up to and including April 30, 2008 was less than $2.50 per share. The Certificate of Designations also provided that, if the volume weighted average price of the Company’s common stock plus 10% over this 30 day trading period was less than $1.75, then the dividend payable on the Preferred Stock would increase. Because the volume weighted average price of the Company’s common stock was below these thresholds over this 30 day period, effective May 1, 2008, the conversion price of the Preferred Stock was lowered to $1.75 and the dividend rate increased to 12% per annum.
Additionally, in accordance with Emerging Issues Task Force (“EITF”) No. 00-27, “Application of Issue No. 98-5, Accounting for Convertible Securities with Beneficial Conversion Features or Contingently Adjustable Conversion Ratios, to Certain Convertible Instruments,” a beneficial conversion feature was triggered as a result of the one time adjustment to the conversion price on May 1, 2008. The Company attributed a discount of $68,414,051 to the Preferred Stock based upon the difference between the effective conversion price after the one-time adjustment of the shares and the closing price of the Preferred Stock on the date of issue. As the Preferred Stock does not have a stated redemption date, the discount resulting from the beneficial conversion
F-14
DUNE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
feature should be amortized from the date of issuance to the earliest conversion date. Additionally, all unamortized discount remaining at the date of conversion is recognized as a dividend. Therefore, on May 1, 2008, the Company recorded a dividend of $68,414,051 related to the beneficial conversion feature.
The conversion price of the Preferred Stock is subject to adjustment pursuant to customary anti-dilution provisions and may also be adjusted upon the occurrence of a fundamental change as defined in the Certificate of Designations. In the event a holder of Dune’s Preferred Stock elects to convert such shares prior to June 1, 2010, then such holder shall be entitled to a make whole premium consisting of the present value of all dividends on the Preferred Stock as if paid in cash from the date of conversion through June 10, 2010, computed using a discount rate equal to the reinvestment yield (as defined in the Certificate of Designations). Dune may elect to pay this amount in cash or shares of its common stock. Should the Company elect to make such payment in shares of its common stock, then such share will be valued at a 10% discount to the volume weighted average price of the Company’s common stock for the 10 trading days preceding any such conversion. The equity ownership of holders of Dune’s common stock could be significantly diluted. The Preferred Stock is redeemable at the option of the holder on December 1, 2012 and subject to the terms of any of the Company’s indebtedness or upon a change of control. In the event Dune fails to redeem shares of Preferred Stock “put” to Dune by a holder, then the conversion price shall be lowered and the dividend rate increased. After December 1, 2012, Dune may redeem shares of Preferred Stock. The Company analyzed the adjustment of the conversion right and the make whole premium for derivative accounting under SFAS 133 and EITF No. 00-19 and determined that it was not applicable to either provision.
The Preferred Stock discount is being amortized over five years using the effective interest method and is charged to paid-in capital as the Company has a deficit balance in retained earnings. Charges to paid-in capital for the years ended December 31, 2008 and 2007 amounted to $1,763,246 and $1,379,016, respectively.
During the twelve months ended December 31, 2008, holders of 16,441 shares of the Preferred Stock converted their shares into 13,257,077 shares of common stock. This amount includes 4,136,307 shares to satisfy the underlying make whole provision associated with the converted Preferred Stock. Shares issued to satisfy the make whole provision were deemed a Preferred Stock dividend and increased the Preferred Stock dividend by $4,544,203.
During the twelve months ended December 31, 2008 and 2007, Dune paid dividends on the Preferred Stock in the amount of $25,328,000 and $11,918,000, respectively. In lieu of cash, the Company elected to issue 25,328 and 11,918 additional shares of Preferred Stock, respectively.
NOTE 4—ACQUISITION
On May 15, 2007, Dune completed its purchase of all of the issued and outstanding shares of common stock of Goldking pursuant to that certain stock purchase and sale agreement dated effective April 13, 2007 with Goldking Energy Holdings, L.P.
The purchase price was $328,500,000, paid as follows: (a) $310,500,000 in cash and (b) 10,055,866 shares of Dune’s common stock, representing shares having a value of $18,000,000 based on the closing price of Dune’s common stock on April 13, 2007. The cash portion of the purchase price was financed from the net proceeds of the $516,000,000 offering of Senior Secured Notes and Preferred Stock. The Company incurred additional costs of $1,802,414 related to the acquisition.
The acquisition has been accounted for in accordance with the provisions of SFAS No. 141, “Business Combinations.” The total purchase price was allocated to the net tangible assets based on the estimated fair
F-15
DUNE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
values. The preliminary allocation of the purchase price was based upon valuation data as of May 15, 2007 and updated at December 31, 2007 to provide for a deferred tax liability related to differences in book and tax basis of oil and natural gas properties acquired. The final allocation of the purchase price is as follows:
| | | | |
Assets: | | | | |
Cash and equivalents | | $ | 1,155,720 | |
Accounts Receivable | | | 17,681,299 | |
Other current assets | | | 3,954,840 | |
Oil and natural gas properties | | | 391,438,250 | |
Other assets | | | 4,739,050 | |
| |
Liabilities: | | | | |
Accounts payable and accrued liabilities | | | (32,192,616 | ) |
Current maturities of long-term debt | | | (981,390 | ) |
Other liabilities | | | (10,270,669 | ) |
Deferred tax liability | | | (45,222,070 | ) |
| | | | |
| | $ | 330,302,414 | |
| | | | |
The following unaudited pro forma information assumes the acquisition of Goldking Energy Corporation occurred as of the beginning of each year. The pro forma results are not necessarily indicative of what actually would have occurred had the acquisition been in effect for the period presented.
| | | | | | | | |
| | | As Reported | | | Pro-Forma | |
Year ended December 31, 2007 | | | | | | |
Revenues | | $ | 71,199,940 | | | $ | 99,476,795 | |
Net loss available to common shareholders | | | (42,217,936 | ) | | | (55,527,536 | ) |
Net loss per share | | $ | (0.58 | ) | | $ | (0.73 | ) |
| | |
Year ended December 31, 2006 | | | | | | |
Revenues | | $ | 3,360,066 | | | $ | 88,718,563 | |
Net loss available to common shareholders | | | (45,555,368 | ) | | | (81,429,495 | ) |
Net loss per share | | $ | (0.78 | ) | | $ | (1.19 | ) |
NOTE 5—HEDGING AND OTHER COMPREHENSIVE LOSS
Hedging Arrangements
In accordance with a requirement of the WF Agreement, Dune and its operating subsidiaries also entered into a Swap Agreement (“Swap Agreement”) with Wells Fargo. The WF Agreement provides that Dune put in place, on a rolling six month basis, separate swap hedges, as adjusted from time to time as specified therein, with respect to notional volumes of not less than 50% and not more than 80% of the estimated aggregate production from (i) Proved Developed Producing Reserves (as defined in the WF Agreement) and (ii) estimated drilling by Dune and its subsidiaries with respect to each of crude oil and natural gas.
F-16
DUNE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
As part of the Swap Agreement, Wells Fargo assumed the rights, liabilities, duties and obligations of substantially all Goldking’s counterparties under prior crude oil and natural gas hedging arrangements between Goldking and various other banking institutions. These hedging arrangements are summarized as follows:
DUNE ENERGY, INC.
Current Hedge Positions as of December 31, 2008
Crude Oil
| | | | | | | | | | | | | | | | | | | |
Instrument | | Beg.
Date | | Ending
Date | | Floor | | Ceiling | | Fixed | | Total Bbls
2009 | | Bbl/d | | Total
Volumes |
Collar | | Jan-09 | | Dec-09 | | $ | 55.00 | | $ | 60.95 | | | | | 264,000 | | 723 | | 264,000 |
Swap/Cap | | Jan-07 | | Dec-09 | | | | | $ | 72.50 | | $ | 60.00 | | 10,080 | | 28 | | 10,080 |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | 274,080 | | 751 | | 274,080 |
| | | | | | | | | | | | | | | | | | | |
Days | | | | | | | | | | | | | | | 365 | | | | |
Hedged Daily Production | | 751 | | | | |
|
| Natural Gas |
| | | | | | | | |
Instrument | | Beg.
Date | | Ending
Date | | Floor | | Ceiling | | Fixed | | Total Mmbtu
2009 | | Mmbtu/d | | Total
Volumes |
Collar | | Jan-09 | | Dec-09 | | $ | 7.25 | | $ | 8.77 | | | | | 1,680,000 | | 4,603 | | 1,680,000 |
3-Way Collar | | Jan-07 | | Dec-09 | | $ | 6.62 | | | | | | | | 492,000 | | 1,348 | | 492,000 |
| | | | | | | | | $ | 13.35 | | $ | 6.62 | | 369,000 | | 1,011 | | 369,000 |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | 2,541,000 | | 6,962 | | 2,541,000 |
| | | | | | | | | | | | | | | | | | | |
Days | | | | | | | | | | | | | | | 365 | | | | |
Hedged Daily Production | | 6,962 | | | | |
Dune hedges a portion of forecasted crude oil and natural gas production volumes with derivative instruments. Dune uses various derivative instruments in connection with anticipated crude oil and natural gas sales to minimize the impact of commodity price fluctuations. The instruments include fixed price swaps, put options and costless collars. A collar is a combination of a purchased put option and sold call option. Dune accounts for its production hedge derivative instruments as defined in Statement of Financial Accounting Standards No. 133,“Accounting for Derivative Instruments and Hedging Activities”, as amended by SFAS No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities” and SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (herein referred as “SFAS No.133”). Under SFAS No. 133, all derivatives are recorded at fair value on the balance sheet.
Effective January 1, 2008, the Company discontinued, prospectively, the designation of its derivatives as cash flow hedges. The net derivative loss related to discontinued cash flow hedges, as of December 31, 2007, will continue to be reported in accumulated other comprehensive loss until such time that they are charged to income or loss as the volumes underlying the cash flow hedges are realized. Beginning January 1, 2008, the gain or losses on derivatives are being recognized in earnings. For the twelve months ended December 31, 2008, Dune recorded a gain on the derivatives of $4,071,507, composed of an unrealized gain on changes in mark-to-market valuations of $13,358,724 and a realized loss on cash settlements of ($9,287,217). For the years ended December 31, 2007 and 2006, Dune recorded a loss of ($1,896,644) and ($33,733), respectively. At December 31, 2008, there was an unrealized net loss on the prior year open hedge contracts of ($3,709,177).
F-17
DUNE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
| | | | | | | | | |
| | | Year Ended December 31, | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | (In thousands) | |
Net loss available to common shareholders | | (239,954 | ) | | (42,218 | ) | | (45,555 | ) |
Other comprehensive income (loss), net of tax, for unrealized gains | | | | | | | | | |
Unrealized holding gains (losses) arising during period | | — | | | (2,878 | ) | | — | |
Reclassification adjustments on settlement contracts | | — | | | (883 | ) | | — | |
Amortization of OCI | | 52 | | | — | | | — | |
Realized gain (loss) on marketable securities | | 70 | | | (70 | ) | | — | |
| | | | | | | | | |
| | 122 | | | (3,831 | ) | | — | |
| | | | | | | | | |
Total comprehensive income (loss) | | (239,832 | ) | | (46,049 | ) | | (45,555 | ) |
NOTE 6—COMMITMENTS AND CONTINGENCIES
Dune and its subsidiaries are involved in litigation in the ordinary course of business. These proceedings are subject to the uncertainties inherent in any litigation. Dune is defending itself vigorously in all such matters and does not believe that the ultimate disposition of such proceedings will have a material adverse effect on its consolidated financial position, results of operations or liquidity.
The Company, as an owner or lessee and operator of oil and gas properties, is subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations and subject the lessee to liability for pollution damages. In some instances, the Company may be directed to suspend or cease operations in the affected area. Dune maintains insurance coverage, which it believes is customary in the industry, although Dune is not fully insured against all environmental risks.
In connection with the acquisition of Goldking, the Company inherited an environmental contingency which after conducting its due diligence and subsequent testing believes is the responsibility of a third party. The matter is being reviewed by the federal regulators to deem the cause of the responsibility. While the final outcome can not be currently determined and any costs to remediate the area may not be covered by insurance, the Company does not believe it will have a material impact on its results of operations or financial position.
The Company is not aware of any other environmental claims existing as of December 31, 2008 which have not been provided for, covered by insurance or otherwise have a material impact on its financial position or results of operations. There can be no assurance, however, that current regulatory requirements will not change or past non-compliance with environmental laws will not be discovered on the Company’s properties.
The Company has a long-term operating lease agreement for its corporate offices that expires September 30, 2011. Under the terms of the lease agreement, the Company received a buildout allowance that is being amortized to expense over the term of the lease. In October 2007, the Company amended it lease agreement to expand the leased office space. The lease term for the additional space also expires in September, 2011. Rent expense for the years ended December 31, 2008, 2007 and 2006 was $0.9 million, $0.5 million, and $0.1 Million, respectively.
F-18
DUNE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Minimum rentals for each of the five years subsequent to December 31, 2008 are as follows (in thousands):
| | | |
| | | Amount |
2009 | | $ | 778 |
2010 | | | 817 |
2011 | | | 612 |
2012 | | | — |
2013 | | | — |
| | | |
| | $ | 2,207 |
| | | |
NOTE 7—RESTRICTED STOCK, STOCK OPTIONS AND WARRANTS
The Company utilizes restricted stock, stock options and warrants to compensate employees, officers, directors and consultants. Total stock-based compensation expense including options, warrants and restricted stock was $5,282,671, $8,071,142, and $1,324,714 for the years ended December 31, 2008, 2007 and 2006, respectively.
On February 1, 2006, Dune sold a total of 9,000,000 shares of common stock at a price of $2.65 per share in a private equity offering. Gross proceeds raised in the offering were $23,850,000. From the gross proceeds, Dune paid the investment bankers a placement agent fee of $1,292,500, a financial advisory fee of $477,000 and expenses of $104,184. Dune also issued a warrant exercisable for up to 900,000 shares of its common stock at an exercise price of $2.65 per share. Pursuant to rights granted by Dune to investors in the February offering, Dune was required to file a registration statement covering all shares purchased and to have such registration statement declared effective June 1, 2006. Because such registration statement was not declared effective until July 5, 2006, Dune was required to pay to the investors a registration rights penalty equal to one and one-half percent (1.5%) of their aggregate investment for each 30-day period beyond June 1, 2006. This resulted in Dune paying investors in the February offering an aggregate of $395,168 which was included in other expense in 2006.
As further consideration for amending and restating their Credit Agreement on September 26, 2006, Dune issued warrants to their lenders, exercisable for up to 500,000 shares of our common stock, at a strike price of $1.35 per share. Pursuant to a warrant agreement any unexercised warrants expire on September 26, 2015. The agreement also affords the holders certain anti-dilution protection, as well as piggy-back registration rights and limited demand registration rights. We analyzed the lender warrants for derivative accounting consideration under SFAS 133 and EITF 00-19. We determined that derivative accounting is not applicable for these lender warrants.
On January 24, 2007, Dune granted stock options for services, exercisable in the aggregate, for up to 500,000 shares of common stock to 6 non-employee directors and its president. Such options vested immediately, expire in five years and are exercisable at $1.94 per share. The fair value of the options amounted to $787,470 and was expensed in 2007. Variables used in the Black-Scholes option-pricing model include (1) risk-free interest rate of 4.4%, (2) expected option life is the actual remaining life of the options, (3) expected volatility of 112% and (4) zero expected dividends.
On April 12, 2007, our board of directors approved the grant of five year stock options for services of two individuals unaffiliated with Dune, to purchase up to an aggregate of 500,000 shares of common stock, at an exercise price of $1.87 (the closing share price on such date). The fair value of the options amounted to $747,701 and was expensed in 2007. Variables used in Black-Scholes option-pricing model include: (1) risk-free interest rate of 4.7%, (2) expected option life is the actual remaining life of the options, (3) expected volatility of 108% and (4) zero expected dividends. The options vested upon the successful completion of the Goldking acquisition on May 15, 2007. Holders of the options were also granted certain piggy-back registration rights.
F-19
DUNE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
On April 17, 2007, we entered into four new employment agreements (collectively, the “Employment Agreements”), pursuant to which we: (a) engaged James A. Watt to serve as our President and Chief Executive Officer, (b) engaged Frank T. Smith, Jr. to serve as Senior Vice President and Chief Financial Officer and (c) extended and modified our employment arrangements with each of Alan Gaines and Amiel David. Under the new employment agreements, Mr. Gaines will continue to serve as our Chairman and consented to no longer serve as Chief Executive Officer and Dr. David agreed to resign as President and Chief Operating Officer and to serve as Senior Advisor to our Board of Directors. We also entered into restricted stock agreements with each of the foregoing individuals, pursuant to which we issued 7,075,000 shares of our common stock. The issuance of these shares of restricted stock triggered anti-dilution protection contained in the September 26, 2006 Warrant Agreement with our former lender and resulted in our issuing additional warrants exercisable for 58,172 shares of our common stock, at a strike price of $1.35 per share. The fair value of the warrants amounted to $71,942. Variables used in the Black-Scholes option-pricing model include (1) risk-free interest rate of 4.7%, (2) expected warrant life is the actual remaining life of the warrants, (3) expected volatility of 108% and (4) zero expected dividends. Pursuant to the Warrant Agreement, any unexercised warrants expire on September 26, 2015. The Company analyzed these warrants for derivative accounting consideration under SFAS 133 on EITF 00.19. The determination was made that derivative accounting is not applicable for these warrants.
During the year ending December 31, 2007, option holders exercised 105,000 options on a cashless basis for 73,549 shares of common stock. This transaction resulted in an increase in common stock of $73 and a reduction in paid-in capital of $73. Dune received no cash consideration in this transaction.
The 2007 Stock Incentive Plan, which was approved by Dune’s stockholders, reserves a total of 7,000,000 shares of common stock for issuance to employees and non-employee directors. The Plan is administered by Dune’s Compensation Committee. On December 17, 2007, pursuant to its 2007 Stock Incentive Plan, the Company issued a total of 1,242,946 shares of its common stock to its employees and non-employee directors. These shares vest ratably over a three year period with the initial vesting occurring December 17, 2008. During the year ended December 31, 2008, 267,350 outstanding shares failed to vest and were cancelled.
During the year ended December 31, 2008, option holders exercised 85,000 options on a cashless basis for 59,465 shares of common stock. This transaction resulted in an increase in common stock of $59 and a reduction in paid-in capital of $59. Dune received no cash consideration in this transaction. Additionally, options to purchase 85,000 shares of common stock expired during the year ended December 31, 2008.
On March 14, 2008, the Company issued 527,058 shares of common stock related to 3 senior employees of the Company in connection with their 2007 annual bonus. Half of such bonus was paid in cash and the other half was paid in shares of restricted common stock equal to 125% of the cash portion and which vests on the one year anniversary of the grant date.
At the end of each quarter of 2008, the Company issued shares of common stock in lieu of cash for fees earned by 3 non-employee directors of the Company. These individuals made a one-time annual election at the beginning of the 2008 fiscal year to receive restricted common stock in lieu of cash for services rendered. The restricted common stock was equal to 125% of the fees to be paid and will vest on the one year anniversary of the grant date. Total issuances during the year ended December 31, 2008 amounted to 365,323 shares.
On August 1, 2008, pursuant to its 2007 Stock Incentive Plan, the Company issued a total of 3,113,500 shares of its common stock to its employees and non-employee directors. These shares vest ratably over a three year period with the initial vesting occurring August 1, 2009. During the year ended December 31, 2008, 184,200 shares were cancelled due to termination of certain employees.
F-20
DUNE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
A summary of stock option transactions follows:
| | | | | | | |
| | | Options | | | Weighted
Average
Price | |
Outstanding as of December 31, 2005 | | 2,278,333 | | | $ | 1.93 | |
Granted during 2006 | | 160,000 | | | | 2.03 | |
Cancelled or expired | | — | | | | — | |
Exercised | | (208,333 | ) | | | (0.71 | ) |
| | | | | | | |
Outstanding as of December 31, 2006 | | 2,230,000 | | | | 1.95 | |
Granted during 2007 | | 1,000,000 | | | | 1.54 | |
Cancelled or expired | | (175,000 | ) | | | (2.47 | ) |
Exercised | | (105,000 | ) | | | (1.24 | ) |
| | | | | | | |
Outstanding as of December 31, 2007 | | 2,950,000 | | | | 1.73 | |
Granted during 2008 | | — | | | | — | |
Cancelled or expired | | (85,000 | ) | | | (1.06 | ) |
Exercised | | (85,000 | ) | | | (0.54 | ) |
| | | | | | | |
Outstanding as of December 31, 2008 | | 2,780,000 | | | $ | 2.10 | |
| | | | | | | |
Options outstanding and exercisable at December 31, 2008 are as follows:
| | | | | | | |
Exercise Price | | Number of
Shares | | Remaining
Life | | Intrinsic Value
(In-the-money)
Options |
0.85 | | 25,000 | | 1.0 years | | $ | — |
1.25 | | 250,000 | | 1.2 years | | | — |
1.50 | | 50,000 | | 2.7 years | | | — |
1.87 | | 500,000 | | 3.3 years | | | — |
1.94 | | 500,000 | | 3.1 years | | | — |
2.35 | | 300,000 | | 1.8 years | | | — |
2.44 | | 1,125,000 | | 1.4 years | | | — |
2.54 | | 30,000 | | 1.7 years | | | — |
| | | | | | | |
| | 2,780,000 | | | | $ | — |
| | | | | | | |
A summary of stock warrant transactions follows:
| | | | | |
| | | Warrants | | Weighted
Average
Price |
Outstanding as of December 31, 2005 | | 324,324 | | $ | 1.57 |
Granted during 2006 | | 1,400,000 | | | 2.44 |
Cancelled or expired | | — | | | — |
Exercised | | — | | | — |
| | | | | |
Outstanding as of December 31, 2006 | | 1,724,324 | | | 2.28 |
Granted during 2007 | | 58,172 | | | 1.23 |
Cancelled or expired | | — | | | — |
Exercised | | — | | | — |
| | | | | |
Outstanding as of December 31, 2007 | | 1,782,496 | | | 2.24 |
Granted during 2008 | | — | | | — |
Cancelled or expired | | — | | | — |
Exercised | | — | | | — |
| | | | | |
Outstanding as of December 31, 2008 | | 1,782,496 | | $ | 2.24 |
| | | | | |
F-21
DUNE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Warrants outstanding and their relative exercise price at December 31, 2008 are as follows:
| | | | | | | |
Exercise Price | | Number of
Shares | | Remaining
Life | | Intrinsic Value
(In-the-money)
Warrants |
1.35 | | 558,172 | | 6.8 years | | $ | — |
1.85 | | 324,324 | | 1.8 years | | | — |
2.65 | | 900,000 | | 2.1 years | | | — |
| | | | | | | |
| | 1,782,496 | | | | $ | — |
| | | | | | | |
NOTE 8—INCOME TAXES
Dune operates through its various subsidiaries in the United States (“U.S.”); accordingly, income taxes have been provided based upon the tax laws and rates of the U.S. as they apply to Dune’s current ownership structure.
Dune accounts for income taxes pursuant to Statement of Financial Accounting Standard No. 109,Accounting for Income Taxes, which requires recognition of deferred income tax liabilities and assets for the expected future tax consequences of events that have been recognized in Dune’s financial statements or tax returns. Dune provides for deferred taxes on temporary differences between the financial statements and tax basis of assets using the enacted tax rates that are expected to apply to taxable income when the temporary differences are expected to reverse.
Dune adopted FIN 48, effective January 1, 2007. Dune recognizes interest and penalties related to unrecognized tax benefits within the provision for income taxes on continuing tax benefits. There are no unrecognized tax benefits that if recognized would affect the tax rate. There was no interest or penalties recognized as of the date of adoption or for the twelve months ended December 31, 2008. The Company files tax returns in the U.S. and states in which it has operations and is subject to taxation. Tax years subsequent to 2005 remain open to examination by taxing authorities.
Dune’s effective tax rate for continuing operations for the year ended December 31, 2008 and 2007 was approximately 15.9% and 35%, respectively. The decrease in the tax rate is due primarily to the impairment of assets and the establishment of a valuation allowance, as further described below.
Prior to 2007, the Company’s taxes were subject to a full valuation allowance. During 2007 the Company acquired the stock of Goldking and was required to step up the book basis of its oil and gas properties while using historical carryover cost for tax purposes (See Note 4). As a result, the Company has significant deferred tax liabilities in excess of its deferred tax assets. At that time, Management determined that a valuation allowance was not necessary as the realization of its deferred tax assets was more likely than not.
During the three months ended December 31, 2008, we incurred a significant impairment loss of our oil and gas properties due to the steep decline in global energy prices over that same time period. As a result, we are in a position of cumulative reporting losses for the current and preceding reporting periods. The volatility of energy prices and uncertainty of when energy prices may rebound is not readily determinable by our management. At this date, this general fact pattern does not allow us to project sufficient sources of future taxable income to offset our tax loss carryforwards and net deferred tax assets in the U.S. Under these current circumstances, it is management’s opinion that the realization of these tax attributes does not reach the “more likely than not criteria” under FAS 109. As a result, we have established a valuation allowance of $20,808,320 at December 31, 2008 against our U.S. net deferred tax assets relating to continuing operations, $5,211,864 relating to discontinued operations, and $1,298,212 relating to Other Comprehensive Income.
F-22
DUNE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
The income tax provision differs from the amount of income tax determined by applying the Federal Income Tax Rate to pre-tax income from continuing operations for the years ended December 31, 2008, 2007 and 2006 due to the following:
| | | | | | | | | | | | |
| | | Year ended December 31, | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | (in thousands) | |
Computed “expected” tax expense (benefit) | | $ | (45,232 | ) | | $ | (15,293 | ) | | $ | (18,773 | ) |
Non-deductible expenses | | | 6 | | | | 6 | | | | — | |
State taxes, net of benefit | | | (37 | ) | | | — | | | | — | |
Accrual adjustment | | | 4,162 | | | | — | | | | — | |
Other | | | (213 | ) | | | (6 | ) | | | — | |
Valuation allowance | | | 20,808 | | | | — | | | | 18,773 | |
| | | | | | | | | | | | |
Income Tax expense (benefit) | | $ | (20,506 | ) | | $ | (15,293 | ) | | $ | — | |
| | | | | | | | | | | | |
Deferred tax assets at December 31, 2008 and 2007 are comprised primarily of net operating loss carryforwards and book impairment from write downs of assets. Deferred tax liabilities consist primarily of the difference between book and tax basis depreciation, depletion and amortization (DD&A). Book basis in excess of tax basis for oil and gas properties and equipment primarily results from differing methodologies for recording property costs and depreciation, depletion and amortization under United States generally accepted accounting principles and income tax reporting. Additionally, upon the acquisition of the stock of Goldking, deferred tax liabilities have resulted for the difference in fair market value of the oil and gas properties relative to their historical tax basis.
F-23
DUNE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Following is a summary of deferred tax assets and liabilities:
| | | | | | | | |
| | | Year ended
December 31, | |
| | | 2008 | | | 2007 | |
| | | (in thousands) | |
Current deferred tax assets: | | | | | | | | |
State taxes | | $ | 95 | | | $ | 95 | |
Unrealized gains/losses | | | 257 | | | | 1,501 | |
Accrued Compensation | | | 601 | | | | — | |
Loss on sale of Discontinued Operations | | | 14,095 | | | | — | |
Derivative instruments | | | 1,298 | | | | 674 | |
| | | | | | | | |
Total current deferred tax assets | | | 16,346 | | | | 2,270 | |
| | | | | | | | |
Noncurrent deferred tax assets: | | | | | | | | |
Derivative instruments | | | — | | | | 1,351 | |
Oil and gas property and equipment (Book DD&A) | | | 40,127 | | | | 20,285 | |
Asset retirement obligation | | | 1,793 | | | | 2,341 | |
Book impairment of assets | | | 60,130 | | | | 16,137 | |
Share based compensation | | | 4,505 | | | | 2,699 | |
Loss carry forwards | | | 89,567 | | | | 78,227 | |
Other oil and gas property related | | | 1,961 | | | | 1,637 | |
Other | | | 171 | | | | 171 | |
| | | | | | | | |
Total noncurrent deferred tax assets | | | 198,254 | | | | 122,848 | |
| | | | | | | | |
Total deferred tax assets | | | 214,600 | | | | 125,118 | |
| | | | | | | | |
Current deferred tax liability | | | — | | | | — | |
Noncurrent deferred tax liabilities: | | | | | | | | |
Property and equipment (Tax DD&A) | | | 36,740 | | | | 25,914 | |
Deferred tax on acquisition | | | 72,309 | | | | 72,309 | |
Deferred state tax obligation | | | 67 | | | | — | |
Unrealized Gains/Losses | | | 3,534 | | | | — | |
Oil and gas exploration and development operations | | | 66,258 | | | | 54,627 | |
Loss on Discontinued Operations | | | 6,149 | | | | — | |
Asset retirement obligation | | | 2,032 | | | | 2,032 | |
Other | | | 193 | | | | 165 | |
| | | | | | | | |
Total noncurrent deferred tax liabilities | | | 187,282 | | | | 155,047 | |
| | | | | | | | |
Total deferred tax liabilities | | | 187,282 | | | | 155,047 | |
Net deferred tax assets (liabilities) | | | 27,318 | | | | (29,929 | ) |
Valuation allowance | | | (27,318 | ) | | | — | |
| | | | | | | | |
Net deferred income tax asset (liability) | | $ | — | | | $ | (29,929 | ) |
| | | | | | | | |
At December 31, 2008, the Company has U.S. tax loss carryforwards of approximately $255.9 million which will expire in various amounts beginning in 2020 and ending in 2029.
We have determined that as a result of the acquisition of all the outstanding stock of Goldking, a change of control pursuant to limitations set forth in Section 382 of the IRS rules and regulations occurred at the Goldking level. As a result, we will be limited to utilizing approximately $13.5 million of Goldking’s U.S. net operating
F-24
DUNE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
losses (NOL’s”) to offset taxable income generated by us during the tax year ended December 31, 2008, and expect similar dollar limits in future years until our U.S. NOL’s are either completely used or expire.
NOTE 9—ASSET RETIREMENT OBLIGATION
Changes in the Company’s asset retirement obligations were as follows:
| | | | | | | | | | |
| | | Year Ended December 31, |
| | | 2008 | | | 2007 | | 2006 |
Asset retirement obligations, beginning of period | | $ | 8,765,802 | | | $ | 377,249 | | $ | 78,682 |
Fair value of liabilities assumed in acquisitions | | | — | | | | 4,764,294 | | | — |
Liabilities related to property sales | | | (212,076 | ) | | | — | | | — |
Revisions in estimated liabilities | | | 7,402,701 | | | | 2,736,915 | | | 273,719 |
Abandonment costs | | | (1,208,920 | ) | | | — | | | — |
Accretion expense | | | 911,012 | | | | 887,344 | | | 24,848 |
| | | | | | | | | | |
Asset retirement obligations, end of period | | $ | 15,658,519 | | | $ | 8,765,802 | | $ | 377,249 |
| | | | | | | | | | |
The Company maintains an escrow agreement that has been established for the purpose of assuring maintenance and administration of a performance bond which secures certain plugging and abandonment obligations assumed by the Company in the acquisition of oil and gas properties from EnerVest. At December 31, 2008 and 2007, the amount of the escrow account totaled $2,250,868 and $2,220,574, respectively and shown as other assets.
NOTE 10—DISCONTINUED OPERATIONS
In June, 2008 Dune signed a Purchase and Sale Agreement to sell its Barnett Shale Properties located in Denton and Wise Counties, Texas for $41.5 million, subject to adjustments. The disposition of the Barnett Shale Properties allowed the Company to focus on substantially higher rates of return generated by its Gulf Coast fields, the majority of which were acquired last year. The effective date of the sale was May 1, 2008 with two closings occurring on August 29, 2008 and September 4, 2008. One final set of properties closed on December 19, 2008.
In conjunction with the sale of these assets, the Company recognized a loss of $43,895,525 in 2008 to write down the related carrying amounts to their fair value plus the cost to sell.
F-25
DUNE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Pursuant to accounting rules for discontinuing operations, Dune has classified 2008 and prior reporting periods to present the activity related to the Barnett Shale Properties as a discontinued operation. Discontinued operations for the twelve months ended December 31, 2008, 2007, and 2006 are summarized as follows:
| | | | | | | | | | | | |
| | | For the Year Ended December 31, | |
| | | 2008 | | | 2007 | | | 2006 | |
Revenues | | $ | 12,232,592 | | | $ | 12,082,104 | | | $ | 4,219,968 | |
| | | | | | | | | | | | |
Costs and expenses: | | | | | | | | | | | | |
Lease operating expense and production taxes | | | 4,928,040 | | | | 3,813,014 | | | | 1,242,554 | |
Depletion, depreciation and amortization | | | 5,224,532 | | | | 6,392,124 | | | | 2,368,459 | |
Impairment on asset | | | 43,895,525 | | | | — | | | | 24,499,632 | |
| | | | | | | | | | | | |
Total operating expense | | | 54,048,097 | | | | 10,205,138 | | | | 28,110,645 | |
| | | | | | | | | | | | |
Income (loss) from discontinued operations before income taxes | | | (41,815,505 | ) | | | 1,876,966 | | | | (23,890,677 | ) |
Provision for income taxes | | | 9,423,563 | | | | (656,938 | ) | | | — | |
| | | | | | | | | | | | |
Income (loss) on discontinued operations | | $ | (32,391,942 | ) | | $ | 1,220,028 | | | $ | (23,890,677 | ) |
| | | | | | | | | | | | |
Production: | | | | | | | | | | | | |
Oil (bbl) | | | 5,820 | | | | 12,401 | | | | 10,097 | |
Gas (mcf) | | | 1,380,527 | | | | 1,808,023 | | | | 676,623 | |
Total (mcfe) | | | 1,415,447 | | | | 1,882,429 | | | | 737,205 | |
NOTE 11—FAIR VALUE MEASUREMENTS
Dune adopted SFAS No. 157, “Fair Value Measurements,” effective January 1, 2008 for financial assets and liabilities measured on a recurring basis. SFAS No. 157 applies to all financial assets and financial liabilities that are being measured and reported on a fair value basis. In February 2008, the FASB issued FSP No. 157-2, which delayed the effective date of SFAS No. 157 by one year for nonfinancial assets and liabilities. As defined in SFAS No. 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). SFAS No. 157 requires disclosure that establishes a framework for measuring fair value and expands disclosure about fair value measurements. The statement requires fair value measurements be classified and disclosed in one of the following categories:
| Level 1 | Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. We consider active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. |
| Level 2 | Quoted prices in markets that are not active or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that we value using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange traded derivatives such as over-the-counter commodity price swaps, investments and interest rate swaps. |
| Level 3 | Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e. supported by little or no market activity). Our valuation models are primarily industry-standard models that consider various inputs |
F-26
DUNE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
| | including: (a) quoted forward prices for commodities, (b) time value, (c) volatility factors and (d) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Level 3 instruments primarily include derivative instruments, such as basic swaps, commodity price collars and floors, as well as investments. Although we utilize third party broker quotes to assess the reasonableness of our prices and valuation techniques, we do not have sufficient corroborating market evidence to support classifying these assets and liabilities as Level 2. |
As required by SFAS No. 157, financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following table summarizes the valuation of our investments and financial instruments by SFAS No. 157 pricing levels as of December 31, 2008:
| | | | | | | | | | | | |
| | | Fair Value Measurements
at December 31, 2008 Using |
| | | Level 1 | | Level 2 | | Level 3 | | Total |
Oil and gas derivative assets | | $ | — | | $ | 4,015,219 | | $ | — | | $ | 4,015,219 |
Oil and gas derivative liabilities | | | — | | | — | | | — | | | — |
| | | | | | | | | | | | |
Total | | $ | — | | $ | 4,015,219 | | $ | — | | $ | 4,015,219 |
| | | | | | | | | | | | |
NOTE 12—QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)
| | | | | | | | | | | | | | | | |
| | | Quarter Ended | |
2008 | | March 31 | | | June 30 | | | Sept 30 | | | Dec 31 | |
| | | (thousands of dollars, except per share) | |
Revenues | | $ | 36,691 | | | $ | 51,503 | | | $ | 36,304 | | | $ | 22,101 | |
Operating income (loss) (1) | | | 6,343 | | | | 19,621 | | | | 8,541 | | | | (133,290 | ) |
Net earnings (loss) available to common shareholders | | | (14,401 | ) | | | (107,830 | ) | | | 7,502 | | | | (126,988 | ) |
Net earnings (loss) per share; | | | | | | | | | | | | | | | | |
Basic (2) | | $ | (0.18 | ) | | $ | (1.24 | ) | | $ | 0.08 | | | $ | (1.34 | ) |
Diluted (2) | | | (0.18 | ) | | | (1.24 | ) | | | 0.06 | | | | (1.34 | ) |
| |
| | | Quarter Ended | |
2007 (3) | | March 31 | | | June 30 | | | Sept 30 | | | Dec 31 | |
| | | (as adjusted) (3) | | | | | | | | | | |
| | | (thousands of dollars, except per share) | |
Revenues | | $ | 829 | | | $ | 10,979 | | | $ | 23,965 | | | $ | 35,426 | |
Operating income (loss) (1) | | | (5,669 | ) | | | (8,264 | ) | | | (4,948 | ) | | | 4,606 | |
Net earnings (loss) available to common shareholders | | | (8,511 | ) | | | (22,231 | ) | | | (13,129 | ) | | | 274 | |
Net earnings (loss) per share; | | | | | | | | | | | | | | | | |
Basic and diluted (2) | | $ | (0.14 | ) | | $ | (0.31 | ) | | $ | (0.17 | ) | | $ | 0.01 | |
| (1) | Operating income (loss) is computed as revenues less lease operating expenses and production taxes, exploration expense, G&A expense, bad debt expense, loss on impairment of investment, impairment of oil and gas properties, depletion, and accretion. |
| (2) | Available to common shareholders. |
| (3) | Amounts have been adjusted to reflect the change in accounting for oil and gas properties from full cost to successful efforts. See NOTE 1 of the Company’s audited financial statements. |
F-27
DUNE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
NOTE 13—SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. Crude oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.
The Company retained Degolyer and MacNaughton, independent third-party reserve engineers, to perform an independent evaluation of proved reserves as of December 31, 2008. Results of drilling, testing and production subsequent to the date of the estimates may justify revision of such estimates. Accordingly, reserve estimates are often different from the quantities of crude oil and natural gas that are ultimately recovered. All of the Company’s reserves are located in the United States.
Proved Reserves
The following reserve schedule was developed by the Company’s reserve engineers and sets forth the changes in estimated quantities for proved reserves of the Company during each of the periods presented:
| | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | Oil | | | Gas | | | Oil | | | Gas | | | Oil | | | Gas | |
PROVED RESERVES AS OF: | | (MBbls) | | | (Mmcf) | | | (MBbls) | | | (Mmcf) | | | (MBbls) | | | (Mmcf) | |
Beginning of the period | | 9,631 | | | 117,564 | | | 440 | | | 26,764 | | | 578 | | | 26,047 | |
Revisions of previous estimates | | (873 | ) | | (5,741 | ) | | 375 | | | 5,326 | | | (191 | ) | | (11,625 | ) |
Extensions, discoveries and other additions | | 409 | | | 11,027 | | | 1,308 | | | 30,164 | | | 2 | | | 56 | |
Production | | (890 | ) | | (7,441 | ) | | (580 | ) | | (5,539 | ) | | (35 | ) | | (880 | ) |
Purchase of minerals in place | | — | | | — | | | 8,088 | | | 60,849 | | | 86 | | | 13,166 | |
Sale of minerals in place | | (78 | ) | | (31,602 | ) | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | | | | | | |
End of period | | 8,199 | | | 83,807 | | | 9,631 | | | 117,564 | | | 440 | | | 26,764 | |
| | | | | | | | | | | | | | | | | | |
Oil and Gas Operations
Aggregate results of operations, in connection with the Company’s crude oil and natural gas producing activities, for each of the periods are shown below:
| | | | | | | | | | | | |
| | | Year Ended December 31, | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | (in thousands) | |
Revenues | | $ | 146,600 | | | $ | 71,200 | | | $ | 3,360 | |
Production Costs (1) | | | (43,501 | ) | | | (28,603 | ) | | | (768 | ) |
Exploration expenses | | | (115 | ) | | | (383 | ) | | | (2,024 | ) |
DD&A and valuation provision | | | (56,692 | ) | | | (29,872 | ) | | | (3,431 | ) |
Accretion expense | | | (911 | ) | | | (887 | ) | | | (25 | ) |
Impairment of oil and gas properties | | | (125,694 | ) | | | — | | | | (6,912 | ) |
| | | | | | | | | | | | |
Income (loss) before income taxes | | | (80,313 | ) | | | 11,455 | | | | (9,800 | ) |
Income tax benefit (expense) | | | 12,743 | | | | (4,009 | ) | | | — | |
| | | | | | | | | | | | |
Income (loss) from oil and gas operations | | $ | (67,570 | ) | | $ | 7,446 | | | $ | (9,800 | ) |
| | | | | | | | | | | | |
| (1) | Production costs consist of lease operating expense, production taxes, ad valorem taxes, transportation and gathering expense, and workover expense supporting the Company’s oil and gas operations. |
F-28
DUNE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Costs incurred in Oil and Gas Activities
Costs incurred in connection with the Company’s crude oil and natural gas acquisition, exploration and development activities for each of the years are shown below:
| | | | | | | | | | | |
| | | Year Ended December 31, | |
| | | 2008 | | 2007 | | | 2006 | |
| | | (in thousands) | |
Property acquisition costs | | $ | — | | $ | 391,438 | | | $ | 36,528 | |
Unproved property | | | 1,571 | | | 455 | | | | 391 | |
Exploration costs | | | 115 | | | 383 | | | | 2,024 | |
Development costs (excluding Barnett Shale for 2008) | | | 51,064 | | | 148,161 | | | | 363 | |
ARO Costs | | | 1,209 | | | — | | | | — | |
| | | | | | | | | | | |
Total consolidated operations | | $ | 53,959 | | $ | 540,437 | | | $ | 39,306 | |
| | | | | | | | | | | |
Less Barnett Shale | | | — | | | (47,246 | ) | | | (32,802 | ) |
| | | | | | | | | | | |
Total consolidated operations excluding Barnett Shale | | $ | 53,959 | | $ | 493,191 | | | $ | 6,504 | |
| | | | | | | | | | | |
Asset retirement obligation (non-cash) | | $ | 7,403 | | $ | 2,737 | | | $ | 274 | |
| | | | | | | | | | | |
Aggregate Capitalized Costs
Aggregate capitalized costs relating to the Company’s crude oil and natural gas producing activities, including asset retirement costs and related accumulated depreciation, depletion and amortization are as follows:
| | | | | | | | |
| | | Year Ended December 31, | |
| | | 2008 | | | 2007 | |
| | | (in thousands) | |
Proved oil and gas properties | | $ | 578,075 | | | $ | 518,037 | |
Accumulated DD&A | | | (222,877 | ) | | | (41,529 | ) |
| | | | | | | | |
Net capitalized costs | | $ | 355,198 | | | $ | 476,508 | |
| | | | | | | | |
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The following information is based on the Company’s best estimate of the required data for the Standardized Measure of Discounted Future Net Cash Flows as of December 31, 2008 and 2007 in accordance with SFAS No. 69, “Disclosures About Oil and Gas Producing Activities” which requires the use of a 10% discount rate. This information is not the fair market value, nor does it represent the expected present value of future cash flows of the Company’s proved oil and gas reserves.
| | | | | | | | |
| | | Year Ended December 31, | |
| | | 2008 | | | 2007 | |
| | | (in thousands) | |
Future cash inflows | | $ | 839,990 | | | $ | 1,753,426 | |
Future production costs (1) | | | 238,300 | | | | 412,634 | |
Future development costs | | | 134,933 | | | | 200,444 | |
Future income tax expense | | | 15,195 | | | | 143,196 | |
| | | | | | | | |
Future net cash flows | | | 451,562 | | | | 997,152 | |
10% annual discount for estimated timing of cash flows | | | (167,926 | ) | | | (360,001 | ) |
| | | | | | | | |
Standardized measure of discounted future net cash flows at the end of the year | | $ | 283,636 | | | $ | 637,151 | |
| | | | | | | | |
| (1) | Production costs include oil and gas operations expense, production ad valorem taxes, transportation costs and general and administrative expense supporting the Company’s oil and gas operations. |
F-29
DUNE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Future cash inflows are computed by applying year-end prices, adjusted for location and quality differentials on a property-by-property basis, to year-end quantities of proved reserves, except in those instances where fixed and determinable price changes are provided by contractual arrangements at year-end. The discounted future cash flow estimates do not include the effects of the Company’s derivative instruments. See the following table for average prices:
| | | | | | |
| | | December 31, |
| | | 2008 | | 2007 |
Average crude oil price (per Bbl) | | $ | 40.41 | | $ | 92.66 |
Average natural gas price (per Mcf) | | $ | 6.07 | | $ | 7.32 |
Future production and development costs, which include dismantlement and restoration expense, are computed by estimating the expenditures to be incurred in developing and producing the Company’s proved crude oil and natural gas reserves at the end of the year, based on the year-end costs, and assuming continuation of existing economic conditions.
Future development costs include $40.9 million, $42.9 million and $2.2 million—that the Company expects to spend in 2009, 2010 and 2011, respectively, to develop proved non-producing and proved undeveloped reserves.
Future income tax expenses are computed by applying the appropriate year-end statutory tax rates to the estimated future pretax net cash flows relating to the Company’s proved crude oil and natural gas reserves, less the tax basis of the properties involved. The future income tax expenses give effect to tax credits and allowances, but do not reflect the impact of general and administrative costs and exploration expenses of ongoing operations relating to the Company’s proved crude oil and natural gas reserves.
Sources of Changes in Discounted Future Net Cash Flows
Principal changes in the aggregate standardized measure of discounted future net cash flows attributable to the Company’s proved crude oil and natural gas reserves, as required by SFAS No. 69, at year end are set forth in the table below:
| | | | | | | | | | | | |
| | | Year Ended December 31, | |
| | | 2008 | | | 2007 | | | 2006 | |
Standardized measure of discounted future net cash flows at the beginning of the year | | $ | 637,151 | | | | 33,636 | | | | 95,476 | |
Extensions, discoveries and improved recovery | | | 38,304 | | | | 123,375 | | | | 347 | |
Revisions of previous quantity estimates | | | (31,212 | ) | | | 13,005 | | | | (25,147 | ) |
Net change in timing | | | — | | | | — | | | | (28,668 | ) |
Changes in estimated future development costs | | | (2,223 | ) | | | (176,996 | ) | | | 5,708 | |
Purchases of minerals in place | | | — | | | | 391,438 | | | | 3,442 | |
Sale of minerals in place | | | (65,594 | ) | | | — | | | | — | |
Net changes in prices and production costs | | | (336,765 | ) | | | 239,131 | | | | (38,710 | ) |
Accretion of discount | | | 28,447 | | | | 26,815 | | | | 9,681 | |
Sales of oil and gas produced, net of production costs | | | (109,797 | ) | | | (51,918 | ) | | | (5,569 | ) |
Development costs incurred during the period | | | 43,370 | | | | 148,161 | | | | — | |
Net Change in income taxes | | | 81,955 | | | | (109,496 | ) | | | 17,076 | |
| | | | | | | | | | | | |
Standardized measure of discounted future net cash flows at the end of the year | | $ | 283,636 | | | $ | 637,151 | | | $ | 33,636 | |
| | | | | | | | | | | | |
F-30
DUNE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
SUBSEQUENT EVENT
On December 15, 2008, the Company received notice from NYSE Alternext US (“the Exchange”) indicating that the Company was not in compliance with certain conditions of the Exchange’s continued listing standards under Section 1003 of the Company guide. The notice was based on a review by the Exchange of publicly available information, including the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008. The Company submitted a plan of compliance on January 13 2009 detailing the steps anticipated in order to regain compliance with the listing standards. On February 17, 2009, the Company was granted an extension until June 15, 2010 to regain compliance with the continued listing standards of the exchange. The exchange notified the Company that they would be subject to periodic review during the extension period.
Subsequent to December 31, 2008 through February 25, 2009, holders of 5,620 shares of Preferred Stock converted their shares into approximately 8,158,779 shares of common stock.
F-31
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| | | | | | |
| | | | DUNE ENERGY, INC. |
| | | |
| Date: March 5, 2009 | | | | By: | | /s/ JAMES A. WATT |
| | | | | | James A. Watt |
| | | | | | Chief Executive Officer |
In accordance with the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities indicated below on March 5, 2009.
|
| Signature and Title |
|
| /S/ JAMES A. WATT |
| James A. Watt |
| Chief Executive Officer and Director |
|
| /S/ FRANK T. SMITH, JR. |
| Frank T. Smith, Jr. |
| Chief Financial Officer |
|
| /S/ ALAN GAINES |
| Alan Gaines |
| Chairman of the Board |
|
| /S/ RICHARD M. COHEN |
| Richard M. Cohen |
| Director and Secretary |
|
| /S/ STEVEN BARRENECHEA |
| Steven Barrenechea |
| Director |
|
| /S/ ALAN D. BELL |
| Alan D. Bell |
| Director |
|
| /S/ WILLIAM E. GREENWOOD |
| William E. Greenwood |
| Director |
|
| /S/ STEVEN M. SISSELMAN |
| Steven M. Sisselman |
