VAALCO ENERGY INC /DE/ - Annual Report: 2009 (Form 10-K)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

For the fiscal year ended December 31, 2009

OR

For the transition period from                      to                     

Commission file number: 1-32167

VAALCO Energy, Inc.

(Exact name of registrant as specified on its charter)

(Registrant’s telephone number, including area code): (713) 623-0801

Securities registered under Section 12(b) of the Exchange Act:

Securities registered under Section 12(g) of the Exchange Act:

None

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 15d of the Act    Yes            No    X

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes    X    No        .

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or such shorter period that the registrant was required to submit and post such files).    Yes            No        .

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

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

Large accelerated filer                    Accelerated filer    X             Non-accelerated filer                    Smaller reporting company         

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

The aggregate market value of the voting and non-voting common equity of the registrant held by non-affiliates, as of June 30, 2009 was $245,827,837 based on a closing price of $4.23 on June 30, 2009.

As of February 28, 2010, there were outstanding 56,427,253 shares of common stock, $0.10 par value per share, of the registrant.

Documents incorporated by reference: Definitive proxy statement of VAALCO Energy, Inc. relating to the Annual Meeting of Stockholders to be filed within 120 days after the end of the fiscal year covered by this Form, which is incorporated into Part III of this 10-K.

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VAALCO ENERGY, INC.

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Glossary of Oil and Gas Terms

Terms used to describe quantities of oil and natural gas

Terms used to describe the Company’s interests in wells and acreage

Terms used to assign a present value to the Company’s reserves

Terms used to classify the Company’s reserve quantities

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Terms which describe the productive life of a property or group of properties

Terms used to describe the legal ownership of the Company’s oil and gas properties

Terms used to describe seismic operations

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PART I

BACKGROUND

VAALCO Energy, Inc., a Delaware corporation incorporated in 1985, is a Houston-based independent energy company principally engaged in the acquisition, exploration, development and production of crude oil and natural gas. VAALCO owns producing properties and conducts exploration activities as operator in Gabon, West Africa, conducts exploration activities as operator in Angola, West Africa and conducts exploration activities as a non-operator in the British North Sea. As used herein, the terms “Company” and “VAALCO” mean VAALCO Energy, Inc. and its subsidiaries, unless the context otherwise requires. The Company’s corporate headquarters are located at 4600 Post Oak Place, Suite 309, Houston, Texas 77027 where the telephone number is (713) 623-0801.

VAALCO’s international subsidiaries are VAALCO Gabon (Etame), Inc., VAALCO Production (Gabon), Inc., VAALCO Angola (Kwanza), Inc., VAALCO UK (North Sea), Ltd., and VAALCO International Inc. VAALCO Energy (USA), Inc. holds interests in certain properties located in the United States.

RECENT DEVELOPMENTS

The Company’s primary source of revenue is from the Etame Production Sharing Contract related to the Etame Marin block located offshore the Republic of Gabon. VAALCO operates the Etame Marin block on behalf of a consortium of companies. At December 31, 2009, VAALCO owned a 30.35% interest in the exploration acreage within the Etame Marin block. The Company owns a 28.1% interest in the development areas surrounding the Etame, Avouma, South Tchibala and Ebouri fields. The development areas were subject to a 7.5% back-in by the Government of Gabon, which occurred for these fields after their successful development.

The Company produces from the Etame, Avouma, South Tchibala and Ebouri fields on the block. Oil production commenced from the Etame field in September 2002, from the Avouma and South Tchibala fields in January 2007, and from the Ebouri field in January 2009. During 2009, the Etame, Avouma, South Tchibala and Ebouri fields produced approximately 8.3 million bbls (1.9 million bbls net to the Company).

Beginning in November 2008, drilling began on the first of two exploration wells within the Etame Marin block. The first of these wells, the North Ebouri, encountered substantial oil-filled Gamba sandstone, proving-up significant additional reserves North of the originally mapped Ebouri field development outline. The second well, the North Etame prospect, encountered water bearing sands and was abandoned. Also beginning in November 2008, drilling began on the first of two development wells in the Ebouri field. Both wells were brought onto production in 2009.

Onshore Gabon, the Company has a 100% working interest in the Mutamba Iroru block located near the coast in central Gabon. The Mutamba Iroru block contains an exploration area of approximately 270,000 acres. Two exploration wells were drilled in 2009 and both wells encountered water bearing sands and were abandoned.

Exploration period extensions were successfully negotiated with the government of Gabon on both of the blocks under contract. The Etame Marin block received a four year extension expiring in 2014 and the Mutamba Iroru block received a two year extension expiring in 2011.

In November 2006, the Company signed a production sharing contract for a 40% working interest in Block 5 offshore Angola. The four year contract with an optional three year extension awards the Company exploration rights to approximately 1.4 million acres along the central coast of Angola. The Company has been interpreting seismic data in preparation for the drilling of two exploration wells. The government-assigned working interest partner has been delinquent on paying their share of the costs several times in 2009 and consequently was placed

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in a default position which has impacted the timing for drilling the wells. In early 2010, the Company began the process to acquire the interest of the non-performing partner and is working with the government of Angola regarding a time extension for the drilling of the commitment wells beyond the November 2010 expiration date. While we believe that the government of Angola will grant us an extension, we can provide no assurances. If the government of Angola were to deny a time extension, the Company risks forfeiture of its $10 million funds in escrow if the wells are not drilled by November 2010 plus the Company may be required to impair its leasehold costs and other investments of $11.4 million as of December 31, 2009. If we are successful in obtaining such extension, the Company estimates the drilling will take place in the first half of 2011 on this block in Angola.

In January 2008, the Company signed a farm-in agreement for a 25% working interest in Block 48/25c offshore in the British North Sea. In February 2009, the Company participated in a well drilled on the block in the Southern Gas Basin. A substantial gas column was found but with low permeability and porosity. The well was deemed to be non-commercial by the consortium and was abandoned.

See Note 14 to the Company’s consolidated financial statements for financial information about the Company’s segments.

AVAILABLE INFORMATION

The Company files annual, quarterly and current reports, proxy statements and other information with the Securities and Exchange Commission. You may read and copy any document the Company files at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the SEC’s Public Reference Room. The Company’s SEC filings are also available to the public at the SEC’s website at www.sec.gov.

You may also obtain copies of the Company’s annual, quarterly and current reports, proxy statements and certain other information filed with the SEC, as well as amendments thereto, free of charge from the Company’s website at www.vaalco.com. No information from the SEC’s or the Company’s website is incorporated by reference herein. The Company has placed on its website copies of its Audit Committee Charter, Code of Business Conduct and Ethics, and Code of Ethics for the Chief Executive Officer and Chief Financial Officer. Stockholders may request a printed copy of these governance materials by writing to the Corporate Secretary, VAALCO Energy Inc., 4600 Post Oak Place, Suite 309, Houston, Texas 77027.

GENERAL

The Company’s current production strategy is to maximize the value of the reserves discovered in Gabon through exploitation of the Etame Marin block (comprised of the Etame, Avouma, South Tchibala and Ebouri fields). The Company also owns a 100% working interest in the 270,000 acre Mutamba Iroru block onshore Gabon and a 40% working interest in the 1.4 million acre Block 5 offshore Angola where, along with the Etame Marin Block, exploration activities take place.

International

The Company’s international strategy is to pursue selected opportunities that are characterized by reasonable entry costs, favorable economic terms, high reserve potential relative to capital expenditures and the availability of existing technical data that may be further developed. The Company believes that it has unique management and technical expertise in identifying international opportunities and establishing favorable operating relationships with host governments and local partners familiar with the local practices and infrastructure. The Company owns producing properties and conducts exploration activities as operator of two exploration licenses in Gabon, and one exploration license in Angola.

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Domestic

The Company’s domestic strategy is to produce existing reserves. There are no plans to drill new domestic wells at this time. Current domestic properties are located in Brazos County, Texas and offshore Louisiana in the Ship Shoal area.

CUSTOMERS

Substantially all of the Company’s oil and gas is sold at posted or indexed prices under short-term contracts, as is customary in the industry. In Gabon, the Company sold oil under a contract with Total Oil Trading S.A. which ran through calendar year 2009. For the 2010 calendar year, the Company will sell its oil under a contract with Vitol S.A. (“Vitol”). While the loss of Vitol as a buyer might have a material effect on the Company in the short term, management believes that the Company would be able to obtain other customers for its crude oil. Domestic production is sold via two contracts, one for oil and one for gas. The Company has access to several alternative buyers for oil and gas sales domestically.

EMPLOYEES

As of December 31, 2009, the Company had 77 full-time employees and consultant contractors, 44 of whom were located in Gabon and nine of whom were located in Angola. The Company is not subject to any collective bargaining agreements, although most of the national employees in Gabon are members of the NEOP (National Organization of Petroleum Workers) union. The Company believes its relations with its employees are satisfactory.

COMPETITION

The oil and gas industry is highly competitive. Competition is particularly intense with respect to acquisitions of desirable oil and gas reserves. There is also competition for the acquisition of oil and gas leases suitable for exploration and the hiring of experienced personnel. In addition, the producing, processing and marketing of oil and gas is affected by a number of factors beyond the control of the Company, the effects of which cannot be accurately predicted.

The Company’s competition for acquisitions, exploration, development and production include the major oil and gas companies in addition to numerous independent oil companies, individual proprietors, investors and others. Many of these competitors possess financial and personnel resources substantially in excess of those available to the Company, giving those competitors an enhanced ability to evaluate and acquire desirable leases properties or prospects. The ability of the Company to generate reserves in the future will depend on its ability to select and acquire suitable producing properties and prospects for future drilling and exploration.

ENVIRONMENTAL REGULATIONS

General

The Company’s activities are subject to federal, state and local laws and regulations governing environmental quality and pollution control in the United States, Gabon and Great Britain and will be subject to the laws and regulations of Angola when exploration drilling begins. Although no assurances can be made, the Company believes that, absent the occurrence of an extraordinary event, compliance with existing laws, rules and regulations regulating the release of materials in the environment or otherwise relating to the protection of the environment will not have a material effect upon the Company’s capital expenditures, earnings or competitive position with respect to its existing assets and operations. The Company cannot predict what effect future regulation or legislation, enforcement policies, and claims for damages to property, employees, other persons and the environment resulting from the Company’s operations could have on its activities. In part because they are developing countries, it is unclear how quickly and to what extent Gabon or Angola will increase their regulation

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of environmental issues in the future; any significant increase in the regulation or enforcement of environmental issues by Gabon or Angola could have a material effect on the Company. Developing countries, in certain instances, have patterned environmental laws after those in the United States which are discussed below. However, the extent to which any environmental laws are enforced in developing countries varies significantly.

Environmental Regulations in the United States

Solid and Hazardous Waste

The Company currently owns or leases, and in the past has owned or leased, properties that have been used for the exploration and production of oil and gas for many years. Although the Company has utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other solid wastes may have been disposed or released on or under the properties owned or leased by the Company or on or under locations where such wastes have been taken for disposal. In addition, some of these properties are or have been operated by third parties. The Company has no control over such entities’ treatment of hydrocarbons or other solid wastes and the manner in which such substances may have been disposed or released. State and federal laws applicable to oil and gas wastes and properties have gradually become stricter over time. The Company could, in the future, be required to remediate property, including groundwater, containing or impacted by previously disposed wastes (including wastes disposed or released by prior owners or operators, or property contamination, including groundwater contamination by prior owners or operators) or to perform remedial plugging operations to prevent future or mitigate existing contamination.

The Company generates wastes, including hazardous wastes that are subject to the federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes. The Environmental Protection Agency (“EPA”) and various state agencies have limited the disposal options for certain wastes, including wastes designated as hazardous under RCRA and state analogs (“Hazardous Wastes”). Furthermore, although oil and gas wastes generally are exempt from regulation as hazardous waste, it is possible that certain wastes generated by the Company’s oil and gas operations that are currently exempt may in the future be designated as Hazardous Wastes under RCRA or other applicable statutes and, therefore, may be subject to more rigorous and costly disposal requirements.

Superfund

The federal Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “Superfund” law, generally imposes joint and several liability for costs of investigation and remediation and for natural resource damages, without regard to fault or the legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances (“Hazardous Substances”). These classes of persons, or so-called potentially responsible parties (“PRPs”), include the current and certain past owners and operators of a facility where there has been a release or threat of release of a Hazardous Substance and persons who disposed of or arranged for the disposal of Hazardous Substances found at a site. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the PRPs the costs of such action.

Although CERCLA generally exempts “petroleum” from the definition of Hazardous Substance, in the course of its operations, the Company has generated, and will generate, wastes that may fall within CERCLA’s definition of Hazardous Substance and may have disposed of these wastes at disposal sites owned and operated by others. The Company may also be the owner or operator of sites on which Hazardous Substances have been released. To its knowledge, neither the Company nor its predecessors have been designated as a PRP by the EPA under CERCLA; the Company also does not know of any prior owners or operators of its properties that are named as PRPs related to their ownership or operation of such properties. States such as Texas have comparable statutes. In the event contamination is discovered at a site on which the Company is or has been an owner or operator or to which the Company sent Hazardous Substances, the Company could be liable for costs of investigation and remediation and natural resources damages.

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Clean Water Act

The Clean Water Act (“CWA”) imposes restrictions and strict controls regarding the discharge of wastes, including produced waters and other oil and natural gas wastes, into waters of the United States, a term broadly defined. These controls have become more stringent over the years, and it is probable that additional restrictions will be imposed in the future. Permits must be obtained to discharge pollutants into federal waters. The CWA provides for civil, criminal and administrative penalties for unauthorized discharges of oil and hazardous substances and of other pollutants. It imposes substantial potential liability for the costs of removal or remediation associated with discharges of oil or hazardous substances and other pollutants. State laws governing discharges to water also provide varying civil, criminal and administrative penalties and impose liabilities in the case of a discharge of petroleum or its derivatives, or other hazardous substances, into state waters. In addition, the EPA has promulgated regulations that may require the Company to obtain permits to discharge storm water runoff, including discharges associated with construction activities. In the event of an unauthorized discharge of wastes, the Company may be liable for penalties and costs.

Oil Pollution Act

The Oil Pollution Act of 1990 (“OPA”), which amends and augments oil spill provisions of the CWA, imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening United States waters or adjoining shorelines. A liable “responsible party” includes the owner or operator of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge, or in the case of offshore facilities, the lessee or permittee of the area in which a discharging facility is located. OPA assigns joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses exist to the liability imposed by OPA, they are limited. In the event of an oil discharge or substantial threat of discharge, the Company may be liable for costs and damages.

The OPA also imposes ongoing requirements on a responsible party, including proof of financial responsibility to cover at least some costs in a potential spill. Certain amendments to the OPA that were enacted in 1996 require owners and operators of offshore facilities that have a worst case oil spill potential of more than 1,000 bbls to demonstrate financial responsibility in amounts ranging from $10 million in specified state waters and $35 million in federal outer continental shelf (“OCS”) waters, with higher amounts, up to $150 million based upon worst case oil-spill discharge volume calculations. The Company believes that it has established adequate proof of financial responsibility for its offshore facilities.

Endangered Species Act.

The Endangered Species Act (“ESA”) was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The U.S. Fish and Wildlife Service must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development. If the Company were to have a portion of its leases designated as critical or suitable habitat, it may adversely impact the value of the affected leases.

Climate Change Legislation

More stringent laws and regulations relating to climate change and greenhouse gases (“GHGs”) may be adopted in the future and could cause us to incur material expenses in complying with them. The U.S. Congress has considered climate change related legislation to regulate GHG emissions that could affect our operations and our regulatory costs, as well as the value of oil and natural gas generally. A climate change bill passed the United States House of Representatives but the Senate has not passed climate legislation. The House bill would establish

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a “cap-and-trade” program under which overall GHG emissions are limited and allowances to emit GHGs are then allocated and/or sold. Although Congress has not passed comprehensive climate change legislation, expectations are that Congress will continue to consider some type of climate change legislation. There is a great deal of uncertainty as to how and when federal regulation of GHGs might take place. In the absence of federal legislative action on climate change, the EPA has initiated a number of rulemakings, the result of which would be the regulation of GHG emissions under the Clean Air Act. Further, the EPA has enacted a mandatory greenhouse gas reporting program which imposes reporting and monitoring requirements on the covered industries; we do not believe our operations to be subject to this program, but there is no guarantee that the EPA will not expand the program to additional industries. Should we be required to report GHG emissions, it could require us to incur costs to monitor, keep records of, and report emissions of GHGs. In addition to possible federal regulation, a number of states, individually and regionally, also are considering or have implemented GHG regulatory programs. These federal and state initiatives may result in regulatory requirements that could result in our incurring material expenses to comply, e.g., by being required to purchase or to surrender allowances for GHGs resulting from our operations under a cap-and-trade program, or installing pollution control equipment to control emissions under the Clean Air Act. These regulatory initiatives also could adversely affect the marketability of the oil and natural gas the Company produces. The impact of such future programs cannot be predicted, but the Company does not expect its operations to be affected any differently than other similarly situated domestic competitors.

Air Emissions

The Company’s operations are subject to local, state and federal regulations for the control of emissions from sources of air pollution. Federal and state laws require new and modified sources of air pollutants to obtain permits prior to commencing construction. Major sources of air pollutants are subject to more stringent, federally imposed requirements including additional permits. Federal and state laws designed to control hazardous (toxic) air pollutants, might require installation of additional controls. Administrative enforcement actions for failure to comply strictly with air pollution regulations or permits are generally resolved by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies could bring lawsuits for civil penalties or require the Company to forego construction, modification or operation of certain air emission sources.

Coastal Coordination

There are various federal and state programs that regulate the conservation and development of coastal resources. The federal Coastal Zone Management Act (“CZMA”) was passed in 1972 to preserve and, where possible, restore the natural resources of the Nation’s coastal zone. The CZMA provides for federal grants for state management programs that regulate land use, water use and coastal development.

In Texas, the Legislature enacted the Coastal Coordination Act (“CCA”), which provides for the coordination among local and state authorities to protect coastal resources through regulating land use, water, and coastal development. The act establishes the Texas Coastal Management Program (“CMP”). The CMP is limited to the nineteen counties that border the Gulf of Mexico and its tidal bays. The act provides for the review of state and federal agency rules and agency actions for consistency with the goals and policies of the Coastal Management Plan. This review may impact agency permitting and review activities and add an additional layer of review to certain activities undertaken by the Company.

OSHA and other Regulations

The Company is subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require the Company to organize and/or disclose information about hazardous materials used or produced in its operations. The Company believes that it is in substantial compliance with these applicable requirements.

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FORWARD-LOOKING STATEMENTS

This Report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934, which are intended to be covered by the safe harbors created by those laws. The Company has based these forward-looking statements on its current expectations and projections about future events. These forward-looking statements include information about possible or assumed future results of the Company’s operations. All statements, other than statements of historical facts, included in this Report that address activities, events or developments that the Company expects or anticipates may occur in the future, including without limitation, statements regarding the Company’s financial position, reserve quantities and net present values, business strategy, plans and objectives of the Company’s management for future operations are forward-looking statements. When the Company uses words such as “anticipate,” “believe,” “estimate,” “expect,” “intend,” “plan,” “probably” or similar expressions, the Company is making forward-looking statements. Many risks and uncertainties may impact the matters addressed in these forward-looking statements.

Some of the events or factors that could affect the Company’s future results and could cause results to differ materially from those expressed in the Company’s forward-looking statements include:

The information contained in this Report, including the information set forth under the heading “Risk Factors,” identifies additional factors that could cause the Company’s results or performance to differ materially from those the Company expresses in its forward-looking statements. Although the Company believes that the assumptions underlying its forward-looking statements are reasonable, any of these assumptions and therefore also the forward-looking statements based on these assumptions, could themselves prove to be inaccurate. In light of the significant uncertainties inherent in the forward-looking statements which are included in this Report, the Company’s inclusion of this information is not a representation by the Company or any other person that the Company’s objectives and plans will be achieved. When you consider the Company’s forward-looking statements, you should keep in mind these risk factors and the other cautionary statements in this Report.

The Company’s forward-looking statements speak only as of the date made and the Company will not update these forward-looking statements unless the securities laws require the Company to do so. The Company’s forward-looking statements are expressly qualified in their entirety by this cautionary statement. In light of these risks, uncertainties and assumptions, any forward-looking events discussed in this Report may not occur.

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You should carefully consider the following risk factors in addition to the other information included in this Report. If any of these risks or uncertainties actually occurs, our business, financial condition and results of operations could be materially adversely affected. Additional risks not presently known to us or which we consider immaterial based on information currently available to us may also materially adversely affect us. In this section, the terms “VAALCO”, “we”, “us” and “our” refer to VAALCO Energy, Inc. and its subsidiaries, unless the context clearly indicates otherwise.

Almost all of the value of our production and reserves is concentrated in a single block offshore Gabon, and any production problems or reductions in reserve estimates related to this property would adversely impact our business.

The Etame field consisting of four producing wells, the Avouma and South Tchibala fields consisting of one producing well each, and the Ebouri field with two producing wells constituted almost 100% of our total production for the year ended December 31, 2009. In addition, at December 31, 2009, almost 100% of our total net proved reserves were attributable to these fields. If mechanical problems, storms or other events curtailed a substantial portion of this production, or if the actual reserves associated with this producing property are less than our estimated reserves, our results of operations and financial condition could be materially adversely affected.

Our results of operations and financial condition could be adversely affected by changes in currency exchange rates.

Our results of operations and financial condition are affected by currency exchange rates. While oil sales are denominated in U.S. dollars, portions of our operating costs in Gabon are denominated in the local currency. A weakening U.S. Dollar will have the effect of increasing operating costs while a strengthening U.S. Dollar will have the effect of reducing operating costs. The Gabon local currency is tied to the Euro. The exchange rate between the Euro and the U.S. dollar has fluctuated widely in response to international political conditions, general economic conditions and other factors beyond our control.

A decrease in oil and gas prices may adversely affect our results of operations and financial condition.

Our revenues, cash flow, profitability and future rate of growth are substantially dependent upon prevailing prices for oil and gas. Our ability to borrow funds and to obtain additional capital on attractive terms is also substantially dependent on oil and gas prices. Historically, world-wide oil and gas prices and markets have been volatile, particularly in 2008 and 2009, and are likely to continue to be volatile in the future. The average price for crude we sold from Gabon in 2009 was $59.54 per barrel compared to $92.87 per barrel in 2008 and $71.16 per barrel in 2007.

Prices for oil and gas are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors that are beyond our control. These factors include international political conditions, the domestic and foreign supply of oil and gas, the level of consumer demand, weather conditions, domestic and foreign governmental regulations, the price and availability of alternative fuels, the health of international economic and credit markets, and general economic conditions. In addition, various factors, including the effect of federal, state and foreign regulation of production and transportation, general economic conditions, changes in supply due to drilling by other producers and changes in demand may adversely affect our ability to market our oil and gas production. Any significant decline in the price of oil or gas would adversely affect our revenues, operating income, cash flows and borrowing capacity and may require a reduction in the carrying value of our oil and gas properties and our planned level of capital expenditures.

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If there is a sustained economic downturn or recession in the United States or globally, oil and natural gas prices may fall and may become and remain depressed for a long period of time, which may adversely affect our results of operations.

We experienced an economic downturn or a recession in the United States and globally. The reduced economic activity associated with the economic downturn or recession may reduce the demand for, and the prices we receive for, our oil and gas production. A sustained reduction in the prices we receive for our oil and gas production will have a material adverse effect on our results of operations.

Unless we are able to replace reserves which we have produced, our cash flows and production will decrease over time.

Our future success depends upon our ability to find, develop or acquire additional oil and gas reserves that are economically recoverable. Except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, our estimated net proved reserves will generally decline as reserves are produced. There can be no assurance that our planned development and exploration projects and acquisition activities will result in significant additional reserves or that we will have continuing success drilling productive wells at economic finding costs. The drilling of oil and gas wells involves a high degree of risk, especially the risk of dry holes or of wells that are not sufficiently productive to provide an economic return on the capital expended to drill the wells. In addition, our drilling operations may be curtailed, delayed or canceled as a result of numerous factors, including title problems, weather conditions, political instability, availability of capital, economic/currency imbalances, compliance with governmental requirements, receipt of additional seismic data or the reprocessing of existing data, material changes in oil or gas prices, prolonged periods of historically low oil and gas prices, failure of wells drilled in similar formations or delays in the delivery of equipment and availability of drilling rigs. Our current domestic oil and gas properties are operated by third parties and, as a result, we have limited control over the nature and timing of exploration and development of such properties or the manner in which operations are conducted on such properties.

Substantial capital, which may not be available to us in the future, is required to replace and grow reserves.

We make, and will continue to make, substantial capital expenditures for the acquisition, exploitation, development, exploration and production of oil and gas reserves. Historically, we have financed these expenditures primarily with cash flow from operations, debt, asset sales, and private sales of equity. During 2009, we participated, and in 2010 we expect to continue to participate, in the further exploration and development projects on our international properties. In Gabon and Angola, we are the operator of the blocks and are thus responsible for contracting on behalf of all the remaining parties participating in the project. We rely on the timely payment of cash calls by our partners to pay for the 69.65% share of the Etame budget and 50% of the Angola Block 5 budget for which they are responsible. However, if lower oil and gas prices, operating difficulties or declines in reserves result in our revenues being less than expected or limit our ability to borrow funds, or our partners fail to pay their share of project costs, we may have a limited ability, particularly in the current economic environment, to expend the capital necessary to undertake or complete future drilling programs. We cannot assure that additional debt or equity financing or cash generated by operations will be available to meet these requirements.

We may need access to the capital markets to fund a portion of our growth strategy. The recent unprecedented disruption in the capital markets may adversely affect our growth strategy.

During 2008 and 2009, the U.S. and international financial markets experienced unprecedented volatility and disruption. This disruption in the financial markets made it difficult for companies to successfully issue common stock or debt securities to fund growth. If the effects of disruption in the financial markets continues for a substantial period of time or if a disruption reoccurs, our ability to fund growth may be adversely affected.

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Our drilling activities require us to risk significant amounts of capital that may not be recovered.

Drilling activities are subject to many risks, including the risk that no commercially productive reservoirs will be encountered. There can be no assurance that new wells drilled by us will be productive or that we will recover all or any portion of our investment. Drilling for oil and gas may involve unprofitable efforts, not only from dry wells, but also from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. The cost of drilling, completing and operating wells is often uncertain and cost overruns are common. Our drilling operations may be curtailed, delayed or canceled as a result of numerous factors, many of which are beyond our control, including title problems, weather conditions, compliance with governmental requirements and shortages or delays in the delivery of equipment and services.

Weather, unexpected subsurface conditions and other unforeseen operating hazards may adversely impact our oil and gas activities.

The oil and gas business involves a variety of operating risks, including fire, explosions, blow-outs, pipe failure, casing collapse, abnormally pressured formations and environmental hazards such as oil spills, gas leaks, ruptures and discharges of toxic gases, the occurrence of any of which could result in substantial losses to us due to injury and loss of life, severe damage to and destruction of property, natural resources and equipment, pollution and other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. Our production facilities are also subject to hazards inherent in marine operations, such as capsizing, sinking, grounding, collision and damage from severe weather conditions. The relatively deep offshore drilling conducted by us overseas involves increased drilling risks of high pressures and mechanical difficulties, including stuck pipe, collapsed casing and separated cable. The impact that any of these risks may have upon us is increased due to the low number of producing properties we own.

We maintain insurance against some, but not all, potential risks; however, there can be no assurance that such insurance will be adequate to cover any losses or exposure for liability. The occurrence of a significant unfavorable event not fully covered by insurance could have a material adverse effect on our financial condition, results of operations and cash flows. Furthermore, we cannot predict whether insurance will continue to be available at a reasonable cost or at all.

Our reserve information represents estimates that may turn out to be incorrect if the assumptions upon which these estimates are based are inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present values of our reserves.

There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves, including many factors beyond our control. Reserve engineering is a subjective process of estimating the underground accumulations of oil and gas that cannot be measured in an exact manner. The estimates included in this document are based on various assumptions required by the SEC, including unescalated prices and costs and capital expenditures subsequent to December 31, 2009, and, therefore, are inherently imprecise indications of future net revenues. Actual future production, revenues, taxes, operating expenses, development expenditures and quantities of recoverable oil and gas reserves may vary substantially from those assumed in the estimates. Any significant variance in these assumptions could materially affect the estimated quantity and value of reserves incorporated by reference in this document. In addition, our reserves may be subject to downward or upward revision based upon production history, results of future development, availability of funds to acquire additional reserves, prevailing oil and gas prices and other factors. Moreover, the calculation of the estimated present value of the future net revenue using a 10% discount rate as required by the SEC is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with our reserves or the oil and gas industry in general. It is also possible that reserve engineers may make different estimates of reserves and future net revenues based on the same available data.

The estimated future net revenues attributable to our net proved reserves are prepared in accordance with current SEC guidelines, and are not intended to reflect the fair market value of our reserves. The SEC amended the definition of proved reserves for all reserve estimated included in filings after January 1, 2010. As a result,

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the estimates of proved reserves filed in reports prior to January 1, 2010 may not be comparable to reports filed after that date, including those in this annual report. In accordance with the rules of the SEC, our reserve estimates are prepared using an average of beginning of month prices received for oil and gas for the preceding twelve months. Future reductions in prices below the average calculated for 2009 would result in the estimated quantities and present values of our reserves being reduced.

A substantial portion of our proved reserves are or will be subject to service contracts, production sharing contracts and other arrangements. The quantity of oil and gas that we will ultimately receive under these arrangements will differ based on numerous factors, including the price of oil and gas, production rates, production costs, cost recovery provisions and local tax and royalty regimes. Changes in many of these factors do not affect estimates of U.S. reserves in the same way they affect estimates of proved reserves in foreign jurisdictions, or will have a different effect on reserves in foreign countries than in the United States. As a result, proved reserves in foreign jurisdictions may not be comparable to proved reserve estimates in the United States.

We have less control over our foreign investments than domestic investments, and turmoil in foreign countries may affect our foreign investments.

Our international assets and operations are subject to various political, economic and other uncertainties, including, among other things, the risks of war, expropriation, nationalization, renegotiation or nullification of existing contracts, taxation policies, foreign exchange restrictions, changing political conditions, international monetary fluctuations, currency controls and foreign governmental regulations that favor or require the awarding of drilling contracts to local contractors or require foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. In addition, if a dispute arises with foreign operations, we may be subject to the exclusive jurisdiction of foreign courts or may not be successful in subjecting foreign persons, especially foreign oil ministries and national oil companies, to the jurisdiction of the United States.

Private ownership of oil and gas reserves under oil and gas leases in the United States differs distinctly from our ownership of foreign oil and gas properties. In the foreign countries in which we do business, the state generally retains ownership of the minerals and consequently retains control of, and in many cases participates in, the exploration and production of hydrocarbon reserves. Accordingly, operations outside the United States may be materially affected by host governments through royalty payments, export taxes and regulations, surcharges, value added taxes, production bonuses and other charges.

Almost all of our proven reserves are located offshore of the Republic of Gabon. As of December 31, 2009, we carried a gross investment of approximately $138.7 million including leasehold and asset retirement obligations on our balance sheet associated with the Etame, Avouma, South Tchibala and Ebouri fields in Gabon. We have operated in Gabon since 1995 and believe we have good relations with the current Gabonese government. However, there can be no assurance that present or future administrations or governmental regulations in Gabon will not materially adversely affect our operations or cash flows.

A time extension for the drilling of two exploration wells in Angola is necessary to protect certain amounts invested in that country.

Due to financial non-performance of the venture partner assigned by the government of Angola, the plans to drill the two obligatory wells by November 2010 have been delayed. While the government of Angola has verbally expressed willingness to work with Company on this matter, we can provide no assurances that an extension will be granted. Steps taken in early 2010 have been taken, in coordination with the government, to acquire the interest of the non-performing partner and to obtain a time extension for the drilling of the wells. At risk is a $10.0 million escrow account that guarantees the Company’s performance to drill the two wells in 2010 plus leasehold and other capitalized assets of $11.4 million at December 31, 2009.

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

We operate in the highly competitive areas of oil exploration, development and production. We compete for the acquisition of exploration and production rights in oil and gas properties from foreign governments and from other oil and gas companies. These properties include exploration prospects as well as properties with proved reserves. Factors that affect our ability to compete in the marketplace include:

Our competitors include major integrated oil companies and substantial independent energy companies, many of which possess greater financial, technological, personnel and other resources than we do. Our competitors may use superior technology which we may be unable to afford or which would require costly investment by us in order to compete.

Compliance with environmental and other government regulations could be costly and could negatively impact production.

The laws and regulations of the United States, Gabon, Angola and Great Britain regulate our current business. Our operations could result in liability for personal injuries, property damage, natural resource damages, oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages. In addition, we could be liable for environmental damages caused by, among others, previous property owners or operators. We could also be affected by more stringent laws and regulations adopted in the future, including any related to climate change and greenhouse gases and use of fracking fluids. As a result, substantial liabilities to third parties or governmental entities may be incurred, the payment of which could have a material adverse effect on our financial condition, results of operations and liquidity.

These laws and governmental regulations, which cover matters including drilling operations, taxation and environmental protection, may be changed from time to time in response to economic or political conditions and could have a significant impact on our operating costs, as well as the oil and gas industry in general. While we believe that we are currently in compliance with environmental laws and regulations applicable to our operations, no assurances can be given that we will be able to continue to comply with such environmental laws and regulations without incurring substantial costs.

If our assumptions underlying accruals for abandonment costs are too low, we could be required to expend greater amounts than expected.

Almost all of our producing properties are located offshore. The costs to abandon offshore wells may be substantial. For financial accounting purposes, we record the fair value of a liability for an asset retirement obligation in the period in which it is incurred by capitalizing it as part of the carrying amount of the long-lived assets. No assurances can be given that such reserves will be sufficient to cover such costs in the future as they are incurred.

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From time to time we may hedge a portion of our production, which may result in our making cash payments or prevent us from receiving the full benefit of increases in prices for oil and gas.

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

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

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

We are highly dependent upon our executive officers and key employees. The unexpected loss of the services of any of these individuals could have a detrimental effect on us. We do not maintain key man life insurance on any of our employees.

We rely on a single purchaser of our Gabon production, which could have a material adverse effect on our results of operations.

Effective January 2010, we sell all of our crude oil production in Gabon to Vitol S.A. The loss of Vitol as a purchaser of our Gabon production could force the shut-in of our Gabon production until the purchaser is replaced, and could have a material adverse effect on our results of operations.

There are inherent limitations in all control systems, and misstatements due to error or fraud that could seriously harm our business may occur and not be detected.

Our management, including our Chief Executive Officer and Chief Financial Officer, do not expect that our internal controls and disclosure controls will prevent all possible error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. In addition, the design of a control system must reflect the fact that there are resource constraints and the benefit of controls must be relative to their costs. Because of the inherent limitations in all control systems, an evaluation of controls can only provide reasonable assurance that all material control issues and instances of fraud, if any, in our Company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Further, controls can be circumvented by the individual acts of some persons or by collusion of two or more persons. The design of any system of controls is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and may not be detected. A failure of our controls and procedures to detect error or fraud could seriously harm our business and results of operations.

None.

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Gabon

Etame Marin

VAALCO has an interest in a 1,186 square mile offshore block in Gabon, the Etame Marin block where it signed a production sharing contract in 1995. The block contains the Etame, Avouma, South Tchibala and Ebouri fields, all of which are on production, and the North Tchibala discovery for which there are no development plans at this time. These fields and discoveries consist of subsalt reservoirs that lie 20 miles offshore in approximately 250 feet of water depth.

VAALCO operates the Etame Marin block on behalf of a consortium of companies. At December 31, 2009, VAALCO owned a 30.35% interest in the exploration acreage within the Etame Marin block. The Company owns a 28.1% interest in the development areas surrounding the Etame, Avouma, South Tchibala and Ebouri fields. The development areas were subject to a 7.5% back-in by the government of Gabon, which occurred for these fields after their successful development.

The Etame Marin block consortium approved the development of the Etame field in 2001. An application for commerciality was filed with the government of Gabon, and in November 2001, the consortium was awarded a 19 square mile exploitation area surrounding the field. The exploitation area has a term of up to 20 years (through 2021).

The Etame field has been developed at an aggregate cost of approximately $124 million ($40.3 million net to the Company). The development included completing subsea wells connected to a contracted floating production, storage and offloading vessel (“FPSO”). There are currently four wells producing in the Etame field.

In April 2005, a development plan for the joint development of the Avouma and South Tchibala fields was approved by the Gabon government. The Company was awarded a 20 square mile exploitation area which has a term of twenty years (until 2025). In 2006, the Company installed a platform in approximately 250 feet of water and drilled two development wells from the platform, one into each field. The two development wells are tied back to the FPSO via a ten mile pipeline. Through December 31, 2009, the cost of developing the Avouma and South Tchibala fields was approximately $121 million ($36.4 million net to the Company).

The Company drilled the Ebouri discovery well to total depth in January 2004. In October 2006, the Gabon government approved the development plan for the Ebouri field and the Company was awarded a nearly 6 square mile exploitation area which has a term of twenty years (until 2026). A platform was installed in July 2008, approximately seven miles from the FPSO, and is tied back to the FPSO via a pipeline as was done for the Avouma and South Tchibala fields. The cost of developing the Ebouri field as of December 31, 2009 totaled approximately $158 million ($51.9 million net to the Company). The first development well began production in January 2009, and the second development well began producing crude oil in April 2009.

The Company has sold a total of 49.0 million gross bbls (11.5 million net bbls) from the fields within the Etame Marin block since startup through December 31, 2009. During 2009, the Etame, Avouma, South Tchibala and Ebouri fields produced approximately 8.3 million gross bbls (1.9 million net bbls).

Beginning in November 2008, drilling began on two exploration wells located within the Etame Marin block. The first of these wells, the North Ebouri, encountered substantial oil-filled Gamba sandstone, proving-up significant additional reserves north of the originally mapped field development outline. The second well, the North Etame prospect, encountered water bearing sands and was abandoned.

The Company negotiated an extension of the exploration permit on this block to 2014. The terms of the extension include an additional exploration well, bringing the total required under the permit to two exploration wells, and to acquire additional 3-D seismic data, which is expected to be acquired in 2010.

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Mutamba Iroru

In November 2005, the Company signed a production sharing contract for the Mutamba Iroru block onshore Gabon. The five year contract awarded the Company exploration rights to approximately 270,000 acres along the central coast of Gabon. The Mutamba Iroru block was previously held by Shell Gabon. The Company has a 100% interest in the Mutamba Iroru block. The Company acquired aeromagnetic gravity data in 2008, and together with seismic data acquired from previous operators over the block in 2006 and 2007, drilled two exploration wells in 2009. Both wells encountered water bearing sands and were abandoned.

The Company negotiated an extension of the exploration period until 2011. The terms of the extension obligate the Company to drill an exploration well and acquire 200 linear kilometers of seismic data during the term of the extension period. The obligation to drill an exploration well was met with the drilling of the second exploration well in 2009.

Angola

Block 5

Effective December 1, 2006, the Company acquired a 40% working interest in Block 5 offshore Angola. The four year contract with an optional three year extension awarded the Company exploration rights to approximately 1.4 million acres offshore Angola. The Company has acquired approximately 1,700 square kilometers of seismic data over a portion of Block 5 and has been interpreting the data and developing potential drilling locations. The plans to drill two exploration wells have been delayed due to a non-performing partner. In early 2010, the Company began the process to acquire the interest of the non-performing partner and is working with the government of Angola regarding a time extension for the drilling of the commitment wells beyond the November 2010 expiration date. While we believe that the government of Angola will grant us an extension, we can provide no assurances. Any adverse developments related to the Company’s ability to extend the drilling obligation date could result in an impairment of the Company’s unproved properties and other assets of approximately $11.4 million as well as the loss of the funds the Company has escrowed to secure its drilling obligations of $10 million. If we are successful in obtaining such extension, the Company estimates the drilling will take place in the first half of 2011 on this block in Angola.

Great Britain

In January 2008, the Company signed a farm-in agreement for a 25% working interest in Block 48/25c offshore in the British North Sea. The Company was obligated to pay its share of the drilling of one exploration well on the block and a portion of the farminee’s share of the well. In February 2009 the Company participated in a well drilled on the block in the Southern Gas Basin. A substantial gas column was found but with low permeability and porosity. The well was deemed to be non-commercial by the consortium and was abandoned.

Domestic United States Properties

The Company has interests in four producing wells in Brazos County Texas producing from the Buda/Georgetown formations. The Company also owns certain non-operated interests in Ship Shoal areas of the Gulf of Mexico. During 2009, the wells produced approximately 900 bbls of oil and 6 million cubic feet of gas net to the Company. No capital expenditures are anticipated in 2010 for these properties.

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Aggregate Production

Aggregate production data (net to the Company) for all of the Company’s operations for the years 2009, 2008, and 2007 are shown below.

Company Owned Production

RESERVE INFORMATION

In December 2008, the SEC announced that it had approved revisions designed to modernize the reserves reporting requirement of oil and natural gas companies. The most significant amendments to the requirements included the following:

The Company adopted the new requirements effective December 31, 2009.

The table below sets for the Company’s estimated net proved reserves for the years ended December 31, 2009, 2008 and 2007 as prepared by Netherland Sewell & Associates, Inc. (NSAI) independent petroleum engineers. There have been no estimates of total proved net oil or gas reserves filed with or included in reports to any federal authority or agency other than the Securities and Exchange Commission since the beginning of the last fiscal year. The reserves are located in Gabon (offshore) and in Texas and Louisiana (onshore and offshore). Reserves estimated by our independent engineers at December 31, 2009, reflect oil and natural gas spot prices based on the average prices during the 12-month period before the ending date of the period covered by this

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report determined as an unweighted, arithmetic average of the first-day-of-the-month price for each month within such period. Reserves estimated by our independent engineers at December 31, 2008 and 2007, reflect oil and natural gas spot prices on the last day of the year.

Proved Undeveloped Reserves

The Company annually reviews all proved undeveloped reserves (“PUDs”) to ensure an appropriate plan for development exists. Generally, the Company’s PUDs are converted to proved developed reserves within five years of the date they are first booked as PUDs. The Company had 2,568 MBbls of PUDs at December 31, 2009, compared with 2,671 MBbls of PUDs at December 31, 2008. In 2009, the Company converted 1,980 MBbls or 74% of the total year-end 2008 PUDs to proved developed reserves. Approximately $22.3 million was spent in 2009 associated with development of PUDs. Of the total $22.3 million spent in 2009, the Company completed the drilling of an exploration well and two development wells in the Ebouri field offshore Gabon.

Controls Over Reserve Estimates

The Company’s policies and practices regarding internal controls over the recording of reserves is structured to objectively and accurately estimate our oil and gas reserves quantities and present values in compliance with

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the SEC’s regulations and GAAP. Compliance in reserves bookings is the responsibility of the Company’s principal engineer, who is the Company’s Vice President-Production. The Company’s principal engineer has over 20 years of experience in the oil and gas industry, including over 10 years as either a reserve evaluator, trainer or manager and is a qualified reserves estimator (QRE), as defined by the Society of Petroleum Engineers’ standards. Further professional qualifications include a degree in petroleum engineering, extensive internal and external reserve training, and asset evaluation and management. In addition, the principal engineer is an active participant in industry reserve seminars, professional industry groups and has been a member of the Society of Petroleum Engineers for over 20 years.

The Company’s controls over reserve estimates included retaining NSAI as our independent petroleum and geological firm. The Company provided information about the Company’s oil and gas properties, including production profiles, prices and costs, to NSAI and they prepare their own estimates of the reserves attributable to our properties. All of the information regarding reserves in this annual report is derived from the report of NSAI. The report of NSAI is included as an Exhibit to this annual report.

The reserves estimates shown herein have been independently evaluated by NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-002699. Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. Derek Newton and Mr. David Nice. Derek Newton has been practicing consulting petroleum engineering at NSAI since 1997. Derek is a Registered Professional Engineer in the State of Texas (License No. 97689) and has over 25 years of practical experience in petroleum engineering, with over 13 years experience in the estimation and evaluation of reserves. He graduated from University College in Cardiff, Wales in 1983 with a Bachelor of Science Degree in Mechanical Engineering and from Strathclyde University in Scotland in 1986 with a Master of Science Degree in Petroleum Engineering. David Nice has been practicing consulting petroleum geology at NSAI since 1998. David is a Certified Petroleum Geologist and Geophysicist in the State of Texas (License No. 346) and has over 25 years of practical experience in petroleum geosciences, with over 12 years experience in the estimation and evaluation of reserves. He graduated from University of Wyoming in 1982 with a Bachelor of Science Degree in Geology and in 1985 with a Master of Science Degree in Geophysics. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

The Audit Committee of the Board of Directors meets with management, including access to the Company’s principal engineer, to discuss matters and policies related to reserves.

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The following tables set forth the net proved reserves of the Company as of December 31, 2009, 2008 and 2007, and the changes during such periods.

The Company does not book proved reserves on discoveries until such time as a development plan has been prepared and approved by the Company’s partners in the discovery. Furthermore, if a government agreement that the reserves are commercial is required to develop the field, this approval must have been received prior to booking any reserves.

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the Company. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of oil and gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and gas sales prices may all differ from those assumed in these estimates. The standardized measure of discounted future net cash flow should not be construed as the current market value of the estimated oil and natural gas reserves attributable to the Company’s properties. The information set forth in the foregoing tables includes revisions for certain reserve estimates attributable to proved properties included in the preceding year’s estimates. Such revisions are the result of additional information from subsequent completions and production history from the properties involved or the result of a decrease (or increase) in the projected economic life of such properties resulting from changes in product prices. Moreover, crude oil amounts shown for Gabon are recoverable under a service contract and the reserves in place remain the property of the Gabon government.

The SEC amended the definition of proved reserves for all reserve estimates included in filings after January 1, 2010. As a result, the estimates of proved reserves filed in reports prior to January 1, 2010 may not be comparable to reports filed after that date, including those in this annual report.

In accordance with the current guidelines of the Securities and Exchange Commission, the Company’s estimates of future net cash flow from the Company’s properties, and the present value thereof, are made using oil and gas contract prices using a twelve month average price and are held constant throughout the life of the

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properties except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. In Gabon, the price was $56.64 per bbl. In the United States, the price was $57.65 per bbl of oil and $3.87 per Mcf of gas. See Note 16 to the Company’s consolidated financial statements for certain additional information concerning the proved reserves of the Company.

Drilling History

The Company participated in the drilling of four exploration wells in 2009, one in the British North Sea, one in the Etame Marin block offshore Gabon and two onshore wells in the Mutamba Iroru block onshore Gabon. In 2008, the Company drilled a development well and an exploration well in the Etame Marin block. The Company participated in one exploration well during 2007-2008 in the British North Sea.

Acreage and Productive Wells

Below is the total acreage under lease and the total number of productive oil and gas wells of the Company as of December 31, 2009:

Office Space

The Company leases its offices in Houston, Texas (approximately 9,000 square feet), in Port Gentil, Gabon (approximately 10,000 square feet) and in Luanda, Angola (approximately 6,000 thousand square feet), which management believes are suitable and adequate for the Company’s operations.

The Company is currently not a party to any material litigation.

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PART II

General

The Company’s common stock is traded on the New York Exchange under the symbol EGY. The following table sets forth the range of high and low sales prices of the common stock for the periods indicated.

On February 26, 2010 the last reported sale price of the common stock on the New York Stock Exchange was $4.27 per share.

As of February 28, 2010 there were approximately 14,000 holders of record of the Company’s common stock.

Dividends

The Company has not paid cash dividends and does not anticipate paying cash dividends on the common stock in the foreseeable future.

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Performance Graph

The following graph compares the yearly percentage change in the Company’s cumulative total shareholder return on its common shares with the cumulative total return of the S&P 500 Index and the S&P/ TSX Capped Energy Index. For this purpose, the yearly percentage change in the Company’s cumulative total shareholder return is calculated by dividing (a) the sum of the dividends paid during the “measurement period,” and the difference between the price for the Company’s shares at the end and the beginning of the measurement period, by (b) the price for the Company’s common shares at the beginning of the measurement period. “Measurement period” means the period beginning at the market close on the last trading day before the beginning of the Company’s fifth preceding fiscal year, through and including the end of the Company’s most recently completed fiscal year. The Corporation first became listed on the New York Stock Exchange on October 12, 2006.

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Securities Authorized for Issuance under Equity Compensation Plans

The following table provides information as of December 31, 2009 regarding the number of shares of common stock that may be issued under the Company’s compensation plans. Please refer to Note 4 to the consolidated financial statements for additional plan information on stock based compensation.

Issuer Purchases of Equity Securities for Quarter Ended December 31, 2009

The following table provides information for the quarter ended December 31, 2009 regarding the number of shares purchased by the Company.

Note 1—On June 24, 2009, the Company announced its intention to purchase up to $10 million of shares of its common stock for the treasury. Purchases may be made in both the open market and through negotiated transactions from time-to-time during the authorized 12 month period. Purchases may be increased, decreased or discontinued at any time without prior notice. The Company has purchased 2,327,779 shares on the open market at an average price of $4.30 per share totaling $10 million since this announcement.

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The following table sets forth, as of the dates and for the periods indicated, selected financial information about the Company. The financial information for each of the five years in the period ended December 31, 2009 has been derived from the Company’s Consolidated Financial Statements for such periods. The information should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Consolidated Financial Statements and Notes thereto. The following information is not necessarily indicative of the Company’s future results.

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INTRODUCTION

The Company’s results of operations are dependent upon the difference between prices received for its oil and gas production and the costs to find and produce such oil and gas. Oil and gas prices have been, and are expected in the future to be, volatile and subject to fluctuations based on a number of factors beyond the control of the Company.

The Company operates the Etame, Avouma, South Tchibala and Ebouri fields on behalf of a consortium of five companies offshore of the Republic of Gabon. Production commenced from the Etame field in 2002 and was subsequently expanded through additional development wells in 2004 and 2005. In 2006, the Company developed the Avouma and South Tchibala fields by setting a platform and tying the field back to the FPSO via a pipeline. Oil production commenced from the Avouma and South Tchibala fields in January 2007. Oil production began in January 2009 from the Ebouri field utilizing a platform that was installed in August 2008 and connected to the FPSO by pipeline.

Impact of the Current Financial and Credit Markets

The U.S. and other international economies experienced a recession, the effects of which could last well into 2010 and beyond. Additionally, the financial and credit markets have experienced unprecedented disruptions. Many financial institutions have liquidity concerns prompting intervention from governments. The Company’s exposure to the disruptions in the financial markets includes the ability to access the capital markets and investments exposure.

The Company does not currently have a credit facility. If in the future the Company determines that it needs a credit facility and the disruption in the financial markets continues or recurs, replacement of the credit facility may be more expensive.

Current market conditions also elevate concerns with the Company’s cash investments (including funds in escrow), which at December 31, 2009 totaled $97.0 million. The Company has reviewed the creditworthiness of the banks and financial institutions with which the Company maintains investments as well as the securities underlying these investments. With regard to the Company’s cash investments, the Company invests in bankers acceptances and money market instruments primarily with JPMorgan Chase & Co., which the Company believes to be creditworthy.

Beginning January 2010, the Company’s production in Gabon is purchased by Vitol, which the Company believes to be a creditworthy purchaser.

Oil and gas prices are also volatile as evidenced by the significant changes during 2008 and 2009. If experienced, lower commodity prices will reduce the Company’s cash flows from operations.

CRITICAL ACCOUNTING POLICIES

The following describes the critical accounting policies used by the Company in reporting its financial condition and results of operations. In some cases, accounting standards allow more than one alternative accounting method for reporting, such is the case with accounting for oil and gas activities described below. In those cases, the Company’s reported results of operations would be different should it employ an alternative accounting method.

Successful Efforts Method of Accounting for Oil and Gas activities

The SEC prescribes in Regulation S-X the financial accounting and reporting standards for companies engaged in oil and gas producing activities. Two methods are prescribed: the successful efforts method and the full cost method. Like many other oil and gas companies, the Company has chosen to follow the successful

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efforts method. Management believes that this method is preferable, as the Company has focused on exploration activities wherein there is risk associated with future success and as such earnings are best represented by attachment to the drilling operations of the Company. Costs of successful wells, development dry holes and leases containing productive reserves are capitalized and amortized on a unit-of-production basis over the life of the related reserves. Other exploration costs, including geological and geophysical expenses applicable to undeveloped leasehold, leasehold expiration costs and delay rentals are expensed as incurred.

In accordance with accounting under successful efforts method of accounting, the Company reviews proved oil and gas properties for indications of impairment whenever events or circumstances indicate that the carrying value of its oil and gas properties may not be recoverable. When it is determined that an oil and gas property’s estimated future net cash flows will not be sufficient to recover its carrying amount, an impairment charge must be recorded to reduce the carrying amount of the asset to its estimated fair value. This may occur if a field contains lower than anticipated reserves or if commodity prices fall below a level that significantly effects anticipated future cash flows on the field.

Impairment of Unproved Property

The Company evaluates its unproved properties for impairment on a property-by-property basis. The majority of the Company’s unproved property consists of acquisition costs related to its undeveloped acreage in Angola. On at least a quarterly basis, management reviews the unproved property for indicators of impairment based on the Company’s current exploration plans with consideration given to results of any drilling and seismic activity during the period and known information regarding exploration activity by other companies on adjacent blocks. See Item 2—Properties and Note 7 to the Consolidated Financial Statements for further information on the Company’s exploration plans in Angola. Any adverse developments related to the Company’s ability to extend the drilling obligation date could result in an impairment of the Company’s unproved properties and other assets of approximately $11.4 million as well as the loss of the funds the Company has escrowed to secure its drilling obligations of $10 million.

CAPITAL RESOURCES AND LIQUIDITY

Cash Flows

Net cash provided by operating activities for 2009 was $23.5 million, as compared to $106.6 million in 2008 and $43.2 million in 2007. The decrease in cash provided by operations was primarily due to a net loss incurred in 2009 versus net income in 2008 and less favorable changes in working capital other than cash. The increase in 2008 compared to 2007 was primarily due to higher net income and more favorable changes in working capital other than cash.

Net cash used in investing activities in 2009 was $49.0 million, compared to net cash used in investing activities for 2008 of $42.4 million and net cash used in investing activities in 2007 of $22.6 million. In 2009, the Company invested $22.3 million primarily for the Ebouri platform and three wells. The Company incurred $33.4 million in dry hole costs and reduced the amount in escrow attributable to a well drilled in the British North Sea by $6.6 million. In 2008, the Company invested $25.7 million primarily for the development of the Ebouri field, FPSO upgrades and onshore Gabon drilling activities. The Company incurred $9.2 million in dry hole costs, and placed $7.4 million in escrow for a well to be drilled in the British North Sea. In 2007, the Company invested $14.5 million in the Etame Marin block operations for the development of the Avouma, South Tchibala and Ebouri fields and drilled a dry well in the North Sea at a cost of $8.1 million.

In 2009, cash used in financing activities was $19.4 million, consisting primarily of purchase of treasury shares of $10.1 million, debt repayment of $5.0 million and distributions to a noncontrolling interest owner of $6.0 million partially offset by proceeds from the issuance of common stock of $1.8 million. In 2008, cash used in financing activities was $15.2 million, consisting of distributions to a noncontrolling interest owner of $6.5 million and

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purchase of treasury shares of $8.9 million. In 2007, cash used in financing activities was $5.2 million, consisting of distributions to a noncontrolling interest owner of $4.0 million and purchase of treasury shares of $2.3 million which was partially offset by proceeds from the issuance of common stock of $1.1 million.

Capital Expenditures

The Company invested $22.3 million in property and equipment additions (including amounts carried in accounts payable and excluding exploration dry hole costs), primarily associated with the drilling of the three wells in the Ebouri field (the appraisal well plus the two development wells drilled from the Ebouri platform) totaling $16.7 million. Additionally, the Company’s share of the leasehold bonus associated with the Etame Marin block exploration period extension totaled $1.4 million. Partially offsetting these additions was a realignment agreement with a joint venture partner that originally did not participate in an appraisal well and one of the development wells in the Ebouri field. Pursuant to the realignment agreement, the joint venture partner paid its proportionate share of capital expenditures for the wells, which reduced the Company’s property and equipment by $5.7 million. During 2008, the Company spent approximately $25.7 million consisting primarily of Ebouri field development costs of $18.2 million, and drilling inventory ($1.4 million). Other expenditures during the year were for FPSO upgrades ($2.0 million), onshore Gabon ($2.2 million) and a well in the British North Sea ($0.8 million). During 2007, the Company spent approximately $14.5 million for the development of the Avouma and South Tchibala fields ($6.0 million) and for the development of the Ebouri field ($8.5 million).

In 2009, the Company incurred $36.5 million in exploration expense including $33.4 million of dry hole costs (British North Sea—$9.6 million, the Etame Marin block offshore Gabon—$3.0 million and the Mutamba Iroru block onshore Gabon—$20.8 million). The Company spent the remaining $3.1 million primarily on seismic processing costs in the Etame Marin block ($0.6 million), Mutamba Iroru block ($0.9 million) and in Angola ($1.4 million). In 2008, the Company spent $14.9 million in exploration expense including $9.2 million of unsuccessful well costs (British North Sea—$6.4 million, offshore Gabon—$0.3 million and onshore Gabon—$2.5 million), $3.5 million to acquire and process seismic in Angola, $1.1 million for aeromagnetic gravity data acquired over the Mutamba Iroru block onshore Gabon and seismic acquisition and processing costs associated with the Etame Marin block of $0.7 million. In 2007, the Company spent $15.3 million to acquire and process seismic in Angola ($4.3 million), to acquire and process seismic in Gabon ($2.6 million), to drill an unsuccessful exploration well in the British North Sea ($8.1 million) and for other seismic costs in the North Sea ($0.3 million).

Historically, the Company’s primary sources of capital resources has been from cash flows from operations, private sales of equity, borrowings and purchase money debt. On December 31, 2009, the Company had cash balances of $80.6 million and funds in escrow of $16.4 million. The Company believes that the cash balances combined with cash flow from operations will be sufficient to fund the Company’s 2010 capital expenditure budget, which is expected to range from $25.0 million to $35.0 million to further develop the Etame Marin block and $5.0 million projected for the beginning of the drilling project in Angola. The Company invests cash, not required for immediate operational and capital expenditure needs, in short-term bankers acceptance and money market instruments primarily with JPMorgan Chase & Co. The Company does not invest in asset-backed commercial paper market which has been subject to a liquidity crisis over the last year. As operator of the Etame, Avouma, South Tchibala and Ebouri fields the Company enters into project related activities on behalf of its working interest partners. The Company generally obtains advances from its partners prior to significant funding commitments.

In June 2005, the Company executed a loan agreement for a $30.0 million revolving credit facility secured by the assets of the Company’s Gabon subsidiary. The facility was available to finance the Ebouri field development activities and other Etame Marin block activities. The facility extended until October 2009 at which point it could be extended by mutual agreement, and the loan drawdown amount could be converted to a term loan at the Company’s option. Because of the Company’s limited use of the facility, the IFC elected to not extend the credit facility. The Company elected to not convert the loan balance to a term loan and instead repaid the loan balance of $5.0 million plus interest in mid-October 2009.

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Contractual Obligations

The table below summarizes the Company’s obligations and commitments at December 31, 2009:

Payment Period

In addition to the contractual obligations described above, the Company entered into a sixth exploration period extension during 2009 and is required to spend $5.3 million for its share of two exploration wells and acquire/process 150 sq km of 3-D seismic on the Etame Marin block by July 2014. The Company entered into the second exploration period for the Mutamba Iroru block which requires the Company to acquire/process 200 kilometers of 2-D seismic, without a specified monetary commitment, by May 2011. In addition, the Company is required to spend $10.0 million for its share of two exploration wells on Block 5 in Angola by November 30, 2010; however, the Company has begun the process of acquiring the interest of its non-performing partner and is working with the government of Angola regarding a time extension for the drilling of the commitment wells. While we believe that the government of Angola will grant us an extension, we can provide no assurances. Any adverse developments related to the Company’s ability to extend the drilling obligation date could result in an impairment of the Company’s unproved properties and other assets of approximately $11.4 million as well as the loss of the funds the Company has escrowed to secure its drilling obligations of $10 million. If we are successful in obtaining such extension, the Company estimates the drilling will take place in the first half of 2011 on this block in Angola.

The Company is carrying $10.7 million of asset retirement obligations as of December 31, 2009, representing the present value of these obligations as of that date. The Company does not anticipate incurring expenditures for any material asset retirement obligations over the next five years.

RESULTS OF OPERATIONS

Year Ended December 31, 2009 Compared to Years Ended December 31, 2008 and 2007

Revenues

Total oil and gas sales for 2009 were $115.3 million as compared to $169.5 million and $125.0 million for 2008 and 2007, respectively. In 2009, the Company sold approximately 1,935,000 bbls at an average price of $59.54 per bbl from the Etame Marin block. Revenues from the United States were $0.1 million. In 2008, the Company sold approximately 1,822,000 bbls at an average price of $92.87 per bbl from the Etame Marin block. Revenues from the United States were $0.3 million. In 2007, the Company sold approximately 1,753,000 net bbls at an average price of $71.16 per bbl from the Etame field in Gabon. Revenues from the United States were $0.3 million. Crude oil sales are a function of the number and size of crude oil liftings from the FPSO and thus crude oil sales do not always coincide with oil volumes produced.

Operating Costs and Expenses

Production expense for 2009 was $22.0 million as compared to $18.5 million and $15.1 million for 2008 and 2007, respectively. Production expenses were higher in 2009 primarily due to higher sales volumes, and higher FPSO costs. The Company matches production expenses with crude oil sales. Any production expenses

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associated with unsold crude oil inventory are capitalized. In 2008, operating expenses increased versus 2007 due to increased volumes sold (17 liftings in 2008 versus 14 liftings in 2007) as well as higher boat rental costs, higher FPSO costs, higher helicopter costs and higher fuel costs.

Exploration cost for 2009 was $36.5 million as compared to $14.9 million and $15.3 million for 2008 and 2007, respectively. In 2009, the Company spent $33.4 million on four unsuccessful exploration wells including the North Etame prospect offshore Gabon ($3.0 million), two wells on the Matumba Iroru block onshore Gabon ($20.8 million) and a well on Block 48/25c in the British North Sea ($9.6 million). Additionally, the Company spent $3.1 million primarily associated with seismic processing costs in Block 5 in Angola and the Mutamba Iroru block in Gabon.

In 2008, the Company spent $9.2 million on unsuccessful exploration wells including the remaining costs of a well in the British North Sea ($6.4 million), plus two wells drilled in early 2009 in Gabon and determined to be unsuccessful ($2.8 million). On both of the wells, the costs incurred as of December 31, 2008 were charged to expense. Additionally, the Company spent $3.0 million for acquiring 524 square kilometers of 3-D seismic in Angola in 2008. Also included in exploration expenses in 2008 were aeromagnetic gravity data acquired over the Mutamba Iroru block, seismic acquisition and processing costs associated with the Company’s Etame Marin block and seismic processing costs in Angola. In 2007, amounts were spent to acquire and process seismic in Angola ($4.3 million), to acquire and process seismic in Gabon ($2.6 million), to drill an unsuccessful exploration well in the British North Sea ($8.1 million) and for other seismic costs in the North Sea ($0.3 million).

Depreciation, depletion and amortization expense was $20.8 million for 2009, and was $18.9 million and $18.0 million for 2008 and 2007, respectively. Depletion, depreciation and amortization expense increased in 2009 versus 2008, and 2008 versus 2007 primarily due to higher production volumes in both comparative periods. In 2009, depletion rates for the Ebouri field averaged $19.73 per bbl, Avouma and South Tchibala fields averaged $7.32 per bbl, and the Etame field averaged $4.30 per bbl. For comparison, the average 2008 depletion rate for the Avouma and South Tchibala fields was $16.01 per bbl and the average depletion rate for the Etame field averaged $4.98 per bbl.

General and administrative expense for 2009 was $9.6 million as compared to $10.8 million and $8.0 million for 2008 and 2007, respectively. General and administrative expense decreased in 2009 versus 2008 due in part to prior year non-recurring legal and solicitation costs associated with corporate matters relating to the Company’s annual meeting. Included in the general and administrative expenses for 2009 was an expense for retirement benefits of $1.5 million which was partially offset by a retroactive compensation adjustment of $0.9 million that benefited the Company by charging the adjustment to the Gabon partners. During 2009, the Company incurred $1.8 million of stock based compensation compared to $2.6 million incurred in 2008 and $2.2 incurred in 2007. The increase in general and administrative expense for 2008 versus 2007 was attributable to the non-recurring legal and solicitation costs explained above plus a full year of operating the Company office in Angola ($1.2 million). In each of the three years, the Company benefited from overhead reimbursement associated with production and development operations on the Etame Marin block.

Other operating income for 2009 was $6.5 million. For 2008 and 2007, no amounts were recorded for other operating income. The other operating income recorded in 2009 was attributable to receipt of proceeds from a joint venture partner that originally elected to not participate in two wells drilled in the Ebouri field, offshore Gabon. The partner later elected to participate and paid for their proportionate share of the capital expenditures for the wells. The $6.5 million payment received represents the Company’s share of an agreed risk premium benefiting the joint venture partners that originally participated in those two wells.

Operating Income

Operating income for 2009 was $33.0 million as compared to a $106.5 million and $68.7 million for 2008 and 2007, respectively. The significant decrease in operating income in 2009 versus 2008 is primarily attributable to the lower average crude sales price of $59.54 per bbl, a decrease of $33.33 per bbl or

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36%, and higher exploration costs for unsuccessful exploratory wells. Also, partially contributing to the decrease in operating income were higher operating expenses and depletion expense.

The increase in operating income in 2008 versus 2007 is attributable to the higher average crude sales price of $92.87 per barrel, an increase of $21.71 per bbl, which was partially offset by increased fuel-related operating costs and depletion.

Other Income (Expense)

Interest income for 2009 was $0.7 million as compared to $2.5 million and $3.9 million in 2008 and 2007, respectively. All the 2009, 2008, and 2007 amounts represent interest earned and accrued on cash balances and funds in escrow. Extremely low interest rates in 2009 versus 2008 account for the decrease in interest income.

Interest expense of $0.5 million was recorded in 2009 as compared to $0.2 million and $1.1 million in 2008 and 2007, respectively. Interest in all three years was associated with the financings from the IFC for use on Etame Marin block activities. The increase in interest expense in 2009 compared to 2008 is attributable to a decrease in the amount of loan interest that could be capitalized.

Other expense of $0.5 million recorded in 2009 was primarily associated with foreign exchange losses. Other expense was negligible in 2008, and in 2007, other income of $0.1 million was attributable to foreign exchange gains.

Income Taxes

In 2009, the Company incurred $36.9 million of income taxes compared to $73.0 million incurred in 2008 which were associated with the Etame Marin block production, and which were paid in Gabon. In 2007, the Company incurred $48.1 million of income taxes associated with the Etame field production, which were paid in Gabon. The decreased tax in Gabon in 2009 versus 2008 was due to lower crude oil sales prices in 2008, which was partially offset by higher sales volumes. Also a larger percentage of crude was subject to taxation in 2009 as part of profit oil versus cost oil.

Loss from Discontinued Operations

No amounts were recorded in 2009 or 2008 related to discontinued operations. In 2007, the loss from discontinued operations in the Philippines was $51,000 as the Company achieved the final closeout of the branch offices.

Net Income (Loss)

The net loss for 2009 was $4.1 million as compared to a net income of $35.7 million and net income of $23.5 million in 2008 and 2007, respectively. The decrease in 2009 versus 2008 is attributable primarily to the unsuccessful exploration well costs and lower crude oil sales prices. The net income increase in 2008 versus 2007 is attributable to increased sales volumes and oil prices partially offset by higher costs, primarily fuel-related costs and depletion.

Income attributable to the noncontrolling interest in the Gabon subsidiary was $3.7 million, $6.0 million and $4.4 million in 2009, 2008, and 2007, respectively.

NEW ACCOUNTING PRONOUNCEMENTS

For a discussion of new accounting pronouncements, see Note 3 to the consolidated financial statements.

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OFF BALANCE SHEET ARRANGEMENTS

For a discussion of off balance sheet arrangements associated with the guarantee by the Company of the charter payments for the FPSO located in Gabon, see Note 7 to the consolidated financial statements.

Market Risk

The Company’s major market risk exposure continues to be the prices applicable to its oil and gas production. Sales prices are primarily driven by the prevailing market price. Historically, prices received for oil and gas production have been volatile and unpredictable.

Foreign Exchange Risk

Our results of operations and financial condition are affected by currency exchange rates. While oil sales are denominated in U.S. dollars, portions of our operating costs in Gabon are denominated in the local currency. A weakening U.S. Dollar will have the effect of increasing operating costs while a strengthening U.S. Dollar will have the effect of reducing operating costs. The Gabon local currency is tied to the Euro. The exchange rate between the Euro and the U.S. dollar has fluctuated widely in response to international political conditions, general economic conditions and other factors beyond our control.

Interest Rate Risk

At December 31, 2009 the Company did not have any debt and thus no exposure to interest rate risk.

Commodity Price Risk

The Company had no derivatives in place as of the date of this report, or in 2009, 2008 or 2007.

The information required here is included in the report as set forth in the “Index to Consolidated Financial Information” on page F-1.

None.

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures.

The Company maintains disclosure controls and procedures that are designed to provide reasonable assurance that information required to be disclosed by the Company in the reports it file or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to the Company’s management, including the Chief Executive Officer and Chief Financial Officer to allow timely decisions regarding required disclosure. The Company’s management, including the Company’s principal executive officer and principal financial officer, has evaluated the effectiveness of the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this Annual Report on Form 10-K. Based on that evaluation, the Company’s principal executive officer and principal financial officer have concluded that the Company’s

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disclosure controls and procedures were effective as of the end of the period covered by this Annual Report on Form 10-K. There were no changes in the Company’s internal controls over financial reporting that occurred during the Company’s last year that have materially affected, or are reasonably likely to materially affect the Company’s internal control over financial reporting.

Management’s Annual Report on Internal Control Over Financial Reporting

The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting for the Company, as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Under the supervision and with the participation of the Company’s management, including the Company’s principal executive and principal financial officers, the Company conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO Framework”). Based on this evaluation under the COSO Framework which was completed on March 16, 2010, management concluded that its internal control over financial reporting was effective as of December 31, 2009.

The Company’s internal control over financial reporting as of December 31, 2009 has been audited by Deloitte & Touche LLP, the independent registered public accounting firm who audited the Company’s consolidated financial statements as of and for the year ended December 31, 2009, as stated in their report which follows.

Changes in Internal Control Over Financial Reporting

No change in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) occurred during the fourth quarter of our fiscal year ended December 31, 2009 that has materially affected, or is reasonable likely to materially affect, our internal control over financial reporting.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of VAALCO Energy, Inc. and subsidiaries:

Houston, Texas

We have audited the internal control over financial reporting of VAALCO Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’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, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and 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 by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel 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 the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the 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, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2009 of the Company, and our report March 16, 2010 expressed an unqualified opinion on those consolidated financial statements and included an explanatory paragraph related to the adoption of new accounting guidance in 2009 related to the estimation of oil and gas reserves and the presentation of noncontrolling interest in the consolidated financial statements.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

March 16, 2010

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The Company has disclosed all information required to be disclosed in a current report on Form 8-K during the year ended December 31, 2009 in previously filed reports on Form 8-K.

PART III

Information required by this item will be included in the Company’s proxy statement for its 2010 annual meeting, which will be filed with the Commission within 120 days of December 31, 2009, and which is incorporated herein by reference.

Information required by this item will be included in the Company’s proxy statement for its 2010 annual meeting, which will be filed with the Commission within 120 days of December 31, 2009, and which is incorporated herein by reference.

Information required by this Item 403 of Regulation S-K concerning the security ownership of certain beneficial owners and management will be included in the Company’s proxy statement for its 2010 annual meeting, which will be filed with the Commission within 120 days of December 31, 2009, and which is incorporated herein by reference. Please see “Item 5 Market for Registrants Common Equity, Related Stockholder Matters and Issuer Purchase of Equity Securities” information on securities that may be issued under the Company’s stock incentive plans.

Information required by this item will be included in the Company’s proxy statement for its 2010 annual meeting, which will be filed with the Commission within 120 days of December 31, 2009, and which is incorporated herein by reference.

The information required by Item 14 is incorporated by reference from the Company’s definitive proxy statement for its 2010 annual meeting, which will be filed with the Commission within 120 days of December 31, 2009, and which is incorporated herein by reference.

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PART IV

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SIGNATURES

In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

VAALCO ENERGY, INC.

(Registrant)

Dated March 16, 2010

In accordance with the Exchange Act, this report has been signed below on the 16th day of March, by the following persons on behalf of the registrant and in the capacities indicated.

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VAALCO ENERGY, INC. AND SUBSIDIARIES

INDEX TO CONSOLIDATED FINANCIAL INFORMATION

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of VAALCO Energy, Inc. and subsidiaries:

Houston, Texas

We have audited the accompanying consolidated balance sheets of VAALCO Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2009 and 2008, and the related statements of consolidated operations, equity, and cash flows for each of the three years in the period ended December 31, 2009. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.