VAALCO ENERGY INC /DE/ - Annual Report: 2010 (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, 2010

OR

For the transition period from                  to                 

Commission file number: 1-32167

VAALCO Energy, Inc.

(Exact name of registrant as specified on its charter)

4600 Post Oak Place

Suite 309

Houston, Texas 77027

(Address of principal executive offices) (Zip Code)

(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, 2010 was $315,992,617 based on a closing price of $5.60 on June 30, 2010.

As of February 28, 2011, there were outstanding 57,017,258 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 10-K, which is incorporated into Part III of this Form 10-K.

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VAALCO ENERGY, INC.

TABLE OF CONTENTS

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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 an operator in Angola, West Africa, and has conducted exploration activities as a non-operator in the British North Sea. The Company owns minor interests in production activities as a non-operator in the United States and recently acquired a lease in Texas in the Granite Wash formation. 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 properties located in the United States.

RECENT DEVELOPMENTS

Offshore Gabon

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, 2010, 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, each of which is located on the Etame Marin block. 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 2010, the Etame, Avouma, South Tchibala and Ebouri fields produced approximately 7.3 million bbls (1.75 million bbls net to the Company).

Beginning in March 2010, drilling began on the first of four planned wells located within the Etame Marin block. In July 2010, the consortium elected to extend the drilling program by two additional wells. The first of these wells was a development well drilled from the Ebouri platform which began producing oil in May 2010. The second well was a successful workover of the Ebouri 3-H well to replace submersible pumps. The third well was an exploration effort with two sidetracks in the Southeast Etame area which resulted in an oil discovery in the Gamba reservoir. Various completion options for the Southeast Etame discovery are being considered as part of a study on future development plans for the Etame Marin block. The fourth well in the drilling program was a subsea completed development well in the Etame field which began producing oil in December 2010. The fifth well in the drilling program was a development well in the South Tchibala field which began producing oil in November 2010 and the sixth well was an exploration well on the Omangou prospect. The sixth well was water-bearing in the objective reservoir and was subsequently abandoned. The Omangou well counts as one of the two exploration wells required per the terms of the sixth exploration period extension. The sixth exploration period expires in July 2014.

Onshore Gabon

The Company executed a farm-out agreement in August 2010 with Total Gabon on the Mutamba Iroru block located near the coast in central Gabon. The Mutamba Iroru block contains an exploration area of

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approximately 270,000 acres. Under the terms of the agreement, the Company and Total Gabon have committed to reprocess 400 kilometers of 2-D seismic data and drill one exploration well. In return for Total Gabon funding an agreed portion of the new work commitment, Total Gabon will receive a 50% interest on the permit. In 2010, the exploration permit was successfully extended until May 2012.

Offshore Angola

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 government-assigned working interest partner was delinquent paying their share of the costs several times in 2009 and consequently was placed in a default position which impacted the timing for drilling the two commitment wells. In early 2010, the Company began working with the government of Angola regarding a time extension for the drilling of the wells beyond the November 2010 expiration date and to obtain a replacement partner. By governmental decree dated December 1, 2010, the former partner was removed from the production sharing contract and a one year time extension was granted. The Company and the government of Angola then agreed on the process for obtaining a replacement partner. The Company opened a data room in Houston which is expected to close in the second quarter of 2011. Information related to interested parties will then be provided to the government of Angola for selection and finalization. If necessary, the government of Angola has expressed willingness to consider a further time extension once the new partner has been selected and a timeline of the drilling plans is completed. While we believe that the government of Angola will grant us another extension if necessary, we can provide no assurances that such an extension will be granted. If the government of Angola were to deny a time extension, and the wells are not drilling by the end of November 2011, the Company risks forfeiture of its $10 million funds in escrow, and the Company may be required to impair its leasehold costs and other investments with a carrying value of $13.7 million as of December 31, 2010.

Onshore Domestic

The Company acquired a 640 acre lease in the Granite Wash formation in north Texas in December 2010. The first well on this acreage is expected to be drilled in the second quarter of 2011.

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 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)

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totaling approximately 759,000 acres. The Company also owns a 50% working interest in the approximately 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. A 640 acre lease in the Granite Wash formation in north Texas was acquired in December 2010. The Company has plans to drill on this lease in 2011.

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.

Domestic

The Company’s domestic strategy has been to produce existing reserves from outside operated properties located in Brazos County, Texas, in Pickens County, Alabama, and offshore Louisiana in the Ship Shoal area. As described above, the Company also plans to drill a well on its recently acquired property in the Granite Wash formation in north Texas. Additionally, the Company is evaluating investment opportunities in resource based properties, including shale properties.

CUSTOMERS

Substantially all of the Company’s oil and gas is sold at the well head 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 Vitol S.A. which ran through calendar year 2010. For the 2011 calendar year, the Company will sell its oil under a contract with Mercuria Trading NV (“Mercuria”). While the loss of Mercuria 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, 2010, the Company had 89 full-time employees and consultant contractors, 48 of whom were located in Gabon and nine of whom were located in Angola. The Company is not yet 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 and NEOP began negotiating a collective bargaining agreement in the first quarter of 2011. 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

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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 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 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, certain wastes generated by the Company may be subject to RCRA or comparable state statutes. 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

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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 facility. 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 substances that may fall within CERCLA’s definition of Hazardous Substance and may have disposed of these substances 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 regulated substances, the Company could be liable for costs of investigation and remediation and natural resources damages.

Clean Water Act

The Clean Water Act (“CWA”) and analogous state laws impose restrictions and strict controls regarding the discharge (including spills and leaks) of pollutants, including produced waters and other oil and natural gas wastes, into state waters and 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. Generally, permits must be obtained to discharge pollutants. 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 other pollutants. The CWA also prohibits the discharge of fill materials to regulated waters, including wetlands, without a permit. 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 pollutants, 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 cleanup and response 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

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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. In light of recent events, it is possible that these requirements may become more stringent. The Company believes that currently it has established adequate proof of financial responsibility for its offshore facilities.

Safe Drinking Water Act and Hydraulic Fracturing

Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing activities are typically regulated by state oil and gas commissions but not at the federal level, as the federal Safe Drinking Water Act expressly excludes regulation of these fracturing activities (except where diesel is a component of the fracturing fluid). Due to public concerns raised regarding potential impacts of hydraulic fracturing on groundwater quality, there have been recent developments at the federal and state levels that could result in regulation of hydraulic fracturing becoming more stringent and costly. The EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, with results of the study anticipated to be available by late 2012. In addition, a committee of the U.S. House of Representatives is conducting an investigation of hydraulic fracturing practices. Moreover, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing by eliminating the current exemption in the Safe Drinking Water Act, and, further, to require disclosure of the chemicals used in the fracturing process. Also, some states have adopted, and other states are considering adopting, regulations that restrict hydraulic fracturing in certain circumstances or that require disclosure of the chemicals in the fracturing fluids. If new laws or regulations imposing significant restrictions or conditions on hydraulic fracturing activities are adopted in areas where the Company conducts business, the Company could incur substantial compliance costs and such requirements could adversely delay or restrict its ability to conduct fracturing activities on its assets.

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 EPA has been moving forward to regulate GHGs as pollutants under the CAA and has already adopted rules establishing GHG emission limits from motor vehicles beginning with the 2012 model year, thus triggering the requirements for the permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. The EPA has adopted a multi-tiered approach to this permitting, with the largest sources first subject to permitting. In addition, both houses of the United States Congress have considered legislation to reduce emissions of greenhouse gases without any ultimate resolution and many states have already taken legal measures to reduce GHG emissions, including, in a few locations, the consideration of a cap and trade program. Most of these cap and trade programs work by requiring major sources of emissions or major producers of fuels to acquire and surrender emission allowances. Depending on the regulatory reach of EPA’s rules or new CAA legislation or implementing regulations restricting the emission of GHGs or state programs, the Company could incur significant costs to control its emissions and comply with regulatory requirements. In addition, in October 2009, the EPA adopted a mandatory GHG emissions reporting program which imposes

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reporting and monitoring requirements on various industries and in November 2010, expanded this GHG reporting rule to include onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmission, storage and distribution facilities. The Company will incur costs to monitor, keep records of, and report emissions of GHGs. We do not believe that our compliance with applicable monitoring, recordkeeping and reporting requirements under the reporting rule as recently amended will have a material adverse effect on our results of operations or financial position.

Because of the lack of any comprehensive legislative program addressing GHGs, there is a great deal of uncertainty as to how federal and state regulation of GHGs will unfold and how it may impact our industry. Moreover, the federal, regional, state and local regulatory initiatives could adversely affect the marketability of the oil and natural gas that 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. At the Federal level, the Clean Air Act is the primary statute governing 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 (or toxic) air pollutants, might require installation of additional controls. Administrative enforcement actions for failure to comply 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 CCA 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.

FORWARD-LOOKING STATEMENTS

This Report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, which are intended

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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, the amount and nature of capital expenditures, 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 five producing wells, the Avouma and South Tchibala fields consisting of one well and two wells, respectively, and the Ebouri field with three producing wells constituted almost 100% of our total production for the year ended December 31, 2010. In addition, at December 31, 2010, 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 2010 was $78.38 per barrel compared to $59.54 per barrel in 2009, $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, including recent uprisings and political unrest in the Middle East and Africa, 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 gas prices may fall and may become and remain depressed for a long period of time, which may adversely affect our results of operations.

In recent years, 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. With the exception of our recently acquired property in the Granite Wash formation in north Texas, our current domestic oil and gas producing 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 2010, we participated, and in 2011 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 you 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 if the situation reoccurs.

Primarily in 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 reoccur, 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, 2010, 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

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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 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 2010 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, 2010, we carried a gross investment excluding amortization of approximately $178.7 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 second time extension for the drilling of two exploration wells in Angola may be necessary to protect certain amounts invested in that country.

Due to financial non-performance of the venture partner assigned by the government of Angola, our plans to drill the two obligatory wells have been delayed. A government decree effective December 1, 2010 removed the former partner from the production sharing agreement and provided us with a one year extension through the end of November 2011. We are working with the government of Angola to secure a replacement partner. After the new partner is selected, another time extension may be required if reasonable time to drill the two commitment wells does not exist. We can give no assurances that another time extension will be granted, if necessary. If the government of Angola were to deny a time extension and the wells are not drilling by the end of November 2011, we risk forfeiture of our $10 million funds in escrow and we may be required to impair our leasehold costs and other investments with a carrying value of $13.7 million as of December 31, 2010.

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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. Failure to comply with environmental laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties and the issuance of orders enjoining operations. 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, resulting in increased operating costs. Additionally, more stringent GHG regulation could impact demand for oil and gas. 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.

The adoption of derivatives legislation and regulations related to derivative contracts could have an adverse impact on our ability to hedge risks associated with our business.

During 2010, President Obama signed into law the Dodd—Frank Wall Street Reform and Consumer Protection Act (the “Act”). Among other things, the Act requires the Commodity Futures Trading Commission and the SEC to enact regulations affecting derivative contracts. We cannot predict the content of these regulations or the effect that these regulations will have on hedging activities. Of particular concern, the Act does not explicitly exempt end users (such as us) from the requirements to post margin in connection with hedging activities. If the regulations ultimately adopted require that companies post margin for hedging activities or impose other requirements that are more burdensome than current regulations, hedging would become more expensive.

Certain U.S. federal income tax preferences currently available with respect to oil and natural gas production may be eliminated as a result of future legislation.

Among the changes contained in President Obama’s Budget Proposal for Fiscal Year 2012 is the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production. The President’s budget proposes to eliminate certain tax preferences applicable to taxpayers engaged in the exploration or production of natural resources. Specifically, the budget proposes to repeal the deduction for percentage depletion with respect to wells, in which case only cost depletion would be available. It is unclear whether any such changes will be enacted or how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could negatively affect our financial condition and results of operations.

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.

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

Effective January 2011, we sell all of our crude oil production in Gabon to Mercuria Trading NV. The loss of Mercuria Trading NV 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 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.

Gabon

Etame Marin

VAALCO has an interest in an approximately 759,000 acre 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, 2010, 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 an approximately 12,000 acre exploitation area surrounding the field. The exploitation area has a term of up to 20 years (through 2021).

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The Etame field has been developed at an aggregate cost of approximately $197.4 million ($53.6 million net to the Company). A successful development well was drilled in 2010 in this field. The development included completing subsea wells connected to a contracted floating production, storage and offloading vessel (“FPSO”). There are currently five 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 an approximately 13,000 acre 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. In 2010, a second development well in the South Tchibala fied was drilled and successfully completed. The three development wells are tied back to the FPSO via a ten mile pipeline. Through December 31, 2010, the cost of developing the Avouma and South Tchibala fields was approximately $146.5 million ($42.8 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 an approximately 3,700 acre 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, 2010 totaled approximately $189.0 million ($59.2 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. A third development well began production in May 2010.

The Company has sold a total of 56.1 million gross bbls (13.3 million net bbls) from the fields within the Etame Marin block since startup through December 31, 2010. During 2010, the Etame, Avouma, South Tchibala and Ebouri fields produced approximately 7.3 million gross bbls (1.75 million net bbls).

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 2011. One of the two commitment exploration wells has been met with the drilling of the Omangou prospect, an unsuccessful effort, in 2010.

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 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.

In 2010, in conjunction with executing a farm-out agreement with Total Gabon, the exploration period was extended until May 2012. This extension requires the Company to reprocess 400 kilometers of 2-D seismic data and drill one exploration well. In return for Total Gabon funding an agreed portion of the new work commitment, Total Gabon will receive a 50% interest on the permit. The seismic reprocessing began in the first quarter of 2011 and the exploration well is expected to be drilled in the first half of 2012.

Angola

Block 5

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

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rights to approximately 1.4 million acres along the central coast of Angola. The government-assigned working interest partner was delinquent paying their share of the costs several times in 2009 and consequently was placed in a default position which impacted the timing for drilling the two commitment wells. In early 2010, the Company began working with the government of Angola regarding a time extension for the drilling of the wells beyond the November 2010 expiration date and to obtain a replacement partner. By governmental decree dated December 1, 2010, the former partner was removed from the production sharing contract and a one year time extension was granted. The Company and the government of Angola then agreed on the process for obtaining a replacement partner. The Company opened a data room in Houston which is expected to close in the second quarter of 2011. Information related to interested parties will then be provided to the government of Angola for selection and finalization. If necessary, the government of Angola has expressed willingness to consider a further time extension once the new partner has been selected and a timeline of the drilling plans is completed. The government of Angola has expressed willingness to consider this further extension once the new partner has been selected and a timeline of the drilling plans is completed. While we believe that the government of Angola will grant us another extension if necessary, we can provide no assurances that such an extension will be granted. If the government of Angola were to deny a time extension, and the wells are not drilling by the end of November 2011, the Company risks forfeiture of its $10 million funds in escrow, and the Company may be required to impair its leasehold costs and other investments with a carrying value of $13.7 million as of December 31, 2010.

Domestic United States Properties

The Company has interests in Brazos County, Texas producing from the Buda/Georgetown formations. The Company also owns certain non-operated interests in the Ship Shoal area of the Gulf of Mexico and in Pickens County, Alabama. During 2010, these wells produced approximately 900 bbls of oil and 14 million cubic feet of gas net to the Company. No capital expenditures are anticipated in 2010 for these properties. In December 2010, the Company acquired a 640 acre lease in north Texas in the Granite Wash formation. Capital expenditures are estimated at $9.0 million in 2011 to drill the first well on the lease.

Aggregate Production

Aggregate production data (net to the Company) for all of the Company’s operations for the years 2010, 2009, and 2008 are shown below.

Company Owned Production

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RESERVE INFORMATION

The table below sets for the Company’s estimated net proved reserves for the years ended December 31, 2010, 2009 and 2008 as prepared by Netherland Sewell & Associates, 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, 2010 and 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 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 reflect oil and natural gas spot prices on the last day of the year. As a result, estimates of proved reserves as of December 31, 2010 and 2009 may not be comparable to those as of December 31, 2008.

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 1,894 MBbls of PUDs at December 31, 2010, compared with 2,568 MBbls of PUDs at December 31, 2009. In 2010, the Company converted 674 MBbls, or 26% of the total year-end 2009 PUDs, to proved developed reserves (PDP). Approximately $28.8 million was spent in 2010 associated with development of PUDs as the Company completed the drilling of three development wells in the Etame Marin block offshore Gabon.

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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 the SEC’s regulations and GAAP. Compliance in reserves bookings is the responsibility of the Company’s Vice President-Production, who is the Company’s principal engineer. The Company’s principal engineer has over 20 years of experience in the oil and gas industry, including over 10 years as 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 Netherland Sewell & Associates, Inc. (“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, 2010, 2009 and 2008, 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.

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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 properties except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. In Gabon, the price was $78.51 per bbl. In the United States, the price was $74.39 per bbl of oil and $5.09 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

In 2010, the Company drilled two exploration wells and three development wells, all in the Etame Marin block offshore Gabon. 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.

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, 2010:

The leases in which we hold an interest in undeveloped acreage with minimum remaining terms are not material to us.

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Office Space

The Company leases its offices in Houston, Texas (approximately 15,400 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 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 28, 2011 the last reported sale price of the common stock on the New York Stock Exchange was $8.02 per share.

As of February 28, 2011 there were approximately 12,000 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 stockholder 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 stockholder 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, 2010 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 information on stock based compensation.

Issuer Purchases of Equity Securities for Year Ended December 31, 2010

The Company did not purchase any shares in the year ended December 31, 2010.

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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, 2010 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.

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 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 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

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Company’s exploration plans in Angola. Any adverse developments related to the Company’s ability to further extend the drilling obligation date, if necessary, could result in an impairment of the Company’s unproved properties and other assets with a carrying value of approximately $13.7 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 2010 was $46.1 million, as compared to $23.5 million in 2009 and $106.6 million in 2008. The increase in cash provided by operating activities was primarily due to net income of $42.4 million in 2010 versus a net loss of $4.1 million in 2009. The decrease in cash provided by operations in 2009 versus 2008 was primarily due to a net loss incurred in 2009 versus net income in 2008 and less favorable changes in operating assets and liabilities.

Net cash used in investing activities in 2010 was $39.9 million, compared to net cash used in investing activities for 2009 of $49.0 million and net cash used in investing activities in 2008 of $42.4 million. In 2010, the Company invested $37.3 million on four wells in the Etame Marin block offshore Gabon. The Company also invested in a Granite Wash formation lease in Texas ($2.2 million) and a second extension of the Mutamba Iroru block onshore Gabon ($1.2 million). In 2009, the Company invested $22.3 million primarily for the Ebouri platform and three wells. Also in 2009, 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. Also in 2008, 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 2010, cash used in financing activities was $5.5 million consisting of distributions to a noncontrolling interest owner of $6.0 million partially offset by proceeds from the issuance of common stock upon the exercise of options of $0.5 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, primarily consisting of distributions to a noncontrolling interest owner of $6.5 million and purchase of treasury shares of $8.9 million.

Capital Expenditures

During 2010, the Company invested $40.0 million in property and equipment additions (including amounts carried in accounts payable and excluding exploration dry hole costs), primarily associated with the drilling of three development wells in the Etame Marin block offshore Gabon totaling $29.3 million. In addition, one successful exploration well was drilled in the Southeast Etame area of the Etame Marin block at a cost of $8.0 million, and the Company invested in a Granite Wash formation lease in Texas ($2.2 million) and a second extension of the Mutamba Iroru block onshore Gabon ($1.2 million). During 2009, the Company invested $22.3 million in property and equipment additions 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 2008 were for FPSO upgrades ($2.0 million), onshore Gabon ($2.2 million) and drilling a well in the British North Sea ($0.8 million).

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In 2010, the Company incurred $6.8 million in exploration expense including $2.6 million on the Omangou unsuccessful exploration well offshore Gabon, $1.4 million for seismic costs in the Etame Marin block offshore Gabon, onshore Gabon exploration expense of $0.7 million, and $0.9 million in Angola primarily for geotechnical studies. 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.

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, 2010, the Company had cash balances of $81.2 million and funds in escrow of $15.8 million. The Company believes that these cash balances combined with cash flow from operations will be sufficient to fund the Company’s 2011 capital expenditure budget, which is expected to range from $35.0 to $60.0 million to further develop the Etame Marin block and for drilling in Angola and the Granite Wash lease in Texas. 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 few years. 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.

Contractual Obligations

The table below summarizes the Company’s net share of obligations and commitments at December 31, 2010:

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 square kilometers of 3-D seismic on the Etame Marin block by July 2014. One of the two exploration commitment wells was drilled in 2010 on the Omangou prospect at a cost of $8.6 million ($2.6 million net to the Company). The Company also entered into the second exploration period for the Mutamba Iroru block which requires the Company to reprocess 400 kilometers of 2-D seismic and drill one exploration well by May 2012. 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, 2011. The government-assigned working interest partner was delinquent paying their share of the costs several times in 2009 and consequently was placed in a default position which impacted the timing for drilling the two commitment wells. In early 2010, the Company began working with the government of Angola regarding a time extension for the drilling of the wells beyond the November 2010 expiration date and to obtain a replacement partner. By governmental decree dated December 1, 2010, the

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former partner was removed from the production sharing contract and a one year time extension was granted. The Company and the government of Angola then agreed on the process for obtaining a replacement partner. The Company opened a data room in Houston which is expected to close in the second quarter of 2011. Information related to interested parties will then be provided to the government of Angola for selection and finalization. If necessary, the government of Angola has expressed willingness to consider a further time extension once the new partner has been selected and a timeline of the drilling plans is completed. While we believe that the government of Angola will grant us another extension if necessary, we can provide no assurances that such an extension will be granted. If the government of Angola were to deny a time extension, and the wells are not drilling by the end of November 2011, the Company risks forfeiture of its $10 million funds in escrow and the Company may be required to impair its leasehold costs and other investments with a carrying value of $13.7 million as of December 31, 2010.

The Company is carrying $13.4 million of asset retirement obligations as of December 31, 2010, 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, 2010 Compared to Years Ended December 31, 2009 and 2008

Revenues

Total oil and gas sales for 2010 were $134.5 million as compared to $115.3 million and $169.5 million for 2009 and 2008, respectively. In 2010, the Company sold approximately 1,714,000 bbls at an average price of $78.38 per bbl from the Etame Marin block with revenues from the United States of $0.1 million. In 2009, the Company sold approximately 1,935,000 bbls at an average price of $59.54 per bbl from the Etame Marin block with revenues from the United States of $0.1 million. In 2008, the Company sold approximately 1,822,000 net bbls at an average price of $92.87 per bbl from the Etame field in Gabon with revenues from the United States of $0.3 million. Crude oil sales from the Etame Marin block 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 2010 was $22.1 million as compared to $22.0 million and $18.5 million for 2009 and 2008, respectively. In the aggregate, production expenses in 2010 were nearly the same as in 2009. In 2010, despite lower sales volumes which reduced production expenses, increased expense resulted from the Ebouri well workover ($1.5 million). Production expenses were higher in 2009 versus 2008 primarily due to higher sales volumes, and higher FPSO costs. The Company matches production expenses with crude oil sales. Any production expenses associated with unsold crude oil inventory are capitalized.

Exploration expense for 2010 was $6.8 million as compared to $36.5 million and $14.9 million for 2009 and 2008, respectively. In 2010, exploration expense is primarily comprised of $2.6 million for the Omangou unsuccessful exploration well offshore Gabon, $1.4 million for seismic costs in the Etame Marin block offshore Gabon, onshore Gabon exploration expense of $0.7 million, and $0.9 million in Angola primarily for geotechnical studies. 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 Mutamba Iroru block onshore Gabon ($20.8 million) and a well on Block 48/25c in the British North Sea ($9.6 million). Additionally, in 2009 the Company also 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

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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.

Depreciation, depletion and amortization expense was $20.0 million for 2010, and was $20.8 million and $18.9 million for 2009 and 2008, respectively. Depletion, depreciation and amortization expense decreased slightly in 2010 versus 2009 due to lower sales volumes partially offset by overall higher depletion rates. The 2010 depletion rates for the Ebouri field averaged $19.95 per bbl, Avouma and South Tchibala fields averaged $7.76 per bbl, and the Etame field averaged $5.26 per bbl. In comparison, the 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. The increase in 2009 versus 2008 was primarily due to higher production volumes.

General and administrative expense for 2010 was $7.4 million as compared to $9.6 million and $10.8 million for 2009 and 2008, respectively. The decrease in general and administrative expense for 2010 versus 2009 was primarily due to $2.1 million of increased overhead reimbursement associated with the extensive drilling program in offshore Gabon and a decrease in retirement benefits of $1.0 million.

General and administrative expense decreased in 2009 versus 2008 due in part to non-recurring legal and solicitation costs associated with corporate matters relating to the Company’s 2008 annual meeting. During 2010, the Company incurred $1.8 million of stock based compensation compared to $1.8 million incurred in 2009 and $2.6 incurred in 2008. 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 2010 and 2008, 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 2010 was $78.1 million as compared to a $33.0 million and $106.5 million for 2009 and 2008, respectively. The significant increase in operating income in 2010 versus 2009 was primarily attributable to the higher average crude sales price of $78.38 per bbl, an increase of $18.84 per bbl, and a year to year decrease in exploration expense totaling $29.7 million. The decrease in exploration expense reflects less dry hole expense incurred in 2010 versus 2009.

The significant decrease in operating income in 2009 versus 2008 was primarily attributable to the lower average crude sales price of $59.54 per bbl, a decrease of $33.33 per bbl compared to the 2008 sales price, and higher exploration costs related to unsuccessful exploratory wells. Also, partially contributing to the decrease in operating income were higher operating expenses and depletion expense.

Other Income (Expense)

Interest income for 2010 was $0.2 million compared to $0.7 million and $2.5 million in 2009 and 2008, respectively. All the 2010, 2009, and 2008 amounts represent interest earned and accrued on cash balances and funds in escrow. Extremely low interest rates in 2010 account for the decrease in interest income.

No interest expense was recorded in 2010. Interest expense of $0.5 million was recorded in 2009 as compared to $0.2 million in 2008. Interest in both 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.

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Other expense for 2010 was $0.6 million compared to $0.5 million in 2009. Other expense was negligible in 2008. The other expense in both 2010 and 2009 was primarily associated with foreign exchange losses.

Income Taxes

In 2010, the Company incurred $35.3 million of income taxes compared to $36.9 million incurred in 2009 which were associated with the Etame Marin block production, and which were incurred in Gabon. In 2008, the Company incurred $73.0 million of income taxes associated with the Etame Marin block production, which were incurred in Gabon. The slightly lower income taxes incurred in 2010 versus 2009 was a function of lower sales quantities largely offset by higher crude oil sales prices. The decreased tax in Gabon in 2009 versus 2008 was due to lower crude oil sales prices in 2009, which was partially offset by higher sales quantities. Also a larger percentage of crude was subject to taxation in 2008 as part of profit oil versus cost oil.

Net Income (Loss)

Net income for 2010 was $42.4 million compared to a net loss in 2009 of $4.1 million. Net income in 2008 was $35.7 million. The increase in net income in 2010 versus 2009 is attributable to the increased crude oil sales prices and lesser unsuccessful exploration well costs incurred in 2010. The decrease in 2009 versus 2008 was attributable primarily to the unsuccessful exploration well costs incurred and lower crude oil sales prices.

Income attributable to the noncontrolling interest in the Gabon subsidiary was $5.0 million, $3.7 million and $6.0 million in 2010, 2009, and 2008, respectively.

NEW ACCOUNTING PRONOUNCEMENTS

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

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, 2010 the Company did not have any debt and thus no exposure to interest rate risk on debt. Interest earned on cash investments is immaterial.

Commodity Price Risk

The Company had no derivatives in place as of the date of this report, or throughout 2010, 2009 or 2008.

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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 Securities Exchange Act of 1934, as amended (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 Exchange Act) 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 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 quarter 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 14, 2011, management concluded that its internal control over financial reporting was effective as of December 31, 2010.

The Company’s internal control over financial reporting as of December 31, 2010 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, 2010, 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, 2010 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, 2010, 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, 2010, 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, 2010 of the Company, and our report dated March 14, 2011 expressed an unqualified opinion on those consolidated financial statements.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

March 14, 2011

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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, 2010 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 2011 annual meeting, which will be filed with the Commission within 120 days of December 31, 2010, and which is incorporated herein by reference.

Information required by this item will be included in the Company’s proxy statement for its 2011 annual meeting, which will be filed with the Commission within 120 days of December 31, 2010, and which is incorporated herein by reference.

Information required by this item under 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 2011 annual meeting, which will be filed with the Commission within 120 days of December 31, 2010, and which is incorporated herein by reference. Please see “Item 5—Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchase of Equity Securities” for 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 2011 annual meeting, which will be filed with the Commission within 120 days of December 31, 2010, and which is incorporated herein by reference.

The information required by this item is incorporated by reference from the Company’s definitive proxy statement for its 2011 annual meeting, which will be filed with the Commission within 120 days of December 31, 2010, and which is incorporated herein by reference.

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PART IV

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