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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K/A

Amendment No. 1

(Mark One)

For the fiscal year ended December 31, 2005

OR

For the transition period from              to             

Commission file number: 0-20928

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

Indicate by check mark if no 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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Large accelerated filer    ¨                Accelerated filer    x                Non-accelerated filer    ¨

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 March 1, 2006 was $364,394,350.

As of March 1, 2006, there were outstanding 57,576,315 shares of common stock, $0.10 par value per share, of the registrant.

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

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We are providing this Amendment to Form 10-K to amend certain incorrect dates in the Report of Independent Registered Public Accounting Firm within Item 9A. Controls and Procedures.

PART I

Item 1. Business

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. Domestically, the Company has minor interests in the Texas Gulf Coast area. 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 Gabon subsidiaries are VAALCO Gabon (Etame), Inc. and VAALCO Production (Gabon), Inc. VAALCO Energy (USA), Inc. holds interests in certain properties located in the United States.

In connection with a merger with 1818 Oil Corp. in 1998, the Company issued to the 1818 Fund II, L.P. (the “1818 Fund”) common stock and preferred stock, representing approximately 65% of the outstanding voting power of the Company on an as converted basis (excluding options and warrants). On March 17, 2005, the 1818 Fund converted its remaining preferred stock into common stock at the rate of 2,750 shares of common stock per share of preferred stock, resulting in 18,334,250 shares of common stock being issued. In connection with the transaction, the holder exercised warrants to purchase 5,250,000 shares of common stock under a cashless exercise procedure and was issued 4,635,244 shares of common stock. The 614,756 shares which were used to pay the purchase price under the cashless exercise were placed in the treasury. The stock acquired by the conversion of preferred stock and exercise of the warrants and shares of common stock already held by the 1818 Fund, totaled 35,898,685 shares. These shares were sold in March 2005 in block sales over the American Stock Exchange with all proceeds going to the 1818 Fund. With the completion of the conversion of preferred stock and exercises of warrants, the Company has no preferred stock or warrants outstanding.

RECENT DEVELOPMENTS

The Company’s primary source of revenue is from the Etame field located offshore the Republic of Gabon. The Company drilled one additional development well in the Etame field during 2005, the Etame 6H well. During 2005, the Etame field produced approximately 6.9 million bbls (1.6 million bbls net to the Company). The Etame field is located within the Etame Marin Block, where the Company discovered two additional fields in 2004, the Avouma field and the Ebouri field. The Avouma discovery is adjacent to the South Tchibala discovery drilled in the late 1970’s by a previous operator, but never developed.

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During 2005, the Company received approval from the Gabon government for a joint development plan for the Avouma and South Tchibala discoveries. A platform is currently being constructed for installation during the summer of 2006, with first production from the Avouma/South Tchibala fields expected to occur in the fourth quarter of 2006. The Company anticipates receiving approval for a development plan for the Ebouri field in 2006. The Company drilled one exploration well on the Etame Block in 2005, the Avouma South No. 1, which did not encounter hydrocarbons.

In November 2005, the Company signed a production sharing contract for the Mutamba Iroru block onshore Gabon. The five year contract awards the Company exploration rights to approximately 270,000 acres along the central coast of Gabon. The Company is currently gathering data from past operators of the area for interpretation and prospect delineation.

AVAILABLE INFORMATION

The Company files annual, quarterly and current reports, proxy statements and other information with the SEC. You may read and copy any document the Company files at the SEC’s Public Reference Room at 450 Fifth Street, N.W., 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 Company, 4600 Post Oak Place, Suite 309, Houston, TX 77027.

GENERAL

The Company’s current strategy is to maximize the value of the reserves discovered in Gabon through exploitation of the Etame field, and development of the Avouma, South Tchibala and Ebouri discoveries. The Company has recently established an office in Aberdeen, Scotland with the intention of participating in the June 2006 bidding round for entrance into the Central Oil Basin and the Southern Gas Basin in the United Kingdom sector of the North Sea. The Company is also actively seeking additional opportunities in West Africa.

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 using current technology. The Company believes that it has unique management and technical expertise in identifying international opportunities and establishing favorable operating

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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 internationally in Gabon.

Domestic

The Company’s domestic strategy is to produce existing reserves. There are no plans to drill new domestic wells at this time.

CUSTOMERS

Substantially all of the Company’s crude oil and natural 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 sells crude oil under a contract with Trafigura Beheer B.V. which runs for the calendar year 2006. While the loss of Trafigura 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 under 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, 2005, the Company had 16 full-time employees, nine of whom were located in Gabon. The Company also utilizes contractors to staff its international operations. The Company is not subject to any collective bargaining agreements and 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, drilling and acquisition programs and others. Many of these competitors possess financial and personnel resources substantially in excess of those available to the Company, giving those competitors an enhanced ability to pay for desirable leases and to evaluate, bid for and purchase 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.

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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 and also are subject to the laws and regulations of Gabon. In addition the Company is subject to the International Finance Corporation environmental guidelines. Although no assurances can be made, the Company believes that, absent the occurrence of an extraordinary event, compliance with existing laws, rules and regulations and the International Finance Corporation environmental guidelines 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, changes in International Finance Corporation environmental guidelines, 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 it is a developing country, it is unclear how quickly and to what extent Gabon will increase its regulation of environmental issues in the future; any significant increase in the regulation or enforcement of environmental issues by Gabon could have a material effect on the Company. Developing countries, in certain instances, have patterned environmental laws after those in the United States. However, the extent to which any environmental laws are enforced in developing countries varies significantly.

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, it is possible that certain wastes generated by the Company’s oil and gas operations that are currently exempt from treatment as Hazardous Wastes 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.

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Superfund

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

Clean Water Act

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

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Oil Pollution Act

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

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

Air Emissions

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

Coastal Coordination

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

In Texas, the Legislature enacted the Coastal Coordination Act (“CCA”), which provides for the coordination among local and state authorities to protect coastal resources through regulating land use, water, and coastal development. The act establishes the Texas Coastal Management Program (“CMP”). The CMP is limited to the nineteen counties that border the

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Gulf of Mexico and its tidal bays. The act provides for the review of state and federal agency rules and agency actions for consistency with the goals and policies of the Coastal Management Plan. This review may impact agency permitting and review activities and add an additional layer of review to certain activities undertaken by the Company.

OSHA and other Regulations

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

International Finance Corporation Environmental Guidelines

The loan agreement dated April 19, 2002 between one of the Company’s subsidiaries and the International Finance Corporation requires the Company to comply with specified environmental guidelines. These guidelines set maximum air emission levels and liquid effluent amounts, impose requirements for proper onshore disposal of all solid and hazardous wastes, and require compliance with other similar environmental guidelines. In addition, the Company is required to utilize environmental best practices for drilling activities and produced water and chemical management, prepare emergency response and oil spill response plans, and implement monitoring and reporting procedures. The Company believes that it is in substantial compliance with all applicable International Finance Corporation environmental guidelines. However, if a project were found to be not in compliance with the guidelines, the International Finance Corporation financing could be in jeopardy.

FORWARD-LOOKING STATEMENTS

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

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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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Item 1A. Risk Factors

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 occur, 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 and its subsidiaries, unless the context clearly indicates otherwise.

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

The Etame field, consisting of four producing wells, constituted almost 100% of our total production for the year ended December 31, 2005. In addition, at December 31, 2005, almost 100% of our total net proved reserves were attributable to this field. 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. An increase in the exchange rate of the local currency to the dollar will have the effect of increasing operating costs while a decrease in the exchange rate will reduce 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. The Euro appreciated substantially against the U.S. dollar in 2003 and 2004, while in 2005 the U.S. dollar appreciated against the Euro.

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 and are likely to continue to be volatile in the future. In 2005, medium/heavy sweet crude oils, which produce higher amounts of residual fuel oil, experienced weaker demand in the marketplace. This has resulted in those crude oils trading at a discount to their traditional benchmark. These crude oils are similar to those produced from the Etame Field, and the lower market price may have an adverse impact upon our results of operations.

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

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that are beyond our control. These factors include international political conditions, the domestic and foreign supply of oil and gas, the level of consumer demand, weather conditions, domestic and foreign governmental regulations, the price and availability of alternative fuels 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.

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, economic/currency imbalances, compliance with governmental requirements or delays in the delivery of equipment and availability of drilling rigs. Our current domestic oil and gas properties are operated by third parties and, as a result, we have limited control over the nature and timing of exploration and development of such properties or the manner in which operations are conducted on such properties.

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

We make, and will continue to make, substantial capital expenditures for the acquisition, exploitation, development, exploration and production of oil and gas reserves. Historically, we have financed these expenditures primarily with cash flow from operations, debt, asset sales, and private sales of equity. During 2005, we have participated, and in 2006 we will continue to participate, in the further exploration and development of the Etame Field offshore Gabon. We are the operator for the field and 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 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 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.

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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 natural 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 incorporated by reference into this document are based on various assumptions required by the SEC, including unescalated prices and costs and capital

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expenditures, 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 SEC guidelines, and are not intended to reflect the fair market value of our reserves. In accordance with the rules of the SEC, our reserve estimates are prepared using period-end prices received for oil and gas. Future reductions in prices below those prevailing at year-end 2005 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

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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, 2005, we carried a gross investment of approximately $52.7 million on our balance sheet associated with the Etame field ($35.7 million net of accumulated depletion, depreciation and amortization costs). 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.

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 and Gabon regulate our business. Our operations could result in liability for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages. In addition, we could be liable for environmental damages caused by, among others, previous property owners or operators. 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.

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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 wells as the oil and gas industry in general. In addition, the Company is subject to International Finance Corporation environmental guidelines published by the World Bank. While we believe that we are currently in compliance with environmental laws and regulations applicable to our operations in Gabon and the U.S., including those required by the International Finance Corporation, 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 adopted Statement of Financial Accounting Standards 143, – Accounting for Asset Retirement Obligations on January 1, 2003. This Statement requires that the fair value of a liability for an asset retirement obligation be recognized 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.

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, our hedging agreements expose us to risk of financial loss if the counterparty to a hedging contract defaults on its contract obligations.

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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, particularly Messrs. Gerry and Scheirman. The unexpected loss of the services of any of these individuals could have a detrimental effect on us. We do not maintain key man life insurance on any of our employees.

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

We sell all of our crude oil production in Gabon to Trafigura Beheer B.V. The loss of Trafigura 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, does 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.

Item 1B. Unresolved Staff Comments

None.

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Item 2. Properties

Gabon

Etame Marin

VAALCO has an interest in a 1,186 square mile offshore block in Gabon, the Etame Marin Block where it signed a production sharing contract in 1995. The block contains five discoveries including the Etame field, which is on production, the Avouma and Ebouri discoveries and two former Gulf Oil Company discoveries, the North and South Tchibala discoveries. These discoveries consist of subsalt reservoirs that lie 20 miles offshore in approximately 250 feet of water depth.

VAALCO operates the Etame block on behalf of a consortium of companies. At December 31, 2005, VAALCO owned a 30.35% interest in the production-sharing contract covering the Etame Block, a 28.1% interest in the development area surrounding the Etame field development and a 30.35% interest in the development area surrounding the Avouma/South Tchibala discoveries. The development areas are subject to a 7.5% back-in by the Government of Gabon, which occurred for the Etame field upon commencement of production.

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

The Etame field has been developed in two phases. The Phase 1 development consisted of completing three subsea wells connected to a Floating Production, Storage and Offloading vessel (“FPSO”) at a cost of approximately $57.3 million ($17.4 million net to the Company).

The Phase 2 Etame field development plan was submitted to the Gabon government for approval in October 2003. The Company drilled two new development wells (the Etame-5H well in 2004 and the Etame 6H well in 2005). The cost of adding the Etame 5H and 6H wells was approximately $60.0 million ($18.2 million net to the Company) and included laying two new flowlines and umbilicals from the well sites to the FPSO onsite in the Etame field.

The Company has sold a total of 19.3 million gross bbls (4.4 million net bbls) since field startup through December 31, 2005. During 2005, the Etame field produced approximately 6.9 million gross bbls (1.6 million net bbls). Production continues at rates of approximately 17,500 BOPD as of the date of this filing.

In April 2005, a development plan for the joint development of the Avouma and South Tchibala discoveries was approved by the Gabon government. The Company was awarded a 20 square mile exploitation area which has a term of twenty years (until 2025). The Company plans to drill two development wells from a platform. The two development wells are expected to be tied back to the Etame FPSO via a pipeline. The platform is currently under construction in Louisiana and is expected to be installed during the summer of 2006. First production is anticipated for the fourth quarter of 2006. The budget for the development of the Avouma field is $102.0 million ($31.0 net to the Company).

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The Company drilled the Ebouri discovery well to total depth in January 2004. The well resulted in a new Gamba sand discovery logging 46 feet of oil pay in a 55 foot Gamba sand. Two sidetracks were performed to delineate the discovery, each of which logged a comparable amount of oil pay in the Gamba. The Company has recently completed processing new seismic data acquired in 2005 over the Ebouri discovery. Based on the results of the seismic data and the well results, a development plan for the Ebouri discovery is currently being prepared for submission to the Gabon government later in 2006.

Mutamba Iroru

In November 2005, the Company signed a production sharing contract for the Mutamba Iroru block onshore Gabon. The five year contract awards the Company exploration rights to approximately 270,000 acres along the central coast of Gabon. The block was previously held by Shell Gabon. The Company is currently gathering data from past operators of the area for interpretation and prospect delineation. The Company currently has a 100% interest in the Mutamba Iroru block.

Domestic Properties

The Company has interests in seven producing wells in Brazos County, Frio County and Dimmit County, Texas producing from the Buda/Georgetown formations. The Company also owns certain non-operated interests in Ship Shoal areas of the Gulf of Mexico. During 2005 the wells produced approximately 2,300 bbls of oil and 17 million cubic feet of gas net to the Company. No capital expenditures are anticipated in 2006 for these properties.

Aggregate Production

Aggregate production data (net to the Company) for all of the Company’s operations for the years 2005 and 2004 are shown below. The production figures exclude discontinued operations:

Company Owned Production

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RESERVE INFORMATION

A reserve report as of December 31, 2005 has been opined on 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 Commission since the beginning of the last fiscal year. The reserves are located in Gabon and in Texas (onshore and offshore).

The following tables set forth the net proved reserves of the Company as of December 31, 2005 and 2004, and the changes during such periods.

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The Company maintains a policy of not booking 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.

In 2004, the Company made two discoveries offshore Gabon, the Ebouri and the Avouma discoveries. The Avouma discovery is adjacent to a previous discovery known as the South Tchibala discovery. The Company has received approval of the Avouma/South Tchibala joint development plan from the Gabon government and booked additions to proven reserves of 1,447,000 bbls for the South Tchibala/Avouma field offshore Gabon in at year-end 2004.

For the Ebouri discovery, because of the decision to participate in a seismic shoot over Ebouri and other areas in the northern part of the Etame Block, the Company did not request any approvals for the development of the Ebouri discovery from its partners or the government, pending the results of the seismic. Therefore, the Company has not booked any reserves for the Ebouri discovery at December 31, 2005. The Company is preparing a development plan for Ebouri to be filed with the Gabon government in 2006. The Company also has not booked any reserves associated with the North Tchibala discovery on the Etame block.

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.

In accordance with the 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 in effect as of year end 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 $56.80 per bbl representing a $1.41 discount to the spot price of Dated Brent Crude at December 31, 2005. In Texas, the price was $54.61 per barrel of oil and $9.07 per Mcf of gas. See Supplemental Information on Oil and Gas Producing Properties for certain additional information concerning the proved reserves of the Company.

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Drilling History

The Company participated in one exploration well and one development well in Gabon during 2005.

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, 2005:

Office Space

The Company leases its offices in Houston, Texas (approximately 8,000 square feet) and in Port Gentil, Gabon (approximately 6,000 square feet), which management believes are suitable and adequate for the Company’s operations.

Available Information

Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are made available free of charge on our website at http://www.vaalco.com as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.

Item 3. Legal Proceedings

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

Item 4. Submission of Matters to a Vote of Security Holders

None.

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PART II

Item 5. Market for Common Equity and Related Stockholder Matters

General

Since July 2004, the Company’s common stock has traded on the American Stock Exchange under the symbol EGY. Prior to such time the Company’s common stock traded on the OTCBB under the symbol VEIX. The following table sets forth the range of high and low sales prices of the common stock for the periods indicated and the high and low bid prices on the OTCBB. OTCBB quotations represent adjusted prices between dealers, do not include retail markups, markdowns or commissions and do not necessarily represent actual transactions.

On February 28, 2006 the last reported sale price of the common stock on the American Stock Exchange was $6.55 per share.

As of February 28, 2005 there were approximately 16,000 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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Item 6. Selected Financial Data

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, 2005 has been derived from the Company’s audited 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.

VAALCO ENERGY COMPANY

SELECTED HISTORICAL FINANCIAL INFORMATION

(In thousands, except per share amounts)

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

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 field on behalf of a consortium of five companies offshore of the Republic of Gabon. The Phase 1 development of the field occurred in 2002 and consisted of completing three wells producing into an FPSO. The Phase 2 development commenced in 2004 and consisted of adding two wells to the Etame field, one in 2004 and one in 2005.

In 2006, the Company will jointly develop the Avouma/South Tchibala discoveries by setting a platform and tying the field back to the FPSO via a pipeline. The platform in currently under construction in Louisiana and will be installed during the summer of 2006, with first production expected in the fourth quarter of 2006.

The Company’s results of operations and financial condition are affected by currency exchange rates. While oil sales are denominated in U.S. dollars, portions of the operating costs in Gabon are denominated in the local currency. An increase in the exchange rate of the local currency to the dollar will have the effect of increasing operating costs while a decrease in the exchange rate will reduce 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. The Euro appreciated substantially against the U.S. dollar in 2003 and 2004, while in 2005 the U.S. dollar appreciated against the Euro.

A substantial portion of the Company’s oil production is located offshore Gabon. In Gabon, the Company produces into a 1.1 million barrel FPSO and sells cargos to Trafigura Beheer, B.V. at spot market prices.

CRITICAL ACCOUNTING POLICIES

The following describes the critical accounting policies used by VAALCO 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.

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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.

For financial accounting purposes the Company adopted SFAS 143 – Accounting for Asset Retirement Obligations on January 1, 2003. This Statement requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred by capitalizing it as part of the carrying amount of the long-lived assets. Other exploration costs, including geological and geophysical expenses applicable to undeveloped leasehold, leasehold expiration costs and delay rentals are expensed as incurred.

In accordance with accounting under successful efforts, 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 discovers lower than anticipated reserves or if commodity prices fall below a level that significantly effects anticipated future cash flows on the field.

SUSPENDED WELL COSTS

FASB Statement No. 19 - Under the “successful efforts” method of accounting used by the Company for its oil and gas exploration and development costs, all expenditures related to exploration, with the exception of costs of drilling exploratory wells are charged to expense as incurred. The costs of exploratory wells are capitalized on the balance sheet pending determination of whether commercially producible oil and gas reserves have been discovered. If the determination is made that a well did not encounter potentially economic oil and gas quantities, the well costs are charged to expense. These determinations are re-evaluated quarterly.

For capitalized exploration drilling costs, if it is determined that a development plan is feasible, and the development plan is approved by the Gabon government, costs associated with the exploratory wells will be transferred along with the costs spent on the development to “wells, platforms and other production facilities” at the time of first production. The costs will subsequently be amortized on a unit of production based method over the life of the reserves as they are produced. In the event it were determined that the discoveries are not commercial, the costs of the exploratory wells would be expensed.

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For offshore exploratory discoveries, it is not unusual to have exploratory well costs remain suspended while additional appraisal and engineering work on the potential oil and gas field is performed and regulatory and government approvals are sought. In Gabon, the government must approve the commerciality of the reserves, assign a development area and approve a formal development plan prior to a field being developed.

On April 4, 2005, the Financial Accounting Standards Board (“FASB”) issued FASB Staff Position No. FAS 19-1 (“FSP FAS 19-1”), which addressed a discussion that was ongoing within the oil industry regarding capitalization of costs of drilling exploratory wells. Paragraph 19 of FASB Statement No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies (“FASB No. 19”), requires costs of drilling exploratory wells to be capitalized pending determination of whether the well has found proved reserves. If the well has found proved reserves, the capitalized costs become part of the entity’s wells, equipment, and facilities. If, however, the well has not found proved reserves, the capitalized costs of drilling the well are expensed. Questions arose in practice about the application of this guidance due to changes in oil and gas exploration processes and lifecycles. The issue was whether there are circumstances that would permit the continued capitalization of exploratory well costs if reserves cannot be classified as proved within one year following the completion of drilling, other than when additional exploration wells are necessary to justify major capital expenditures and those wells are underway or firmly planned for the near future. FSP FAS 19-1 amends FASB No. 19 to allow for the continued capitalization of suspended well costs when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the plan. The issuance of this amendment did not result in an adjustment to the Company’s suspended well costs.

The Company had $6.5 million of suspended well costs associated with exploration wells at Avouma and Ebouri in Gabon at December 31, 2005, which is being carried as work in progress. In February 2005, the Company received approval to declare the Avouma reserves commercial from the Gabon government and in April 2005 the Gabon government approved a joint development plan for the Avouma/South Tchibala discoveries, and assigned a twenty year development area. Construction of the platform facilities to develop Avouma/South Tchibala is ongoing.

For Ebouri, the Company acquired new seismic data over the discovery in January 2005 and completed processing of the seismic in December 2005. Based on the results of the seismic data, the Company believes the discovery is commercial and intends to seek government approval of commerciality of the discovery, file for a development area and submit a development plan in 2006.

CAPITAL RESOURCES AND LIQUIDITY

Cash Flows

Net cash provided by operating activities for 2005 was $35.9 million, as compared to $22.8 million in 2004 and $22.6 million in 2003. Net cash provided by operations in 2005

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consisted of net income of $29.2 million, non-cash depreciation, depletion and amortization of $5.4 million and add back of non-cash exploration expense of $2.7 million associated with the Avouma South exploration well. Working capital, other than cash, decreased $5.0 million in 2005, primarily associated with Gabon operations. A non-cash add back of $3.6 million was associated with minority interest in VAALCO Gabon (Etame), Inc.

Net cash provided by operations in 2004 included net income of $22.9 million, non-cash depreciation, depletion and amortization of $4.8 million and working capital decreases net of taxes payable of $8.4 million, which was primarily associated with Gabon operations. Non cash exploration expense added 0.3 million and non-cash loss on the sale of the Philippines assets added back $0.2 million. Also, a non-cash add back of $3.1 million was associated with minority interests in Gabon.

Net funds provided by operations in 2003 included net income of $8.9 million, non-cash depreciation, depletion and amortization of $5.9 million and working capital increases of $4.1 million, which was primarily as a result of operations in the Etame field. Net funds provided by operations also included the add back of non-cash exploration expense of $1.8 million associated with the write off of the Etame 2V well in Gabon and certain acreage acquired prior to 2003, and non-cash add back of $1.3 million of minority interest expense, as well as non-cash compensation expense of $0.4 million, non-cash amortization of debt discount adding back $1.6 million and the cumulative effect of accounting change use of $1.7 million.

Net cash used in investing activities for 2005 was $16.7 million compared to $14.7 net cash used in investing activities in 2004 and $6.0 million provided by investing activities in 2003. In 2005, the primary components of the $13.3 million of cash used for property and equipment were $6.9 million to drill the Etame 6H development well, $5.6 million to commence construction of the Avouma platform and $0.8 million to add a gas lift compressor to the FPSO. The Company also used $2.7 million to drill the Avouma South exploration well. In 2004, the Company invested $9.7 million to fund its share of the Phase 2 development of the Etame Block, and $4.6 million to drill the Ebouri and Avouma exploration wells. The Ebouri and Avouma wells were subsequently suspended as discovery wells in 2004. An additional amount of $1.2 million was used for discontinued operations transaction expense in 2004 and a net of $1.0 million was sourced from funds in escrow. In 2003, the Company added to its investment in Gabon by participating in the Ebouri exploration well, which was classified as work in progress at year end 2003 and finished drilling in 2004. The Company received $7.9 million net funds in escrow.

In 2005, net cash used in financing activities was $2.9 million consisting of $2.3 million of debt repayment and $2.0 million of distributions to a minority interest holder, offset by $1.4 million of proceeds from the issuance of common stock. In 2004, net cash used by financing activities was $3.5 million, consisting of $3.3 million in debt repayment and $0.6 million in distributions to a minority interest holder, which was offset by $0.3 million proceeds from the issuance of common stock. In 2003, net cash used by financing activities was $13.3 million consisting primarily of $13.0 million of debt reduction and $0.3 million of distributions to a minority interest holder.

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Capital Expenditures

During 2005, the Company spent $6.9 million to drill and hookup the Etame 6H well, $5.6 million on Avouma platform design and construction and $0.8 on gas lift compressor installation on the FPSO and other FPSO modifications. During 2004, the Company spent $9.7 million on activities associated with the Etame Phase 2 development program, and $4.6 million on the Ebouri and Avouma exploration wells. During 2003, the Company spent $1.9 million on activities associated with the Phase 2 development and to commence the drilling of an exploration well. During 2006, the Company anticipates spending $26.4 million for its share of the development of the Avouma field. The Company may also participate in other exploration activities in Gabon or the North Sea, although no projects have been firmly designated at the time of this filing.

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, 2005, the Company had cash balances of $43.9 million. The Company believes that this cash balance combined with cash flow from operations will be sufficient to fund the Company’s 2006 capital expenditure budget of approximately $26.4 million to develop the Avouma field and additional investments in working capital resulting from potential growth. As operator of Etame field the Company enters into project related activities on behalf of its working interest partners. The Company generally obtains advances from it partners prior to significant funding commitments.

To fund its share of the Phase 1 Etame field development costs, on April 19, 2002, the Company entered into a $10.0 million credit facility with the International Finance Corporation (“IFC”), a subsidiary of the World Bank. During the year ended December 31, 2005 the Company repaid $2.25 million of the loan as called for under the facility repayment schedule and had a remaining due to $1.5 million at December 31, 2005.

In June 2005, the Company executed a loan agreement for a $30.0 million revolving credit facility secured by the assets of the Company’s Gabon subsidiary. The facility will be utilized to finance a portion of the Avouma and Ebouri field development activities. The facility extends through June 2008 at which point it can be extended, or converted to a term loan. This facility became effective during the first quarter of 2006. This facility replaced the existing term credit facility, which was repaid on February 15, 2006 in connection with a borrowing from this revolving facility. The Company will incur a charge of $159,000 to write off capitalized finance charges associated with the early repayment of the term credit facility in the first quarter of 2006.

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Contractual Obligations

In addition to its lending relationships and obligations, the Company has contractual obligations under operating leases. The table below summarizes these obligations and commitments at December 31, 2005:

Payment Period

In addition to the contractual obligations described above, the Company is required to spend $2.1 million for its share of an exploration well on the Etame block by July 6, 2009 and $4.0 million for it share of an exploration well on the Mutamba Iroru block by November 11, 2008.

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RESULTS OF OPERATIONS

Year Ended December 31, 2005 Compared to Years Ended December 31, 2004 and 2003

Amounts stated hereunder have been rounded to the nearest $100,000.

Revenues

Total oil and gas sales for 2005 were $84.9 million as compared to $56.5 and $35.5 million for 2004 and 2003. In 2005, the Company sold 1,633,000 net bbls at an average price of $52.04 from the Etame field in Gabon. Revenues from Texas amounted to $0.2 million. In 2004, the Company sold 1,467,000 net bbls at an average price of $38.36 per barrel from the Etame field in Gabon. Revenues from Texas in 2004 were approximately $0.25 million. Revenues in 2003 were predominately from production from the Etame field, where the Company sold 1,227,000 net bbls at an average price of $28.54 per barrel. Revenues from Texas in 2003 were approximately $0.4 million. The increased oil volumes from Etame in 2005 versus 2004 were due to the addition of the Etame 6H Phase 2 development well completed in July 2005. The increased oil volumes from Etame in 2004 versus 2003 were due to the addition of the Etame 5H Phase 2 development well completed in August 2004.

Operating Costs and Expenses

Production expenses for 2005 were $10.6 million as compared to $10.0 and $9.0 million for 2004 and 2003. In 2005, operating expenses increased due to higher support vessel charges associated with crude oil liftings, and an increase in the FPSO lease rate due to addition of the gas lift compressor. In 2004, operating expenses increases for the Etame field due to the devaluation of the dollar versus the Euro. Personnel costs for manning the FPSO are Euro based.

Exploration costs for 2005 were $2.7 million as compared to $0.3 and $2.1 million for 2004 and 2003. In 2005, exploration expenditures were associated with the Avouma South exploration well, which did not encounter hydrocarbons and was plugged and abandoned. In 2004, exploration expenditures were associated with seismic processing and interpretation activities in Gabon. Exploration costs in 2003 included of a $1.5 million write off of the Etame 2V well, which had previously been carried as work in progress, and the $0.3 million write off of certain leases that expired in Alabama and Mississippi. In 2003, exploration expense also included $0.3 million for seismic reprocessing in Gabon.

Depreciation, depletion and amortization expense was $5.4 million for 2005, and was $4.7 million and $5.8 million for 2004 and 2003 respectively. Depletion increased in 2005 versus 2004 primarily due to higher production rates. Depletion in 2004 was lower than in 2003 at the Etame field due to the increase in reserves booked at year end 2003. Depletion in 2003 included Etame production accounting for $5.6 million of the year’s total. The $0.2 million balance was associated with the Texas wells.

General and administrative expenses for 2005 were $2.7 million as compared to $1.3 and $2.0 million for 2004 and 2003. Expenses increased in 2005 versus 2004 due to increased administrative activity to acquire the Mutamba Iroru block, and the Company’s efforts to open a

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new office in Aberdeen to evaluate entrance into the North Sea. Expenses were lower in 2004 than in 2003, as the Company received reimbursement for general and administrative expenses associated with the Phase 2 development project and the Ebouri and Avouma exploration wells.

Operating Income

Operating income for 2005 was $63.6 million as compared to a $40.3 and $16.6 million operating income for 2004 and 2003. Higher oil sales volumes and prices in Gabon were the primary reason for the increases in each of 2004 and 2005.

Other Income (Expense)

Interest income for 2005 was $1.1 million compared to $0.3 and $0.1 million in 2004 and 2003. Both the 2004 and 2005 amounts represent interest earned and accrued on cash balances and funds in escrow. Interest rates also increased in 2005 as compared to 2004.

Interest expense of $0.4 million was recorded in 2005 as compared to $0.5 and $2.6 million in 2004 and 2003. Interest in all three years was associated with the financings for the development of the Etame field. In 2003, interest expense included $1.6 million of non cash amortization of debt discount associated with the issuance of warrants in connection with the 1818 Fund Loan.

Income Taxes

In 2005, the Company incurred $31.5 million of income taxes associated with the Etame field production, which were paid in Gabon. In 2004, the Company incurred $12.0 million of foreign income taxes associated with the Etame field production, which were paid in Gabon. This compared to $5.5 million paid in Gabon in 2003. The increase in 2005 was due to attaining recovery of all previous costs expended on the Etame block, which results in a higher tax rate per barrel going forward.

Minority Interest

A provision for minority interest in the Gabon subsidiary of $3.6 million, $3.1 million and $1.3 million was made for in 2005, 2004 and 2003 respectively.

Loss from Discontinued Operations

Loss from discontinued operation in the Philippines was $69,000 in 2005 for wind up costs of shutting down the branch offices in Manila. Loss from discontinued operations associated with the sale of the Company’s former Philippines assets was $2.1 million in 2004, consisting of $1.8 million in branch profit remittance income taxes and $0.3 million in general and administrative and interest costs associated with closing down the branch offices. Loss from discontinued operations was $35,000 in 2003.

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Cumulative Effect of Accounting Change

In 2003 the Company experienced a one time gain of $1.7 million associated with the adoption of SFAS No. 143 “Accounting for Asset Retirement Obligations.”

Net Income

Net income for 2005 was $29.2 million as compared to a net income of $22.9 and $8.9 million in 2004 and 2003. The impact of higher oil sales volumes in Gabon from the addition of the Etame 6H development well and higher oil and gas prices was responsible for the increase in net income in 2005 as compared to 2004. The impact of higher oil sales volumes in Gabon from the addition of the Etame 5H development well and higher oil and gas prices was responsible for the increase in net income in 2004 as compared to 2003.

NEW ACCOUNTING PRONOUNCEMENTS

SFAS 123(R), Share Based Payment - In December 2004, the FASB issued SFAS No. 123(R), Share-Based Payment, which establishes accounting standards for all transactions in which an entity exchanges its equity instruments for goods and services. SFAS No. 123(R) focuses primarily on accounting for transactions with employees, and carries forward without change to prior guidance for share-based payments for transactions with non employees.

SFAS No. 123(R) eliminates the intrinsic value measurement objective in APB Opinion 25 and generally requires the Company to measure the cost of employee services received in exchange for an award of equity instruments based on the fair value of the award on the date of the grant. The standard requires grant date fair value to be estimated using either an option-pricing model which is consistent with the terms of the award or a market observed price, if such a price exists. Such cost must be recognized over the period during which an employee is required to provide service in exchange for the award (which is usually the vesting period). The standard also requires the Company to estimate the number of instruments that will ultimately be issued, rather than accounting for forfeitures as they occur.

The Company is required to apply SFAS No. 123(R) to all awards granted, modified or settled in the first reporting period under U.S. GAAP after June 15, 2005. The Company is also required to use either the “modified prospective method” or the “modified retrospective method.” Under the modified prospective method, the Company must recognize compensation cost for all awards granted after the Company adopts the standard and for the unvested portion of previously granted awards that are outstanding on that date.

Under the modified retrospective method, the Company must restate previously issued financial statements to recognize the amounts the Company previously calculated and reported on a pro forma basis, as if the prior standard had been adopted. See Note 2 – Stock Based Compensation.

Under both methods, the Company is permitted to use either a straight line or an accelerated method to amortize the cost as an expense for awards with graded vesting. The standard permits and encourages early adoption.

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The Company has commenced the analysis of the impact of SFAS 123(R), but has not yet decided: whether the Company will use the modified prospective method or elect to use the modified retrospective method, and whether the Company will elect to use straight line amortization or an accelerated method. Additionally, the Company cannot predict with reasonable certainty the number of options that will be unvested and outstanding upon adoption.

Accordingly, the Company cannot currently quantify with precision the effect that this standard would have on its financial position or results of operations in the future, except that the Company probably will recognize a greater expense for any awards that the Company may grant in the future than the Company would using the current guidance. If the Company were to adopt SFAS No. 123(R) using the modified retrospective method, net income would have been $2.9 less than reported in the year ended December 31, 2005.

SFAS 151, Inventory Costs - In November 2005, the FASB issued SFAS No. 151, Inventory Costs an amendment of ARB No. 43, Chapter 4, which amends Chapter 4 of ARB No. 43 that deals with inventory pricing. The statement clarifies the accounting for abnormal amounts of idle facility expenses, freight, handling costs, and spoilage. Under previous guidance, paragraph 5 of ARB No. 43, chapter 4, items such as idle facility expense, excessive spoilage, double freight, and rehandling costs might be considered to be so abnormal, under certain circumstances, as to require treatment as current period charges. This statement eliminates the criterion of “so abnormal” and requires that those items be recognized as current period charges. This statement is effective for inventory costs incurred during fiscal years beginning after June 15, 2005, although earlier application is permitted for fiscal years beginning after the date of issuance of this statement. Retroactive application is not permitted. Management is analyzing the requirements of this new Statement and believes that its adoption will not have any significant impact on the Company’s financial position, results of operations or cash flows.

SFAS 153, Exchange of Non-Monetary Assets - In December 2005, the FASB issued SFAS No. 153, Exchanges of Nonmonetary Assets an amendment of APB No. 29 (“Opinion 29”). This Statement amends Opinion 29 to eliminate the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. The statement specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. This statement is effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. Earlier application is permitted for nonmonetary asset exchanges occurring in fiscal periods beginning after the date this statement is issued. Retroactive application is not permitted. Management is analyzing the requirements of this new statement and believes that its adoption will not have any significant impact on the Company’s financial position, results of operations or cash flows.

FASB Statement No. 154, Accounting Changes and Error Corrections - In May 2005, the FASB issued FASB Statement No. 154, Accounting Changes and Error Corrections (“Statement 154”). Statement 154 requires companies to recognize changes in accounting principle, including changes required by a new accounting pronouncement when the pronouncement does not include specific transition provisions, retrospectively to prior periods’ financial statements. Statement 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The Company does not believe that the adoption of Statement 154 will have a material effect on its financial position or results of operations.

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FASB Statement No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies – On April 4, 2005, the FASB issued FASB Staff Position No. FAS 19-1 (“FSP FAS 19-1”), which addressed a discussion that was ongoing within the oil industry regarding capitalization of costs of drilling exploratory wells. Paragraph 19 of FASB Statement No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies (“FASB No. 19”), requires costs of drilling exploratory wells to be capitalized pending determination of whether the well has found proved reserves. If the well has found proved reserves, the capitalized costs become part of the entity’s wells, equipment, and facilities. If, however, the well has not found proved reserves, the capitalized costs of drilling the well are expensed. Questions arose in practice about the application of this guidance due to changes in oil and gas exploration processes and lifecycles. The issue was whether there are circumstances that would permit the continued capitalization of exploratory well costs if reserves cannot be classified as proved within one year following the completion of drilling, other than when additional exploration wells are necessary to justify major capital expenditures and those wells are underway or firmly planned for the near future. FSP FAS 19-1 amends FASB No. 19 to allow for the continued capitalization of suspended well costs when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the plan. The issuance of this amendment did not result in an adjustment to the Company suspended well costs.

The Company had $6.5 million of suspended well costs associated with exploration wells at Avouma and Ebouri at December 31, 2005 being carried as work in progress. In February 2005, the Company received approval to declare the Avouma/South Tchibala reserves commercial from the Gabon government and in April 2005 the Gabon government approved a joint development plan for the Avouma/South Tchibala discoveries, and assigned a twenty year development area. Construction of the platform facilities to develop Avouma/South Tchibala is ongoing.

For Ebouri, the Company acquired new seismic over the discovery in January 2005 and completed processing of the seismic in December 2005. Based on the results of the seismic, the Company believes the discovery is commercial and intends to seek government approval of commerciality of the discovery, file for a development area and submit a development plan in 2006.

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The table below provides additional information with respect to the Company’s capitalized exploration drilling costs.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk

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

Interest Rate Market Risk

At December 31, 2005, total debt was $1.5 million. The debt is tied to floating or market interest rates. Fluctuations in floating interest rates will cause the Company’s annual interest costs to fluctuate. During the fourth quarter of 2005, the interest rate on the Company’s bank debt averaged 8.22%. If the balance of the bank debt at December 31, 2005 were to remain constant, a 10% change in market interest rates would impact our cash flow by an estimated $3,100 per quarter.

Commodity Risk

The Company has utilized derivative commodity instruments to hedge future sales prices on a portion of its oil production to achieve a more predictable cash flow, as well as to reduce exposure to adverse price fluctuations of oil. The derivatives were not held for trading purposes. While the use of hedging arrangements limits the downside risk of adverse price movements, it also limits increases in future revenues as a result of favorable price movements. The use of hedging transactions also involves the risk that the counterparties are unable to meet the financial terms of such transactions. Hedging instruments that the Company has used are collars, which the Company generally places with major investment grade financial institutions believed to have minimal credit risks. The Company had no derivatives in place as of the date of this report.

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Item 8. Financial Statements and Supplementary Data

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

Item 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures.

Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we conducted an evaluation of our disclosure controls and procedures, as this term is defined under Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Based on this evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures were effective as of the end of the period covered by this Annual Report.

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 1, 2006, management concluded that its internal control over financial reporting was effective as of December 31, 2005.

Management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005 has been audited by Deloitte and Touche LLP, an independent registered public accounting firm who audited the Company’s consolidated financial statements as of and for the year ended December 31, 2005, as stated in their report which appears below.

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, 2005 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.

Houston, Texas

We have audited management’s assessment, included in the accompanying Management’s report on Internal Control over Financial Reporting, that VAALCO Energy, Inc. and subsidiaries (the “Company”) maintained effective internal control over financial reporting as of December 31, 2005, 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. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Partnership’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, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

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.

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In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, 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, 2005 of the Company and our report dated March 8, 2006, expressed an unqualified opinion on those financial statements.

/s/ Deloitte & Touche LLP

Houston, Texas

March 8, 2006

Item 9B. Other Information

The Company has disclosed all information required to be disclosed in a current report on Form 8-K during the 4^th quarter of the year ended December 31, 2005 in previously filed reports on Form 8-K.

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PART III

Item 10. Directors and Executive Officers of the Registrant

Information required by this item will be included in the Company’s proxy statement for its 2006 annual meeting, which will be filed with the Commission within 120 days of December 31, 2005, and which is incorporated herein by reference.

Item 11. Executive Compensation

Information required by this item will be included in the Company’s proxy statement for its 2006 annual meeting, which will be filed with the Commission within 120 days of December 31, 2005, and which is incorporated herein by reference.

Item 12. Security Ownership of Certain Beneficial Owners and Management

Information required by this Item 403 of Regulation S-K concerning the security ownership of certain beneficial owners and management will be included in the Company’s proxy statement for its 2006 annual meeting, which will be filed with the Commission within 120 days of December 31, 2005, and which is incorporated herein by reference.

The following table provides information as of December 31, 2005 regarding the number of shares of common stock that may be issued under the Company’s compensation plans.

Item 13. Certain Relationships and Related Transactions

Information required by this item will be included in the Company’s proxy statement for its 2006 annual meeting, which will be filed with the Commission within 120 days of December 31, 2005, and which is incorporated herein by reference.

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Item 14. Principal Accountant Fees and Services

The information required by Item 14 is incorporated by reference from the Company’s definitive proxy statement for its 2006 annual meeting, which will be filed with the Commission within 120 days of December 31, 2005, and which is incorporated herein by reference.

PART IV

Item 15. Exhibits and Financial Statement Schedules

(a) 1. The following is an index to the financial statements and financial statement schedules that are filed as part of this Form 10-K.

(a) 2. Schedules other than those listed above are omitted because they are not required, not applicable or the required information is included in the financial statements or notes thereto.

(a) 3. Exhibits:

2. Plan of acquisition, reorganization , arrangement, liquidation or succession

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3. Articles of Incorporation and Bylaws

10. Material Contracts

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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

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Terms used to classify the Company’s reserve quantities

The SEC definition of proved oil and gas reserves, per Article 4-10(a) (2) of Regulation S-X, is as follows:

Proved oil and gas reserves. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

(a) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

(b) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

(c) Estimates of proved reserves do not include the following: (1) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”; (2) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (3) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (4) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

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

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2004 or 2003 equal the estimated net proved reserves attributable to a property or group of properties divided by production from the property or group of properties for the four fiscal quarters preceding the date as of which the proved reserves were estimated.

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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SIGNATURES

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

VAALCO ENERGY, INC.

(Registrant)

Dated March 8, 2006

In accordance with the Exchange Act, this report has been signed below on the 8th day of March, by the following persons on behalf of the registrant and in the capacities indicated.

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VAALCO ENERGY, INC. AND SUBSIDIARIES

INDEX TO CONSOLIDATED FINANCIAL INFORMATION

VAALCO ENERGY, INC. AND SUBSIDIARIES