UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

x ANNUAL REPORT UNDER TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2006

OR

¨ TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                     

Commission file number: 0-20928

VAALCO Energy, Inc.

(Exact name of registrant as specified on its charter)

Delaware	76-0274813
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
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:

Title of each class	Name of exchange on which registered
Common Stock, $.10 par value	New York Stock Exchange

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.

Check one: Large accelerated file    ¨                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 June 30, 2006 was $551,126,540.

As of February 28, 2007, there were outstanding 59,052,813 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.

VAALCO ENERGY, INC.

TABLE OF CONTENTS

PART I
Item 1.	Business	3
Item 1A.	Risk Factors	9
Item 1B.	Unresolved Staff Comments	14
Item 2.	Properties	14
Item 3.	Legal Proceedings	18
Item 4.	Submission of Matters to a Vote of Security Holders	18
PART II
Item 5.	Market for Common Equity and Related Stockholder Matters	19
Item 6.	Selected Financial Data	21
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	30
Item 8.	Financial Statements and Supplementary Data	30
Item 9.	Changes In and Disagreements with Accountants on Accounting and Financial Disclosure	31
Item 9A.	Controls and Procedures	31
Item 9B.	Other Information	33
PART III
Item 10.	Directors and Executive Officers of the Registrant	33
Item 11.	Executive Compensation	33
Item 12.	Security Ownership of Certain Beneficial Owners and Management	33
Item 13.	Certain Relationships and Related Transactions	33
Item 14.	Principal Accountant Fees and Services	33
PART IV
Item 15.	Exhibits and Financial Statement Schedules	34
	Glossary of Oil and Gas Terms	37
Index to Consolidated Financial Information		F-1

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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 and also conducts exploration activities in Angola, Africa. The Company has also organized a British subsidiary and is actively screening prospects for potential entry into the British North Sea. 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 international subsidiaries are VAALCO Gabon (Etame), Inc., VAALCO Production (Gabon), Inc., VAALCO Angola (Kwanza), Inc. and VAALCO UK (North Sea), Ltd. VAALCO Energy (USA), Inc. holds interests in certain properties located in the United States.

RECENT DEVELOPMENTS

The Company’s primary source of revenue is from the Etame Production Sharing Contract located offshore the Republic of Gabon. The Company produces from the Etame, Avouma and South Tchibala fields on the license. Oil production commenced from the Avouma and South Tchibala fields in January 2007. During 2006, the Etame field produced approximately 6.4 million bbls (1.5 million bbls net to the Company). In addition to the Etame, Avouma and South Tchibala fields, the Company is developing one additional field, the Ebouri field, which was discovered in 2004.

During 2006, the Company received approval from the Gabon government for the development plan for the Ebouri discovery. A platform is currently being constructed for installation during the fall of 2007, with first production from the Ebouri field expected to occur in early 2008.

Onshore Gabon, the Company has a 100% working interest in the Mutamba block located near the coast in central Gabon. The block contains approximately 270,000 acres for exploration. The Company acquired seismic data from previous operators over the block in 2006 and will be reprocessing and interpreting the data to map prospects during 2007.

In November 2006, the Company signed a production sharing contract for a 40% working interest in Block 5 offshore Angola. The seven year contract awards the Company exploration rights to approximately 1.4 million acres along the central coast of Angola. The Company has recently acquired 1,000 square kilometers of seismic data over a portion of the block and will process and interpret the seismic data during 2007.

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

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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 production strategy is to maximize the value of the reserves discovered in Gabon through exploitation of the Etame field, Avouma and South Tchibala fields, and to develop the Ebouri field during 2007. The Company owns a 100% working interest in the 270,000 acre Mutamba block onshore Gabon and a 40% working interest in the 1.4 million acre Block 5 offshore Angola. During 2007, the Company will be mapping prospects on these blocks using available seismic data in order to develop exploration drilling prospects for 2008. The Company participated 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 was recently notified that it was unsuccessful in obtaining any blocks in the bid round, but will continue to evaluate farmin opportunities. The Company is also actively seeking additional opportunities in West Africa and elsewhere.

International

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

Domestic

The Company’s domestic strategy is to produce existing reserves. There are no plans to drill new domestic wells at this time. During 2006, the Company sold several small interests onshore wells and current domestic properties are located in Brazos County, Texas and offshore in the Ship Shoal area.

CUSTOMERS

Substantially all of the Company’s oil and gas is sold at the well head at posted or indexed prices under short-term contracts, as is customary in the industry. In Gabon, the Company sells oil under a contract with ADDAX Oil and Gas Ltd. which runs through the calendar year 2007. While the loss of ADDAX as a buyer might have a material effect on the Company in the short term, management believes that the Company would be able to obtain other customers for its crude oil. Domestic production is sold via two contracts, one for oil and one for gas. The Company has access to several alternative buyers for oil and gas sales domestically.

EMPLOYEES

As of December 31, 2006, the Company had 16 full-time employees, ten 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

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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.

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 Gabon and will be subject to the laws and regulations of Angola when exploration begins. 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 they are developing countries, it is unclear how quickly and to what extent Gabon or Angola will increase its regulation of environmental issues in the future; any significant increase in the regulation or enforcement of environmental issues by Gabon or Angola could have a material effect on the Company. Developing countries, in certain instances, have patterned environmental laws after those in the United States which are discussed below. However, the extent to which any environmental laws are enforced in developing countries varies significantly.

Environmental Regulations in the United States

Solid and Hazardous Waste

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

The Company generates wastes, including hazardous wastes that are subject to the federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes. The Environmental Protection Agency

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(“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.

Superfund

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

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

Clean Water Act

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

Oil Pollution Act

The Oil Pollution Act of 1990 (“OPA”), which amends and augments oil spill provisions of 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

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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 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 signed in June 2005 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

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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.

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 volatility of oil and natural gas prices;

• the uncertainty of estimates of oil and natural gas reserves;

• the impact of competition;

• the availability and cost of seismic, drilling and other equipment;

• operating hazards inherent in the exploration for and production of oil and natural gas;

• difficulties encountered during the exploration for and production of oil and natural gas;

• difficulties encountered in delivering oil to commercial markets;

• general economic conditions;

• changes in customer demand and producers’ supply;

• the uncertainty of the Company’s ability to attract capital;

• compliance with, or the effect of changes in, the foreign governmental regulations regarding the Company’s exploration and production;

• actions of operators of the Company’s oil and gas properties; and

• weather conditions.

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.

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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.

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 occurs, our business, financial condition and results of operations could be materially adversely affected. Additional risks not presently known to us or which we consider immaterial based on information currently available to us may also materially adversely affect us. In this section, the terms “VAALCO”, “we”, “us” and “our” refer to VAALCO 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, 2006. In addition, at December 31, 2006, 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.

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

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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, receipt of additional seismic data or the reprocessing of existing data, material changes in oil or gas prices, failure of wells drilled in similar formations or delays in the delivery of equipment and availability of drilling rigs. Our current domestic oil and gas properties are operated by third parties and, as a result, we have limited control over the nature and timing of exploration and development of such properties or the manner in which operations are conducted on such properties.

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

We make, and will continue to make, substantial capital expenditures for the acquisition, exploitation, development, exploration and production of oil and gas reserves. Historically, we have financed these expenditures primarily with cash flow from operations, debt, asset sales, and private sales of equity. During 2006, we have participated, and in 2007 we will continue to participate, in the further exploration and development of the Etame block offshore Gabon. We are the operator for the block 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.

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

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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 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 2006 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

11

of drilling contracts to local contractors or require foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. In addition, if a dispute arises with foreign operations, we may be subject to the exclusive jurisdiction of foreign courts or may not be successful in subjecting foreign persons, especially foreign oil ministries and national oil companies, to the jurisdiction of the United States.

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

Almost all of our proven reserves are located offshore of the Republic of Gabon. As of December 31, 2006, we carried a gross investment of approximately $80.2 million on our balance sheet associated with the Etame, Avouma and South Tchibala fields in Gabon. We have operated in Gabon since 1995 and believe we have good relations with the current Gabonese government. However, there can be no assurance that present or future administrations or governmental regulations in Gabon will not materially adversely affect our operations or cash flows.

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 access to the capital necessary to drill wells and acquire properties;

• our ability to acquire and analyze seismic, geological and other information relating to a property;

• our ability to retain the personnel necessary to properly evaluate seismic and other information relating to a property;

• the location of, and our ability to access, platforms, pipelines and other facilities used to produce and transport oil and gas production; and

• the standards we establish for the minimum projected return on an investment of our capital.

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 current business and the laws of Angola will regulate our business once we begin operating there. 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.

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,

12

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, and that we will be able to comply with applicable laws and regulations in Angola, 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.

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 ADDAX Oil and Gas Ltd. The loss of ADDAX 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

13

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.

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, Avouma and South Tchibala fields, which are on production, the Ebouri discovery and one former Gulf Oil Company discovery, the North Tchibala discovery. These fields and 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, 2006, VAALCO owned a 30.35% interest in the exploration acreage within the Etame Block, and in the Ebouri and North Tchibala discoveries. The Company owns a 28.1% interest in the development areas surrounding the Etame, Avouma and South Tchibala field developments. The development areas were subject to a 7.5% back-in by the Government of Gabon, which occurred for the Etame, Avouma and South Tchibala fields after their successful development.

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 at a cost of approximately $117.3 million ($35.6 million net to the Company). The development consisted of completing subsea wells connected to a Floating Production, Storage and Offloading vessel (“FPSO”). There are currently four wells producing at the Etame field. The Company has sold a total of 25.7 million gross bbls (5.9 million net bbls) since field startup through December 31, 2006. During 2006, the Etame field produced approximately 6.4 million gross bbls (1.4 million net bbls).

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). In 2006, the Company installed a platform in approximately 250 feet of water and drilled two development wells from the platform, one into each field. The two development wells are tied back to the Etame FPSO via a 10 mile pipeline. The cost of developing the Avouma and South Tchibala fields was $108 million, ($30.3 million net to the Company).

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The Company drilled the Ebouri discovery well to total depth in January 2004. In October 2006, the Gabon government approved the development plan for Ebouri. A platform will be installed approximately seven miles from the FPSO and a single development well will be drilled to produce the field. The platform will be tied back to the FPSO via a pipeline as was done for Avouma and South Tchibala.

Mutamba Iroru

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

Angola

Block 5

Effective December 1, 2006 the Company acquired a 40% working interest in Block 5 offshore Angola. The seven year contract awarded the Company exploration rights to approximately 1.4 million acres offshore Angola. The Company has recently purchased 1,000 square kilometers of seismic date over a portion of the block, which it will use to map the area to determine potential drilling prospects during 2007.

Domestic United States Properties

The Company has interests in four producing wells in Brazos County Texas producing from the Buda/Georgetown formations. The Company also owns certain non-operated interests in Ship Shoal areas of the Gulf of Mexico. During 2006 the wells produced approximately 1,400 bbls of oil and 11 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 2006, 2005 and 2004 are shown below. The production figures exclude discontinued operations:

Company Owned Production

	Year Ended December 31,
	2006			2005			2004
	BOE	Bbl	Mcf	BOE	Bbl	Mcf	BOE	Bbl	Mcf
Average Daily Production (Oil in BOPD, gas in MCFD)	4,258	4,253	30	4,488	4,480	47	4,036	4,026	59
Average Sales Price ($/unit)	63.26	63.29	5.91	52.02	52.04	6.88	38.36	38.37	5.63
Average Production Cost ($/unit)	7.90	7.90	1.32	6.46	6.46	1.08	6.74	6.74	1.12

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RESERVE INFORMATION

A reserve report as of December 31, 2006 has been prepared by Netherland Sewell & Associates, independent petroleum engineers. There have been no estimates of total proved net oil or gas reserves filed with or included in reports to any federal authority or agency other than the Commission since the beginning of the last fiscal year. The reserves are located in Gabon and in Texas (onshore and offshore).

	As of December 31,
	2006		2005		2004
Crude Oil
Proved Developed Reserves (MBbls)		4,686		5,326		4,738
Proved Undeveloped Reserves (MBbls)		1,305		2,501		3,996
Total Proved Reserves (MBbls)		5,991		7,827		8,734
Natural Gas
Proved Developed Reserves (MMcf)		17		21		54
Proved Undeveloped Reserves (MMcf)		—		—		—
Total Proved Reserves (MMcf)		17		21		54
Standard measure of proved reserves	$	133,602	$	161,209	$	123,321

The following tables set forth the net proved reserves of the Company as of December 31, 2006, 2005 and 2004, and the changes during such periods.

	Oil (MBbls)		Gas (MMcf)
PROVED RESERVES:
BALANCE AT JANUARY 1, 2004	9,011		140
Production	(1,469	)	(22	)
Revisions	96		(64	)
Additions	1,447		—
Sale of reserves in place	(351	)	—
BALANCE AT DECEMBER 31, 2004	8,734		54
Production	(1,635	)	(17	)
Revisions	728		(16	)
BALANCE AT DECEMBER 31, 2005	7,827		21
Production	(1,552	)	(11	)
Revisions	(1,590	)	7
Additions	1,306		—
BALANCE AT DECEMBER 31, 2006	5,991		17
	Oil (MBbls)		Gas (MMcf)
PROVED DEVELOPED RESERVES
Balance at December 31, 2003	6,492		140
Balance at December 31, 2004	4,738		54
Balance at December 31, 2005	5,326		21
Balance at December 31, 2006	4,686		17

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. The Company received approval for the development of the Ebouri discovery in October 2006. Accordingly the Company booked proved undeveloped reserves for Ebouri at year end 2006.

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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 $57.07/bbl representing a $1.81 discount to the spot price of Dated Brent Crude at December 31, 2006. In Texas, the price was $56.33 per barrel of oil and $4.99 per Mcf of gas. See Supplemental Information on Oil and Gas Producing Properties for certain additional information concerning the proved reserves of the Company.

Drilling History

The Company participated in two development wells in Gabon during 2006

	United States						International
	Gross			Net			Gross			Net
Wells Drilled	2006	2005	2004	2006	2005	2004	2006	2005	2004	2006	2005	2004
Exploration Wells
Productive	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0	2.0	0.00	0.00	0.61
Dry	0.0	0.0	0.0	0.0	0.0	0.0	0.0	1.0	0.0	0.00	0.30	0.00
Development Wells
Productive	0.0	0.0	0.0	0.0	0.0	0.0	2.0	1.0	1.0	0.56	0.28	0.28
Dry	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.00	0.00	0.00
Total Wells	0.0	0.0	0.0	0.0	0.0	0.0	2.0	2.0	3.0	0.56	0.58	0.89

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, 2006:

	United States		International
	Gross	Net (1)	Gross	Net (1)
	(In thousands except wells)
Developed acreage	6.7	0.8	25.0	7.0
Undeveloped acreage	0.0	0.0	2,439.8	1,057.7
Productive gas wells	1	0.1	0	0
Productive oil wells	9	1.4	6	1.7

(1) Net acreage and net productive wells are based upon the Company’s working interest in the properties.

17

Office Space

The Company leases its offices in Houston, Texas (approximately 8,000 square feet) and in Port Gentile, Gabon (approximately 10,000 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 October 2006, the Company’s common stock has traded on the New York Exchange under the symbol EGY. Prior to such time the Company’s common stock traded on the American Stock Exchange under the symbol EGY. The following table sets forth the range of high and low sales prices of the common stock for the periods indicated.

Period	High		Low
2005:
First Quarter	$	5.09	$	3.60
Second Quarter		4.06		3.10
Third Quarter		4.88		3.49
Fourth Quarter		4.24		3.07
2006:
First Quarter	$	7.30	$	4.40
Second Quarter		10.00		6.03
Third Quarter		10.10		6.98
Fourth Quarter		8.81		6.99
2007:
First Quarter (through March 1, 2007)	$	6.93	$	6.25

On March 1, 2007 the last reported sale price of the common stock on the New York Stock Exchange was $6.36 per share.

As of March 1, 2007 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.

19

Performance Graph

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

	2001		2002		2003		2004		2005		2006
VAALCO Energy, Inc	$	100	$	267	$	255	$	705	$	771	$	1227
S&P500 Composite	$	100	$	77	$	97	$	106	$	109	$	124
S&P/ TSX Capped Energy	$	100	$	111	$	138	$	178	$	285	$	290

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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, 2006 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)

	Years Ended December 31,
	2006(3)			2005			2004			2003			2002
Revenues:
Oil and gas sales	$	98,325		$	84,935		$	56,502		$	35,481		$	9,359
Gain on sale of assets		—			—			—			—			12
Total revenues		98,325			84,935			56,502			35,481			9,371
Operating costs and expenses:
Production expenses		12,217			10,584			9,958			8,969			2,414
Exploration expense		2,672			2,709			267			2,096			240
Depreciation, depletion and amortization		6,720			5,369			4,749			5,785			2,124
General and administrative expenses		2,386			2,696			1,260			2,007			1,496
Total operating costs and expenses		23,995			21,358			16,234			18,857			6,274
Operating income		74,330			63,577			40,268			16,624			3,097
Other income (expense):
Interest income		2,987			1,099			265			80			137
Interest expense		(1,026	)		(418	)		(485	)		(2,630	)		(828	)
Other, net		(35	)		131			22			—			(15	)
Total other income (expense)		1,925			812			(198	)		(2,550	)		(706	)
Income from continuing operations before taxes, minority interest and cumulative effect of accounting change		76,255			64,389			40,070			14,074			2,391
Income tax expense		30,496			31,491			11,972			5,514			1,385
Income from continuing operations before minority interest and cumulative effect of accounting change		45,760			32,898			28,098			8,560			1,006
Minority interest in earnings of subsidiaries		(5,174	)		(3,647	)		(3,069	)		(1,306	)		(341	)
Income from continuing operations		40,585			29,251			25,029			7,254			665
Discontinued operations:
Loss from discontinued operations before income taxes (including loss on disposal of $125 in 2004)		(74	)		(69	)		(327	)		(244	)		(209	)
Income taxes		(168	)		—			(1,764	)		209			(11	)
Loss on discontinued operations (1)		(242	)		(69	)		(2,091	)		(35	)		(220	)
Cumulative effect of accounting change (2)		—			—			—			1,717			—
Net income	$	40,343		$	29,182		$	22,938		$	8,936		$	445

21

	Years Ended December 31,
	2006		2005		2004			2003		2002
Basic income per common share from continuing operations before cumulative effect of accounting change	$	0.69	$	0.56	$	0.94		$	0.34	$	0.03
Loss from discontinued operations		—		—		(0.08	)		—		(0.01	)
Cumulative effect of accounting change		—		—		—			0.08		—
Basic income per common share	$	0.69	$	0.56	$	0.86		$	0.42	$	0.02
Diluted income per common share from continuing operations before cumulative effect of accounting change	$	0.67	$	0.50	$	0.43		$	0.13	$	0.01
Loss from discontinued operations		—		—		(0.04	)		—		—
Cumulative effect of accounting change		—		—		—			0.03		—
Diluted income per common share	$	0.67	$	0.50	$	0.39		$	0.16	$	0.01
Basic weighted average common shares outstanding		58,136		51,772		26,604			21,237		20,778
Diluted weighted average common shares outstanding		60,476		58,253		58,157			55,355		53,992
	As of December 31,
	2006		2005		2004			2003		2002
Balance Sheet Data
Cash and cash equivalents	$	60,979	$	43,880	$	27,574		$	22,995	$	7,724
Working capital		57,495		48,999		26,010			8,552		11,279
Net property and equipment		70,507		37,198		26,349			16,609		21,296
Total assets		167,942		98,162		68,371			46,367		48,563
Total debt		5,000		1,500		3,750			7,000		18,376
Total liabilities		37,715		14,061		16,427			20,416		32,684
Stockholders’ equity		122,264		78,315		47,808			24,554		15,198

(1) In February 2004, the Company sold all of its assets in the Philippines and incurred a net loss on discontinued operations in that year of $2.1 million. Prior years have been restated to reflect the discontinued operations.

(2) Effective January 1, 2003, the Company adopted SFAS 143 and recorded a cumulative effect of the change in accounting principle as an increase in earnings of $1.7 million.

(3) Effective January 1, 2006 the Company adopted SFAS 123(R) resulting in expense of $1.1 million in 2006.

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.

22

In 2006, the Company developed the Avouma and South Tchibala discoveries during 2006 by setting a platform and tying the field back to the FPSO via a pipeline. Production from Avouma and South Tchibala commenced in January 2007.

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 2004 and 2006, 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 ADDAX Oil and Gas Ltd. at spot market prices based on the price of Dated Brent.

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.

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

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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.

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 Company had $2.6 million of suspended well costs associated with the exploration well in the Ebouri field in Gabon which was being carried as work in progress at December 31, 2006. In July 2006, the Company received approval to declare the Ebouri field’s reserves commercial from the Gabon government and in October 2006 the Gabon government approved a development plan for the Ebouri field, and assigned a twenty year development area surrounding the field. Construction of the platform facilities to develop the Ebouri field is ongoing. The Company will no longer treat these costs as suspended once first production occurs, which is dependent upon construction and delivery of the platform facilities. First production is estimated to occur in 2008.

CAPITAL RESOURCES AND LIQUIDITY

Cash Flows

Net cash provided by operating activities for 2006 was $64.4 million, as compared to $35.9 million in 2005 and $22.8 million in 2004. Net cash provided by operations in 2006 consisted of net income of $40.3 million, non cash depreciation, depletion and amortization of $6.7 million, add back of exploration expense of $2.7 million,

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debt issuance costs amortized of $0.6 million and non cash stock based compensation of $1.1 million. Working capital other than cash increased $7.8 million, primarily associated with Gabon operations. A non cash add back of $5.2 million was associated with minority interest in VAALCO Gabon (Etame), Inc.

Net cash provided by operations in 2005 consisted of net income of $29.2 million, non-cash depreciation, depletion and amortization of $5.4 million and an add back of exploration expense of $2.7 million associated with the Avouma South exploration well. Working capital, other than cash, decreased $5.2 million in 2005 as compared to 2004, 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. Exploration expense added $0.3 million and non-cash loss on the sale of the Philippines assets added back $0.2 million. Also, non-cash add back of $3.1 million was associated with minority interests in VAALCO Gabon (Etame), Inc.

Net cash used in investing activities for 2006 was $50.0 million compared to $16.7 million net cash used in investing activities in 2005 and $14.7 million net cash used in investing activities in 2004. In 2006, the Company invested $22.4 million in Etame block operations primarily for development of the Avouma and South Tchibala fields and $10.8 million in bonus and leasehold payments for Block 5 offshore Angola. The Company also placed $14.8 million of funds in escrow to secure obligations in Angola, which was partially offset by the release of $1.1 million of funds in escrow associated with Gabon operations at year end 2005. The Company also incurred $2.7 million in exploration expenses associated seismic acquisition and reprocessing in the Etame block ($1.1 million), preparations for possible entry into the North Sea ($1.1 million), seismic processing for the Mutamba block onshore Gabon ($0.3 million), and in Angola ($0.1 million).

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 2006, cash provided by financing activities of $2.7 million consisted of $3.5 million net borrowings, $2.5 million proceeds from issuance of common stock and $3.0 used for distributions to minority interest holders. In addition the Company capitalized $0.3 million of debt issuance costs. 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 $1.3 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.

Capital Expenditures

During 2006, the Company spent approximately $22.4 million for the development of the Avouma and South Tchibala fields, and $10.8 million for the acquisition of Block 5 offshore Angola. 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. The Company may also participate in other exploration activities from time to time, although no other projects have been firmly designated at the time of this filing.

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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, 2006, the Company had cash balances of $61.0 million and funds in escrow for Angolan operations of $14.8 million. The Company believes that these cash balances combined with cash flow from operations will be sufficient to fund the Company’s 2007 capital expenditure budget of approximately $34.5 million to develop the Ebouri field, for Gabon and Angola seismic acquisition and processing and additional investments in working capital resulting from potential growth. As operator of Etame, Avouma and South Tchibala fields 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.

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 is available to finance the Ebouri field development activities and other Etame block 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 an existing term credit facility, which was repaid on February 15, 2006 in connection with a borrowing from this revolving facility. The Company incurred 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.

Contractual Obligations

The table below summarizes the Company’s obligations and commitments at December 31, 2006:

Payment Period

(in thousands)	2007		2008	2009	Thereafter
Long term debt(1)	—		5,000	—	—
Interest on long term debt	430	(2)	323	—	—
Operating leases(3)	19,385		16,510	16,355	12,561

1. The facility extends through June 2008 at which point it can be extended or converted to a term loan.

2. Interest is based on rates and principal payments in effect at 12/31/2006

3. The Company is Guarantor of a lease for an FPSO utilized in Gabon, which represents $61.2 million of the total obligations. The Company can cancel the lease anytime after September 7, 2010, with 12 month prior notice. Approximately 72% of the payment is co-guaranteed by the Company’s partners in Gabon.

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 its share of an exploration well on the Mutamba Iroru block by November 11, 2008.

RESULTS OF OPERATIONS

Year Ended December 31, 2006 Compared to Years Ended December 31, 2005 and 2004

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

Revenues

Total oil and gas sales for 2006 were $98.3 million as compared to $84.9 and $56.5 million for 2005 and 2004. In 2006, the Company sold approximately 1,554,000 net bbls at an average price of $63.26 per bbl from the Etame field in Gabon. Revenues from Texas amounted to $0.2 million. 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 bbl from the Etame field

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in Gabon. Revenues from Texas in 2004 were approximately $0.25 million. The decrease in oil volumes sold from the Etame field in 2006 compared to 2005 reflect declining oil rates from the field as well as lifting timing differences. The increased oil volumes from the Etame field in 2005 versus 2004 were due to the addition of the Etame 6H Phase 2 development well completed in July 2005.

Operating Costs and Expenses

Production expenses for 2006 were $12.2 million as compared to $10.6 and $10.0 million for 2005 and 2004. In 2006, operating expenses increased due to higher support vessel charges associated with crude oil lifting, and due to a change out of the communications system in Gabon to accommodate the new facilities for the Avouma and South Tchibala fields. 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 increased 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 2006 were $2.7 million as compared to $2.7 and $0.3 million for 2005 and 2004. In 2006, the Company incurred exploration expenses associated seismic acquisition and reprocessing in the Etame block ($1.1 million), preparations for possible entry into the North Sea ($1.1 million), seismic processing for the Mutamba block onshore Gabon ($0.3 million), and in Angola ($0.1 million). 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.

Depreciation, depletion and amortization expense was $6.7 million for 2006, and was $5.4 million and $4.7 million for 2005 and 2004 respectively. Depletion, depletion and amortization expense increased in 2006 versus 2005 due to the full year effect of the addition of the costs of adding the Etame 6H well which came on line in July 2005. Depletion, depletion and amortization expense increased in 2005 versus 2004 primarily due to higher production rates.

General and administrative expenses for 2006 were $2.4 million as compared to $2.7 and $1.3 million for 2005 and 2004. General and administrative expenses decreased in 2006 versus 2005 due to higher general and administrative reimbursement received associated with the development of the Avouma and South Tchibala fields. General and administrative 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 new office in Aberdeen to evaluate entrance into the North Sea.

Operating Income

Operating income for 2006 was $74.3 million as compared to a $63.6 and $40.3 million operating income for 2005 and 2004. The Company benefited from higher oil prices in 2006 compared to 2005, which more than offset lower production rates. Higher oil sales volumes and prices in Gabon were the primary reason for the increases in 2005 as compared to 2004.

Other Income (Expense)

Interest income for 2006 was $3.0 million compared to $1.1 and $0.3 million in 2005 and 2004. Both the 2005 and 2006 amounts represent interest earned and accrued on cash balances and funds in escrow. Interest rates also increased in during in 2006 over 2005 and in 2005 over 2004.

Interest expense of $1.0 million was recorded in 2006 as compared to $0.4 and $0.5 million in 2005 and 2004. Interest in all three years was associated with the financings from the IFC for use on Etame block activities. In 2006, the Company also incurred $0.6 million of amortization of capitalized financing costs, compared to $0.2 million in each of 2005 and 2004.

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Income Taxes

In 2006, the Company incurred $30.5 million of income taxes associated with the Etame field production, which were paid in Gabon. 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. The decrease in 2006 compared to 2005 was due to depreciation of Avouma and South Tchibala development costs which reduced profit oil tax payments. The increase in 2005 compared to 2004 was due to completing depreciation of all previous costs expended on the Etame block, which resulted in a higher tax rate per barrel.

Minority Interest

A provision for minority interest in the Gabon subsidiary of $5.2 million, $3.6 million and $3.1 million was made for in 2006, 2005 and 2004 respectively.

Loss from Discontinued Operations

Loss from discontinued operation in the Philippines was $0.2 million consisting of final branch profit remittance taxes paid in the Philippines. 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.

Net Income

Net income for 2006 was $40.3 million as compared to a net income of $29.2 and $22.9 million in 2005 and 2004. Higher oil prices in 2006 compared to 2005 more than offset a decline in production year over year. 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.

NEW ACCOUNTING PRONOUNCEMENTS

SFAS No. 123(R), Share Based Payment—In December 2004, FASB issued SFAS No. 123 (Revised 2004), Share-Based Payment, (“SFAS 123(R)”), which establishes accounting standards for all transactions in which an entity exchanges its equity instruments for goods and services. SFAS 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 123(R) eliminates the intrinsic value measurement objective in Accounting Principles Board (“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 adopted SFAS 123(R) on January 1, 2006. The Company has elected to use the “modified prospective 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. See Note 5—Stock Based Compensation.

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SFAS No. 151, Inventory Costs—In November 2005, the FASB issued SFAS No. 151, Inventory Costs an amendment of Accounting Research Board (“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 was effective January 1, 2006 and there was no impact from the adoption of this standard on the Company’s financial position, results of operations or cash flows.

SFAS No. 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 was effective January 1, 2006 and there was no impact from the adoption of this standard 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 (SFAS 154). SFAS 154 requires companies to recognize changes in accounting principles, including changes required by a new accounting pronouncement when the pronouncement does not include specific transition provisions, retrospectively to prior periods’ financial statements. This statement was effective January 1, 2006 and there was no impact from the adoption of Statement 154 on the Company’s financial position or results of operations.

FASB Statement No. 155, Accounting for Certain Hybrid Financial Instruments—In February 2006, the FASB issued SFAS No. 155, Accounting for Certain Hybrid Financial Instruments (“SFAS 155”), an amendment of FASB Statements No. 133 and No. 140. SFAS 155 amends SFAS 133, which required that a derivative embedded in a host contract that does not meet the definition of a derivative be accounted for separately under certain conditions. SFAS 155 amends SFAS 133 to narrow the scope exception to strips that represent rights to receive only a portion of the contractual interest cash flows or of the contractual principal cash flows of a specific debt instrument. In addition, SFAS 155 amends SFAS 140, which permitted a qualifying special-purpose entity to hold only a passive derivative financial instrument pertaining to beneficial interests issued or sold to parties other than the transferor. SFAS 155 amends SFAS 140 to allow a qualifying special purpose entity to hold a derivative instrument pertaining to beneficial interests that itself is a derivative financial instrument. SFAS 155 is effective for all financial instruments acquired or issued (or subject to a remeasurement event) following the start of an entity’s first fiscal year beginning after September 15, 2006. The Company will adopt SFAS 155 on January 1, 2007 and does not expect this standard to have a material impact, if any, on its combined financial statements.

FASB Statement No. 157, Fair Value Measurements—In September 2006, the FASB issued FASB Statement 157 Fair Value Measurements, (“SAFS 157”), which provides a single definition of fair value, together with a framework for measuring it, and requires additional disclosure about the use of fair value to measure assets and liabilities. SFAS 157 emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and sets out a fair value hierarchy with the highest priority being quoted prices in active markets. Under the Statement, fair value measurements are disclosed by level within that hierarchy. While the Statement does not add any new fair value measurements, it does change current practice. Changes to practice include:

• A requirement for an entity to include its own credit standing in the measurement of its liabilities.

• A modification of the transaction price presumption. A prohibition on the use of block discounts when valuing large blocks of securities for broker dealers and investment companies.

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• A requirement to adjust the value of restricted stock for the effect of the restriction even if the restriction lapses within one year.

The Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. Earlier application is encouraged, provided that no financial statements have yet been issued within that fiscal year by the reporting entity. The Statement shall be applied prospectively as of the beginning of the fiscal year in which the Statement is initially applied. The Company will adopt SFAS 157 on January 1, 2007 and does not expect this standard to have a material impact, if any, on its financial statements.

FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement No. 109—During July 2006, the FASB issued Financial Interpretation (FIN) No. 48, Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement No. 109 (“FIN 48”). FIN 48 addresses the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109, Accounting for Income Taxes. FIN 48 prescribes specific criteria for the financial statement recognition and measurement of the tax effects of a position taken or expected to be taken in a tax return. This interpretation also provides guidance on derecognition of previously recognized tax benefits, classification of tax liabilities on the balance sheet, recording interest and penalties on tax underpayments, accounting in interim periods, and disclosure requirements. FIN 48 is effective for fiscal periods beginning after December 15, 2006. The Company does not believe that the adoption of FIN 48 will have a material impact on its financial statements.

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, 2006, total debt was $5.0 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 2006, the interest rate on the Company’s bank debt averaged 8.9%. If the balance of the bank debt at December 31, 2006 were to remain constant, a 1% change in market interest rates would impact our cash flow by an estimated $12,500 per quarter.

Commodity Risk

In 2005, the Company 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.

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.

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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, 2007, management concluded that its internal control over financial reporting was effective as of December 31, 2006.

Management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006 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, 2006, as stated in their report which follows.

Changes in Internal Control Over Financial Reporting

No change in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) occurred during the fourth quarter of our fiscal year ended December 31, 2006 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 Annual 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, 2006, 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 Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, 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.

In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2006, 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, 2006, 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, 2006 of the Company and our report dated March 6, 2007, expressed an unqualified opinion on those financial statements, and included an explanatory paragraph relating to the adoption of a new accounting principle for share-based payments.

/s/ Deloitte & Touche LLP

Houston, Texas

March 6, 2007

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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, 2006 in previously filed reports on Form 8-K.

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 2007 annual meeting, which will be filed with the Commission within 120 days of December 31, 2006, 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 2007 annual meeting, which will be filed with the Commission within 120 days of December 31, 2006, 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 2007 annual meeting, which will be filed with the Commission within 120 days of December 31, 2006, and which is incorporated herein by reference.

The following table provides information as of December 31, 2006 regarding the number of shares of common stock that may be issued under the Company’s compensation plans.

Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights	Weighted-average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in the first column)
Equity compensation plans approved by security holders	1,422,336	$	1.95	—
Equity compensation plans not approved by security holders	2,946,345	$	6.28	—
Total	4,368,671	$	4.87	—

Item 13. Certain Relationships and Related Transactions

Information required by this item will be included in the Company’s proxy statement for its 2007 annual meeting, which will be filed with the Commission within 120 days of December 31, 2006, and which is incorporated herein by reference.

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 2007 annual meeting, which will be filed with the Commission within 120 days of December 31, 2006, and which is incorporated herein by reference.

33

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.

VAALCO ENERGY, INC. AND SUBSIDIARIES
Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets December 31, 2006 and 2005	F-3
Statements of Consolidated Operations Years ended December 31, 2006, 2005 and 2004	F-4
Statements of Consolidated Stockholders’ Equity Years ended December 31, 2006, 2005 and 2004	F-5
Statements of Consolidated Cash Flows Years ended December 31, 2006, 2005 and 2004	F-6
Notes to the Consolidated Financial Statements	F-7

(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:

3. Articles of Incorporation and Bylaws

3.1(b)	Restated Certificate of Incorporation
3.2(b)	Certificate of Amendment to Restated Certificate of Incorporation
3.3(b)	Bylaws
3.4(b)	Amendment to Bylaws
3.5(c)	Designation of Convertible Preferred Stock, Series A

10. Material Contracts

10.1(d)	Indemnity Agreement entered into among the Company and certain of its officers and directors listed therein.
10.2(e)	Exploration and Production Sharing contract between the Republic of Gabon and VAALCO Gabon (Etame), Inc. dated July 7, 1995.
10.3(e)	Deed of Assignment and Assumption between VAALCO Gabon (Etame), Inc., VAALCO Energy (Gabon), Inc. and Petrofields Exploration & Development Co., Inc. dated September 28, 1995.
10.4(f)	Letter of Intent for Etame Block, Offshore Gabon dated January 22, 1998 between the Company and Western Atlas International, Inc.
10.5(g)	2001 Stock Incentive Plan dated August 16, 2001
10.6(h)	Trustee and Paying Agent Agreement by and between VAALCO Gabon (Etame), Inc., J.P. Morgan Trustee and Depositary Company Limited and JPMorgan Chase Bank, London Branch, dated June 26, 2002.

34

10.7(i)	Stock Purchase Agreement dated as of August 23, 2002, by and between the Company, VAALCO International, Inc. and Nissho Iwai Corporation.
10.8(i)	Stockholders’ Agreement dated August 23, 2002, by and among the Company, VAALCO International, Inc. and Nissho Iwai Corporation.
10.9(i)	Subscription Agreement between the Company and VAALCO International, Inc. dated August 23, 2002.
10.10(j)	2003 Stock Incentive Plan dated December 16, 2003
10.11(k)	Exploration and Production Sharing contract between the Republic of Gabon and VAALCO Production (Gabon), Inc., Permit Mutamba Iroru dated November 11, 2005.
10.12(l)	Loan Agreement between VAALCO Gabon (Etame), Inc. and International Finance Corporation dated June 13, 2005

21. Subsidiaries of the Company

21.1 Subsidiaries of the Registrant

23. Consents of Experts and Counsel

23.1	Consent of Deloitte and Touche LLP
23.2	Consent of Netherland Sewell

31. Rule 13a-14(a) Certifications

31.2	Certification pursuant to section 302 of the Sarbanes-Oxley Act of 2002
31.2	Certification pursuant to section 302 of the Sarbanes-Oxley Act of 2002

32. Section 1350 Certifications

32.1	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act Of 2002.
32.2	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act Of 2002.

(a) Filed as an exhibit to the Company’s report on Form 8-K filed with the Commission on March 4, 1998 (file no. 000-20928) and hereby incorporated by reference herein.

(b) Filed as an exhibit to the Company’s Registration Statement on Form S-3 filed with the Commission on July 15, 1998 and hereby incorporated by reference herein.

(c) Filed as an exhibit to the Company’s Report on Form 8-K filed with the Commission on May 6, 1998 and hereby incorporated by reference herein.

(d) Filed as an exhibit to the Company’s Form 10 (File No. 0-20928) filed on December 3, 1992, as amended by Amendment No. 1 on Form 8 on January 7, 1993, and by Amendment No. 2 on Form 8 on January 25, 1993, and hereby incorporated by reference herein.

(e) Filed as an exhibit to the Company’s Form 10-QSB for the quarterly period ended September 30, 1995, and hereby incorporated by reference herein.

35

(f) Filed as an exhibit to the Company’s Form 10-KSB for the annual period ended December 31, 1996, and hereby incorporated by reference herein.

(g) Filed as an exhibit to the Company’s Registration Statement Form S-8 filed with the Commission on August 18, 2001, and incorporated by reference herein

(h) Filed as an exhibit to the Company’s Form 10-QSB for the quarterly period ended June 30, 2002, and hereby incorporated by reference herein.

(i) Filed as an exhibit to the Company’s Form 10-QSB for the quarterly period ended September 30, 2002, and hereby incorporated by reference herein.

(j) Filed as an exhibit to Form10-KSB for the annual period ended December 31, 2004, and hereby incorporated by reference herein.

(k) Filed as an exhibit to Form 10K for the annual period ended December 31, 2005, and hereby incorporated by reference herein.

(l) Filed as an exhibit to the Company’s Form 8K filed with the Commission on February 21, 2006, and hereby incorporated by reference herein.

36

Glossary of Oil and Gas Terms

Terms used to describe quantities of oil and natural gas

• Bbl—One stock tank barrel, or 42 US gallons liquid volume, of crude oil or other liquid hydrocarbons.

• Bcf—One billion cubic feet of natural gas.

• Bcfe—One billion cubic feet of natural gas equivalent.

• BOE—One barrel of oil equivalent, converting gas to oil at the ratio of 6 Mcf of gas to 1 Bbl of oil.

• BOPD—One barrel of oil per day

• MBbl—One thousand Bbls.

• Mcf—One thousand cubic feet of natural gas.

• McfD—One thousand cubic feet of natural gas per day.

• Mcfe—One thousand cubic feet of natural gas equivalent.

• MMBbl—One million Bbls of oil or other liquid hydrocarbons.

• MMcf—One million cubic feet of natural gas.

• MBOE—One thousand BOE.

• MMBOE—One million BOE.

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

• Gross oil and gas wells or acres—The Company’s gross wells or gross acres represent the total number of wells or acres in which the Company owns a working interest.

• Net oil and gas wells or acres—Determined by multiplying “gross” oil and natural gas wells or acres by the working interest that the Company owns in such wells or acres represented by the underlying properties.

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

• Standard measure of proved reserves—The present value, discounted at 10%, of the pre-United States income tax future net cash flows attributable to estimated net proved reserves. The Company calculates this amount by assuming that it will sell the oil and gas production attributable to the proved reserves estimated in its independent engineer’s reserve report for the prices it received for the production on the date of the report, unless it had a contract to sell the production for a different price. The Company also assumes that the cost to produce the reserves will remain constant at the costs prevailing on the date of the report. The assumed costs are subtracted from the assumed revenues resulting in a stream of future net cash flows. Estimated future income taxes using rates in effect on the date of the report are deducted from the net cash flow stream. The after-tax cash flows are discounted at 10% to result in the standardized measure of the Company’s proved reserves.

Terms used to classify the Company’s reserve quantities

• Proved reserves—The estimated quantities of crude oil, natural gas and natural gas liquids which, upon analysis of geological and engineering data, appear with reasonable certainty to be recoverable in the future from known oil and natural gas reservoirs under existing economic and operating conditions.

37

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.

• Proved developed reserves—Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

• Proved undeveloped reserves—Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required.

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

• Reserve life—A measure of the productive life of an oil and gas property or a group of oil and gas properties, expressed in years. Reserve life for the years ended December 31, 2006, 2005 or 2004 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

• Royalty interest—A real property interest entitling the owner to receive a specified portion of the gross proceeds of the sale of oil and natural gas production or, if the conveyance creating the interest provides, a specific portion of oil and natural gas produced, without any deduction for the costs to explore for, develop or produce the oil and natural gas. A royalty interest owner has no right to consent to or approve the operation and development of the property, while the owners of the working interests have the exclusive right to exploit the mineral on the land.

• Working interest—A real property interest entitling the owner to receive a specified percentage of the proceeds of the sale of oil and natural gas production or a percentage of the production, but requiring the owner of the working interest to bear the cost to explore for, develop and produce such oil and natural gas. A working interest owner who owns a portion of the working interest may participate either as operator or by voting his percentage interest to approve or disapprove the appointment of an operator and drilling and other major activities in connection with the development and operation of a property.

38

Terms used to describe seismic operations

• Seismic data—Oil and gas companies use seismic data as their principal source of information to locate oil and gas deposits, both to aid in exploration for new deposits and to manage or enhance production from known reservoirs. To gather seismic data, an energy source is used to send sound waves into the subsurface strata. These waves are reflected back to the surface by underground formations, where they are detected by geophones which digitize and record the reflected waves. Computers are then used to process the raw data to develop an image of underground formations.

• 2-D seismic data—2-D seismic survey data has been the standard acquisition technique used to image geologic formations over a broad area. 2-D seismic data is collected by a single line of energy sources which reflect seismic waves to a single line of geophones. When processed, 2-D seismic data produces an image of a single vertical plane of sub-surface data.

• 3-D seismic data—3-D seismic data is collected using a grid of energy sources, which are generally spread over several miles. A 3-D survey produces a three dimensional image of the subsurface geology by collecting seismic data along parallel lines and creating a cube of information that can be divided into various planes, thus improving visualization. Consequently, 3-D seismic data is a more reliable indicator of potential oil and natural gas reservoirs in the area evaluated.

39

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)

By	/S/    W. RUSSELL SCHEIRMAN
	W. Russell Scheirman, President, Chief Financial Officer and Director

Dated March 6, 2007

In accordance with the Exchange Act, this report has been signed below on the 6th day of March, by the following persons on behalf of the registrant and in the capacities indicated.

	Signature	Title
By:	/s/ ROBERT L. GERRY, III. Robert L. Gerry, III.	Chairman of the Board, Chief Executive Officer and Director (Principal Executive Officer)
By:	/s/ W. RUSSELL SCHEIRMAN W. Russell Scheirman	President, Chief Financial Officer and Director (Principal Financial Officer and Principal Accounting Officer)
By:	/s/ Robert H. Allen Robert H. Allen	Director
By:	/s/ Luigi Caflisch Luigi Caflisch	Director
By:	/s/ O. Donald Chapolton O. Donald Chapolton	Director
By:	/s/ William S. Farish William S. Farish	Director
By:	/s/ Arne R. Nielsen Arne R. Nielsen	Director

40

VAALCO ENERGY, INC. AND SUBSIDIARIES

INDEX TO CONSOLIDATED FINANCIAL INFORMATION

VAALCO ENERGY, INC. AND SUBSIDIARIES
Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets December 31, 2006 and 2005	F-3
Statements of Consolidated Operations Years ended December 31, 2006, 2005 and 2004	F-4
Statements of Consolidated Stockholders’ Equity Years ended December 31, 2006, 2005 and 2004	F-5
Statements of Consolidated Cash Flows Years ended December 31, 2006, 2005 and 2004	F-6
Notes to the Consolidated Financial Statements	F-7

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited the consolidated balance sheets of VAALCO Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2006 and 2005, and the related statements of consolidated operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2006. These financial statements are the responsibility of Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of VAALCO Energy, Inc. and subsidiaries as of December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006 in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 5 to the financial statements, effective January 1, 2006, the Company changed its method of accounting for share based payments.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 6, 2007 expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ Deloitte & Touche LLP

Houston, Texas

March 6, 2007

F-2

VAALCO ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands of dollars, except number of shares and par value amounts)

	December 31, 2006			December 31, 2005
ASSETS
Current assets:
Cash and cash equivalents	$	60,979		$	43,880
Funds in escrow		4,764			1,130
Receivables:
Trade		7,608			6,453
Accounts with partners		5,540			2,255
Other		1,333			1,234
Crude oil inventory		560			518
Materials and supplies		324			290
Prepayments and other		3,073			2,185
Total current assets		84,181			57,945
Property and equipment – successful efforts method:
Wells, platforms and other production facilities		90,398			43,805
Work in progress		3,720			10,832
Equipment and other		1,854			1,783
		95,972			56,420
Accumulated depreciation, depletion and amortization		(25,465	)		(19,222	)
Net property and equipment		70,507			37,198
Other assets:
Deferred tax asset		1,257			1,257
Funds in escrow		10,843			820
Other long term assets		1,154			942
TOTAL	$	167,942		$	98,162
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	26,686		$	8,555
Current liabilities of discontinued operations		—			391
Total current liabilities		26,686			8,946
Long term debt		5,000			1,500
Asset retirement obligations		6,029			3,615
Total liabilities		37,715			14,061
Commitments and contingencies
Minority interest in consolidated subsidiaries		7,963			5,786
Stockholders’ equity:
Common stock, $0.10 par value, 100,000,000 authorized shares 60,058,155 and 58,314,792 shares issued with 1,060,342 in treasury at December 31, 2006 and 2005, respectively		6,006			5,831
Additional paid-in capital		48,093			44,662
Retained earnings		68,431			28,088
Less treasury stock, at cost		(266	)		(266	)
Total stockholders’ equity		122,264			78,315
TOTAL	$	167,942		$	98,162

See notes to consolidated financial statements.

F-3

VAALCO ENERGY, INC. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED OPERATIONS

FOR THE YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

(in thousands of dollars, except per share amounts)

	Year Ended December 31
	2006			2005			2004
Revenues:
Oil and gas sales	$	98,325		$	84,935		$	56,502
Operating costs and expenses:
Production expenses		12,217			10,584			9,958
Exploration expense		2,672			2,709			267
Depreciation, depletion and amortization		6,720			5,369			4,749
General and administrative expenses		2,386			2,696			1,260
Total operating costs and expenses		23,995			21,358			16,234
Operating income		74,330			63,577			40,268
Other income (expense):
Interest income		2,987			1,099			265
Interest expense		(1,026	)		(418	)		(485	)
Other, net		(36	)		131			22
Total other income (expense)		1,925			812			(198	)
Income from continuing operations before income taxes, minority interest and discontinued operations		76,255			64,389			40,070
Income tax expense		30,496			31,491			11,972
Income from continuing operations before minority interest and discontinued operations		45,759			32,898			28,098
Minority interest in earnings of subsidiaries		(5,174	)		(3,647	)		(3,069	)
Income from continuing operations		40,585			29,251			25,029
Discontinued operations: (Note 11)
Loss from discontinued operations net of tax		(242	)		(69	)		(2,091	)
Net income	$	40,343		$	29,182		$	22,938
Basic income per share from continuing operations	$	0.69		$	0.56		$	0.94
Income (loss) from discontinued operations		—			—			(0.08	)
Basic income per share	$	0.69		$	0.56		$	0.86
Diluted income per share from continuing operations	$	0.67		$	0.50		$	0.43
Income (loss) from discontinued operations		—			—		$	(0.04	)
Diluted income per share	$	0.67		$	0.50		$	0.39
Basic weighted shares outstanding		58,136			51,772			26,604
Diluted weighted average shares outstanding		60,476			58,253			58,157

See notes to consolidated financial statements.

F-4

VAALCO ENERGY, INC. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED STOCKHOLDERS’ EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

(in thousands of dollars)

	Preferred Stock					Common Stock			Additional Paid-in Capital			Retained Earnings/ (Accumulated Deficit)			Treasury Stock			Total Stockholders’ Equity
	Shares		Amount			Shares	Amount
Balance at January 1, 2004	10,000		$	250		21,531,829	$	2,153	$	46,358		$	(24,032	)	$	(175	)	$	24,554
Conversion of Preferred Shares	(3,333	)		(83	)	9,165,750		916		(833	)		—			—			—
Proceeds from stock issuance	—			—		2,546,665		255		87			—			—			342
Purchase of treasury shares	—			—		—		—		—			—			(26	)		(26	)
Net Income	—			—		—		—		—			22,938			—			22,938
Balance at December 31, 2004	6,667			167		33,244,244		3,324		45,612			(1,094	)		(201	)		47,808
Conversion of Preferred Shares	(6,667	)		(167	)	18,334,250		1,833		(1,666	)		—			—			—
Proceeds from stock issuance	—			—		6,736,298		674		716			—			—			1,390
Purchase of treasury shares	—			—		—		—		—			—			(65	)		(65	)
Net Income	—			—		—		—		—			29,182			—			29,182
Balance at December 31, 2005	—			—		58,314,792		5,831		44,662			28,088			(266	)		78,315
Proceeds from stock issuance	—			—		1,743,363		175		2,366			—			—			2,541
Stock based compensation	—			—		—		—		1,065			—			—			1065
Net Income	—			—		—		—		—			40,343			—			40,343
Balance at December 31, 2006	—		$	—		60,058,155	$	6,006	$	48,093		$	68,431		$	(266	)	$	122,264

See notes to consolidated financial statements.

F-5

VAALCO ENERGY, INC. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED CASH FLOWS

(in thousands of dollars)

	Year Ended December 31,
	2006			2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	40,343		$	29,182		$	22,938
Adjustments to reconcile net income to net cash provided by (used in) operating activities
Depreciation, depletion and amortization		6,720			5,369			4,749
Amortization of debt issuance costs		596			159			165
Exploration expense		2,672			2,709			267
Loss on asset sales		—			—			191
Stock based compensation		1,065			—			—
Minority interest in earnings of subsidiary		5,174			3,647			3,070
Change in operating assets and liabilities:
Trade receivables		(1,155	)		(1,117	)		(4,786	)
Accounts with partners		(3,285	)		883			(6,251	)
Other receivables		(99	)		(1,025	)		241
Crude oil inventory		(42	)		206			(138	)
Materials and supplies		(34	)		24			(364	)
Deferred tax asset		—			33			(410	)
Prepayments and other		(889	)		(1,184	)		(797	)
Accounts payable and accrued liabilities		13,761			(2,845	)		2,059
Accounts payable discontinued operations		(391	)		—			—
Income taxes payable		—			(140	)		1,859
Net cash provided by operating activities		64,436			35,901			22,793
CASH FLOWS FROM INVESTING ACTIVITIES
Funds in escrow, net		(13,657	)		9			986
Discontinued operations transaction expense		—			—			(1,187	)
Exploration expense		(2,672	)		(2,709	)		(267	)
Additions to property and equipment		(33,244	)		(13,347	)		(14,324	)
Other—net		(473	)		(625	)		113
Net cash used in investing activities		(50,046	)		(16,672	)		(14,679	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of common stock		2,541			1,325			315
Debt issuance costs capitalized		(335	)		—			—
Borrowings		5,000			—			—
Debt repayment		(1,500	)		(2,250	)		(3,250	)
Distribution to minority interest		(2,997	)		(1,998	)		(600	)
Net cash provided by (used in) financing activities		2,709			(2,923	)		(3,535	)
NET CHANGE IN CASH AND CASH EQUIVALENTS		17,099			16,306			4,579
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		43,880			27,574			22,995
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	60,979		$	43,880		$	27,574
Supplemental disclosure of cash flow information
Income taxes paid	$	30,496		$	31,598		$	27,574
Interest paid	$	333		$	209		$	325
Supplemental disclosure of non cash flow information
Investment in property and equipment not paid	$	4,956		$	585			—
Treasury stock purchase		—		$	65		$	26
Conversion of preferred stock and warrants		—		$	1,833			—

See notes to consolidated financial statements.

F-6

VAALCO ENERGY, INC AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION

VAALCO Energy, Inc., a Delaware corporation, is a Houston-based independent energy company principally engaged in the acquisition, exploration, development and production of crude oil and natural gas. As used herein, the terms “Company” and “VAALCO” mean VAALCO Energy, Inc. and its subsidiaries, unless the context otherwise requires. VAALCO owns producing properties and conducts exploration activities as operator of consortiums internationally in Gabon and Angola. Domestically, the Company has interests in the Texas Gulf Coast area. In Gabon and Angola, VAALCO serves as the operator for groups of companies which own the working interest in the production sharing contract, collectively referred to as a consortium.

VAALCO’s active subsidiaries include VAALCO Gabon (Etame), Inc., VAALCO Production (Gabon), Inc., VAALCO Angola (Kwanza), Inc. and VAALCO Energy (USA), Inc.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation—The accompanying consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. The portion of the income and net assets applicable to the non-controlling interest in the majority-owned operations of the Company’s Gabon subsidiary is reflected as minority interest. All significant transactions within the consolidated group have been eliminated in consolidation.

Cash and Cash Equivalents—For purposes of the statements of consolidated cash flows, the Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash and cash equivalents.

Funds in Escrow—Escrow cash includes cash that is contractually restricted for non-operational purposes such as debt service and capital expenditures. Restricted cash and cash equivalents are classified as a current or non-current asset based on their designated purpose. Current amounts at December 31, 2006 represent an escrow securing the Company’s seismic obligations for Block 5 in Angola. Current amounts at December 31, 2005 represent an escrow for principal and interest on the Company’s then outstanding loan amounting to $1.1 million. Long term amounts represent amounts to secure the Company’s drilling obligations in Angola ($10.0 million), an escrow to secure charter payments for the Floating Production Storage and Offloading tanker (“FPSO”) in Gabon ($0.8 million) and for the abandonment of certain Gulf of Mexico properties ($40 thousand). The Company invests funds in escrow and excess cash in certificates of deposit and commercial paper issued by banks with maturities typically not exceeding 90 days.

Inventory—Materials and supplies are valued at the lower of cost, determined by the weighted-average method, or market. Crude oil inventories are carried at the lower of cost or market and represent the Company’s share of crude oil production produced and stored on the tanker, but unsold. Inventory cost represents the production expenses excluding depletion.

Income Taxes—VAALCO accounts for income taxes under an asset and liability approach that recognizes deferred income tax assets and liabilities for the estimated future tax consequences of differences between the financial statements and tax bases of assets and liabilities. Valuation allowances are provided against deferred tax assets that are not likely to be realized.

Property and Equipment—The Company follows the successful efforts method of accounting for exploration and development costs. Under this method, exploration costs, other than the cost of exploratory wells, are charged to expense as incurred. Exploratory well costs are initially capitalized until a determination as to whether proved reserves have been discovered. If an exploratory well is deemed to not have found proved

F-7

VAALCO ENERGY, INC AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

reserves, the associated costs are expensed at that time. All development costs, including developmental dry hole costs, are capitalized. Provisions for impairment of undeveloped oil and gas leases are based on periodic evaluations and other factors. The Company recognizes gains/losses for the sale of developed properties based upon an allocation of property costs between the interests sold and the interests retained based on the fair value of those interests.

The Company reviews its oil and gas properties for impairment whenever events or changes in circumstances indicate that the carrying amount of such 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. Other exploration costs, including geological and geophysical expenses applicable to undeveloped leasehold, leasehold expiration costs and delay rentals are expensed as incurred.

Depletion of wells, platforms and other production facilities are provided on a field basis under the unit-of-production method based upon estimates of proved developed reserves. For financial accounting purposes the Company adopted Statement of Financial Accounting Standards (“SFAS”) 143 – Accounting for Asset Retirement Obligations on January 1, 2003 (See Note 10). 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. Provision for depreciation of other property is made primarily on a straight-line basis over the estimated useful life of the property. The annual rates of depreciation are as follows:

Office and miscellaneous equipment	3-5 years
Leasehold improvements	8-12 years

Foreign Exchange Transactions—For financial reporting purposes, the subsidiaries use the United States dollar as their functional currency. Monetary assets and liabilities denominated in foreign currency are translated to U.S. dollars at the rate of exchange in effect at the balance sheet date, and items of income and expense are translated at average monthly rates. Nonmonetary assets and liabilities are translated at the exchange rate in effect at the time such assets were acquired and such liabilities were incurred. Gains and losses on foreign currency transactions are included in income currently. The Company incurred a gain on foreign currency transactions of $110 in 2006, $126 in 2005 and $19 in 2004.

Accounts With Partners—Accounts with partners represent cash calls due or excess cash calls paid by the partners for exploration, development and production expenditures made by VAALCO Gabon (Etame), Inc.

Revenue Recognition—The Company recognizes revenues from crude oil and natural gas sales upon delivery to the buyer.

Stock-Based Compensation—On January 1, 2006, the Company adopted SFAS 123(R), Share-Based Payments. Prior to the adoption of SFAS 123(R), the Company had adopted the disclosure-only provisions of SFAS 123 Accounting for Stock-Based Compensation and continued to account for stock-based compensation using the intrinsic value method prescribed in APB Opinion No. 25, “Accounting for Stock Issued to Employees.” Accordingly, no compensation cost had been recognized for the Company’s stock-based plans prior to January 1, 2006. (See Note 5 – Stock Based Compensation)

Fair Value of Financial Instruments—The Company’s financial instruments consist primarily of cash, funds in escrow, trade accounts, note receivables, trade payables and debt. The book values of cash, trade receivables, and trade payables are representative of their respective fair values due to the short-term maturity of these instruments. The book value of the Company’s notes receivable and debt instruments are considered to approximate the fair value, as the interest rates are adjusted based on rates currently in effect.

F-8

VAALCO ENERGY, INC AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Risks and Uncertainties—The Company’s interests are located overseas in certain offshore areas in Gabon and in Texas.

Substantially all of the Company’s crude oil and natural gas is sold at the well head at posted or index prices under short-term contracts, as is customary in the industry. In Gabon, effective January 1, 2007, the Company sells crude oil under a contract with ADDAX Oil and Gas, Ltd.. In 2006 Trafigura Beheer B.V. and in 2005 and 2004 Shell Western Supply and Trading Limited, respectively, were the crude oil buyers in Gabon and accounted for all of the Company’s revenues in Gabon for those years. While the loss of the Company’s buyer might have a material effect on the Company in the near term, management believes that the Company would be able to obtain other customers for its crude oil. Domestic production is sold under two types of contracts, one for oil and one for gas. The Company has access to several alternative buyers for oil and gas sales domestically.

Estimates of oil and gas reserves as made in the financial statements require extensive judgments and are generally less precise than other estimates made in connection with financial disclosures. Assigning monetary values to such estimates does not reduce the subjectivity and changing nature of such estimates of value. The information set forth herein is therefore subjective and, since judgments are involved, may not be comparable to estimates of value made by other companies. The Company considers its estimates to be reasonable; however, due to inherent uncertainties and the limited nature of data, estimates are imprecise and subject to change over time as additional information become available.

Use of Estimates in Financial Statement Preparation—The preparation of financial statements in conformity with generally accepted accounting principles requires estimates and assumptions that affect the reported amounts of assets and liabilities as well as certain disclosures. The Company’s financial statements include amounts that are based on management’s best estimates and judgments. Actual results could differ from those estimates.

Reclassifications—Certain immaterial amounts from 2004 and 2005 have been reclassified in the statement of cash flows to conform to the 2006 presentation.

3. NEW ACCOUNTING PRONOUNCEMENTS

SFAS 151, Inventory Costs—In November 2005, the Financial Accounting Standards Board (the “FASB”) issued SFAS 151, Inventory Costs an amendment of Accounting Research Board (“ARB”) 43, Chapter 4, which amends Chapter 4 of ARB 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 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 was effective January 1, 2006 and there was no impact from the adoption of this standard 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 153, Exchanges of Nonmonetary Assets an amendment of APB 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 was effective January 1, 2006 and there was no impact from the adoption of this standard on the Company’s financial position, results of operations or cash flows.

F-9

VAALCO ENERGY, INC AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

FASB Statement 154, Accounting Changes and Error Corrections – In May 2005, the FASB issued FASB Statement 154, Accounting Changes and Error Corrections (SFAS 154). SFAS 154 requires companies to recognize changes in accounting principles, including changes required by a new accounting pronouncement when the pronouncement does not include specific transition provisions, retrospectively to prior periods’ financial statements. This statement was effective January 1, 2006 and there was no impact from the adoption of Statement 154 on the Company’s financial position or results of operations.

FASB Statement 155, Accounting for Certain Hybrid Financial Instruments – In February 2006, the FASB issued SFAS 155, Accounting for Certain Hybrid Financial Instruments (“SFAS 155”), an amendment of FASB Statements 133 and 140. SFAS 155 amends SFAS 133, which required that a derivative embedded in a host contract that does not meet the definition of a derivative be accounted for separately under certain conditions. SFAS 155 amends SFAS 133 to narrow the scope exception to strips that represent rights to receive only a portion of the contractual interest cash flows or of the contractual principal cash flows of a specific debt instrument. In addition, SFAS 155 amends SFAS 140, which permitted a qualifying special-purpose entity to hold only a passive derivative financial instrument pertaining to beneficial interests issued or sold to parties other than the transferor. SFAS 155 amends SFAS 140 to allow a qualifying special purpose entity to hold a derivative instrument pertaining to beneficial interests that itself is a derivative financial instrument. SFAS 155 is effective for all financial instruments acquired or issued (or subject to a remeasurement event) following the start of an entity’s first fiscal year beginning after September 15, 2006. The Company will adopt SFAS 155 on January 1, 2007 and does not expect this standard to have a material impact, if any, on its combined financial statements.

FASB Statement 157, Fair Value Measurements – In September 2006, the FASB issued FASB Statement 157 Fair Value Measurements, (“SFAS 157”), which provides a single definition of fair value, together with a framework for measuring it, and requires additional disclosure about the use of fair value to measure assets and liabilities. SFAS 157 emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and sets out a fair value hierarchy with the highest priority being quoted prices in active markets. Under the Statement, fair value measurements are disclosed by level within that hierarchy. While the Statement does not add any new fair value measurements, it does change current practice. Changes to practice include:

• A requirement for an entity to include its own credit standing in the measurement of its liabilities.

• A modification of the transaction price presumption. A prohibition on the use of block discounts when valuing large blocks of securities for broker dealers and investment companies.

• A requirement to adjust the value of restricted stock for the effect of the restriction even if the restriction lapses within one year.

The Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. Earlier application is encouraged, provided that no financial statements have yet been issued within that fiscal year by the reporting entity. The Statement shall be applied prospectively as of the beginning of the fiscal year in which the Statement is initially applied. The Company will adopt SFAS 157 on January 1, 2008 and does not expect this standard to have a material impact, if any, on its financial statements.

FASB Interpretation 48, Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement 109—During July 2006, the FASB issued Financial Interpretation (“FIN”) 48, Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement 109 (“FIN 48”). FIN 48 addresses the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109, Accounting for Income Taxes. FIN 48 prescribes specific criteria for the financial statement recognition and measurement of the tax effects of a position taken or expected to be taken in a tax return. This interpretation also provides guidance on derecognition of previously recognized tax benefits, classification of tax

F-10

VAALCO ENERGY, INC AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

liabilities on the balance sheet, recording interest and penalties on tax underpayments, accounting in interim periods, and disclosure requirements. The Company does not believe that the adoption of FIN 48 will have a material impact on its financial statements.

4. SUSPENDED WELL COSTS

On April 4, 2005, the FASB issued FASB Staff Position 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 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 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 $2.6 million of suspended well costs associated with the exploration well in the Ebouri field in Gabon which was being carried as work in progress at December 31, 2006. In July 2006, the Company received approval to declare the Ebouri field’s reserves commercial from the Gabon government and in October 2006 the Gabon government approved a development plan for the Ebouri field, and assigned a twenty year development area surrounding the field. The Company will no longer treat these costs as suspended once first production occurs, which is dependent upon construction and delivery of the platform facilities. First production is estimated to occur in 2008.

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

	2006			2005			2004
Beginning balance at January 1	$	6,533		$	6,508		$	1,905
Additions to capitalized exploratory drilling costs		—			2,426			4,603
Capitalized exploratory drilling costs reclassified to property and equipment		(3,926	)		—			—
Capitalized exploratory drilling costs expensed		—			(2,401	)		—
Ending balance at December 31	$	2,607		$	6,533		$	6,508
Number of wells requiring major capital expenditures where additional drilling efforts are not underway or firmly planned for the near future		0			1	(1)		2	(2)
Amount capitalized for wells requiring major capital expenditures where additional drilling efforts are not underway or firmly planned		—		$	2,607		$	2,597

(1) Ebouri No. 1 well, see discussion above.

(2) Ebouri No. 1 well and Avouma No. 1 well

F-11

VAALCO ENERGY, INC AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The $2,607 of exploratory drilling costs capitalized at December 31, 2006 are all associated with proven undeveloped reserves and were capitalized in 2006. There are no capitalized exploratory drilling costs associated with unproven reserves.

5. STOCK BASED COMPENSATION

SFAS 123(R), Share Based Payment—In December 2004, FASB issued SFAS 123 (Revised 2004), Share-Based Payment, (“SFAS 123(R)”), which establishes accounting standards for all transactions in which an entity exchanges its equity instruments for goods and services. SFAS 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 123(R) eliminates the intrinsic value measurement objective in Accounting Principles Board (“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 adopted SFAS 123(R) on January 1, 2006. The Company has elected to use the “modified prospective method.” Under the modified prospective method, the Company recognizes 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.

Stock options are granted under the Company’s long-term incentive plan and have an exercise price that may not be less than the fair market value of the underlying shares on the date of grant. In general, stock options granted will become exercisable over a period determined by the Compensation Committee. In addition, stock options will become exercisable upon a change in control, unless provided otherwise by the Compensation Committee. At December 31, 2006 there were no shares subject to options authorized but not granted.

During the year ended December 31, 2006, the Company granted 100,000 stock options to purchase an equal number of common shares at an exercise price of $6.20 per share to a newly appointed director. The options were vested on the date of the grant and have a term of five years. During the year ended December 31, 2006, a total of 1,811,500 options were granted to employees and directors on December 12, 2006 at an exercise price of $7.97 per share. The options have a five year term and one third of each employee’s options vest on each of December 12, 2007, 2008 and 2009, so long as the employee continues to be employed by the Company. The directors’ options (125,000 total) vested on the issuance date.

For the year ended December 31, 2006, the Company recognized non-cash compensation expense of $1.1 million (or $0.02 and $0.02 per basic and diluted share), related to stock options granted and stock options which vested during the period, net of anticipated forfeitures. This amount was recorded as general and administrative expense. Because the Company does not pay significant United States taxes, no amounts were recorded for tax benefits related to excess stock based compensation deductions.

F-12

VAALCO ENERGY, INC AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

A summary of the unit option activity for the year ended December 31, 2006 is provided below:

	Number of Units Underlying Options (in thousands)		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term	Aggregate Intrinsic Value (in millions)
Outstanding—beginning of period	4,340		$	2.15	3.08	$	19.9
Granted	1,911			7.88	4.90		(2.1	)
Exercised	(1,744	)		1.47	2.13		(9.2	)
Forfeited	(138	)		3.85	3.04		(0.4	)
Outstanding—end of period	4,369			4.87	3.65		8.2
Vested—end of period	2,293		$	2.76	2.80	$	9.1
Vested and expected to vest—end of period	4,141		$	4.75	3.60	$	8.3

The intrinsic value of a stock option is the amount by which the current market value of the underlying stock exceeds the exercise price of the option. As of December 31, 2006, unrecognized compensation costs totaled $3.2 million. The expense is expected to be recognized over a weighted average period of 1.5 years.

A summary of the values of options granted, exercised and vested for each of the years ending December 31, 2006, 2005 and 2004 is provided below:

	2006		2005		2004
Options granted—(thousands)		1,911		1,657		—
Weighted average exercise price—($/share)	$	7.88	$	3.86	$	—
Weighted average grant-date fair value—($/share)	$	2.23	$	2.20	$	—
Options/warrants exercised (thousands)(1)		1,744		6,236		2,547
Total intrinsic value of options/warrants exercised—($thousands)	$	10,885	$	23,950	$	8,217
Options vested—(thousands)		694		1,964		1,215
Total fair value of options vested ($thousands)	$	1,558	$	1,614	$	389

(1) 5,500,000 and 2,000,000 warrants were exercised in 2005 and 2004 respectively with an intrinsic value of $20.4 million and $6.5 million respectively. There were no warrants outstanding at December 31, 2006 and 2005

The Company received cash proceeds of $2.5 million from options exercised in 2006.

F-13

VAALCO ENERGY, INC AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Prior to January 1, 2006, had compensation cost for the Company’s stock-based compensation plans been determined based on the fair value at the grant dates for awards under those plans consistent with the optional method prescribed by SFAS No. 123, the Company’s net income and net income per share would have been adjusted to the pro forma amounts indicated below (in thousands, except per share data):

Years Ended December 31,	2005		2004
Net income as reported	$	29,182	$	22,938
Deduct: Total stock based employee compensation expense		2,909		959
Proforma net income	$	26,273	$	21,979
Basic earnings per share
As reported	$	0.56	$	0.86
Pro forma	$	0.51	$	0.83
Diluted earnings per share
As reported	$	0.50	$	0.39
Pro forma	$	0.45	$	0.38

The total stock based employee compensation expense was determined under the fair value based method for all awards, net of related tax effects.

The effects of applying SFAS No. 123 in the disclosure may not be indicative of future amounts as additional awards in future years are anticipated.

The valuation of the options is based upon a Black Scholes model assuming expected volatility ranging from 31% to 62%, risk-free interest rate ranging from 5.5% to 8.0%, expected life of options of 3 to 10 years, depending upon the award and expected dividend yield of 0%. The table below summarizes the assumptions used to value the options issued in 2006, and 2005. No options were granted in 2004.

Year	Options Issued	Volatility Range		Weighted Avg. Volatility		Life Range	Risk Free Interest Range		Expected Dividend Yield
2006	1,911	31-56	%	32	%	2.5-5 years	5.5-8.0	%	0	%
2005	1,507	62	%	62	%	3-10 years	5.5	%	0	%

The Company has no set policy for sourcing shares for options grants. Historically the shares issued under options grants have been new shares.

6. STOCKHOLDERS’ EQUITY AND EARNINGS PER SHARE

The Company is authorized to issue up to 100 million shares of common stock. Stockholder’s equity consists of common stock and options. Set out in the table below is a summary of the number of shares on an as converted basis assuming cash exercise of all options outstanding as of December 31, 2006 and 2005.

	2006	2005
Common shares issued and Outstanding (1)	58,997,813	57,254,450
Options	4,368,672	4,339,535
Total shares on an as converted, As exercised basis	63,366,485	61,593,985

(1) Net of treasury shares

F-14

VAALCO ENERGY, INC AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The Company follows SFAS No. 128 – “Earnings per Share,” which establishes the requirements for presenting earnings per share (“EPS”). SFAS No. 128 requires the presentations of “basic” and “diluted” EPS on the face of the income statement.

The following schedule is presented as a reconciliation of the numerators and denominators of basic and diluted earnings per share computations.

(In thousands except per share amounts)	For the Year Ended December 31, 2006
	Per-Share Amount			Net Income (Numerator)			Shares (Denominator)
Basic EPS
Income from continuing operations attributable to common stockholders	$	0.69		$	40,585		58,136
Loss from discontinued operations attributable to common stockholders		—			(242	)	—
Net income attributable to common stockholders		0.69			40,343		58,136
Effect of Dilutive Securities
Common stock and options		(0.02	)		—		2,340
Diluted EPS
Net income attributable to common stockholders	$	0.67		$	40,343		60,476
(In thousands except per share amounts)	For the Year Ended December 31, 2005
	Per-Share Amount			Net Income (Numerator)			Shares (Denominator)
Basic EPS
Income from continuing operations attributable to common stockholders	$	0.56		$	29,251		51,772
Loss from discontinued operations attributable to common stockholders		—			(69	)	—
Net income attributable to common stockholders		0.56			29,182		51,772
Effect of Dilutive Securities
Preferred stock, common stock options and warrants		(0.06	)		—		6,481
Diluted EPS
Net income attributable to common stockholders	$	0.50		$	29,182		58,253

F-15

VAALCO ENERGY, INC AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(In thousands except per share amounts)	For the Year Ended December 31, 2004
	Per-Share Amount			Net Income (Numerator)			Shares (Denominator)
Basic EPS
Income from continuing operations attributable to common stockholders	$	0.94		$	25,029		26,604
Loss from discontinued operations attributable to common stockholders		(0.08	)		(2,091	)	26,604
Net income attributable to common stockholders		0.86			22,938		26,604
Effect of Dilutive Securities
Preferred stock, common stock options and warrants		(0.47	)		—		31,553
Diluted EPS
Net income attributable to common stockholders	$	0.39		$	22,938		58,157

Diluted shares consist of the following:

	Year Ended
Item	December 31, 2006	December 31, 2005	December 31, 2004
Basic weighted average common stock issued and outstanding	58,135,850	51,772,219	26,604,299
Preferred stock convertible to Common stock	—	3,817,542	22,942,168
Dilutive warrants	—	977,504	5,831,837
Dilutive options	2,340,023	1,686,170	2,779,075
Total diluted shares	60,475,874	58,253,435	58,157,379

On March 17, 2005, the holder of the Company’s preferred stock converted 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 holder 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 holder. With the completion of the conversion of preferred stock and exercises of warrants, the Company has no preferred stock or warrants outstanding.

F-16

VAALCO ENERGY, INC AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

7. INCOME TAXES

The Company and its domestic subsidiaries file a consolidated United States income tax return. Certain subsidiaries’ operations are also subject to foreign income taxes. Provision for income taxes consists of the following:

(In thousands)	Year Ended December 31,
	2006		2005		2004
U.S. federal:
Current	$	—	$	—	$	370
Deferred		—		33		(370	)
Foreign:
Current		30,496		31,458		11,972
Deferred		—		—		—
Total	$	30,496	$	31,491	$	11,972

The primary differences between the financial statement and tax bases of assets and liabilities at December 31, 2006 and 2005 are as follows: (In thousands)

	2006			2005
Deferred Tax Assets:
Basis difference in fixed assets	$	1,457		157
Foreign tax credit carry forwards		18,682		17,929
Alternative minimum tax credit carryover		1,257		1,257
Asset retirement obligations		1,955		1,265
		23,351		20,608
Valuation allowance		(22,094	)	(19,351	)
Total deferred tax asset	$	1,257		1,257

Pretax income (loss) is comprised of the following:

(In thousands)	Year Ended December 31,
	2006		2005		2004
United States	$	91	$	95	$	131
Foreign		76,164		64,294		39,939
	$	76,255	$	64,389	$	40,070

The statutory rate reconciliation is as follows:

(In thousands)	Year Ended December 31,
	2006		2005		2004
Pre-tax income multiplied by 35%	$	26,690	$	22,536	$	14,024
Foreign taxes not offset by U.S. foreign tax credits		3,806		8,922		98
U.S. net operating losses benefited		—		—		(2,150	)
Return to provision adjustment		—		33		—
Total income tax	$	30,496	$	31,491	$	11,972

At December 31, 2006, the Company was subject to foreign and United States federal taxes only, with no allocations made to state and local taxes.

F-17

VAALCO ENERGY, INC AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

8. COMMITMENTS AND CONTINGENCIES

In connection with the charter of the FPSO at the Etame field, the Company as operator of the Etame field guaranteed the charter payments through September 2010. The charter continues for two years beyond that period unless one year’s prior notice is given to the owner of the FPSO. The Company obtained several guarantees from its partners for their share of the charter payment. The Company’s share of the charter payment is 28.1%. The Company believes the need for performance under the charter guarantee is remote. The estimated obligations for the annual charter payment and the Company’s share of the charter payments through the end of the charter are as follows: (in thousands)

Year	Full Charter Payment		Company Share
2007	$	17,192	$	4,826
2008	$	16,155	$	4,535
2009	$	16,001	$	4,492
2010	$	11,824	$	3,319

The Company has recorded a liability of $0.4 million at December 31, 2006 representing the guarantee’s fair value.

The Company’s share of charter expense, including a $0.25 per barrel charter fee was $5.6 million, $5.5 million and $5.5 million for the years ending December 31, 2006, 2005 and 2004 respectively.

In addition to the FPSO, the Company has operating lease obligations for rentals as follows: (In thousands)

2007	2008	2009	2010	2011	Total
$2,193	$356	$354	$331	$179	$3,549

The Company incurred rent expense of $1.1 million, $1.1 million and $1.0 million under operating leases during the years ending December 31, 2006, 2005 and 2004 respectively.

In January 2006 the consortium elected to extend the Etame block for an additional five-year term commencing July 2006. The extension consists of a three-year and a two-year follow-on term. The first term carries a minimum work obligation of one exploration well for a minimum $7.0 million exploration expenditure commitment ($2.1 million net to the Company). An additional exploration well is required during the optional two year extension.

Under the terms of the Etame Production Sharing Contract, the Contractor is required to provide to the local government refinery a volume of crude at a 25% discount to market price (the “Domestic Obligation”). The volume required to be furnished is the amount of the Etame block production divided by the total Gabon production times the volume of oil refined by the refinery per year. In 2006, the Company paid $1.1 million for its share of the 2005 obligation. In 2005, the Company paid $859,000 for its share of the 2004 obligation. In 2004, the Company paid $747,000 for its share of the 2002 and 2003 Domestic Obligation. The Company accrues an amount for the Domestic Obligation based on management’s best estimate of the volume of crude required, because the refinery does not publish its throughput figures. The amount accrued at December 31, 2006 is $1.1 million.

The Company believes it is substantially in compliance with all environmental regulations.

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 along the central coast of Gabon. During the first three years of the contract the Company is required to drill one exploration well and expend a minimum

F-18

VAALCO ENERGY, INC AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

of $4.0 million. During the optional two year extension to the contract, the Company is required to acquire specified levels of seismic data, drill one exploration well and expend a minimum of $5.0 million. The Company is currently gathering data from past operators of the area for interpretation and prospect delineation.

In November 2006, the Company signed a production sharing contract for Block 5 offshore Angola. The seven year contract awards the Company exploration rights to 1.4 million acres offshore central Angola. The Company’s working interest in the Contract is 40%. Additionally, the Company is required to carry the Angolan National Oil Company Sonangol P&P for 10% of the work program. During the first four years of the contract the Company is required to acquire and process 1,000 square kilometers of 3-D seismic, drill two exploration wells and expend a minimum of $29.5 million ($14.8 million net to the Company). During the optional three year extension to the contract, the Company is required to acquire 600 square kilometers of 3-D seismic data, drill two exploration wells and expend a minimum of $27.2 million ($13.6 million net to the Company). The Company acquired the 1,000 square kilometers of 3-D data called for in the first exploration period at a cost of $7.5 million ($3.75 million net to the Company) in January 2007.

9. LONG TERM DEBT

In June 2005, the Company executed a loan agreement with the International Finance Corporation (“IFC”) for a $30.0 million revolving credit facility secured by the assets of the Company’s Gabon subsidiary. The loan bears interest at LIBOR plus 3.5% payable quarterly. The Company is required to comply with certain covenants including maintaining certain loan to property value ratios and interest coverage ratios. The Company was in compliance with all covenants at December 31, 2006 and had drawn a balance of $5.0 million on the facility at December 31, 2006.

The facility is available to finance the Ebouri field development activities or other Etame block projects. 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 and replaced an existing term credit facility, which was paid in full on February 15, 2006. The Company incurred 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. The Company reclassified $1.25 million of short term debt to long term debt associated with the refinancing at December 31, 2005.

Under the loan agreements, the IFC holds a pledge of the Company’s interest in the Etame block, and pledge of the shares of VAALCO Gabon (Etame), Inc. the subsidiary which owns the Company’s interest in the Etame Block. The IFC also has a security interest in the crude oil sales contract with ADDAX.

10. ASSET RETIREMENT OBLIGATIONS

The Company accounts for asset retirement obligations in accordance with SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 addresses financial accounting and reporting for obligations associated with the retirement of tangible, long-lived assets and the associated asset retirement costs. 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. The statement requires the systematic, accretion and depreciation of future abandonment costs of tangible assets such as platforms, wells, service assets, pipelines, and other facilities. SFAS No. 143 requires that the fair value of a liability for an asset’s retirement obligation be recorded in the period in which it is incurred if a reasonable estimate of fair value can be made, and that the corresponding cost is capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.

F-19

VAALCO ENERGY, INC AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

A summary of the recording of the estimated fair value of the Company’s asset retirement obligations is presented as follows: (In thousands)

	2006		2005		2004
Balance January 1,	$	3,615	$	1,330	$	1,165
Accretion Expense		210		113		65
Additions		1,807		528		294
Revisions		397		1,644		(194	)
Balance December 31,	$	6,029	$	3,615	$	1,330

During the year ended December 31, 2006 the Company increased ARO liabilities by $2,206 to reflect the fair value of the ARO at December 31, 2006. The increase was primarily due to the increased abandonment liability associated with the addition of the Avouma platform and revisions due to earlier abandonment timing. During the year ended December 31, 2005 the Company increased ARO liabilities by $2.3 million to reflect the fair value of the ARO at December 31, 2005. The increase was primarily due to the increased liability associated with the addition of the ET-6H well and due to increases in oil service prices resulting in higher abandonment cost estimates. During the year ended December 31, 2004 the Company increased the ARO liabilities by $165,000 to reflect the fair value of the ARO at December 31, 2004. The increase was primarily due to the increased liability associated with addition of the Etame 5H well at the Etame field partially offset by revisions to abandonment timing.

As of December 31, 2006, the Company had $40,000 legally restricted for settling asset retirement obligations in the United States.

F-20

VAALCO ENERGY, INC AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

11. DISCONTINUED OPERATIONS

On April 30, 2004, the Company closed the sale to its former partners of all of its assets associated with Service Contract 6 and Service Contract 14 in the Philippines (Matinloc and Nido fields). Terms of the sale included the assumption by the partners of the Company’s entire share of any abandonment, environmental or other liabilities associated with the Service Contracts. The Company gave its share of $1.5 million of funds held by the operator for working capital and abandonment liabilities (approximately $0.5 million) to the new operator. During the fourth quarter of 2004, the Company recorded a charge of $1.8 million for branch profit remittance taxes and interest based on the preliminary results of an audit by the Philippines Bureau of Internal Revenues (BIR). The BIR, the equivalent of the IRS in the United States, assessed the taxes in association with the closing of the branch offices in the Philippines. The Company has reclassified earnings to break out the results of discontinued operations. The Company realized a loss of $125,000 after paying transaction costs of $1.3 million which was recorded in 2004 as follows.

(thousands of dollars)
Future asset retirement obligations assumed by buyer	$	1,498
Book value of assets transferred to buyer
Materials and supplies		(321	)
Prepaid expenses		(2	)
Notes receivable		1
Property and equipment		(4	)
Deposits and other assets		(12	)
Accounts due partners		(98	)
Payments required under the purchase and sale agreement
Payment to contingency fund		(198	)
Payment to operating account		(136	)
Severance benefits		(747	)
Other closing costs		(106	)
Loss on asset sale	$	(125	)

F-21

VAALCO ENERGY, INC AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

In 2006, the Company settled all remaining tax liabilities with the Philippines government. The Company paid additional tax amounts over and above what had been accrued at year end 2005 of $169,000. The Company anticipates closing the branches and liquidating the subsidiaries during 2007. A summary of discontinued operations for the years ending December 31, 2006, 2005 and 2004 follows.

	Year ended December 31,
	(thousands of dollars)
	2006			2005			2004
Loss from discontinued operations
Revenues from oil sales	$	—		$	—		$	40
Operating costs and expenses:
Production expenses		—			—			71
General and administrative expenses		88			55			37
Total operating costs and expenses		88			55			108
Other revenues (expenses):
Interest income		15			—			6
Interest expense		—			—			(136	)
Other expenses (net)		—			(14	)		(4	)
Loss on asset sale		—			—			(125	)
Loss from discontinued operations before income taxes		(73	)		(69	)		(327	)
Income tax expense (credit)		169			—			1,764
Loss from discontinued operations	$	(242	)	$	(69	)	$	(2,091	)

A summary of account balances for discontinued operations is presented as follows below in thousands:

(In thousands)	December 31, 2005
Current Assets
Other receivables	$	—
Total current assets	$	—
Current liabilities
Accounts payable	$	11
Income tax payable		380
Total current liabilities	$	391

F-22

VAALCO ENERGY, INC AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

12. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

The following represents our unaudited quarterly results for years ended December 31, 2006 and 2005. The quarterly results were prepared in accordance with generally accepted accounting principles and reflect all adjustments that are, in the opinion of management, necessary for a fair statement of the results. These adjustments are of a normal recurring nature.

(In thousands of dollars except per share information)	1st Quarter			2nd Quarter			3rd Quarter			4th Quarter
2006
Total revenues	$	31,237		$	25,575		$	25,640		$	15,873
Total operating costs and expenses		6,110			5,546			5,352			6,986
Operating Income		25,127			20,029			20,288			8,888
Income from continuing operations		11,689			11,832			14,657			6,151
Minority interest		(1,432	)		(1,329	)		(1,555	)		(860	)
Income (loss) on discontinued operations		715			(14	)		488			(1	)
Net income	$	10,974		$	10,489		$	13,590		$	5,290
Basic income per share from continuing operations before discontinued operations	$	0.20		$	0.18		$	0.22		$	0.09
Income (loss) from discontinued operations		(0.01	)		—			0.01			—
Basic income per common share	$	0.19		$	0.18		$	0.23		$	0.09
Diluted income per share from continuing operations before discontinued operations	$	0.19		$	0.17		$	0.21		$	0.09
Income (loss) from discontinued operations		(0.01	)		—			0.01			—
Diluted income per common share	$	0.18		$	0.17		$	0.22		$	0.09
2005
Total revenues	$	23,144		$	16,599		$	26,240		$	18,952
Total operating costs and expenses		5,257			6,238			4,743			5,120
Operating Income		17,887			10,361			21,497			13,832
Income from continuing operations		8,132			5,637			13,362			5,767
Minority interest		(878	)		(640	)		(1,434	)		(695	)
Income (loss) on discontinued operations		8			1			(25	)		(53	)
Net income	$	7,262		$	4,998		$	11,903		$	5,019
Basic income per share from continuing operations before discontinued operations	$	0.20		$	0.09		$	0.21		$	0.09
Income (loss) from discontinued operations		—			—			—			—
Basic income per common share	$	0.20		$	0.09		$	0.21		$	0.09
Diluted income per share from continuing operations before discontinued operations	$	0.12		$	0.09		$	0.20		$	0.09
Income (loss) from discontinued operations		—			—			—			—
Diluted income per common share	$	0.12		$	0.09		$	0.20		$	0.09

Quarterly earnings per share are based on the weighted average number of shares outstanding during the quarter. Because of changes in the number of shares outstanding during the quarters due to the exercise of stock options and issuance of common stock, the sum of quarterly earnings per share may not equal earnings per share for the year.

F-23

VAALCO ENERGY, INC AND SUBSIDIARIES

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING PROPERTIES

(Unaudited)

13. SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES

The following information is being provided as supplemental information in accordance with certain provisions of SFAS No. 69, Disclosures about Oil and Gas Producing Activities. The Company’s reserves are located offshore of Gabon and Texas. The following tables set forth costs incurred, capitalized costs, and results of operations relating to oil and natural gas producing activities for each of the periods. (See Footnote 1—“ORGANIZATION”)

Costs Incurred in Oil and Gas Property

Acquisition, Exploration and Development Activities

(In thousands)	United States
	2006		2005		2004
Costs incurred during the year:
Exploration—capitalized	$	—	$	—	$	—
Exploration—expensed		—		—		—
Development		1		1		1
Total	$	1	$	1	$	1
(In thousands)	Gabon
	2006		2005		2004
Costs incurred during the year:
Exploration—capitalized	$	11,138	$	25	$	5,182
Exploration—expensed		2,672		2,709		267
Development		24,520		15,519		9,242
Total	$	38,330	$	18,253	$	14,691

No costs were incurred for acquisitions, exploration and development activities associated with the discontinued operation in the Philippines in 2006, 2005, and 2004. Exploration expense includes $2.4 million for dry hole expense in 2005. No amounts of exploration costs were for dry hole expense in 2006 and 2004.

Capitalized Costs Relating to Oil and Gas Producing Activities:

(In thousands)	Year Ended December 31, 2006			Year Ended December 31, 2005			Year Ended December 31, 2004
Capitalized costs—
Properties not being amortized	$	3,720		$	10,832		$	6,508
Properties being amortized (1)		90,398			43,805			33,222
Total capitalized costs		94,118			54,637			39,730
Less accumulated depreciation, depletion, and amortization		(25,465	)		(19,222	)		(13,940	)
Net capitalized costs	$	68,653		$	35,415		$	25,790

(1) Includes $5.5 million, $3.5 million and $1.4 million of asset retirement cost in 2006, 2005 and 2004 respectively.

The capitalized costs pertain to the Company’s producing activities in Gabon and U.S. activities.

F-24

VAALCO ENERGY, INC AND SUBSIDIARIES

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES

Results of Operations for Oil and Gas Producing Activities:

(In thousands)	United States									International
	2006			2005			2004			2006			2005			2004
										Gabon			Gabon			Gabon
Crude oil and gas sales	$	155		$	236		$	245		$	98,170		$	84,700		$	56,257
Production expense		(89	)		(97	)		(69	)		(12,128	)		(10,485	)		(9,889	)
Exploration expense		—			—			—			(1,128	)		(2,631	)		(267	)
Depreciation, depletion and Amortization		(36	)		(44	)		(38	)		(6,149	)		(5,212	)		(4,600	)
Income (loss) before taxes		30			95			138			78,765			66,372			41,501
Income tax (provision)		11			33			—			30,496			31,458			(11,972	)
Results from oil and gas producing activities	$	19		$	62		$	138		$	48,269		$	34,914		$	29,529

Proved Reserves

A reserve report as of December 31, 2006 has been prepared by Netherland Sewell & Associates, independent petroleum engineers. The following tables set forth the net proved reserves of VAALCO Energy, Inc. as of December 31, 2006, 2005 and 2004, and the changes therein during the periods then ended.

(In thousands)	Oil (MBbls)		Gas (MMcf)
PROVED RESERVES:
BALANCE AT JANUARY 1, 2004	9,011		140
Production	(1,469	)	(22	)
Revisions	96		(64	)
Additions	1,447		—
Sale of reserves in place	(351	)	—
BALANCE AT DECEMBER 31, 2004	8,734		54
Production	(1,635	)	(17	)
Revisions	728		(16	)
BALANCE AT DECEMBER 31, 2005	7,827		21
Production	(1,552	)	(11	)
Revisions	(1,590	)	7
Additions	1,306		—
BALANCE AT DECEMBER 31, 2006	5,991		17
	Oil (MBbls)		Gas (MMcf)
PROVED DEVELOPED RESERVES
Balance at December 31, 2003	6,492		140
Balance at December 31, 2004	4,738		54
Balance at December 31, 2005	5,326		21
Balance at December 31, 2006	4,686		17

The Company’s proved developed reserves are located offshore Gabon and in Texas. The reserves in Gabon include the minority interest share of reserves held by the 9.99% owner of VAALCO International, Inc., which owns VAALCO Gabon (Etame), Inc. Proved oil reserves associated with discontinued operations in the Philippines were 351 Mbbls at January 1, 2004 and were sold in 2004. There were no gas reserves in the Philippines at January 1, 2004.

F-25

VAALCO ENERGY, INC AND SUBSIDIARIES

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES

The revisions in 2004 were predominately associated with better than expected reservoir performance from the Etame field offshore Gabon. Revisions in 2005 were associated with the Etame field and the Texas properties performance. Revisions in 2006 were associated primarily with Etame field performance.

The Company maintains a policy of not booking proved reserves on discoveries until such time as a development plan has been prepared for the discovery. Additionally, the development plan is required to have the approval of 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 was adjacent to a previous discovery known as the South Tchibala discovery. The Company received approval of the Avouma/South Tchibala joint development plan from the Gabon government and booked additions to proven reserves of 1,447 Mbbls for the South Tchibala and Avouma fields offshore Gabon in 2004.

For the Ebouri discovery the Company received approval of the development plan from the Gabon government in 2006 and booked approximately 800,000 bbls of proven undeveloped reserves for the Ebouri field as of December 31, 2006.

Standardized Measure of Discounted Future Net Cash

Flows Relating to Proved Oil Reserves

The information that follows has been developed pursuant to procedures prescribed by SFAS No. 69 and utilizes reserve and production data estimated by independent petroleum consultants. The information may be useful for certain comparison purposes, but should not be solely relied upon in evaluating VAALCO Energy, Inc. or its performance.

The future cash flows are based on sales prices and costs in existence at the dates of the projections, excluding Gabon royalties, and the interests of the Philippine government and the other consortium members. Future production costs do not include overhead charges allowed under joint operating agreements or headquarters general and administrative overhead expenses. Future development costs include $5.9 million attributable to future abandonment when the wells become uneconomic to produce. The standardized measure of discounted cash flows does not include the costs of abandoning the Company’s non-producing properties.

(In thousands)	United States									International									Total
	December 31,									December 31,									December 31,
	2006			2005			2004			2006			2005			2004			2006			2005			2004
										Gabon			Gabon			Gabon
Future cash inflows	$	374		$	533		$	977		$	341,930		$	444,249		$	350,234		$	342,304		$	444,782		$	351,211
Future production costs		(203	)		(204	)		(344	)		(81,121	)		(121,531	)		(98,143	)		(81,324	)		(121,735	)		(98,487	)
Future development costs		—			—			—			(37,575	)		(30,927	)		(27,554	)		(37,575	)		(30,927	)		(27,554	)
Future income tax expense		(32	)		(48	)		(86	)		(59,518	)		(76,467	)		(58,520	)		(59,550	)		(76,515	)		(58,606	)
Future net cash flows		139			281			547			163,716			215,324			166,017			163,855			215,605			166,564
Discount to present value at 10% annual rate		(20	)		(82	)		(127	)		(30,233	)		(54,314	)		(43,116	)		(30,253	)		(54,396	)		(43,243	)
Standardized measure of discounted future net cash flows	$	119		$	199		$	420		$	133,483		$	161,010		$	122,901		$	133,602		$	161,209		$	123,321

F-26

VAALCO ENERGY, INC AND SUBSIDIARIES

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES

Income taxes represent amounts payable to the Government of Gabon on profit oil as final payment of corporate income taxes and for severance taxes in Texas.

Changes in Standardized Measure of Discounted Future Net Cash Flows:

The following table sets forth the changes in standardized measure of discounted future net cash flows as follows:

(In thousands)	December 31,
	2006			2005			2004
BALANCE AT BEGINNING OF PERIOD	$	161,209		$	123,321		$	101,610
Sales of oil and gas, net of production costs		(86,108	)		(74,321	)		(46,544	)
Net changes in prices and production costs		1,254			87,991			48,242
Revisions of previous quantity estimates		(51,797	)		24,780			1,437
Additions		52,320			—			33,887
Sale of reserves in place		—			—			(1,451	)
Changes in estimated future development costs		(8,124	)		(4,358	)		(11,154	)
Development costs incurred during the period		22,106			11,852			9,721
Accretion of discount		16,141			12,332			10,019
Net change in income taxes		8,585			(14,506	)		(9,064	)
Change in production rates (timing) and other		18,022			(5,882	)		(13,413	)
Discontinued Operations		—			—			31
BALANCE AT END OF PERIOD	$	133,602		$	161,209		$	123,321

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 crude oil and natural 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 natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and natural 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 are recoverable under the service contracts and the reserves in place remain the property of the Gabon.

In accordance with the guidelines of the U.S. Securities and Exchange Commission, the Company’s estimates of future net cash flows from the Company’s properties and the present value thereof are made using oil and natural 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. The contract price as of December 31, 2006 in Gabon was $57.07 per bbl oil, representing a $1.81 discount to the spot price of Dated Brent crude at December 31, 2006. In Texas, the price was $56.33 per bbl oil and $4.99 per mcf gas at December 31, 2006.

Under the Production Sharing Contract in Gabon, the Gabonese government is the owner of all oil and gas mineral rights. The right to produce the oil and gas is stewarded by the Directorate Generale de Hydrocarbeures and the Production Sharing contract was awarded by a decree from the State. Pursuant to the service contract, the Gabon government receives a variable royalty depending on production rate.

F-27

VAALCO ENERGY, INC AND SUBSIDIARIES

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES

The consortium maintains a Cost Account, which entitles it to receive 70% of the production remaining after deducting the royalty so long as there are amounts remaining in the cost account. At December 31, 2006, there was $13.8 million in the cost account ($1.8 million net to the Company). As payment of corporate income taxes the consortium pays the government an allocation of the remaining “profit oil” production from the contract area ranging from 50% to 60% of the oil remaining after deducting the royalty and the cost oil. The percentage of “profit oil” paid to the government as tax is a function of production rates. So long as amounts remain in the Cost Account, the net share that the consortium receives from production can range from a low of 67.7% of production at production rate in excess of 25,000 BOPD to a high of 82.5% of production at rates below 5,000 bopd. However, when the cost account becomes substantially recovered, the Company only recovers ongoing operating expenses and new project capital expenditures, resulting in a higher tax rate. The Cost Account has been substantially recovered since the first quarter of 2005. During 2006, the Company cost recovered 629,000 bbls for ongoing operating expenses and capital expenditures out of a theoretical maximum Cost Oil of 1,070,000 bbls which would have been recoverable if the Cost Account was full. Also because of the nature of the Cost Account, decreases in oil prices result in a greater number of barrels required to recover costs, therefore at lower oil prices, the Company’s net reserves would increase. The Company also paid $16.9 million of royalties to the Gabon government, which is not reflected in the Company’s financial statements.

The Etame Production Sharing Contract allows for the carve-out of a development area, which was performed for the Etame field and for the Avouma field. The Etame development area has a term of 20 years and will expire in 2021. The Avouma field development area has a term of 20 years and will expire in 2025. The Ebouri field development area has a term of 20 years and will expire in 2026. The balance of the Etame block comprises the exploration area, which expires in July 2009 but is extendable to 2011 via an exploration well work commitment.

Under the service contract, it is not anticipated that the Gabonese government will take physical delivery of its allocated production. Instead, the Company is authorized to sell the Gabonese government’s share of production and remit the proceeds to the Gabonese government.

The Mutamba Iroru production sharing contract entitles the Company to receive 70% of the any future production remaining after deducting the royalty so long as there are amounts remaining in the cost account. At December 31, 2005 there was $0.1 million in the cost account. As payment of corporate income taxes the consortium pays the government an allocation of the remaining “profit oil” production from the contract area ranging from 50% to 63% of the oil remaining after deducting the royalty and the cost oil. The percentage of “profit oil” paid to the government as tax is a function of production rates. So long as amounts remain in the Cost Account, the net share that the consortium receives from production can range from a low of 72% of production at production rate in excess of 20,000 BOPD to a high of 85% of production at rates below 7,500 barrel per day. However, when the cost account becomes substantially recovered, the Company only recovers ongoing operating expenses and new project capital expenditures, resulting in a higher tax rate. The Mutamba Iroru service contract provides for a discovery to be reclassified into a development area with a term of twenty years.

The Block 5 production sharing contract in Angola entitles the Company to receive 50% of the any future production so long as there are amounts remaining in the cost account. There are no royalty payments under the contract. The consortium pays the government an allocation of the remaining “profit oil” production from the contract area ranging from 30% to 90% of the oil remaining after deducting the cost oil. The percentage of “profit oil” paid to the government as tax is a function of the Company’s rate of return for each development area. In addition, the Company will pay 50% of its share of the profit oil as income tax to the government of Angola. The Block 5 production sharing contract provides for a discovery to be reclassified into a development area with a term of twenty years.

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