VAALCO Energy (EGY) 10-K 2007 FY Annual report

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, 2007

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

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

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

Large accelerated filer    ¨            Accelerated filer    x            Non-accelerated filer    ¨            Smaller reporting company    ¨

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

The aggregate market value of the voting and non-voting common equity of the registrant held by non-affiliates, as of June 29, 2007 was $276,066,436 based on a closing price of $4.83 on June 29, 2007.

As of February 29, 2008, there were outstanding 59,194,182 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	15
Item 3.	Legal Proceedings	18
Item 4.	Submission of Matters to a Vote of Security Holders	18
PART II
Item 5.	Market for Registrants Common Equity, Related Stockholder Matters and Issuer Purchase of Equity Securities	19
Item 6.	Selected Financial Data	22
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	28
Item 8.	Financial Statements and Supplementary Data	28
Item 9.	Changes In and Disagreements with Accountants on Accounting and Financial Disclosure	29
Item 9A.	Controls and Procedures	29
Item 9B.	Other Information	31
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	31
Item 11.	Executive Compensation	31
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	31
Item 13.	Certain Relationships, Related Transactions and Director Independence	31
Item 14.	Principal Accountant Fees and Services	31
PART IV
Item 15.	Exhibits and Financial Statement Schedules	32
	Glossary of Oil and Gas Terms	35
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 conducts exploration activities as operator in Angola, Africa. The Company has also organized a British subsidiary which participated in its first exploration well in the British North Sea in late 2007 and plans to participate in another well during 2008. Domestically, the Company has minor interests in the Texas Gulf Coast area and offshore Louisiana. 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 Etame field in September 2002 and from the Avouma and South Tchibala fields in January 2007. During 2007, the Etame Avouma and South Tchibala fields produced approximately 7.4 million bbls (1.8 million bbls net to the Company). In addition to the Etame, Avouma and South Tchibala fields, the Company is developing the Ebouri field, which was discovered in 2004. A platform is currently being constructed for installation during the summer of 2008, with first production from the Ebouri field expected to occur in late 2008.

Onshore Gabon, the Company has a 100% working interest in the Mutamba Iroru block located near the coast in central Gabon. The Mutamba Iroru block contains approximately 270,000 acres for exploration. The Company acquired seismic data from previous operators over the block in 2006 and 2007 and plans to drill one or two exploration wells on the block during 2008.

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 acquired 1,175 square kilometers of seismic data over a portion of the Block 5 and is interpreting the seismic data. The Company expects the first exploration well to be drilled in late 2008 or in early 2009.

In December 2007, the Company signed a farm-in agreement for a 25% working interest in Block 9/28d offshore in the British North Sea. The Company was obligated to pay its share of the drilling of one well on the block and a portion of the share of the farminee’s share of the well. The well was spudded in December 2007 and reached total depth in January 2008. The well was suspended as a non-commercial discovery in January 2008.

In January 2008, the Company signed a farm-in agreement for a 25% working interest in Block 48/25c offshore in the British North Sea. The Company is obligated to pay its share of the drilling of one well on the block and a portion of the farminee’s share of the well. Block 48/25c is located in the Southern Gas Basin and an exploration well is expected to be drilled during the third quarter of 2008.

See Note 12 to the Company’s consolidated financial statements for financial information about the Company’s segments.

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AVAILABLE INFORMATION

The Company files annual, quarterly and current reports, proxy statements and other information with the SEC. You may read and copy any document the Company files at the SEC’s Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the SEC’s Public Reference Room. The Company’s SEC filings are also available to the public at the SEC’s website at www.sec.gov.

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

GENERAL

The Company’s current 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 2008. The Company owns a 100% working interest in the 270,000 acre Mutamba Iroru block onshore Gabon and a 40% working interest in the 1.4 million acre Block 5 offshore Angola. During 2008, the Company will continue mapping prospects on these blocks using available seismic data in order to develop exploration drilling prospects for 2008 and 2009. The Company has a 25% working interest in two blocks in the British North Sea. 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, one exploration license in Angola and as non-operator in two blocks in the British North Sea.

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 in onshore wells. Current domestic properties are located in Brazos County, Texas and offshore Louisiana in the Ship Shoal area.

CUSTOMERS

Substantially all of the Company’s oil and gas is sold at 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 Shell Western Supply and Trading Limited (Shell) which runs through the calendar year 2008. While the loss of Shell 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.

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EMPLOYEES

As of December 31, 2007, the Company had 25 full-time employees, ten of whom were located in Gabon and six of whom were located in Angola. The Company also utilizes contractors to staff its international operations. The Company is not subject to any collective bargaining agreements and believes its relations with its employees are satisfactory.

COMPETITION

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

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

ENVIRONMENTAL REGULATIONS

General

The Company’s activities are subject to federal, state and local laws and regulations governing environmental quality and pollution control in the United States, Gabon and Great Britain and will be subject to the laws and regulations of Angola when exploration begins. 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 their regulation of environmental issues in the future; any significant increase in the regulation or enforcement of environmental issues by Gabon or Angola could have a material effect on the Company. Developing countries, in certain instances, have patterned environmental laws after those in the United States which are discussed below. However, the extent to which any environmental laws are enforced in developing countries varies significantly.

Environmental Regulations in the United States

Solid and Hazardous Waste

The Company currently owns or leases, and in the past has owned or leased, properties that have been used for the exploration and production of oil and gas for many years. Although the Company has utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other solid wastes may have been disposed or released on or under the properties owned or leased by the Company or on or under locations where such wastes have been taken for disposal. In addition, some of these properties are or have been operated

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by third parties. The Company has no control over such entities’ treatment of hydrocarbons or other solid wastes and the manner in which such substances may have been disposed or released. State and federal laws applicable to oil and gas wastes and properties have gradually become stricter over time. The Company could in the future be required to remediate property, including groundwater, containing or impacted by previously disposed wastes (including wastes disposed or released by prior owners or operators, or property contamination, including groundwater contamination by prior owners or operators) or to perform remedial plugging operations to prevent future or mitigate existing contamination.

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

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,

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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 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.

Greenhouse Gas Emissions

Recent scientific studies have suggested that manmade emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to the warming of the atmosphere resulting in climate change. In response to such studies, the United States Congress is actively considering legislation to reduce emissions of greenhouse gases. In addition, at least 17 states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts v. EPA, the EPA may regulate greenhouse gas emissions from mobile sources (e.g., cars and trucks) and possibly from stationary sources as well under certain federal Clean Air Act programs, even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. New legislation or regulatory programs that restrict emissions of greenhouse gases in areas where the Company conducts business could adversely affect its operations and the demand for hydrocarbon products generally. The impact of such future programs cannot be predicted, but we do not expect our operations to be affected any differently than other similarly situated domestic competitors.

Air Emissions

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

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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 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;

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• 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.

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 block 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 and the Avouma and South Tchibala fields, consisting of one producing well each, constituted almost 100% of our total production for the year ended December 31, 2007. In addition, at December 31, 2007, almost 100% of our total net proved reserves were attributable to these fields. If mechanical problems, storms or other events curtailed a substantial portion of this production, or if the actual reserves associated with this producing property are less than our estimated reserves, our results of operations and financial condition could be materially adversely affected.

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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 2007 and 2006.

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.

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 and British North Sea 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 2007, we have participated, and in 2008 we will continue to participate, in the further exploration and

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development projects on our international properties. In Gabon and Angola, we are the operator for the blocks 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 Etame budget and 50% of the Angola Block 5 budget for which they are responsible. However, if lower oil and gas prices, operating difficulties or declines in reserves result in our revenues being less than expected or limit our ability to borrow funds, or our partners fail to pay their share of project costs, we may have a limited ability 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 gas may involve unprofitable efforts, not only from dry wells, but also from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. The cost of drilling, completing and operating wells is often uncertain and cost overruns are common. Our drilling operations may be curtailed, delayed or canceled as a result of numerous factors, many of which are beyond our control, including title problems, weather conditions, compliance with governmental requirements and shortages or delays in the delivery of equipment and services.

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

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

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

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

There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves, including many factors beyond our control. Reserve engineering is a subjective process of estimating the underground accumulations of oil and gas that cannot be measured in an exact manner. The estimates included in this document are based on various assumptions required by the SEC, including unescalated prices and costs and capital expenditures, 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

11

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 2007 would result in the estimated quantities and present values of our reserves being reduced.

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

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

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

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

Almost all of our proven reserves are located offshore of the Republic of Gabon. As of December 31, 2007, we carried a gross investment of approximately $80.1 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.

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

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

• our 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, Gabon, Angola and Great Britain regulate our current business. Our operations could result in liability for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages. In addition, we could be liable for environmental damages caused by, among others, previous property owners or operators. As a result, substantial liabilities to third parties or governmental entities may be incurred, the payment of which could have a material adverse effect on our financial condition, results of operations and liquidity.

These laws and governmental regulations, which cover matters including drilling operations, taxation and environmental protection, may be changed from time to time in response to economic or political conditions and could have a significant impact on our operating costs, as wells as the oil and gas industry in general. In addition, the Company is subject to International Finance Corporation environmental guidelines published by the World Bank. While we believe that we are currently in compliance with environmental laws and regulations applicable to our operations in Gabon, Great Britain 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.

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

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

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

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

Item 1B. Unresolved Staff Comments

None.

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Item 2. Properties

Gabon

Etame Marin

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

VAALCO operates the Etame Marin block on behalf of a consortium of companies. At December 31, 2007, VAALCO owned a 30.35% interest in the exploration acreage within the Etame Marin Block, and in the Ebouri field and North Tchibala discovery. 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.

In April 2005, a development plan for the joint development of the Avouma and South Tchibala fields was approved by the Gabon government. The Company was awarded a 20 square mile exploitation area which has a term of twenty years (until 2025). In 2006, the Company installed a platform in approximately 250 feet of water and drilled two development wells from the platform, one into each field. The two development wells are tied back to the FPSO via a 10 mile pipeline. The cost of developing the Avouma and South Tchibala fields was $121 million, ($33.9 million net to the Company). The Company has sold a total of 33.1 million gross bbls (8.0 million net bbls) from the fields within the Etame Marin block since startup through December 31, 2007. During 2007, the Etame, Avouma and South Tchibala fields produced approximately 7.4 million gross bbls (1.8 million net bbls).

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 beginning in late 2008. The platform will be tied back to the FPSO via a pipeline as was done for the Avouma and South Tchibala fields.

Mutamba Iroru

In November 2005, the Company signed a production sharing contract for the Mutamba Iroru block onshore Gabon. The five year contract awarded the Company exploration rights to approximately 270,000 acres along the central coast of Gabon. The Mutamba Iroru block was previously held by Shell Gabon. The Company has been interpreting seismic and well data from past operators of the area and expects to drill one or two wells on the block in 2008. 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 acquired 1,175 square kilometers of seismic data over a portion of Block 5 and is interpreting the seismic data. A first exploration well could be expected late 2008 or in early 2009.

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Great Britain

In December 2007, the Company signed a farm-in agreement for a 25% working interest in Block 9/28d offshore in the British North Sea. The Company was obligated to pay its share of the drilling of one well on the block and a portion of the share of the farminee’s share of the well. The well was spudded in December 2007 and reached total depth in January 2008. The well was suspended as a non-commercial discovery in January 2008.

In January 2008 the Company signed a farm-in agreement for a 25% working interest in Block 48/25c offshore in the British North Sea. The Company is obligated to pay its share of the drilling of one well on the block and a portion of the share of the farminee’s share of the well. The block is located in the Southern Gas Basin and an exploration well is expected to be drilled during the third quarter of 2008.

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 2007 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 2008 for these properties.

Aggregate Production

Aggregate production data (net to the Company) for all of the Company’s operations for the years 2007, 2006 and 2005 are shown below. The production figures exclude discontinued operations:

Company Owned Production

	Year Ended December 31,
	2007			2006			2005
	BOE	Bbl	Mcf	BOE	Bbl	Mcf	BOE	Bbl	Mcf
Average Daily Production
(Oil in BOPD, gas in MCFD)	4,819	4,809	47	4,258	4,253	30	4,488	4,480	47
Average Sales Price ($/unit)	71.10	71.16	6.51	63.26	63.29	5.91	52.02	52.04	6.88
Average Production Cost ($/unit)	8.57	8.57	1.43	7.90	7.90	1.32	6.46	6.46	1.08

RESERVE INFORMATION

A reserve report as of December 31, 2007 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 and Louisiana (onshore and offshore).

	As of December 31,
	2007		2006		2005
Crude Oil
Proved Developed Reserves (MBbls)		4,506		4,691		6,620
Proved Undeveloped Reserves (MBbls)		1,708		1,305		1,207
Total Proved Reserves (MBbls)		6,214		5,996		7,827
Natural Gas
Proved Developed Reserves (MMcf)		61		17		21
Proved Undeveloped Reserves (MMcf)		—		—		—
Total Proved Reserves (MMcf)		61		17		21
Standardized measure of proved reserves	$	191,669	$	133,602	$	161,209

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The following tables set forth the net proved reserves of the Company as of December 31, 2007, 2006 and 2005, and the changes during such periods.

	Oil (MBbls)		Gas (MMcf)
PROVED RESERVES:
BALANCE AT JANUARY 1, 2005	8,734		54
Production	(1,635	)	(17	)
Revisions of previous estimates	728		(16	)
BALANCE AT DECEMBER 31, 2005	7,827		21
Production	(1,552	)	(11	)
Revisions of previous estimates	(1,585	)	7
Extensions and discoveries	1,306		—
BALANCE AT DECEMBER 31, 2006	5,996		17
Production	(1,756	)	(20	)
Revisions of previous estimates	1,979		64
BALANCE AT DECEMBER 31, 2007	6,214		61

	Oil (MBbls)	Gas (MMcf)
PROVED DEVELOPED RESERVES
Balance at December 31, 2004	4,738	54
Balance at December 31, 2005	6,620	21
Balance at December 31, 2006	4,691	17
Balance at December 31, 2007	4,506	61

The Company does not book proved reserves on discoveries until such time as a development plan has been prepared and approved by the Company’s partners in the discovery. Furthermore, if a government agreement that the reserves are commercial is required to develop the field, this approval must have been received prior to booking any reserves. The Company received approval for the development of the Ebouri field in October 2006. Accordingly the Company booked proved undeveloped reserves for the Ebouri field at year end 2006.

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

17

escalations. In Gabon, the price was $94.96 per bbl. In the United States, the price was $90.97 per bbl. of oil and $7.26 per Mcf of gas. SeeSupplemental Information on Oil and Gas Producing Properties for certain additional information concerning the proved reserves of the Company.

Drilling History

The Company participated in one exploration well during 2007 in the British North Sea. In 2006 the Company participated in two development wells in Gabon during 2006. In 2005 the Company participated in one exploration well and one development well, both in Gabon.

	United States						International
	Gross			Net			Gross			Net
Wells Drilled	2007	2006	2005	2007	2006	2005	2007	2006	2005	2007	2006	2005
Exploration Wells
Productive	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.00	0.00	0.00
Dry	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0	1.0	0.00	0.00	0.30
In progress(1)	0.0	0.0	0.0	0.0	0.0	0.0	1.0	0.0	0.0	0.25	0.00	0.00
Development Wells
Productive	0.0	0.0	0.0	0.0	0.0	0.0	0.0	2.0	1.0	0.00	0.56	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	1.0	2.0	2.0	0.25	0.56	0.58

(1) The well was drilling in the British North Sea at December 31, 2007 and was abandoned as dry in January 2008.

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, 2007:

	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	2,426.6	1,060.8
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.

Office Space

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

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 Registrants Common Equity, Related Stockholder Matters and Issuer Purchase of Equity Securities

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
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	$	6.93	$	4.61
Second Quarter		5.84		4.62
Third Quarter		5.41		3.68
Fourth Quarter		5.40		4.12
2008:
First Quarter (through February 29, 2008)	$	5.13	$	4.19

On February 29, 2008 the last reported sale price of the common stock on the New York Stock Exchange was $4.46 per share.

As of February 29, 2008 there were approximately 16,000 holders of record of the Company’s common stock.

Dividends

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

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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 Company’s cumulative total shareholder return is calculated by dividing (a) the sum of the dividends paid during the “measurement period,” and the difference between the price for the Company’s shares at the end and the beginning of the measurement period, by (b) the price for the Company’s common shares at the beginning of the measurement period. “Measurement period” means the period beginning at the market close on the last trading day before the beginning of the Company’s fifth preceding fiscal year, through and including the end of the Company’s most recently completed fiscal year. The Corporation first became listed on the New York Stock Exchange on October 12, 2006.

	2002		2003		2004		2005		2006		2007
VAALCO Energy, Inc	$	100	$	95	$	264	$	288	$	459	$	316
S&P500 Composite	$	100	$	126	$	138	$	142	$	161	$	167
S&P/ TSX Capped Energy	$	100	$	124	$	161	$	257	$	262	$	285

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Securities Authorized for Issuance Under Equity Compensation Plans

The following table provides information as of December 31, 2007 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	420,668	$	3.85	3,008,333
Equity compensation plans not approved by security holders	2,830,640	$	6.22	112,860
Total	3,251,308	$	5.91	3,121,193

Issuer Purchases of Equity Securities for Year Ended December 31, 2007

The following table provides information as of December 31, 2007 regarding the number of shares of common stock of the Company purchased by the Company.

	Number of shares purchased	Average price per share	Total number of shares purchased as part of publicly announced plans or programs	Maximum number of shares that may yet be purchased under the plans or programs
October 2007	255,000	4.70	255,000
November 2007	45,000	4.42	45,000
December 2007	200,000	4.44	200,000
Total	500,000	4.57	500,000	(See note 1	)

Note 1—On September 14, 2007, the Company announced its intention to purchase up to $20 million of shares of its common stock for the treasury. The announcement did not specify an amount of shares or expiration date. The Corporation has purchased shares since this announcement and will report future purchased volumes in its Quarterly Reports on Form 10-Q. Purchases may be made in both the open market and through negotiated transactions, and purchases may be increased, decreased or discontinued at any time without prior notice.

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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, 2007 has been derived from the Company’s Consolidated Financial Statements for such periods. The information should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Consolidated Financial Statements and Notes thereto. The following information is not necessarily indicative of the Company’s future results.

	Years Ended December 31,
	2007		2006(1)		2005		2004		2003
	(In thousands, except per share amounts)
Total revenues	$	125,044	$	98,325	$	84,935	$	56,502	$	35,481
Income from continuing operations	$	19,103	$	40,585	$	29,251	$	25,029	$	7,254
Net income	$	19,052	$	40,343	$	29,182	$	22,938	$	8,936
Basic income per common share from continuing operations	$	0.32	$	0.69	$	0.56	$	0.94	$	0.34
Diluted income per common share from continuing operations	$	0.32	$	0.67	$	0.50	$	0.43	$	0.13
Total assets	$	186,558	$	167,942	$	98,162	$	68,371	$	46,367
Total debt	$	5,000	$	5,000	$	1,500	$	3,750	$	7,000

(1) Effective January 1, 2006 the Company adopted SFAS 123(R) resulting in expense of $1.1 million in 2006 and $2.2 million in 2007.

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

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, Angola and Great Britain 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 primary operating costs are at the Company’s producing fields in Gabon where the 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 2007 and 2006.

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CRITICAL ACCOUNTING POLICIES

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

Successful Efforts Method of Accounting for Oil and Gas activities

The SEC prescribes in Regulation S-X the financial accounting and reporting standards for companies engaged in oil and gas producing activities. Two methods are prescribed: the successful efforts method and the full cost method. Like many other oil and gas companies, the Company has chosen to follow the successful efforts method. Management believes that this method is preferable, as the Company has focused on exploration activities wherein there is risk associated with future success and as such earnings are best represented by attachment to the drilling operations of the Company. Costs of successful wells, development dry holes and leases containing productive reserves are capitalized and amortized on a unit-of-production basis over the life of the related reserves.

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 contains lower than anticipated reserves or if commodity prices fall below a level that significantly effects anticipated future cash flows on the field.

Suspended Well Costs

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.

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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.

In December 2007 the Company spudded a well of block 9/28b in the British North Sea. The well was suspended as a non-commercial discovery in January 2008. Accordingly the Company expensed as Exploration Expense all costs incurred through December 31, 2007. The Company also anticipates expensing the additional costs incurred while drilling the well in January 2008, which are estimated to be approximately $4.0 million.

CAPITAL RESOURCES AND LIQUIDITY

Cash Flows

Net cash provided by operating activities for 2007 was $43.2 million, as compared to $61.8 million in 2006 and $35.6 million in 2005. The decrease in cash provided by operations in 2007 compared to 2006 was primarily due to an increase in cash used for geological and geophysical exploration activities of $7.2 million and an increase in working capital other than cash of $9.0 million, primarily associated with Gabon operations, compared to a decrease in working capital other than cash of $7.9 million in 2006.

Net cash provided by operations in 2006 increased by $26.2 million over 2005 primarily due to improved operating results and favorable movements in working capital. Working capital other than cash decreased $7.9 million, primarily associated with Gabon operations, compared to an increase of $5.2 million in 2005.

Net cash used in investing activities in 2007 was $22.6 million, compared to net cash used in investing activities for 2006 of $47.3 million and net cash used in investing activities in 2005 of $16.4 million. In 2007, the Company invested $14.5 million in the Etame Marin block operations for the development of the Avouma, South Tchibala and Ebouri fields and drilled a dry well in the North Sea at a cost of $8.1 million.

In 2006, the Company invested $22.4 million in Etame Marin 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.

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. In addition, the Company drilled a dry well on the Etame Marin block at a cost of $2.4 million.

In 2007, cash used in financing activities was $5.2 million, consisting of distributions to a minority interest owner of $4.0 million and purchase of treasury shares of $2.3 million which was partially offset by proceeds

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from issuance of common stock of $1.1 million. 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.

Capital Expenditures

During 2007, the Company spent approximately $14.5 million for the development of the Avouma and South Tchibala fields ($6.0 million) and for the development of the Ebouri field ($8.5 million). 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.

In 2007, the Company also spent $15.3 million to acquire and process seismic in Angola ($4.3 million), to acquire and process seismic in Gabon ($2.6 million), to drill an unsuccessful exploration well in the British North Sea ($8.1 million) and for other seismic costs in the North Sea ($0.3 million). In 2006, the Company spent $2.7 million to acquire seismic in Gabon and on North Sea projects. In 2005, the Company spent $2.4 million to drill an unsuccessful exploration well in Gabon and spent $0.3 million on seismic processing. As a successful efforts company, all of these amounts were expensed.

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, 2007, the Company had cash balances of $76.5 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 2008 capital expenditure budget of approximately $44.5 million to develop the Ebouri field, for the Gabon, Angola and North Sea exploration programs and for additional investments in working capital resulting from potential growth. As operator of the 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 Marin 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.

Contractual Obligations

The table below summarizes the Company’s obligations and commitments at December 31, 2007:

Payment Period

(in thousands)	2008	2009	2010	Thereafter
Long term debt(1)	—	5,000	—	—
Interest on long term debt(2)	435	344	—	—
Operating leases(3)	11,730	9,993	5,094	22,947

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

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2. Interest is based on rates and principal payments in effect at 12/31/2007

3. The Company is Guarantor of a lease for the FPSO utilized in Gabon, which has remaining obligations of $61.2 million. The Company’s share of these payments is included in the table above. The Company can cancel the lease anytime after September 7, 2013, 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 Marin block by July 6, 2009, $4.0 million for its share of an exploration well on the Mutamba Iroru block by November 11, 2008, $10 million for its share of two exploration wells on Block 5 in Angola by November 30, 2010 and $8.0 million for its share of an exploration well in Block 48/25c in the British North Sea during 2008 .

The Company is carrying $6.7 million of asset retirement obligations as of December 31, 2007, representing the present value of these obligations as of that date. The company does not anticipate incurring expenditures for any material asset retirement obligations over the next five years.

RESULTS OF OPERATIONS

Year Ended December 31, 2007 Compared to Years Ended December 31, 2006 and 2005

Revenues

Total oil and gas sales for 2007 were $125.0 million as compared to $98.3 and $84.9 million for 2006 and 2005. In 2007 the Company sold approximately 1,753,000 bbls at an average price of $71.16 per bbl from the Etame Marin block. Revenues from the United States were $0.3 million. 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 the United States were $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 the United States were $0.2 million. The increased oil volumes from the Etame Marin block in 2007 versus 2006 were due to the addition of Avouma and South Tchibala fields in January 2007. 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.

Operating Costs and Expenses

Production expenses for 2007 were $15.1 million as compared to $12.2 million and $10.6 million for 2006 and 2005. In 2007, operating expenses increased due to the addition of the Avouma and South Tchibala fields, as well as increased costs for support vessels for liftings, fuel costs and personnel costs. In addition a second field boat was required. In 2006, operating expenses increased compared to 2005 due to higher support vessel charges associated with crude oil liftings, and due to a change out of the communications system in Gabon to accommodate the new facilities for the Avouma and South Tchibala fields.

Exploration costs for 2007 were $15.3 million as compared to $2.7 million and $2.7 million for 2006 and 2005. In 2007 amounts were spent to acquire and process seismic in Angola ($4.3 million), to acquire and process seismic in Gabon ($2.6 million), to drill an unsuccessful exploration well in the British North Sea ($8.1 million) and for other seismic costs in the North Sea ($0.3 million). In 2006, the Company incurred exploration expenses associated seismic acquisition and reprocessing in the Etame Marin block ($1.1 million), preparations for possible entry into the North Sea ($1.1 million), seismic processing for the Mutamba Iroru 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.

Depreciation, depletion and amortization expense was $18.0 million for 2007, and was $6.7 million and $5.4 million for 2006 and 2005 respectively. Depletion, depreciation and amortization expense increased in 2007

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versus 2006 due to the addition of the platform and pipeline for the development of the Avouma and South Tchibala fields. Depletion rates for the Avouma and South Tchibala fields average $17.68 per bbl compared to $4.69 per bbl from the Etame field. Depletion, depreciation 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.

General and administrative expenses for 2007 were $8.0 million as compared to $2.4 million and $2.7 million for 2006 and 2005. General and administrative expenses increased in 2007 versus 2006 due to increased administrative activity for the Mutamba Iroru block in Gabon, Block 5 in Angola and North Sea activity. Additionally, the Company incurred $2.2 million in non-cash stock based compensation expense in 2007 compared to $1.1 million in 2006. The Company also received lower administrative reimbursements from the Etame Marin block due to lower capital expenditure activity in 2007 compared to 2006. 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.

Operating Income

Operating income for 2007 was $68.7 million as compared to a $74.3 million and $63.6 million operating income for 2006 and 2005. Increased revenues due to higher production rates and oil prices in 2007 were offset by higher exploration costs in Gabon, Angola and the North Sea, and higher depletion expense in Gabon. The Company benefited from higher oil prices in 2006 compared to 2005, which more than offset lower production rates.

Other Income (Expense)

Interest income for 2007 was $3.9 million compared to $3.0 million and $1.1 million in 2006 and 2005. All the 2007, 2006 and 2006 amounts represent interest earned and accrued on cash balances and funds in escrow. Interest rates also increased during 2006 over 2005.

Interest expense of $1.1 million was recorded in 2007 as compared to $1.0 million and $0.4 million in 2006 and 2005. Interest in all three years was associated with the financings from the IFC for use on Etame Marin block activities. In 2007, the Company also incurred $0.6 million of amortization of capitalized financing costs, compared to $0.5 million and $0.2 million in each of 2006 and 2005.

Income Taxes

In 2007, the Company incurred $48.1 million of income taxes, compared to $30.5 million of income taxes incurred in 2006, all of which were associated with the Etame block production and 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. The increased tax in Gabon in 2007 was due to higher production rates and oil prices, as well as lower capital expenditures which reduced cost recovery bbls and increased profit oil taxes. The decrease in 2006 compared to 2005 was due to depreciation of Avouma and South Tchibala development costs which reduced profit oil tax payments.

Minority Interest

A provision for minority interest in the Gabon subsidiary of $4.4 million, $5.2 million and $3.6 million was made for in 2007, 2006 and 2005 respectively.

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Loss from Discontinued Operations

Loss from discontinued operations in the Philippines was $51,000 as the Company achieved the final closeout of the branch offices during 2007. Loss from discontinued operation in 2006 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 the branch offices in Manila.

Net Income

Net income for 2007 was $19.1 million as compared to a net income of $40.3 million and $29.2 million in 2006 and 2005. In 2007, higher production, exploration, depletion and general and administrative costs, and higher taxes in Gabon, more than offset increases in production and oil prices as compared to 2006. Higher oil prices in 2006 compared to 2005 was the primary driver of the increase in net income in 2006 compared to 2005.

NEW ACCOUNTING PRONOUNCEMENTS

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

OFF BALANCE SHEET ARRANGEMENTS

For a discussion of off balance sheet arrangements associated with the guarantee by the company of the charter payments for the FPSO located in Gabon, see Note 8 to the consolidated 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 gas production. Sales prices are primarily driven by the prevailing market price. Historically, prices received for oil and gas production have been volatile and unpredictable.

Interest Rate Market Risk

At December 31, 2007, 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 2007, the interest rate on the Company’s bank debt averaged 8.7%. If the balance of the bank debt at December 31, 2007 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 in 2007 or 2006 or 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.

The Company maintains disclosure controls and procedures that are designed to provide reasonable assurance that information required to be disclosed by the Company in the reports it file or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to the Company’s management, including the Chief Executive Officer and Chief Financial Officer to allow timely decisions regarding required disclosure. The Company’s management, including the Company’s principal executive officer and principal financial officer, has evaluated the effectiveness of the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this Annual Report on Form 10-K. Based on that evaluation, the Company’s principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures were effective as of the end of the period covered by this Annual Report on Form 10-K. There were no changes in the Company’s internal controls over financial reporting that occurred during the Company’s last year that have materially affected, or are reasonably likely to materially affect the Company’s internal control over financial reporting.

Management’s Annual Report on Internal Control Over Financial Reporting

The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting for the Company, as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Under the supervision and with the participation of the Company’s management, including the Company’s principal executive and principal financial officers, the Company conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework inInternal Control—Integrated Frameworkissued 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, 2008, management concluded that its internal control over financial reporting was effective as of December 31, 2007.

The Company’s internal control over financial reporting as of December 31, 2007 has been audited by Deloitte & Touche LLP, the independent registered public accounting firm who audited the Company’s consolidated financial statements as of and for the year ended December 31, 2007, 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, 2007 that has materially affected, or is reasonable likely to materially affect, our internal control over financial reporting.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

Houston, Texas

We have audited the internal control over financial reporting of VAALCO Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2007, based on criteria established inInternal Control—Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based upon the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the criteria established inInternal Control—Integrated Frameworkissued 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, 2007 of the Company and our report dated March 12, 2008 expressed an unqualified opinion on those financial statements.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

March 12, 2008

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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 year ended December 31, 2007 in previously filed reports on Form 8-K.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

Information required by this item will be included in the Company’s proxy statement for its 2008 annual meeting, which will be filed with the Commission within 120 days of December 31, 2007, 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 2008 annual meeting, which will be filed with the Commission within 120 days of December 31, 2007, and which is incorporated herein by reference.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

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 2008 annual meeting, which will be filed with the Commission within 120 days of December 31, 2007, and which is incorporated herein by reference.

Item 13. Certain Relationships, Related Transactions and Director Independence

Information required by this item will be included in the Company’s proxy statement for its 2008 annual meeting, which will be filed with the Commission within 120 days of December 31, 2007, 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 2008 annual meeting, which will be filed with the Commission within 120 days of December 31, 2007, and which is incorporated herein by reference.

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PART IV

Item 15. Exhibits and Financial Statement Schedules

(a) 1. The following is an index to the financial statements 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, 2007 and 2006	F-3
Statements of Consolidated Operations Years ended December 31, 2007, 2006 and 2005	F-4
Statements of Consolidated Stockholders’ Equity Years ended December 31, 2007, 2006 and 2005	F-5
Statements of Consolidated Cash Flows Years ended December 31, 2007, 2006 and 2005	F-6
Notes to the Consolidated Financial Statements	F-7

(a) 2. Schedules 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 Marin 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.

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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 & 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.

(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.

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(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.

34

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.

35

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 predictability 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, 2007, 2006 or 2005 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.

36

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.

37

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 12, 2008

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

	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

38

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, 2007 and 2006	F-3
Statements of Consolidated Operations Years ended December 31, 2007, 2006 and 2005	F-4
Statements of Consolidated Stockholders’ Equity Years ended December 31, 2007, 2006 and 2005	F-5
Statements of Consolidated Cash Flows Years ended December 31, 2007, 2006 and 2005	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:

Houston, Texas

We have audited the accompanying consolidated balance sheets of VAALCO Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2007 and 2006, and the related statements of consolidated operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2007. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the 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, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Notes 2 and 5 to the financial statements, effective January 1, 2006 the Company changed its method of accounting for share-based payment.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2007, based on the criteria established inInternal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 12, 2008 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

March 12, 2008

F-2

VAALCO ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

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

	December 31, 2007			December 31, 2006
ASSETS
Current assets:
Cash and cash equivalents	$	76,450		$	60,979
Funds in escrow		4,764			4,764
Receivables:
Trade		19,766			7,608
Accounts with partners		3,829			5,540
Other		1,646			1,333
Crude oil inventory		927			560
Materials and supplies		339			324
Prepayments and other		2,162			3,073
Total current assets		109,883			84,181
Property and equipment—successful efforts method:
Wells, platforms and other production facilities		80,052			77,557
Undeveloped acreage		12,841			12,841
Work in progress		11,822			3,720
Equipment and other		2,261			1,854
		106,976			95,972
Accumulated depreciation, depletion and amortization		(42,984	)		(25,465	)
Net property and equipment		63,992			70,507
Other assets:
Deferred tax asset		1,457			1,257
Funds in escrow		10,871			10,843
Other long term assets		355			1,154
TOTAL	$	186,558		$	167,942
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	23,904		$	26,686
Income taxes payable		200			—
Total current liabilities		24,104			26,686
Long term debt		5,000			5,000
Asset retirement obligations		6,728			6,029
Total liabilities		35,832			37,715
Commitments and contingencies (Note 8)
Minority interest in consolidated subsidiaries		8,396			7,963
Stockholders’ equity:
Common stock, $0.10 par value, 100,000,000 authorized shares 61,054,824 and 60,058,155 shares issued with 1,560,342 and 1,060,342 shares in treasury at December 31, 2007 and 2006, respectively		6,105			6,006
Additional paid-in capital		51,294			48,093
Retained earnings		87,483			68,431
Less treasury stock, at cost		(2,552	)		(266	)
Total stockholders’ equity		142,330			122,264
TOTAL	$	186,558		$	167,942

See notes to consolidated financial statements.

F-3

VAALCO ENERGY, INC. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED OPERATIONS

(in thousands of dollars, except per share amounts)

	Year Ended December 31
	2007			2006			2005
Revenues:
Oil and gas sales	$	125,044		$	98,325		$	84,935
Operating costs and expenses:
Production expenses		15,080			12,217			10,584
Exploration expense		15,340			2,672			2,709
Depreciation, depletion and amortization		17,952			6,720			5,369
General and administrative expenses		7,999			2,386			2,696
Total operating costs and expenses		56,371			23,995			21,358
Operating income		68,673			74,330			63,577
Other income (expense):
Interest income		3,928			2,987			1,099
Interest expense		(1,094	)		(1,026	)		(418	)
Other, net		106			(36	)		131
Total other income (expense)		2,940			1,925			812
Income from continuing operations before income taxes, minority interest and discontinued operations		71,613			76,255			64,389
Income tax expense		48,081			30,496			31,491
Income from continuing operations before minority interest and discontinued operations		23,532			45,759			32,898
Minority interest in earnings of subsidiaries		(4,429	)		(5,174	)		(3,647	)
Income from continuing operations		19,103			40,585			29,251
Loss from discontinued operations, net of tax		(51	)		(242	)		(69	)
Net income	$	19,052		$	40,343		$	29,182
Basic income per share from continuing operations	$	0.32		$	0.69		$	0.56
Loss per share from discontinued operations		—			—			—
Basic net income per share	$	0.32		$	0.69		$	0.56
Diluted income per share from continuing operations	$	0.32		$	0.67		$	0.50
Loss per share from discontinued operations		—			—			—
Diluted net income per share	$	0.32		$	0.67		$	0.50
Basic weighted shares outstanding		59,134			58,136			51,772
Diluted weighted average shares outstanding		60,091			60,476			58,253

See notes to consolidated financial statements.

F-4

VAALCO ENERGY, INC. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED STOCKHOLDERS’ EQUITY

(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, 2005	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			—			—			1,065
Net Income	—			—		—		—		—			40,343			—			40,343
Balance at December 31, 2006	—			—		60,058,155		6,006		48,093			68,431			(266	)		122,264
Proceeds from stock issuance	—			—		996,669		99		1,023			—			—			1,122
Stock based compensation	—			—		—		—		2,178			—			—			2,178
Purchase of treasury shares	—			—		—		—		—			—			(2,286	)		(2,286	)
Net Income	—			—		—		—		—			19,052			—			19,052
Balance at December 31, 2007	—			—		61,054,824	$	6,105	$	51,294		$	87,483		$	(2,552	)	$	142,330

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,
	2007			2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	19,052		$	40,343		$	29,182
Adjustments to reconcile net income to net cash provided by (used in) operating activities
Depreciation, depletion and amortization		17,952			6,720			5,369
Amortization of debt issuance costs		556			596			159
Dry hole costs		8,053			—			2,415
Stock based compensation		2,178			1,065			—
Minority interest in earnings of subsidiary		4,429			5,174			3,647
Change in operating assets and liabilities:
Trade receivables		(12,158	)		(1,155	)		(1,117	)
Accounts with partners		1,711			(3,285	)		883
Other receivables		(313	)		(99	)		(1,025	)
Crude oil inventory		(367	)		(42	)		206
Materials and supplies		(15	)		(34	)		24
Deferred tax asset		(200	)		—			33
Other long term assets		243			—			—
Prepayments and other		910			(889	)		(1,184	)
Accounts payable and accrued liabilities		1,001			13,370			(2,845	)
Income taxes payable		200			—			(140	)
Net cash provided by operating activities		43,232			61,764			35,607
CASH FLOWS FROM INVESTING ACTIVITIES
Funds in escrow, net		(28	)		(13,657	)		9
Additions to property and equipment		(14,520	)		(33,244	)		(13,347	)
Dry hole costs		(8,053	)		—			(2,415	)
Other—net		—			(473	)		(625	)
Net cash used in investing activities		(22,601	)		(47,374	)		(16,378	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of common stock		1,122			2,541			1,325
Debt issuance costs capitalized		—			(335	)		—
Borrowings		—			5,000			—
Debt repayment		—			(1,500	)		(2,250	)
Purchase of treasury shares		(2,286	)		—			—
Distribution to minority interest		(3,996	)		(2,997	)		(1,998	)
Net cash provided by (used in) financing activities		(5,160	)		2,709			(2,923	)
NET CHANGE IN CASH AND CASH EQUIVALENTS		15,471			17,099			16,306
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		60,979			43,880			27,574
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	76,450		$	60,979		$	43,880
Supplemental disclosure of cash flow information
Income taxes paid	$	50,016		$	30,496		$	31,598
Interest paid	$	523		$	333		$	209
Supplemental disclosure of non cash flow information
Change in investment in property and equipment not paid	$	(3,783	)	$	4,371		$	585
Treasury stock purchase		—			—		$	65
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 and as a non-operator in the British North Sea. 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., VAALCO Energy (USA), Inc. and VAALCO (UK) North Sea, Limited.

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, 2007 and 2006 represent an escrow securing the Company’s seismic obligations for Block 5 in Angola. 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 including 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 records the fair value of a liability for an asset retirement obligation in the period in which it is incurred by capitalizing it as part of the carrying amount of the long-lived assets.

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. 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. Gains and losses on foreign currency transactions are included in income currently. The Company incurred a gain on foreign currency transactions of $105,000 in 2007, $110,000 in 2006, $126,000 in 2005.

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 Payment. 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)

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.

F-8

VAALCO ENERGY, INC AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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.

Fair Value of Financial Instruments—The Company’s financial instruments consist primarily of cash, funds in escrow, trade accounts, 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.

Risks and Uncertainties—The Company’s interests are located overseas in certain onshore and offshore areas in Gabon, offshore in Angola and the British North Sea and in Texas and Louisiana.

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, 2008, the Company sells crude oil under a contract with Shell Western Supply and Trading Limited. In 2007 Addax B.V. and in 2006 Trafigura Beheer B.V., 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 used in the financial statements to estimate depletion expense require extensive judgments and are generally less precise than other estimates made in connection with financial disclosures. 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 amounts from 2006 and 2005 have been reclassified in the statement of cash flows to present cash outflows for certain exploration costs as operating cash flows rather than investing. This reclassification reduced cash provided by operating activities and cash used in investing activities by $2.7 million and $0.3 million in 2006 and 2005, respectively

3. NEW ACCOUNTING PRONOUNCEMENTS

FASB Statement 157, Fair Value Measurements—In September 2006, the FASB issued FASB Statement 157Fair 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 SFAS 157, fair value measurements are disclosed by level within that hierarchy. While SFAS 157 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.

F-9

VAALCO ENERGY, INC AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

• 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.

SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. However, in January 2008, the FASB issued FASB Staff Position (“FSP”) No. FAS 157-b, “Effective Date of FASB Statement No. 157,” which delays the effective date of SFAS 157 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis. SFAS 157 shall be applied prospectively as of the beginning of the fiscal year in which SFAS 157 is initially applied. The Company adopted SFAS 157, as amended by FSP No. 157-b, on January 1, 2008 and does not expect this standard to have a material impact, if any, on its financial statements.

FASB Statement 141(R), Business Combinations, and FASB Statement 160, Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51—In December 2007, the FASB issued FASB Statement 141(R),Business Combinations, which replaced FASB Statement 141,Business Combinations,(“SFAS 141(R)”). In December 2007, the FASB also issued FASB Statement 160,Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51,(“SFAS 160”). These statements significantly change the accounting for business combinations and noncontrolling interests. Among other things, and compared to the predecessor guidance, these statements will require more assets acquired and liabilities assumed to be measured at fair value as of the acquisition date, liabilities related to contingent consideration to be remeasured to fair value each subsequent reporting period, an acquirer in preacquisition periods to expense all acquisition-related costs, and noncontrolling interests in subsidiaries initially to be measured at fair value and classified as a separate component of equity. These statements are to be applied prospectively for fiscal years beginning after December 15, 2008. The Company is evaluating SFAS 141(R) and SFAS 160 to determine the impact of these statements on our consolidated financial statements.

FASB Interpretation 48, Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement 109—The Company adopted Financial Interpretation (“FIN”) No. 48,Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement No. 109(“FIN 48”) on January 1, 2007. 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. The adoption of this interpretation did not have a material impact on the Company’s financial statements. See Note 7—Income Taxes for disclosures required by FIN 48.

FASB Statement 159, The Fair Value Option for Financial Assets and Financial Liabilities—Including an amendment of FASB Statement No. 115—In February 2007, the FASB issued FASB Statement 159,The Fair Value Option for Financial Assets and Financial Liabilities—Including an amendment of FASB Statement No. 115, (“SFAS 159”). SFAS 159 permits companies to choose to measure many financial instruments and certain other items at fair value, with changes in fair value reflected in earnings. SFAS 159 is effective as of the beginning of the first fiscal year that begins after November 15, 2007. The Company adopted SFAS 159 as of January 1, 2008 and did not elect the fair value option for any instruments that were not previously reported at fair value.

F-10

VAALCO ENERGY, INC AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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, 2005. 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 table below provides additional information with respect to the Company’s capitalized exploration drilling costs.

	2007		2006			2005
Beginning balance at January 1	$	—	$	2,607		$	181
Additions to capitalized exploratory drilling costs		—		—			2,426
Capitalized exploratory drilling costs reclassified to property and equipment		—		(2,607	)		—
Capitalized exploratory drilling costs expensed		—		—			—
Ending balance at December 31	$	—	$	—			2,607
Number of wells requiring major capital expenditures where additional drilling efforts are not underway or firmly planned for the near future		—		—			1	(1)
Amount capitalized for wells requiring major capital expenditures where additional drilling efforts are not underway or firmly planned		—		—		$	2,607

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

5. STOCK BASED COMPENSATION

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 which in the past has been a five year life, with the options vesting over a three year period. In addition, stock options will become exercisable upon a change in control, unless provided otherwise by the Compensation Committee. At December 31, 2007 there were 3,121,193 shares subject to options authorized but not granted.

F-11

VAALCO ENERGY, INC AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

For the year ended December 31, 2007 and 2006, the Company recognized non-cash compensation expense of $2.2 million and $1.1 million, respectively. These amounts were recorded as general and administrative expense. Because the Company does not pay significant United States taxes, no amounts were recorded for tax benefits.

A summary of the stock option activity for the year ended December 31, 2007 is provided below:

	Number of Shares Underlying Options (in thousands)		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term	Aggregate Intrinsic Value (in millions)
Outstanding—beginning of period	4,369		$	4.87	3.65
Granted	—			—	—
Exercised	(997	)		1.17	0.15
Forfeited	(121	)		7.50	3.50
Outstanding—end of period	3,251			5.91	3.44	$	1.7
Vested—end of period	2,203		$	4.93	3.20	$	1.7
Vested and expected to vest—end of period	3,136		$	5.84	3.42	$	1.7

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, 2007, unrecognized compensation costs totaled $1.3 million. The expense is expected to be recognized over a weighted average period of 1.0 years.

A summary of the values of options granted, exercised and vested for each of the years ending December 31, 2007, 2006 and 2005 is provided below:

	2007		2006		2005
Options granted—(thousands)		—		1,911		1,657
Weighted average exercise price—($/share)		—	$	7.88	$	3.86
Weighted average grant-date fair value—($/share)		—	$	3.00	$	2.20
Options/warrants exercised (thousands)(1)		997		1,744		6,236
Total intrinsic value of options/warrants exercised—($thousands)	$	3,664	$	10,885	$	23,950
Options vested—(thousands)		914		694		1,964
Total fair value of options vested ($thousands)	$	311	$	1,558	$	1,614

(1) 5,500,000 warrants were exercised in 2005 with an intrinsic value of $20.4 million. There were no warrants outstanding at December 31, 2007, 2006 and 2005

The Company received cash proceeds of $1.1 million from options exercised in 2007.

F-12

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):

Year Ended December 31,	2005
Net income as reported	$	29,182
Deduct: Total stock based employee compensation expense		2,909
Proforma net income	$	26,273
Basic earnings per share
As reported	$	0.56
Pro forma	$	0.51
Diluted earnings per share
As reported	$	0.50
Pro forma	$	0.45

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. The table below summarizes the assumptions used to value the options issued in 2006 and 2005. There were no options issued in 2007.

Year	Options Issued	Volatility Range		Weighted Avg. Volatility		Life Range	Risk Free Interest Range		Expected Dividend Yield
2006	1,911	56	%	56	%	2.5-5 years	4.67-5.5	%	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. Stockholders’ equity consists of common stock and options.

A reconciliation of diluted shares consists of the following:

	Year Ended
Item	December 31, 2007	December 31, 2006	December 31, 2005
Basic weighted average common stock issued and outstanding	59,133,888	58,135,850	51,772,219
Preferred stock convertible to Common stock	—	—	3,817,542
Dilutive warrants	—	—	977,504
Dilutive options	957,034	2,340,023	1,686,170
Total diluted shares	60,090,922	60,475,874	58,253,435

F-13

VAALCO ENERGY, INC AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

A total of 749,213, 125,000 and 100,000 shares under option were not included because they were anti-dilutive during the years ended December 31, 2007, 2006 and 2005 respectively.

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.

In September 2007, the Company’s Board of Directors authorized the purchase up to $20 million of the Company’s common stock. Under the stock buy-back program shares of common stock will be purchased on the open market or through privately negotiated transactions from time-to-time during the 12 month period following the board’s authorization. Under the authorization, the timing and amount of purchases will be based upon market conditions, securities law limitations and other factors. The stock buy-back program does not obligate the Company to acquire any specific number of shares in any period, and may be modified, suspended, extended or discontinued at any time without prior notice. A total of 500,000 shares were acquired during the fourth quarter of 2007 at an average price of $4.57 per share.

On September 14, 2007, the Board of Directors of the Company adopted a Rights Agreement dated as of September 14, 2007 between the Company and the Registrar and Transfer agent of the Company, as Rights Agent. The Plan creates a dividend of one right for each outstanding share of the Company’s Common Stock. The rights are represented by and traded with the Company’s Common Stock. Initially, there will be no separate certificates or market for the rights. The rights do not separate from the Common Stock unless one or both of the following conditions are met: a public announcement that a person has acquired 15% or more of the Common Stock of the Company, or a tender or exchange offer is made which, if completed, would result in the bidder beneficially owning 15% or more of the Common Stock of the Company.

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,
	2007			2006		2005
U.S. federal:
Current	$	(60	)	$	—	$	—
Deferred		(200	)		—		33
Foreign:
Current		48,341			30,496		31,458
Deferred		—			—		—
Total		48,081		$	30,496	$	31,491

F-14

VAALCO ENERGY, INC AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The primary differences between the financial statement and tax bases of assets and liabilities at December 31, 2007 and 2006 are as follows:(In thousands)

	2007			2006
Deferred Tax Assets:
Basis difference in fixed assets	$	3,042		$	1,457
Foreign tax credit carry forwards		6,303			18,682
Alternative minimum tax credit carryover		1,457			1,257
Foreign net operating losses		4,434			—
Asset retirement obligations		2,355			1,955
		17,591			23,351
Valuation allowance		(16,134	)		(22,094	)
Total deferred tax asset	$	1,457		$	1,257

Pretax income (loss) is comprised of the following:

(In thousands)	Year Ended December 31,
	2007		2006		2005
United States	$	125	$	91	$	95
Foreign		71,488		76,164		64,294
	$	71,613	$	76,255	$	64,389

The statutory rate reconciliation is as follows:

(In thousands)	Year Ended December 31,
	2007		2006		2005
Pre-tax income multiplied by 35%	$	25,065	$	26,690	$	22,536
Foreign taxes not offset by U.S. foreign tax credits		23,016		3,806		8,922
Return to provision adjustment		—		—		33
Total income tax	$	48,081	$	30,496	$	31,491

At December 31, 2007, the Company was subject to foreign and United States federal taxes only, with no allocations made to state and local taxes.

The Company adopted the provisions of FIN 48 on January 1, 2007. There was no impact related to the cumulative effect of the change in accounting principle. As of the adoption date, the Company had no unrecognized tax benefits.

The following table summarizes the activity to our unrecognized tax benefits:

(In thousands)
Balance at January 1, 2007	$	—
Increases related to prior year positions		13,201
Balance at December 31, 2007	$	13,201

F-15

VAALCO ENERGY, INC AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The 2007 increases related to prior year positions reduced the Company’s gross deferred tax assets and valuation allowance. If recognized, none of the uncertain tax positions would impact the effective rate because they would be offset by valuation allowance.

Our accounting policy is to recognize interest and penalties accrued related to unrecognized tax benefits in income tax expense. The Company has no accruals for the payment of interest and penalties.

The following table summarizes the tax years that remain subject to examination by major tax jurisdictions:

United States	2003-2006
Gabon	2004-2006

Certain of the Company’s U.S. income tax returns are currently under audit by the Internal Revenue Service. While the amounts ultimately agreed upon in resolution of the issues raised may differ from the recorded amount of unrecognized tax benefits, the Company does not expect the outcome to have a material adverse impact on our financial position, results of operations or cash flows.

8. COMMITMENTS AND CONTINGENCIES

In September 2007, the Company entered into an amendment with the owner of the FPSO chartered for the Etame field to extend the contract until September 2015. In connection with the charter of the FPSO, the Company as operator of the Etame field guaranteed the charter payments through September 2013. 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
2008	$	17,765	$	4,987
2009	$	17,269	$	4,848
2010	$	16,962	$	4,762
2011	$	16,762	$	4,706
2012	$	16,659	$	4,677
Thereafter	$	16,613	$	4,664

The Company has recorded a liability of $0.7 million at December 31, 2007 representing the guarantee’s fair value.

The Company’s share of charter expense, including a $0.25 per bbl charter fee for production up to 20,000 bopd and a $2.50 per bbl charter fee for those bbls produced in excess of 20,000 bopd was $5.7 million, $5.6 million and $5.5 million for the years ending December 31, 2007, 2006 and 2005 respectively.

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

2008	2009	2010	2011	2012	Thereafter	Total
$6,743	$5,145	$333	$179	$179	$15	$12,594

F-16

VAALCO ENERGY, INC AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The Company incurred rent expense of $0.7 million, $0.6 million and $0.7 million under operating leases for the years December 31, 2007, 2006 and 2005, respectively.

In January 2006 the consortium elected to extend the Etame Marin 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 consortium 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 Marin block production divided by the total Gabon production times the volume of oil refined by the refinery per year. In 2007 the Company paid $1.6 million for its share of the 2006 obligation. 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. 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, 2007 is $1.6 million.

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 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 interpreting data from past operators of the area and expects to drill one or two wells in 2008.

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 1,175 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.

In December 2007, the Company signed a farm-in agreement for Block 9/28d offshore the United Kingdom in the British North Sea. The Company is obligated to pay its share of the drilling of one well on the block and a portion of the share of the farminee’s share of the well. The well was spudded in December 2007 and reached total depth in January 2008. The well was suspended as a non-commercial discovery in January 2008. In 2007, the Company incurred $8.0 million in exploration costs associated with the well. An additional $4.0 million is anticipated to be incurred in the first quarter of 2008. The Company is carrying no capitalized amounts on its books for this well.

In January 2008 the Company signed a farm-in agreement for a 25% working interest in Block 48/25c offshore in the British North Sea. The Company is obligated to pay its share of the drilling of one well on the block and a portion of the share of the farminee’s share of the well. The block is located in the Southern Gas

F-17

VAALCO ENERGY, INC AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Basin and an exploration well is expected to be drilled during the third quarter of 2008. It is anticipated that the Company share of costs for this well will be approximately $8.0 million.

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, 2007 and had drawn a balance of $5.0 million on the facility at December 31, 2007.

The facility is available to finance the Ebouri field development activities or other Etame Marin block projects. The facility extends through October 2009 at which point it can be extended, or converted to a term loan at the Company’s option. 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.

Under the loan agreements, the IFC holds a pledge of the Company’s interest in the Etame Marin block, and pledge of the shares of VAALCO Gabon (Etame), Inc. the subsidiary which owns the Company’s interest in the Etame Marin 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, which 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.

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

	2007		2006		2005
Balance January 1,	$	6,029	$	3,615	$	1,330
Accretion Expense		415		210		113
Additions		—		1,807		528
Revisions		284		397		1,644
Balance December 31,	$	6,728	$	6,029	$	3,615

During the year ended December 31, 2007, revisions were due to higher estimated abandonment costs. During the year ended December 31, 2006 the Company increased ARO liabilities by $2.2 million 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 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.

F-18

VAALCO ENERGY, INC AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

As of December 31, 2007 the Company had $40,000 legally restricted for settling asset retirement obligations in the United States.

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). 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 closed the branches and liquidating the subsidiaries during 2007 and incurred final net costs of $51,000 for that year. A summary of discontinued operations for the years ending December 31, 2007, 2006 and 2005 follows.

	Year ended December 31,
	(thousands of dollars)
	2007			2006			2005
Loss from discontinued operations
Revenues from oil sales	$	—		$	—		$	—
Operating costs and expenses:
General and administrative expenses		56			88			55
Total operating costs and expenses		56			88			55
Other revenues (expenses):
Interest income		5			15			—
Other expenses (net)		—			—			(14	)
Loss from discontinued operations before income taxes		(51	)		(73	)		(69	)
Income tax expense (credit)		—			169			—
Loss from discontinued operations	$	(51	)	$	(242	)	$	(69	)

F-19

VAALCO ENERGY, INC AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

12. SEGMENT INFORMATION

The Company’s operations are based in Gabon, Angola, the British North Sea and in the United States. Beginning in 2007 and in particular, during the fourth quarter of 2007 with our entry into the North Sea, the Company began making significant expenditures in its operations outside of Gabon. Management reviews and evaluates the operation of each geographic segment separately. The operations of all segments include exploration for and production of hydrocarbons where commercial reserves have been found and developed. The accounting policies of the reportable segments are the same as in Note 2 to the Consolidated Financial Statements. Revenues are based on the location of hydrocarbon production. The Company evaluates each segment based on income (loss) from operations. Segment activity for the years ending December 31, 2007, 2006 and 2005 are as follows:(in thousands)

	Gabon		Angola			North Sea			Corporate and Other			Total
2007
Revenues	$	124,745	$	—		$	—		$	298		$	125,044
Depreciation, depletion and amortization		17,876		—			—			75			17,952
Income from operations		90,063		(4,775	)		(8,053	)		(8,562	)		68,673
Interest income		2,190		—			—			1,739			3,928
Interest expense		947		—			147			—			1,094
Income taxes		48,341		—			—			(260	)		48,081
Additions to properties and equipment		10,926		24			—			55			11,004
Long lived assets		53,207		10,688			—			98			63,993
Total assets		119,600		11,149			—			55,809			186,558
2006
Revenues		98,170		—			—			155			98,325
Depreciation, depletion and amortization		6,429		219			—			72			6,720
Income from operations		80,771		(865	)		—			(5,576	)		74,330
Interest income		2,063		—			—			924			2,987
Interest expense		1,026		—			—			—			1,026
Income taxes		30,496		—			—			—			30,496
Additions to (disposals of) properties and equipment		28,911		10,829			—			(188	)		39,552
Long lived assets		59,725		10,664			—			118			70,507
Total assets		124,223		10,829			—			32,890			167,942
2005
Revenues		84,700		—			—			235			84,935
Depreciation, depletion and amortization		5,212		—			—			157			5,369
Income from operations		67,271		—			—			(3,694	)		63,577
Interest income		908		—			—			191			1,099
Interest expense		418		—			—			—			418
Income taxes		31,458		—			—			33			31,491
Additions to (disposals of) properties and equipment		16,139		—			—			(34	)		16,105
Long lived assets		37,021		—			—			177			37,198
Total assets		104,175		—			—			(6,013	)		98,162

F-20

VAALCO ENERGY, INC AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

13. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

The following represents our unaudited quarterly results for years ended December 31, 2007 and 2006. 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
2007
Total revenues	$	29,131		$	24,128		$	34,828		$	36,957
Total operating costs and expenses		16,830			8,940			11,071			19,529
Operating Income		12,301			15,188			23,757			17,428
Income from continuing operations		5,785			4,323			10,002			3,422
Minority interest		(1,203	)		(582	)		(1,206	)		(1,438	)
Income (loss) on discontinued operations		(27	)		(24	)		—			—
Net income	$	4,555		$	3,717		$	8,796		$	1,985
Basic income per share from continuing operations before discontinued operations	$	0.08		$	0.06		$	0.15		$	0.03
Income (loss) from discontinued operations		—			—			—			—
Basic income per common share	$	0.08		$	0.06		$	0.15		$	0.03
Diluted income per share from continuing operations before discontinued operations	$	0.08		$	0.06		$	0.15		$	0.03
Income (loss) from discontinued operations		—			—			—			—
Diluted income per common share	$	0.08		$	0.06		$	0.15		$	0.03
2006
Total revenues	$	31,237		$	25,575		$	25,640		$	15,873
Total operating costs and expenses		6,110			5,546			5,352			6,985
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

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-21

VAALCO ENERGY, INC AND SUBSIDIARIES

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING PROPERTIES

(Unaudited)

14. 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
	2007		2006		2005
Costs incurred during the year:
Exploration—capitalized	$	—	$	—	$	—
Exploration—expensed		—		—		—
Development		—		1		1
Total	$	—	$	1	$	1
(In thousands)	International
	2007		2006		2005
Costs incurred during the year:
Exploration—capitalized	$	—	$	11,138	$	25
Exploration—expensed		15,340		2,672		2,709
Development		14,520		24,520		15,519
Total	$	29,860	$	38,330	$	18,253

No costs were incurred for acquisitions, exploration and development activities associated with the discontinued operation in the Philippines in 2007, 2006, and 2005. Exploration expense includes $8.1 million and $2.4 million for dry hole expense in 2007 and 2005, respectively. No amounts of exploration costs were for dry hole expense in 2006.

Capitalized Costs Relating to Oil and Gas Producing Activities:

(In thousands)	December 31, 2007			December 31, 2006			December 31, 2005
Capitalized costs—
Properties not being amortized	$	24,663		$	16,561		$	10,832
Properties being amortized(1)		80,052			77,557			43,805
Total capitalized costs		104,715			94,118			54,637
Less accumulated depreciation, depletion, and amortization		(42,984	)		(25,465	)		(19,222	)
Net capitalized costs	$	61,731		$	68,653		$	35,415

(1) Includes $5.8 million, $5.5 million and $3.5 million asset retirement cost in 2007, 2006 and 2005 respectively.

F-22

VAALCO ENERGY, INC AND SUBSIDIARIES

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES

(Unaudited)

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

Results of Operations for Oil and Gas Producing Activities:

(In thousands)	United States									International
	2007			2006			2005			2007			2006			2005
										Gabon			Gabon			Gabon
Crude oil and gas sales	$	298		$	155		$	236		$	124,745		$	98,170		$	84,700
Production expense		(118	)		(89	)		(97	)		(14,175	)		(12,128	)		(10,485	)
Exploration expense					—			—			(1,349	)		(1,128	)		(2,631	)
Depreciation, depletion and Amortization		(56	)		(36	)		(44	)		(17,876	)		(6,149	)		(5,212	)
Income (loss) before taxes		124			30			95			91,345			78,765			66,372
Income tax (provision)		43			11			33			48,038			30,496			31,458
Results from oil and gas producing activities	$	81		$	19		$	62		$	43,307		$	48,269		$	34,914

Proved Reserves

A reserve report as of December 31, 2007 has been prepared by Netherland Sewell & Associates, independent petroleum engineers. The following tables set forth the net proved reserves of the Company as of December 31, 2007, 2006 and 2005, and the changes during such periods.

	Oil (MBbls)		Gas (MMcf)
PROVED RESERVES:
BALANCE AT JANUARY 1, 2005	8,734		54
Production	(1,635	)	(17	)
Revisions of previous estimates	728		(16	)
BALANCE AT DECEMBER 31, 2005	7,827		21
Production	(1,552	)	(11	)
Revisions of previous estimates	(1,585	)	7
Extensions and discoveries	1,306		—
BALANCE AT DECEMBER 31, 2006	5,996		17
Production	(1,756	)	(20	)
Revisions of previous estimates	1,979		64
BALANCE AT DECEMBER 31, 2007	6,214		61
	Oil (MBbls)		Gas (MMcf)
PROVED DEVELOPED RESERVES
Balance at December 31, 2004	4,738		54
Balance at December 31, 2005	6,620		21
Balance at December 31, 2006	4,691		17
Balance at December 31, 2007	4,506		61

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.

F-23

VAALCO ENERGY, INC AND SUBSIDIARIES

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES

(Unaudited)

Revisions in 2005 were associated with better reservoir performance at the Etame field and poorer gas well production performance at the Texas properties. Revisions in 2006 were associated primarily with the Etame field as higher operating costs led to a shorter projected economic life. The shorter economic life also resulted in lower projected production costs over the life of the property in 2006 versus 2005. Revisions in 2007 were associated with Etame, South Tchibala and Avouma reservoir performance, changes in oil prices, operating costs and taxes. Higher projected oil prices resulted in upward revision in reserves, but were partially offset by higher taxes. Total remaining operating costs for the fields declined due to shorter remaining field life after another year’s production.

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.

For the Ebouri discovery the Company received approval of the development plan from the Gabon government in 2006 and booked approximately 800,000 bbls to discoveries of proven undeveloped reserves for the Ebouri field as of December 31, 2006 and 500,000 bbls of extensions to the Etame field.

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 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 $8.9 million attributable to future abandonment when the wells become uneconomic to produce.

(In thousands)	United States									International									Total
	December 31,									December 31,									December 31,
	2007			2006			2005			2007			2006			2005			2007			2006			2005
										Gabon			Gabon			Gabon
Future cash inflows	$	1,146		$	374		$	533		$	592,053		$	341,930		$	444,249		$	593,199		$	342,304		$	444,782
Future production costs		(405	)		(203	)		(204	)		(68,589	)		(81,121	)		(121,531	)		(68,994	)		(81,324	)		(121,735	)
Future development costs		—			—			—			(41,954	)		(37,575	)		(30,927	)		(41,954	)		(37,575	)		(30,927	)
Future income tax expense		(101	)		(32	)		(48	)		(252,111	)		(59,518	)		(76,467	)		(252,212	)		(59,550	)		(76,515	)
Future net cash flows		640			139			281			229,399			163,716			215,324			230,039			163,855			215,605
Discount to present value at 10% annual rate		(157	)		(20	)		(82	)		(38,213	)		(30,233	)		(54,314	)		(38,370	)		(30,253	)		(54,396	)
Standardized measure of discounted future net cash flows	$	483		$	119		$	199		$	191,186		$	133,483		$	161,010		$	191,669		$	133,602		$	161,209

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.

F-24

VAALCO ENERGY, INC AND SUBSIDIARIES

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES

(Unaudited)

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,
	2007			2006			2005
BALANCE AT BEGINNING OF PERIOD	$	133,602		$	161,209		$	123,321
Sales of oil and gas, net of production costs		(108,964	)		(86,108	)		(74,321	)
Net changes in prices and production costs		228,256			1,254			87,991
Revisions of previous quantity estimates		86,014			(51,797	)		24,780
Additions		—			52,320			—
Changes in estimated future development costs		(21,815	)		(8,124	)		(4,358	)
Development costs incurred during the period		14,520			22,106			11,852
Accretion of discount		13,360			16,141			12,332
Net change in income taxes		(161,616	)		8,585			(14,506	)
Change in production rates (timing) and other		8,312			18,022			(5,882	)
BALANCE AT END OF PERIOD	$	191,669		$	133,602		$	161,209

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 $94.96 per bbl. In the United States, the price was $90.97 per bbl of oil and $7.26 per Mcf of gas.

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.

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, 2007, there was $11.7 million in the cost account ($3.5 million net to the Company). As payment of corporate income

F-25

VAALCO ENERGY, INC AND SUBSIDIARIES

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES

(Unaudited)

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. In 2007, the company cost recovered 418,000 bbls for ongoing operating expenses and capital expenditures out of a theoretical maximum of 1,220,000 which would have been recoverable if the Cost Account was full. The lower number of bbls cost recovered in 2007 versus 2006 was primarily due to lower capital expenditures in 2007. Also because of the nature of the Cost Account, increases in oil prices result in a lesser number of bbls required to recover costs, therefore at higher oil prices, the Company’s net reserves after taxes would decrease. The Company also paid $22.1 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 Marin 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 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 bbl 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.

F-26