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Article by DailyStocks_admin    (03-19-08 04:27 AM)

The Daily Magic Formula Stock for 03/19/2008 is Vaalco Energy Inc. According to the Magic Formula Investing Web Site, the ebit yield is 30% and the EBIT ROIC is 75-100 %.

Dailystocks.com only deals with facts, not biased journalism. What is a better way than to go to the SEC Filings? It's not exciting reading, but it makes you money. We cut and paste the important information from SEC filings for you to get started on your research on a specific company.


Dailystocks.com makes NO RECOMMENDATIONS whatsoever, and provides this for informational purpose only.

BUSINESS OVERVIEW

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.

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.

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 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, 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.

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.

CEO BACKGROUND
Robert H. Allen – Mr. Allen is the managing partner of Challenge Investment Partners, which is active in mining ventures in Canada, Greenland, Mexico, South America and Indonesia. He is a certified public accountant and a member of the Texas Society of CPA’s. He is the past Chairman, Chief Executive Officer and a Director of Gulf Resources and Chemical Corporation from which he retired in 1982. He has served on many boards including Gulf Indonesia Resources Ltd., Federal Express Corporation, and Gulf Canada Resources Ltd. He served as Chairman of the Board of Gulf Indonesia Resources Ltd. and The University of Texas Investment Management Company. He is Regent Emeritus of Texas A&M University. Mr. Allen received his B.B.A. degree in 1951 from Texas A&M University.

Luigi P. Caflisch - Mr. Caflisch was appointed to the Board on April 6, 2005. Mr. Caflisch holds a Doctorate Degree in Geology. Prior to his retirement, he spent 48 years in the Petroleum industry including 31 years with Gulf Oil and Chevron where his attention for many years was focused on hydrocarbon exploration on the African Continent. He served in Algeria, Libya, Nigeria, Angola, Gabon and Cabinda before being elevated to Chevron’s management team where he shared responsibilities for directing the Chevron’s entire worldwide upstream operations. Mr. Caflisch holds a Doctorate Degree with Honors in Geology and Geophysics from the University of Milan.

O. Donaldson Chapoton - Mr. Chapoton was appointed to the Board on February 15, 2006. He joined Baker Botts, LLP in the early 1960’s specializing in tax law. Mr. Chapoton served as Assistant Secretary for Tax Policy at the U.S. Treasury Department from 1986 to 1989.

He rejoined Baker Botts, LLP as the partner-in-charge of the firm’s Washington office in 1989 and served in that position through 2000. In 2001, Mr. Chapoton became involved in real estate activities and is currently a partner in the VMS Group, a firm which provides services to the private equity community. Mr. Chapoton received his LL.B., with honors, from The University of Texas School of Law.

William S. Farish – Mr. Farish was appointed to the Board on November 28, 2004. Mr. Farish has been President of W. S. Farish and Company, an investment firm in Houston, Texas and is the owner of Lane’s End Farms, a thoroughbred breeding facility in Versailles, Kentucky. He is also former Chairman of Churchill Downs, Inc. Mr. Farish served as the United States Ambassador to the Court of St. James from 2001 until mid 2004.

Robert L. Gerry III - Mr. Gerry has been our Chairman of the Board and Chief Executive Officer since August 1997. Prior to August 1997, Mr. Gerry had been Vice-Chairman of Nuevo Energy Company (“Nuevo”) since February 1994. Prior to being appointed Vice-Chairman of Nuevo, Mr. Gerry had served as President and Chief Operating Office of Nuevo since its formation in March 1990. Mr. Gerry had been Senior Vice President of Energy Assets International Corporation (“EAIC”) since January 1989. For ten years prior to joining EAIC, Mr. Gerry was active as an independent investor concentrating on energy investments. He served on the Board of Directors of Nuevo from 1990 through 2004 and was appointed as a member of Plains Exploration and Production Company Board of Directors in 2004. He has serves as a Trustee of Texas Children’s Hospital for 15 years.

Arne R. Nielsen - Mr. Nielsen has been a Director of ours since March 1989. He is currently the Chairman of the Board of Directors of Shiningbank Energy Income Fund. He served as the Chairman of the Board of Serenpet, Inc. from April 1995 through July 1996, President, Chief Executive Officer and Chairman of the Board of Poco Petroleums Ltd. from January 1992 through May 1994, and President and Chief Executive Officer of Bowtex Energy (Canada) Corporation from July 1990 through January 1992. Mr. Nielsen also served as the Chairman of the Board and Chief Executive Officer of Mobil Oil Canada from April 1986 to January 1989.

W. Russell Scheirman - Mr. Scheirman has served as our President since 1992, and as our Chief Financial Officer and a director since 1991. From 1991 to 1992, Mr. Scheirman was our Executive Vice President. He was an associate at McKinsey & Company, Inc. from 1989 to 1991, an investment banker with Copeland, Wickersham and Wiley from 1984 to 1989, and a Petroleum Reservoir Engineer for Exxon Company, U.S.A. from 1978 to 1984. Mr. Scheirman holds a B.S. (summa cum laude) and M.S. in Mechanical Engineering from Duke University (1977 and 1978, respectively) and an M.B.A. from California Lutheran University (1984).

Mr. Nielsen is a Canadian citizen. All other officers and directors of VAALCO are United States citizens.

COMPENSATION

Base Salary . At its regularly scheduled meeting, the committee meets to review the base salaries of the company’s executive officers. During the first portion of the meeting, the committee reviews the compensation of the chief executive officer, and the chief executive officer is not present. Following this private session, the chief executive officer joins the meeting, and base salary levels of the company’s other executive officers are discussed with his input.

In setting base salaries, the committee takes into account a combination of subjective factors as well as data available from objective, professionally-conducted market studies obtained from a range of industry and general market sources. We generally target base salaries to be competitive with the salaries compared to CEOs and executive officers of comparable companies. Subjective factors the committee considers include individual achievements, the company’s performance, level of responsibility, experience, leadership abilities, increases or changes in duties and responsibilities and contributions to the company’s performance. For 2006, we increased base salaries for certain officers, including the CEO, in order to make salaries competitive with those of independent oil and gas companies with international operations.

Bonus . The company has established a program whereby executive officers, senior management and other non-management personnel have the potential to receive a meaningful cash bonus if annual financial and operational objectives or goals, pre-established by the compensation committee, are met.

At a regularly scheduled meeting, usually prior to the end of the year, the company’s board of directors approves the operating budget and financial forecast for the ensuing fiscal year. Based on the budget and forecast, the Compensation Committee sets various target for measures such as oil and gas production levels, operating expenses, pre-tax net income and cash flows from operations. In addition, non-financial targets are established such as exploration prospects to be generated, safety goals, accounting systems implementation and environmental regulations compliance goals.

A significant portion of each executive’s total compensation is dependent on achieving both the short and long term financial and strategic goals outlined above. Accordingly, at the end of each fiscal year, incentive bonuses, if any, will be awarded to the chairman of the board and chief executive officer and to the president and chief financial officer. In determining the incentive bonuses earned, the committee gives substantial weight to the company’s achievement of the goals and objectives set out in the company’s budget for the preceding year. The committee may also consider matters other than those set out in the schedule of goals and objectives in the budget such as stock performance for the previous budget year, indicated return on stockholders’ investment, corporate debt levels, revenues, change in oil and gas reserves, cash flow, capital expenditures and other items that are considered to be critical to our success, including safety performance and environmental performance. We do not assign these measures relative weights preferring to make a subjective determination after considering all measures collectively. The committee must find that the executive’s performance met or exceeded stated goals and objectives set out in the previous year’s annual budget. As an example, should the performance level be determined at 80%, then the incentive bonus would be 80% of base salary. In order for there to be an incentive bonus payment, performance has to meet or exceed 75%. Should the committee determine that the minimum standard of 75% has not been met, it may recommend that the board of directors consider payment of discretionary bonuses for the executive officers. Only with committee recommendations and board approval can the annual incentive bonus pay-out exceed 100% of each executive’s base salary.

In addition to the above, incentive bonuses may be paid to other employees as determined by the chairman and chief executive officer and president and chief financial officer. All incentive bonuses exceeding 100% of base salary must be approved by the Compensation Committee.

In 2006, the Compensation Committee decided to eliminate year-end bonuses and to award bonuses for prior year results at the end of the first quarter of the following year, when actual results for the entire year are known. Accordingly, no bonus amounts were incurred in 2006. In its discretion, the Compensation Committee decided to award bonuses in March of 2007 for fiscal 2006 results based upon our achievement of the following performance goals:


•

Achievement of oil and gas production targets
•

Achievement of Direct Operating Cost budget
•

Stewartship of the General and Administrative expense budget
•

Installation of the Avouma/South Tchibala platform in Gabon
•

Approval of the Ebouri Development Plan in Gabon
•

Exploration Department goals including goal to obtain at least one new major exploration concession
•

Implementation of Sarbanes Oxley controls and successful first audit
•

Safety and Environmental program goals

We provide executives the opportunity to defer receipt of earned annual incentives.

Long-Term Equity-Based Incentives . The Compensation Committee and/or our Board of Directors act as the manager of our incentive plans and perform functions that include selecting award recipients, determining the timing of grants and assigning the number of shares subject to each award, fixing the time and manner in which awards are exercisable, setting exercise prices and vesting and expiration dates, and from time to time adopting rules and regulations for carrying out the purposes of our plans. For compensation decisions regarding the grant of equity compensation to executive officers, our Compensation Committee typically considers recommendations from our chief executive officer. Typically, awards vest over multiple years but the committee maintains the discretionary authority to vest the equity grant immediately if the individual situation merits. In the event of a change of control, or upon the death, disability, retirement or termination of a grantee’s employment without good reason, all outstanding equity-based awards will immediately vest.

We have no set formula for granting awards to our executives or employees. In determining whether to grant awards and the amount of any awards, we take into consideration discretionary factors such as the individual’s current and expected future performance, level of responsibilities, retention considerations, and the total compensation package. Previous awards, whether vested or unvested, impact current year awards and grants.

In December 2006, the Compensation Committee approved the award of an aggregate of 1,810,500 options to purchase common stock were awarded to the company’s officers and employees, representing 3.1% of the outstanding common shares on the date of grant. A total of 19 employees and key consultants, and 5 non-employee directors received stock option awards, including the three named executive officers, who received an aggregate of 829,500 stock options or 45.8% of the total stock options granted in fiscal 2006. All stock options granted vest in three equal parts at twelve month intervals, with the first portion vesting one year after award, and are subject to forfeiture in the event of termination of employment (other than a termination not for good reason).

Benefits . We provide company benefits, or perquisites, that we believe are standard in the industry to all of our employees. These benefits consist of a group medical and dental insurance program for employees and their qualified dependents and a 401-K employee savings and protection plan. The costs of these benefits are paid for entirely by the company. The company does not provide employee life insurance amounts surpassing the Internal Revenue Service maximum. The company does not make matching contributions to the 401-K contribution of each qualified participant. The company pays all administrative costs to maintain the plan.

MANAGEMENT DISCUSSION FROM LATEST 10K

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 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.

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 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.

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.

MANAGEMENT DISCUSSION FOR LATEST QUARTER

RESULTS OF OPERATIONS

Three months ended September 30, 2007 compared to three months ended September 30, 2006

Revenues

Total revenues were $34.8 million for the three months ended September 30, 2007 compared to $25.6 million for the comparable period in 2006. The Company sold approximately 472,000 net barrels of oil equivalent at an average price of $73.79 in three months ended September 30, 2007. In the three months ended September 30, 2006, the Company sold approximately 391,000 net barrels of oil equivalent at an average price of $65.50 per barrel. Crude oil production from the Etame, Avouma and South Tchibala fields averaged approximately 20,000 barrels oil per day (“BOPD”) during the three months ended September 30, 2007 compared to approximately 16,800 BOPD in the three months ended September 30, 2006. Crude oil sales are a function of the number and size of crude oil liftings in each quarter from the FPSO and thus crude oil sales do not always coincide with volumes produced in any given quarter.

Operating Costs and Expenses

Total production expenses for the three months ended September 30, 2007 were $3.8 million compared to $3.1 million in the three months ended September 30, 2006. The Company matches production expenses with crude oil sales. Any production expenses associated with unsold crude oil inventory are capitalized. Expenses in the three months ended September 30, 2007 were higher than in the three months ended September 30, 2006 due in part to higher volumes sold, higher insurance costs, higher boat rental and boat fuel costs, and higher FPSO costs.

Exploration expense was $0.7 million for the three months ended September 30, 2007 compared to $0.5 million in the comparable period in 2006. Exploration expense for the three months ended September 30, 2007 were for processing seismic data in Gabon and acquiring 2-D seismic data in Angola. In the three months ended September 30, 2006, exploration expense consisted of approximately $0.3 million associated with North Sea exploration activities and $0.2 million for exploration activities on the Mutamba Iroru block onshore Gabon.

Depreciation, depletion and amortization expenses were $4.8 million in the three months ended September 30, 2007 compared to $1.8 million in the three months ended September 30, 2006. The higher depreciation, depletion and amortization expenses during the three months ended September 30, 2007 compared to the three months ended September 30, 2006 was due to amounts included in depletable assets for the Avouma and South Tchibala fields, which are higher on a per barrel basis than for the Etame field.

General and administrative expenses for the three months ended September 30, 2007 were $1.8 million. The Company did not incur general and administrative expenses for the three months ended September 30, 2006. During the three months ended September 30, 2007 and September 30, 2006, the Company incurred stock based compensation expense of $0.6 million and $0.3 million, respectively. In both of the three months ended September 30, 2007 and 2006, the Company benefited from overhead reimbursement associated with production and development operations on the Etame Block. Due to high capital costs for the installation of the Avouma platform in the three months ended September 30, 2006 the overhead reimbursements were particularly high for that quarter.

Other Income (Expense)

Interest income received on amounts on deposit was $1.0 million in the three months ended September 30, 2007 compared to $0.9 million in the three months ended September 30, 2006. The increase in interest income received on amounts on deposit reflects higher cash balances and higher interest rates in 2007. Interest expense and financing charges for the IFC loan was $26,000 for the three months ended September 30, 2007 compared to $0.3 million for the three months ended September 30, 2006. In the three months ended September 30, 2006, the Company had higher interest on amounts drawn on the IFC revolving credit facility and higher loan commitment fees.

Income Taxes

Income taxes amounted to $14.7 million and $6.3 million for the three months ended September 30, 2007 and 2006, respectively. In the three months ended September 30, 2007 and in the three months ended September 30, 2006, the income taxes were all paid in Gabon. Income taxes in the three months ended September 30, 2007 were higher than in the three months ended September 30, 2006 due to lower capital spending compared to the three months ended September 30, 2006, resulting in lower amounts costs recovered in Gabon and therefore higher profit oil tax payments. In particular, the Company incurred $9.8 million in capital costs related to the installation of the Avouma platform during the three months ended September 30, 2006 and such costs reduced income taxes.

Discontinued Operations

Income from discontinued operations in the Philippines was $0.5 million in the three months ended September 30, 2006 due to a reversal of a $0.5 million tax accrual after a settlement was reached on branch profit remittance tax assessments in the Philippines. Discontinued operations activity ceased at the end of the second quarter of 2007 so there were no costs associated with discontinued operations in the three months ended September 30, 2007.

Minority Interest

The Company incurred $1.2 million and $1.6 million in minority interest charges in the three months ended September 30, 2007 and 2006, respectively. These minority interest charges were associated with VAALCO Energy (International), Inc., a subsidiary that is 90.01% owned by the Company.

Net Income

Net income for the three months ended September 30, 2007 was $8.8 million, compared to net income of $13.6 million for the same period in 2006. Higher income taxes was the primary reason for the lower net income for the three months ended September 30, 2007, although higher production costs, depreciation, depletion and amortization costs and general and administrative costs also contributed to the lower net income in 2007.

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