VAALCO ENERGY INC /DE/ - Quarter Report: 2012 September (Form 10-Q)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

For the quarterly period ended September 30, 2012

For the transition period from              to             

Commission file number 1-32167

VAALCO Energy, Inc.

(Exact name of registrant as specified in its charter)

(713) 623-0801

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the past 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x     No  ¨.

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ¨     No  ¨.

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.

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

As of October 31, 2012, there were outstanding 57,845,800 shares of common stock, $0.10 par value per share, of the registrant.

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CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

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

See notes to unaudited condensed consolidated financial statements.

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CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS

(unaudited)

(in thousands of dollars, except per share amounts)

See notes to unaudited condensed consolidated financial statements.

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CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(unaudited)

(in thousands of dollars)

See notes to unaudited condensed consolidated financial statements.

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CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Unaudited)

(in thousands of dollars)

See notes to unaudited condensed consolidated financial statements.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The condensed consolidated financial statements of VAALCO Energy, Inc. and subsidiaries (collectively, “VAALCO” or the “Company”), included herein are unaudited, but include all adjustments consisting of normal recurring accruals which the Company deems necessary for a fair presentation of its financial position, results of operations and cash flows for the interim period. Such results are not necessarily indicative of results to be expected for the full year. These financial statements should be read in conjunction with the financial statements and notes thereto included in the Company’s Form 10-K for the year ended December 31, 2011, which also contains a summary of the significant accounting policies followed by the Company in the preparation of its consolidated financial statements. These policies were also followed in preparing the quarterly report included herein. The Company follows the successful efforts method of accounting for oil and gas exploration and development costs.

VAALCO 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 internationally in Gabon and Angola and domestically in Montana, South Dakota and Texas. The Company operates oil production sharing contracts in Gabon and Angola. In the United States the Company operates properties in the Granite Wash formation in Texas, the Bakken/Three Forks formation in Montana and the Red River formation in South Dakota. Additionally, the Company has minor interests in Brazos County, Texas producing from the Buda/Georgetown formations. The Company also owns certain minor non-operated interests in the Ship Shoal area of the Gulf of Mexico and in Pickens County, Alabama.

VAALCO’s subsidiaries include VAALCO Gabon (Etame), Inc., VAALCO Production (Gabon), Inc., VAALCO Angola (Kwanza), Inc., VAALCO UK (North Sea), Ltd., and VAALCO Energy (USA), Inc, and VAALCO Energy (EG), Inc.

The Company has evaluated subsequent events through November 8, 2012, the date the financial statements were issued. Refer to Note 7 of the Company’s consolidated financial statements for reportable subsequent events.

Basic earnings per share (“EPS”) is calculated using the average number of shares of common stock outstanding during each period. Diluted EPS assumes the exercise of all stock options having exercise prices less than the average market price of the common stock using the treasury stock method.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Diluted shares consist of the following:

Options to purchase 1,018,900 and 1,018,900 shares were excluded in the three months and nine months ended September 30, 2012, respectively, because they would have been anti-dilutive. Options to purchase 2,490,004 and 2,490,004 shares were excluded in the three months and nine months ended September 30, 2011, respectively, because they would have been anti-dilutive.

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. A portion of the stock options granted in March 2012 and 2011 were vested immediately with the others vesting over a two year period. In addition, stock options will become exercisable upon a change in control, unless provided otherwise by the Compensation Committee. At September 30, 2012, there were 3,363,446 shares subject to options authorized but not granted.

For the three months and nine months ended September 30, 2012, the Company recognized non-cash compensation expense of $0.4 million and $2.1 million, respectively, related to stock options. For the three months and nine months ended September 30, 2011, the Company recognized non-cash compensation expense of $0.3 million and $1.9 million, respectively related to stock options. These amounts were recorded as general and administrative expense. Because the Company does not pay significant United States federal income taxes, no amounts were recorded for tax benefits related to excess stock based compensation deductions.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

A summary of the stock option activity for the nine months ended September 30, 2012 is provided below:

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 September 30, 2012, unrecognized compensation costs totaled $1.3 million. The expense is expected to be recognized over a weighted average period of 1.2 years. Stock options vested during the nine months ended September 30, 2012 totaled 1.1 million options.

Offshore Gabon

The Company entered into a sixth exploration period extension during November 2009 and is required to spend $5.3 million for its share of two exploration wells and to acquire and process 150 square kilometers of 3-D seismic on the Etame Marin block by July 2014. One of the two exploration commitment wells was drilled in 2010 on the Omangou prospect at a cost of $8.6 million ($2.6 million net to the Company). The seismic obligation was met with the acquisition of 223 square kilometers of 3-D seismic in 2011. The remaining obligation is the drilling of one exploration well by July 2014, which is expected to be drilled in 2013.

As part of securing the second ten year production license with the government of Gabon, the Company agreed, in January 2012, to a cash funding arrangement for the eventual abandonment of the offshore wells, platforms and facilities. The agreement calls for annual funding for the next seven years at 12.14% of the total abandonment estimate per year and 5.0% per year for the last three years of the production license. The amounts paid will be reimbursed through the cost account. The funding is expected to begin in the fourth quarter of 2012 after the final details are agreed with the government of Gabon. The abandonment costs for this purpose are estimated to be approximately $9.6 million net to the Company on a discounted basis. The obligation for abandonment expenses related to the Gabon offshore facilities is included in the asset retirement obligation shown on the Company’s balance sheet. The Company also agreed to a fixed royalty rate of 13% effective July 17, 2011, replacing the sliding scale royalty provided for in the production sharing contract.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

In July 2012, the Company shut-in two of its three producing wells in the Ebouri field as a precaution after detecting the presence of hydrogen sulfide (H2S) on the Ebouri platform. The contamination is isolated to two wells in the Ebouri field and the Company continues to maintain production from the rest of the Etame complex including one well at Ebouri at approximately 19,000 barrels per day. Investigations are underway to ascertain the root cause of the H2S and develop a plan to produce the remaining reserves in a timely manner. Although the investigative work and recommendations were not complete by the end of the third quarter of 2012, it appears that additional capital investment will be required to produce the impacted reserves. The additional capital investment required may include re-working the wells with upgraded metallurgy, including well head replacement, and installing H2S processing equipment on the platform. The amount of such investment is not estimable at this time.

Onshore Gabon

In October 2010, the Company signed a second exploration period extension for the Mutamba Iroru block which was to expire in May 2012. The Company was obligated to reprocess 400 square kilometers of 2D seismic and drill one exploration well. An agreement with Total Gabon (“Total”) was completed in August 2010, which established a joint operation on the block whereby Total acquired a 50% working interest in the block effective November 1, 2010. The terms of the agreement provided for Total paying 75% of the seismic reprocessing costs and the exploration well drilling costs. The seismic reprocessing has been completed. The Company commenced drilling of the exploration well in late September 2012, which satisfies the drilling obligation.

In April 2012, the Company signed a third exploration period extension for the Mutamba Iroru block, which expires at the end of February 2013. In addition, the latest extension requires the Company to reprocess an additional 350 kilometers of 2-D seismic by the end of February 2013. The additional seismic reprocessing required by the third extension is underway and expected to be completed in the fourth quarter of 2012 with the cost being equally split between the Company and Total.

Angola

In November 2006, the Company signed a production sharing contract for Block 5 offshore Angola. The four year primary term with an optional three year extension awarded the Company exploration rights to 1.4 million acres offshore central Angola. The Company’s working interest 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 was required to acquire and process 1,000 square kilometers of 3-D seismic data, drill two exploration wells and expend a minimum of $29.5 million ($14.8 million net to the Company). The Company fulfilled its seismic obligation when it acquired 1,175 square kilometers of 3-D seismic data at a cost of $7.5 million ($3.75 million net to the Company) in January 2007 and 524 square kilometers of 3-D seismic data during the fourth quarter of 2008 at a cost of $6.0 million ($3.0 million net to the Company).

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The government-assigned working interest partner was delinquent paying their share of the costs several times in 2009 and consequently was placed in a default position. By a governmental decree dated December 1, 2010, the former partner was removed from the production sharing contract, and a one year time extension was granted for drilling the two exploration commitment wells. Following the decree, the Company and the government of Angola have been working together to obtain a replacement partner. In early 2012, the Angolan government granted a further one year extension to November 30, 2012 for drilling the two exploration commitment wells in accordance with the production sharing contract. In July 2012, the Angolan government granted an additional two year extension until November 30, 2014 to drill the two exploration commitment wells.

In the first quarter of 2012, the Company provided the Angolan government with a written offer that would allow the Company to proceed with exploration activities without obtaining a new partner, subject to certain criteria including changes to the work commitment and working interest percentages. In the second quarter of 2012, the Company identified a potential partner to acquire the available 40% working interest and submitted the name of the interested party to the Angolan government for approval. In November 2012, the government advised the Company that it has entered into negotiations with the potential partner. The company is unable to estimate when or how the negotiations will conclude with the potential partner or determine what the Angolan government’s response will be to our written offer.

The remaining obligation is a two well exploration commitment. Each well is subject to a $5.0 million penalty ($10.0 million in aggregate for both wells) if not drilled during the contract term. The $10.0 million is currently recorded as restricted cash and is held at a financial institution located in the United States.

Because of the continuing uncertainty with the Angolan government approving a replacement partner, the Company has recorded a full allowance totaling $5.4 million as of September 30, 2012, against the accounts receivable from partners for the amounts owed to the Company above its 40% working interest plus the 10% carried interest. The allowance recorded in the nine months ended September 30, 2012 totaled $1.0 million with the remainder having been recorded in 2011. The Company expects the reserved amounts will be paid to the Company if a new partner in the block is approved.

United States – Roosevelt County, Montana

In September 2011, the Company acquired a 65% working interest in approximately 22,000 gross acres (14,300 net acres) in the East Poplar Dome field in Roosevelt County, Montana. The primary objective for this field is the Bakken/Three Forks formation. Pursuant to the terms of the acquisition, the Company is required to drill three wells at its sole cost, one of which must have been drilled by June 1, 2012, with the remaining two wells by the end of 2012. A vertical exploration well, which met the time requirement for drilling the first well, was completed in June 2012 after discovering oil shows in the Bakken/Three Forks formation. However, the well did not initially discover commercial quantities of hydrocarbons in the formations below the Bakken/Three Forks formation and has been temporarily suspended to consider further stimulation and completion options. The Company recorded dry hole expense of $2.9 million in the second quarter of 2012 for drilling costs associated with the deeper formations. A second well, EPU-133, was spudded in June 2012, and was hydraulically fractured. This well is being considered for installation of electrical submersible pumps (“ESPs”) in an effort to establish production during the fourth quarter of 2012. Using ESPs to obtain production has been successfully utilized on other wells in this area. The Company plans to drill the third obligation well during the fourth quarter of 2012.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

United States – Sheridan County, Montana

In May 2011, the Company acquired a 70% working interest in approximately 5,200 acres (3,640 net acres) in Sheridan County, Montana in the Middle Bakken formation. The Company’s interest in the field is made up of various mineral leases with expiration dates ranging from September 2013 to October 2019. The primary objective of this property is the Bakken/Three Forks formation.

The Company drilled two wells in the field. The Bolke 11-01H well was drilled and hydraulically fractured whereas the Bolke 7-01H well was drilled, but is awaiting hydraulic fracturing scheduled to begin in November 2012. Following the installation of electrical submersible pumps, the Bolke 11-01 well is currently undergoing a 30 day test to determine commerciality. The results of this test are expected in the fourth quarter of 2012. The Company has capitalized $4.6 million associated with the costs attributable to the Bolke 11-1H well and $2.7 million associated with the costs attributable to the Bolke 7-01H well in accordance with the criteria contained in ASC Topic 932.

United States – South Dakota

In September 2012, the Company acquired a 100% working interest in approximately 10,000 acres in Harding County, South Dakota. The primary objective for this property is the Red River formation. Pursuant to the terms of the acquisition, the Company is obligated to drill and complete a well, or reenter and complete an existing well within twelve months of the acquisition date. Once this obligation is met and within sixteen months of the acquisition date, the Company must elect to proceed or withdraw from the transaction. Should the Company elect to proceed, it must pay an additional amount of approximately $3.6 million and commit to drill and complete an additional well, or reenter and complete another existing well within twelve months of the date the Company elects to proceed with the transaction. The Company expects to drill the initial well on the property in the fourth quarter of 2012.

ASC Topic 932—Extractive Industries provides that an exploratory well shall be capitalized as part of the entity’s uncompleted wells pending the determination of whether the well has found proved reserves. Further, an exploration well that discovers oil and gas reserves, but those reserves cannot be classified as proved when drilling is completed, shall be capitalized if the well has found a sufficient quantity of reserves to justify its completion as a producing well and the entity is making sufficient progress assessing the reserves and the economic and operating viability of the project. If either condition is not met, the exploration well would be assumed to be impaired and its costs would be charged to expense.

Offshore Gabon

In the second and third quarters of 2010, the Company drilled the Southeast Etame No. 1 well with two sidetracks in the Etame Marin block offshore Gabon. The well discovered a five meter sand of oil. Additional evaluation of the well and sidetrack information was conducted to facilitate options for developing the discovery. The Company and its joint venture partners evaluated the merits of two development options. One option involved a sub-sea well to develop the Southeast Etame discovery only, whereas the second option envisioned a platform development to access both the Southeast Etame area as well as the North Tchibala field, where a discovery was made on the block prior to VAALCO’s block participation. In the second quarter of 2012, the Company and its partners agreed to proceed with the development plan featuring a fixed leg platform for developing the Southeast Etame discovery area and the North Tchibala field. The Company has capitalized $8.1 million for this well in accordance with the criteria contained in ASC Topic 932.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

United States – Montana

In the second quarter of 2012, the Company completed the EPU-120 exploration well in the East Poplar Dome field in Roosevelt County, Montana at a total cost of $8.9 million. The vertical well discovered hydrocarbons shows in the Bakken/Three Forks formation, but did not initially find commercial quantities of hydrocarbons in the formations deeper than the Bakken/Three Forks formation. Targeting the Nisku formation, the Company is planning to drill an additional well in this field in the fourth quarter of 2012. The outcome of that well will be used to consider further stimulation and completion options for the EPU-120 well. The Company has capitalized $6.0 million associated with the costs attributable to the Bakken/Three Forks formation segment of this well in accordance with the criteria contained in ASC Topic 932 and, as previously stated, recorded dry hole expense of $2.9 million for the costs associated with the deeper formations.

During the three months ended September 30, 2012 the Company recognized an impairment loss in its United States segment for $7.6 million to write down the value of its first Granite Wash formation lease to its estimated fair value of $7.7 million. A combination of continued production declines from both producing wells and low natural gas prices has had a negative impact on the fair value of the assets and an impairment charge was warranted.

The initial measurement of these assets at fair value is calculated using discounted cash flow techniques and based on estimates of future revenues and costs associated with the Granite Wash formation well. Significant Level 3 assumptions associated with the calculation of discounted cash flows used in the impairment analysis include the Company’s estimate of future crude oil and natural gas prices, production costs, development expenditures, and anticipated production of proved and probable reserves, appropriate risk-adjusted discount rates and other relevant data. For crude oil, estimates were based on NYMEX West Texas Intermediate prices, adjusted for quality, transportation fees, and a regional price differential. For natural gas, estimates were based on NYMEX Henry Hub prices, adjusted for energy content, transportation fees, and a regional price differential.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

In July 2012, the Company signed a definitive agreement with PETRONAS CARIGALI OVERSEAS SDN BHD for the purchase of a 31% working interest in Block P, located offshore Equatorial Guinea at a cost of $10.0 million. The acquisition was completed on November 1, 2012. There is no obligation to drill any wells to maintain this interest, but two exploration wells are expected to be drilled on this block in 2013. A subsidiary, VAALCO Energy (EG), Inc., was formed in association with the acquisition.

Drilling of the N’Gongui 2 well on the onshore Gabon Mutamba Iroru block commenced in October 2012 resulting in an oil discovery. Sidetracks to appraise the discovery commenced in late October 2012 in an effort to quantify the discovery and determine commerciality.

On November 1, 2012, the Company’s Board of Directors approved a one-time payment to the Company’s United States based employees to settle an employee benefit policy. In eliminating this benefit, compensation expense of $1.0 million will be recorded in the fourth quarter of 2012 in addition to the $2.6 million previously expensed. The payments that will be made in December 2012 are estimated to be $3.6 million net to the Company.

The Company’s operations are based in Gabon, Angola, the British North Sea and in the United States. 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. Revenues are based on the location of hydrocarbon production. The Company evaluates each segment based on income (loss) from operations. Segment activity for the three months and nine months ended September 30, 2012 and 2011 are as follows: (in thousands)

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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This Report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, which are intended 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, operating performance and results, reserve quantities and net present values, market prices, business strategy, derivative activities, the amount and nature of capital expenditures, plans and objectives of the Company’s management for future operations are forward-looking statements. When the Company uses words such as “anticipate,” “believe,” “estimate,” “expect,” “intend,” “forecast,” “outlook,” “aim,” “will,” “could,” “should,” “may,” “likely,” “plan,” “probably” or similar expressions, the Company is making forward-looking statements. Many risks and uncertainties 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, but are not limited to: the volatility of oil and natural gas prices; the uncertainty of estimates of oil and natural gas reserves; the impact of competition; the availability and cost of seismic, drilling and other equipment; operating hazards inherent in the exploration for and production of oil and natural gas; difficulties encountered during the exploration for and production of oil and natural gas; difficulties encountered in delivering oil to commercial markets; discovery, acquisition, development and replacement of oil and gas reserves; timing and amount of future production of oil and gas; hedging decisions, including whether or not to enter into derivative financial instruments; our ability to effectively integrate companies and properties that we acquire; general economic conditions, including any future economic downturn, disruption in financial markets and the availability of credit; changes in customer demand and producers’ supply; future capital requirements and the Company’s ability to attract capital; currency exchange rates; actions by the governments and events occurring in the countries in which we operate; actions by our venture partners; compliance with, or the effect of changes in, governmental regulations regarding the Company’s exploration and production, including those related to climate change; actions of operators of the Company’s oil and gas properties; weather conditions; and statements set forth in the Company’s Annual Report on Form 10-K for the year ended December 31, 2011.

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.

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The Company’s forward-looking statements speak only as of the date made and the Company will not update these forward-looking statements unless the securities laws require the Company to do so. The Company’s forward-looking statements are expressly qualified in their entirety by this cautionary statement. In light of these risks, uncertainties and assumptions, any forward-looking events discussed in this Report may not occur.

INTRODUCTION

The Company operates oil production sharing contracts in Gabon and Angola. In the United States the Company operates properties in the Granite Wash formation in Texas, the Bakken/Three Forks formation in Montana and the Red River formation in South Dakota. Additionally, the Company has minor interests in Brazos County, Texas producing from the Buda/Georgetown formations. The Company also owns certain minor non-operated interests in the Ship Shoal area of the Gulf of Mexico and in Pickens County, Alabama.

In July 2012, the Company signed a definitive agreement for the purchase of a 31% working interest in Block P, located offshore Equatorial Guinea at a cost of $10.0 million. The acquisition was completed on November 1, 2012.

Offshore Gabon

The Company’s primary source of revenue is from the Etame Production Sharing Contract related to the Etame Marin block located offshore the Republic of Gabon. VAALCO operates the Etame Marin block on behalf of a consortium of companies. VAALCO owns a 30.35% interest in the exploration acreage within the Etame Marin block. The Company owns a 28.1% interest in the development areas in and surrounding the Etame, Avouma, South Tchibala and Ebouri fields, each of which is located on the Etame Marin block. The development areas were subject to a 7.5% back-in by the Government of Gabon, which occurred for these fields after their successful development.

The Company produces from the Etame, Avouma, South Tchibala and Ebouri fields on the block. Oil production commenced from the Etame field in September 2002, from the Avouma and South Tchibala fields in January 2007, and from the Ebouri field in January 2009. During the three months and nine months ended September 30, 2012, the Etame, Avouma, South Tchibala and Ebouri fields produced, approximately 1.7 million Bbls (0.4 million Bbls net to the Company), and 5.5 million Bbls (1.3 million Bbls net to the Company), respectively.

In July 2012, the Company shut-in two of its three producing wells in the Ebouri field as a precaution after detecting the presence of hydrogen sulfide (H2S) on the Ebouri platform. The contamination is isolated to two wells in the Ebouri field and the Company continues to maintain production from the rest of the Etame complex including one well at Ebouri at approximately 19,000 barrels per day. Investigations are underway to ascertain the root cause of the H2S and develop a plan to produce the remaining reserves in a timely manner. Although the investigative work and recommendations were not complete by the end of the third quarter of 2012, it appears that additional capital investment will be required to produce the impacted reserves. The additional capital investment required may include re-working the wells with upgraded metallurgy, including wellhead replacement, and installing H2S processing equipment on the platform. The amount of such investment is not estimable at this time.

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The Company and its partners are proceeding with the plans to build two new platforms, one to be located in the Etame field and the other in the Southeast Etame/North Tchibala area. These platforms will provide the capacity to drill multiple wells in the Etame field, Southeast Etame discovery area, and the North Tchibala field. Installation of the platforms is expected to occur in the first half of 2014.

In November 2009, The Company entered into the sixth exploration period for the Etame block, which expires in July 2014. During the sixth exploration period, the Company is obligated to drill two exploration wells. In 2010, the Company fulfilled one of the two required exploration well obligations with the drilling of the Omangou well, an unsuccessful effort. The remaining commitment in the exploration period is the drilling of one additional exploration well, expected to be drilled in 2013.

As part of securing the second ten year production license with the government of Gabon, in January 2012 the Company agreed to a cash funding arrangement for the eventual abandonment of the offshore wells, platforms and facilities. The agreement calls for annual funding for the next seven years at 12.14% of the total abandonment estimate per year and 5.0% per year for the last three years of the production license. The amounts paid will be reimbursed through the cost account. The funding is expected to begin in the fourth quarter of 2012, after the final details are agreed with the government of Gabon. The abandonment costs for this purpose are estimated to be approximately $9.6 million net to the Company on a discounted basis. The obligation for abandonment expenses related to the Gabon offshore facilities is included in the asset retirement obligation shown on the Company’s balance sheet. The Company also agreed to a fixed royalty rate of 13% effective July 17, 2011, replacing the sliding scale royalty provided for in the production sharing contract.

Onshore Gabon

The Company executed a farm-out agreement in August 2010 with Total Gabon on the Mutamba Iroru block located onshore near the coast in central Gabon. In October 2010, the Company signed a second exploration period extension for the Mutamba Iroru block which was to expire in May 2012. The Company was obligated to reprocess 400 square kilometers of 2D seismic and drill one exploration well. An agreement with Total Gabon (“Total”) was completed in August 2010, which established a joint operation on the block whereby Total acquired a 50% working interest in the block effective November 1, 2010. The terms of the agreement provided for Total paying 75% of the seismic reprocessing costs and the exploration well drilling costs. The seismic reprocessing has been completed. The Company commenced drilling of the exploration well in late September 2012, which satisfies the drilling obligation.

In April 2012, the Company signed a third exploration period extension for the Mutamba Iroru block, which expires at the end of February 2013. In addition, the latest extension requires the Company to reprocess an additional 350 kilometers of 2-D seismic by the end of February 2013. The additional seismic reprocessing required by the third extension is underway and expected to be completed in the fourth quarter of 2012 with the cost being equally split between the Company and Total.

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Offshore Angola

In November 2006, the Company signed a production sharing contract for Block 5 offshore Angola. The four year primary term with an optional three year extension awarded the Company exploration rights to 1.4 million acres offshore central Angola. The Company’s working interest 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 was required to acquire and process 1,000 square kilometers of 3-D seismic data, drill two exploration wells and expend a minimum of $29.5 million ($14.8 million net to the Company). The Company fulfilled its seismic obligation when it acquired 1,175 square kilometers of 3-D seismic data at a cost of $7.5 million ($3.75 million net to the Company) in January 2007 and 524 square kilometers of 3-D seismic data during the fourth quarter of 2008 at a cost of $6.0 million ($3.0 million net to the Company).

The government-assigned working interest partner was delinquent paying their share of the costs several times in 2009 and consequently was placed in a default position. By a governmental decree dated December 1, 2010, the former partner was removed from the production sharing contract, and a one year time extension was granted for drilling the two exploration commitment wells. Following the decree, the Company and the government of Angola have been working together to obtain a replacement partner. In early 2012, the Angolan government granted a further one year extension to November 30, 2012 for drilling the two exploration commitment wells in accordance with the production sharing contract. In July 2012, the Angolan government granted an additional two year extension until November 30, 2014 to drill the two exploration commitment wells.

In the first quarter of 2012, the Company provided the Angolan government with a written offer that would allow the Company to proceed with exploration activities without obtaining a new partner, subject to certain criteria including changes to the work commitment and working interest percentages. In the second quarter of 2012, the Company identified a potential partner to acquire the available 40% working interest and submitted the name of the interested party to the Angolan government for approval. In
November 2012, the government advised the Company that it has entered into negotiations with the potential partner. The company is unable to estimate when or how the negotiations will conclude with the potential partner or determine what the Angolan government’s response will be to our written offer.

The remaining obligation is a two well exploration commitment. Each well is subject to a $5.0 million penalty ($10.0 million in aggregate for both wells) if not drilled during the contract term. The $10.0 million is currently recorded as restricted cash and is held at a financial institution located in the United States.

Because of the continuing uncertainty with the Angolan government approving a replacement partner, the Company has recorded a full allowance totaling $5.4 million as of September 30, 2012, against the accounts receivable from partners for the amounts owed to the Company above its 40% working interest plus the 10% carried interest. The allowance recorded in the nine months ended September 30, 2012 totaled $1.0 million with the remainder having been recorded in 2011. The Company expects the allowance amounts will be paid to the Company if a new partner in the block is approved.

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Offshore Equatorial Guinea

In November 2012, the Company acquired a 31% non-operated working interest, from PETRONAS CARIGALI OVERSEAS SDN BHD, in 57,000 gross acres in Block P at a cost of $10.0 million. Two exploration wells are expected to be drilled on the block in 2013.

International – Outside Operated

The Company’s United Kingdom subsidiary was largely inactive during the nine months ended September 30, 2012.

United States - Texas

The Company acquired a 640 acre lease in the Granite Wash formation in North Texas in December 2010 and a 480 acre lease in the same formation in July 2011. The first well on the initial acreage began production in August 2011, but mechanical problems with the well exist and the Company recorded an impairment charge of $5.0 million on the well in the fourth quarter of 2011. In November 2011, the Company commenced drilling a second well on the initial Granite Wash formation lease. The well landed in the objective reservoir in February 2012 and was successfully completed and began production in March 2012. However, due to a combination of continued production declines and low natural gas prices, the Company recorded an additional impairment charge of $7.6 million on the combined assets in the third quarter of 2012 to reflect the fair value of the assets based on the latest reserve estimates from this field.

The acreage on the first Granite Wash lease the Company acquired is held by production. The expiration date of the primary term of the second Granite Wash lease is August 2014.

United States - Montana

In September 2011, the Company acquired a 65% working interest in approximately 22,000 gross acres (14,300 net acres) in the East Poplar Dome field in Roosevelt County, Montana. The primary objective for this field is the Bakken/Three Forks formation. Pursuant to the terms of the acquisition, the Company is required to drill three wells at its sole cost, one of which must have been drilled by June 1, 2012, with the remaining two wells by the end of 2012. In the second quarter of 2012, the Company completed the EPU-120 exploration well in the East Poplar Dome field in Roosevelt County, Montana at a total cost of $8.9 million. The vertical well discovered hydrocarbons shows in the Bakken/Three Forks formation, but did not initially find commercial quantities of hydrocarbons in the formations deeper than the Bakken/Three Forks formation, and has been temporarily suspended. The Company recorded dry hole expense of $2.9 million in the second quarter of 2012 for drilling costs associated with the deeper formations. The well may be re-entered at a later date to retest certain formations or to convert the well into a horizontal producing well.

A second well, EPU-133 was spudded in June 2012 and was completed as a horizontal well in the Bakken/Three Forks formation. The well was hydraulicly fractured, and may be equipped with electrical submersible pumps (“ESPs”) in the fourth quarter of 2012 in an effort to establish production. Using ESPs to obtain production has been successfully utilized in other wells in the area. The Company will make a decision on this approach following a test of this process in either one or both wells recently drilled in the Salt Lake field in Sheridan County, Montana, as discussed below. The Company has capitalized $7.9 million associated with the costs attributable to the EPU-133 well. The Company plans to drill the third obligation well during the fourth quarter 2012.

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In May 2011, the Company acquired a 70% working interest in approximately 5,200 acres (3,640 net acres) in the Salt Lake field in Sheridan County, Montana. During the third quarter of 2012, The Company drilled two wells in the Salt Lake Field located in Sheridan County, Montana. The Bolke 11-01H was drilled and hydraulically fractured whereas the Bolke 7-01H well was drilled, but is awaiting hydraulic fracturing scheduled for November 2012. Following the installation of electrical submersible pumps, the Bolke 11-01 well is undergoing a 30 day test to determine commerciality. The results of this test are expected in the fourth quarter of 2012 and, if successful, may be repeated in the Bolke 7-01H well and/or the EPU-133 well in the East Poplar Dome field. The Company has capitalized $4.6 million associated with the costs attributable to the Bolke 11-1H well and $2.7 million associated with the costs attributable to the Bolke 7-01H well.

United States – South Dakota

In September 2012, the Company acquired a 100% working interest in approximately 10,000 acres in Harding County, South Dakota. The primary objective for this property is the Red River formation. Pursuant to the terms of the acquisition, the Company is obligated to drill and complete a well, or reenter and complete an existing well within twelve months of the acquisition date. Once this obligation is met and within sixteen months of the acquisition date, the Company must elect to proceed or withdraw from the transaction. Should the Company elect to proceed, an additional payment of $3.6 million is required and the Company must commit to drill and complete an additional well, or reenter and complete another existing well within twelve months of the date the Company elects to proceed with the transaction. The Company expects to drill the initial well on this property in the fourth quarter of 2012.

Domestic – Outside Operated

The Company has minor interests in Brazos County, Texas producing from the Buda/Georgetown formations. The Company also owns certain minor non-operated interests in the Ship Shoal area of the Gulf of Mexico and in Pickens County, Alabama. No significant activity was undertaken on these properties during the nine months ended September 30, 2012.

CAPITAL RESOURCES AND LIQUIDITY

Cash Flows

Net cash provided by operating activities for the nine months ended September 30, 2012 was $44.8 million, as compared to $54.3 million for the nine months ended September 30, 2011. Net income for the nine months ended September 30, 2012 was $5.6 million lower than net income for the comparable period in 2011. Non-cash adjustments to net income were $29.8 million and $23.6 million for the nine months ended September 30, 2012 and 2011, respectively. Changes in working capital other than cash used was $9.3 million for the nine months ended September 30, 2012, compared to cash provided of $0.8 million for the nine months ended September 30, 2011.

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Net cash used in investing activities for the nine months ended September 30, 2012 was $43.5 million, compared to net cash used in investing activities for the nine months ended September 30, 2011 of $19.0 million. For the nine months ended September 30, 2012, the Company paid $43.5 million for capital expenditures, which was partially offset by a $55 thousand release of restricted cash in Gabon. For the nine months ended September 30, 2011, the Company paid $23.0 million for capital expenditures, which was partially offset by the release of restricted cash in Gabon of $3.9 million.

For the nine months ended September 30, 2012, cash used in financing activities was $2.2 million consisting of distributions to a noncontrolling interest of $5.6 million and the receipt of $3.4 million in proceeds from the issuance of common stock upon the exercise of stock options. For the nine months ended September 30, 2011, cash used in financing activities was $4.0 million consisting of distributions to a noncontrolling interest of $5.2 million and the receipt of $1.2 million in proceeds from the issuance of common stock upon the exercise of stock options.

Capital Expenditures

During the nine months ended September 30, 2012, the Company incurred $44.1 million of net property and equipment additions, primarily with $32.2 million spent in the United States ($13.9 million for two wells in the Montana East Poplar Dome unit, $9.6 million for the second Granite Wash formation well, $7.2 million for two wells in the Montana Salt Lake lease, and $1.5 million for a lease acquisition in the State of South Dakota), $11.1 million spent offshore Gabon for platform modifications and advance purchases for the upcoming drilling program, and $0.8 million advance purchases for the onshore drilling program in Gabon.

During the remainder of 2012, the Company anticipates its share of capital expenditures will approximate $32.0 million for the acquisition of a block in Equatorial Guinea, completion of wells underway in Montana, new wells in Montana and South Dakota, completion of the onshore Gabon well, offshore infrastructure projects in Gabon and the initial drilling costs of a multi-well program scheduled to begin late in the fourth quarter offshore Gabon.

Oil and Gas Exploration Costs

The Company uses the “successful efforts” method of accounting for its oil and gas exploration and development costs. All expenditures related to exploration, with the exception of costs of drilling exploration wells are charged as an expense when incurred. The costs of exploration wells are capitalized 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 as an expense. For the nine months ended September 30, 2012, exploration expense was $5.0 million, consisting primarily of a $2.9 million dry-hole charge to write-off the exploratory costs associated with drilling and testing of several intervals below the Bakken/Three Forks formation on the EPU-120 well drilled in the East Poplar Dome field in Montana. Additional exploratory costs incurred in the nine months ended September 30, 2012 were $0.7 million for North America, $0.4 million onshore Gabon, $0.6 million offshore Gabon, $0.2 million in Angola and $0.2 million in the United Kingdom. For the nine months ended September 30, 2011, exploration expense was $3.6 million, which was primarily comprised of $2.0 million spent in North America, $0.5 million offshore Gabon, $0.4 million onshore Gabon, $0.5 million in Angola and $0.3 million in the United Kingdom.

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Liquidity

The Company’s primary source of capital has been cash flows from operations. At September 30, 2012, the Company had unrestricted cash of $136.3 million. The Company believes that this cash combined with cash flow from operations will be sufficient to fund the Company’s remaining 2012 capital expenditure budget and potential growth investments. As operator of the Etame Marin and Mutamba Iroru blocks in Gabon, Block 5 in Angola, and the two Middle Bakken formation properties in Montana, the Company enters into project related activities on behalf of its working interest partners. The Company generally obtains advances from its partners prior to significant funding commitments.

Substantially all of the Company’s crude oil and gas is sold at the well head at posted or index prices under short-term contracts. In Gabon, the Company markets its crude oil under an agreement with Mercuria Trading NV (“Mercuria”). While the loss of Mercuria as a buyer might have a material adverse effect on the Company in the near term, management believes that the Company would be able to obtain other customers for its crude oil in Gabon.

Domestically, the Company markets its oil condensate and natural gas under arrangements with Sunoco Partners Marketing & Terminals L.P. (“Sunoco”) (as of August 1, 2012) and Eagle Rock Field Services, LP (“Eagle Rock”), respectively. While the loss of Sunoco or Eagle Rock as buyers might have a material adverse effect on the Company in the near term, management believes that the Company would be able to obtain other customers for its oil condensate and natural gas in the United States. The Company has access to several alternative buyers for oil condensate and natural gas sales domestically.

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RESULTS OF OPERATIONS

Three months ended September 30, 2012 compared to three months ended September 30, 2011

Total Revenues

Total oil and natural gas revenues were $37.6 million for the three months ended September 30, 2012 compared to $37.4 million for the same period of 2011.

Oil Revenues

Gabon

Crude oil revenues for the three months ended September 30, 2012 were $37.0 million, as compared to revenues of $36.4 million for the same period 2011. In the three months ended September 30, 2012, the Company sold approximately 342,000 net barrels of oil from three liftings at an average price of $107.94/Bbl, while in the three months ended September 30, 2011 it sold approximately 322,000 net barrels of oil equivalent from two liftings at an average price of $113.09/Bbl. Crude oil sales are a function of the number and size of crude oil liftings in each quarter from the floating production, storage and offloading (“FPSO”) facility and thus crude oil sales do not always coincide with volumes produced in any given quarter.

At September 30, 2012, the Company’s share of oil in inventory aboard the FPSO was 98,703 barrels as compared to 118,823 barrels in inventory at September 30, 2011.

United States

Condensate sales from the Granite Wash formation wells, located in Hemphill County, Texas for the three months ended September 30, 2012 were $178,000, resulting from the sale of approximately 2,000 net barrels of oil condensate at an average price of $77.48/Bbl. For the same period in 2011, condensate sales from the Granite Wash formation wells were $146,000, resulting from the sale of approximately 2,000 net barrels of oil condensate at an average price of $74.63/Bbl.

Natural Gas Revenues

United States

Natural gas revenues including revenues from natural gas liquids for the three months ended September 30, 2012 were $0.5 million compared to $0.8 million for the comparable period in 2011. Natural gas sales were 147 MMcf at an average price of $3.32/Mcf for the three months ended September 30, 2012. For the same period of 2011, natural gas sales were 137 MMcf at an average price of $5.62/Mcf.

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Operating Costs and Expenses

Total production expenses for the three months ended September 30, 2012 were $5.9 million compared to $4.5 million for the three months ended September 30, 2011. The $1.4 million cost increase in the three months ended September 30, 2012 as compared to the three months ended September 30, 2011 is mainly due to a $0.6 million retroactive FPSO cost pursuant to a contract extension and revision, and $2.3 million higher production costs as a result of lower expenses capitalized associated with unsold crude oil inventory, partially offset by a $2.0 million lower Domestic Market Obligation (“DMO”) charge payable to the Republic of Gabon.

Exploration expense was $0.7 million for the three months ended September 30, 2012 compared to $1.3 million for the comparable period in 2011. For the three months ended September 30, 2012, exploration expense consisted primarily of $0.3 million for exploration activities in North America, $0.1 million for exploration activities offshore Gabon, and $0.2 million for exploration activities in Angola. Exploration expense for the three months ended September 30, 2011 consisted primarily of $0.6 million for exploration activities in North America, $0.4 million for exploration activities offshore Gabon and $0.2 million for exploration activities in Angola.

Depreciation, depletion and amortization expenses were $4.9 million in the three months ended September 30, 2012 compared to $5.2 million in the three months ended September 30, 2011. Lower depreciation, depletion and amortization expenses during the three months ended September 30, 2012 compared to the three months ended September 30, 2011 were primarily due to lower depletion rates for the quarter, partially offset by higher sales volumes.

General and administrative expenses for the three months ended September 30, 2012 and 2011 were $2.5 million and $2.6 million, respectively. In each of the three month periods ended September 30, 2012 and 2011, the Company benefited from overhead reimbursement associated with production and development operations on the Etame Marin block. Overhead reimbursement for the three months ended September 30, 2012 was $0.8 million compared to $0.5 million for the same period in 2011.

During the three months ended September 30, 2012 and 2011, the Company recorded a bad debt provision of $0.4 million and $4.1 million, respectively, related to the uncertainty in collecting its joint venture receivables in Angola.

Furthermore, during the three months ended September 30, 2012, the Company recorded an impairment loss of $7.6 million to write down its investment in the Granite Wash formation of North Texas to its fair value. The impairment charge was due to a combination of continued production declines from both wells and low natural gas prices.

Other Income

Other income for the three months ended September 30, 2012 was $9,000 compared to income of $0.7 million for the three months ended September 30, 2011. The other income recorded in the three months ended September 30, 2011 was primarily due to a foreign exchange gain resulting from currency fluctuations in its international operations.

Income Taxes

Income tax expense amounted to $14.2 million and $17.1 million for the three months ended September 30, 2012 and 2011, respectively. In the three months ended September 30, 2012 and

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2011, the income taxes were all paid in Gabon. Income tax expense for the three months ended September 30, 2012 was lower than in the same period of 2011 due to a lower percentage of oil allocated as “profit oil” versus “cost oil” in Gabon. The income taxes the consortium pays the government of Gabon is an allocation of the remaining profit oil production from a specific contract area ranging from 50% to 60% of the oil remaining after deducting the royalty and the cost oil.

Net Income

Net income including the noncontrolling interest for the three months ended September 30, 2012 was $1.4 million, compared to $3.5 million for the same period in 2011. Net income allocated to noncontrolling interest was $1.3 million and $1.1 million in the three months ended September 30, 2012 and 2011, respectively. The noncontrolling interest is associated with VAALCO Energy (International), Inc., a subsidiary that is 90.01% owned by the Company.

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Nine months ended September 30, 2012 compared to nine months ended September 30, 2011

Total Revenues

Total oil and natural gas revenues were $141.7 million for the nine months ended September 30, 2012 compared to $142.7 million for the same period of 2011.

Oil Revenues

Gabon

Crude oil revenues for the nine months ended September 30, 2012 were $139.6 million, a $2.1 million decrease from revenues of $141.7 million for the same period of 2011. The Company sold approximately 1,248,000 net barrels of oil equivalent from nine liftings at an average price of $111.79/Bbl in the nine months ended September 30, 2012. The Company sold approximately 1,260,000 net barrels of oil equivalent from eight liftings at an average price of $112.42/Bbl in the nine months ended September 30, 2011. 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.

At September 30, 2012, the Company’s share of oil in inventory aboard the FPSO was 98,703 barrels as compared to 118,823 barrels in inventory at September 30, 2011.

United States

Condensate sales from the Granite Wash wells, located in Hemphill County, Texas for the nine months ended September 30, 2012 were $0.6 million, resulting from approximately 7,000 barrels at an average price of $82.81/Bbl. For the same period in 2011, condensate sales from the Granite Wash wells were $0.1 million, resulting from approximately 2,000 barrels at an average price of $74.63/Bbl. Condensate production from the first Granite Wash well began in August 2011.

Natural Gas Revenues

United States

Natural gas revenues, including revenues from natural gas liquids, for the nine months ended September 30, 2012 were $1.5 million compared to $0.8 million for the same period in 2011. The increase in natural gas revenues is due to production from the Company’s domestic property in the Granite Wash formation, located in Hemphill County, Texas. Natural gas sales were 421 MMcf at an average price of $3.65/Mcf for the nine months ended September 30, 2012. For the same period of 2011, natural gas sales were 155 MMcf at an average price of $5.32/Mcf. Natural gas and natural gas liquids production from the first Granite Wash well began in August 2011.

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Operating Costs and Expenses

Total production expenses for the nine months ended September 30, 2012 were $18.0 million compared to $15.5 million in the nine months ended September 30, 2011. The $2.5 million cost increase in the nine months ended September 30, 2012, as compared to the nine months ended September 30, 2011, is mainly due to a $1.7 million retroactive FPSO cost pursuant to a contract extension and revision, and $2.2 million higher production costs as a result of lower expenses capitalized associated with unsold crude oil inventory, partially offset by a $1.7 million lower DMO charge payable to the Republic of Gabon.

For the nine months ended September 30, 2012, exploration expense was $5.0 million, consisting primarily of a $2.9 million dry-hole charge to write-off the exploratory costs associated with the drilling and testing of several intervals below the Bakken/Three Forks formation on a well drilled in the East Poplar Dome field in Montana. Additional exploratory costs incurred in the nine months ended September 30, 2012 were $0.7 million for North America, $0.4 million onshore Gabon, $0.6 million offshore Gabon, $0.2 million in Angola and $0.2 million in the United Kingdom.

For the nine months ended September 30, 2011, exploration expense was $3.6 million, including $2.0 million exploration expenditures for North America, $0.4 million onshore Gabon, $0.5 million offshore Gabon, $0.5 million in Angola and $0.3 million in the United Kingdom.

Depreciation, depletion and amortization expenses were $16.7 million for the nine months ended September 30, 2012 compared to $17.8 million for the nine months ended September 30, 2011. The lower depreciation, depletion and amortization expense during the nine months ended September 30, 2012 compared to the nine months ended September 30, 2011 was mainly due to lower depletion rates in Gabon.

General and administrative expenses for the nine months ended September 30, 2012 and 2011 were $9.1 million and $8.1 million, respectively. The increase in general and administrative costs in the nine months ended September 30, 2012 compared to the same period in 2011 were primarily due to the Company’s recent office and staffing expansion in anticipation of the various planned increased exploration and development activities.

During the nine months ended September 30, 2012, the Company incurred $2.1 million of stock based compensation expense compared to $1.9 million incurred in the nine months ended September 30, 2011. In both of the nine months ended September 30, 2012 and 2011, the Company benefited from overhead reimbursement associated with production and development operations on the Etame Marin block. Overhead reimbursement for the nine months ended September 30, 2012 was $2.0 million compared to $1.7 million in the same period in 2011.

During the nine months ended September 30, 2012 and 2011, the Company recorded bad debt provisions of $1.0 million and $4.1 million, respectively, related to the uncertainty in collecting its joint venture receivables in Angola.

Furthermore, during the nine months ended September 30, 2012, the Company recorded an impairment loss of $7.6 million to write down its investment in the Granite Wash formation of North Texas to its fair value. The impairment charge was due to a combination of continued production declines from both wells and low natural gas prices.

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Other Income

Other income for the nine months ended September 30, 2012 was $0.7 million compared to $1.2 million for the nine months ended September 30, 2011. The other income recorded in the nine months ended September 30, 2012 was primarily due to a foreign exchange gain of $0.6 million, compared to a foreign exchange gain of $0.8 million for the same period in 2011. Interest income received on amounts on deposit was $0.1 million in each of the nine months ended September 30, 2012 and 2011.

Income Taxes

Income tax expense amounted to $60.7 million and $65.0 million for the nine months ended September 30, 2012 and 2011, respectively. In the nine months ended September 30, 2012 and 2011, the income taxes were all paid in Gabon. Income tax expense for the nine months ended September 30, 2012 was lower than in the same period of 2011 due to a lower percentage of oil allocated as “profit oil” versus “cost oil”. The income taxes the consortium pays the government of Gabon is an allocation of the remaining profit oil production from a specific contract area ranging from 50% to 60% of the oil remaining after deducting the royalty and the cost oil.

Net Income

Net income including the noncontrolling interest for the nine months ended September 30, 2012 was $24.3 million, compared to a net income of $29.9 million for the same period in 2011. Net income allocated to noncontrolling interest for the nine months ended September 30, 2012 was $4.7 million as compared to $4.4 million for the nine months ended September 30, 2011. The noncontrolling interest is associated with VAALCO Energy (International), Inc., a subsidiary that is 90.01% owned by the Company.

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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 does not presently have any active hedges in place, but may do so in the future.

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 files 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 Quarterly Report on Form 10-Q. 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 Quarterly Report on Form 10-Q. There were no changes in the Company’s internal controls over financial reporting that occurred during the Company’s last fiscal quarter that have materially affected, or are reasonably likely to materially affect the Company’s internal control over financial reporting.

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PART II. OTHER INFORMATION

There have been no material changes to the disclosure on this matter since our annual report on Form 10-K for the year ended December 31, 2011.

Rule 13a-14(a)/15d-14(a) Certifications

Section 1350 Certifications

Interactive Data Files

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SIGNATURES

In accordance with the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

VAALCO ENERGY, INC.

(Registrant)

Dated: November 8, 2012

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EXHIBIT INDEX

Exhibits

Rule 13a-14(a)/15d-14(a) Certifications

Section 1350 Certifications

Interactive Data Files

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