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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

For the quarterly period ended June 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 July 31, 2012, there were outstanding 57,845,799 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)

Six Months Ended June 30, 2012

Six Months Ended June 30, 2011

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 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 and the Bakken/Three Forks formation in Montana. 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.

The Company has evaluated subsequent events through August 7, 2012, the date the financial statements were issued. Refer to Note 6 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 six months ended June 30, 2012, respectively, because they would have been anti-dilutive. Options to purchase 2,490,004 and 1,320,940 shares were excluded in the three months and six months ended June 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 June 30, 2012, there were 3,363,446 shares subject to options authorized but not granted.

For the three months and six months ended June 30, 2012, the Company recognized non-cash compensation expense of $0.4 million and $1.7 million, respectively, related to stock options. For the three months and six months ended June 30, 2011, the Company recognized non-cash compensation expense of $0.3 million and $1.6 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.

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

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 June 30, 2012, unrecognized compensation costs totaled $1.7 million. The expense is expected to be recognized over a weighted average period of 1.4 years.

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.

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 third 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 $9.2 million net to the Company on a discounted basis. This $9.2 million abandonment liability is $5.4 million less than previous abandonment cost estimates of $14.6 million at March 31, 2012. The changes in estimates are the result of the Company’s reassessment of the mobilization/demobilization cost estimates as well as alternative abandonment procedures for the eventual abandonment of the block. 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 impact of the changes in estimates on the results from operations for the three months ended June 30, 2012 was a $0.7 million reduction in operating costs due to decreased depletion expense, resulting in a $0.01 increase in per share amounts on a fully diluted basis.

Onshore Gabon

In October 2010, the Company signed a second exploration period extension for the Mutamba Iroru block which expired 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.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

In April 2012, the Company signed a third exploration period extension for the Mutamba Iroru block, which expires at the end of February 2013. The latest extension requires the Company to reprocess an additional 350 kilometers of 2-D seismic by the end of February 2013.

The well location site has been determined and drilling the exploration well is expected in the second half of 2012. The additional seismic reprocessing required by the third extension is scheduled to commence in the third 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 awards 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. While waiting on a response to the offer, the Company identified a potential partner to participate in the block during the second quarter of 2012. The Angolan government and the potential partner are in discussions regarding the working interest acquisition. The Company believes the Angolan government will not respond to the Company’s written offer made in the first quarter of 2012 until the outcome of the discussions with the potential partner are concluded.

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 in a financial institution located in the United States.

Because of the continuing uncertainty with the Angolan government providing a replacement partner, the Company has recorded a full allowance totaling $5.0 million as of June 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 six months ended June 30, 2012 totaled $0.6 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 to the block is obtained.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

United States

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 be 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, finished drilling in June 2012 after discovering commercial quantities of oil in the Bakken/Three Forks formation. However, the well did not discover commercial quantities of hydrocarbons in the formations below 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. A second well was spudded in June 2012 to be completed as a horizontal well in the Bakken/Three Forks formation and a third well is expected to be drilled in the fourth quarter of 2012 which will satisfy the drilling obligation.

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.

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 were previously evaluating the merits of two development options. One option involved a sub-sea well to develop the Southeast

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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.

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 well discovered hydrocarbons in the Bakken/Three Forks formation, but did not find commercial quantities of hydrocarbons in the formations deeper than the Bakken/Three Forks formation. 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.

In July 2012, the Company signed a definitive agreement for the purchase of a partial working interest at a cost of $10.0 million in a concession in a West African country new to the Company. The acquisition, which has been approved by the Company’s Board of Directors, is expected to close prior to the end of the third quarter of 2012, and is subject to customary closing conditions, including approval of the agreement by the government of the West African country.

In July 2012, the Company elected to shut-in two 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 entire 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. Until the investigative work is done, the Company is unable to provide a time estimate of when (or if) production will resume from the two shut-in wells, nor is the Company able to determine if additional capital expenditures and higher operating costs will be required to produce the impacted reserves.

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 six months ended June 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. 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

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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 and the Bakken/Three Forks formation in Montana. 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 partial working interest at a cost of $10.0 million in a concession in a West African country new to the Company. The acquisition, which has been approved by the Company’s Board of Directors, is expected to close prior to the end of the third quarter of 2012, and is subject to customary closing conditions, including approval of the agreement by the government of the West African country.

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 six months ended June 30, 2012, the Etame, Avouma, South Tchibala and Ebouri fields produced, approximately 1.8 million bbls (0.4 million net to the Company), and 3.8 million bbls (0.9 million bbls net to the Company), respectively.

In July 2012, the Company elected to shut-in two 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 entire 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. Until the investigative work is done, the Company is unable to provide a time estimate of when (or if) production will resume from the two shut-in wells, nor is the Company able to determine if additional capital expenditures and higher operating costs will be required to produce the impacted reserves.

The Company has two platforms in the Etame Marin block. During the three months ended June 30, 2012, the Company continued to invest in platform modifications, primarily electrical and power generation upgrades to both of the offshore platforms to accommodate the drilling of additional wells planned to begin in the second half of 2012. A new personnel accommodation module was installed on the Avouma platform in the second quarter of 2012. The Company also invested in the construction of water knock-out facilities for the Avouma platform which are expected to be installed in the second half of 2012.

In addition, 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.

The sixth exploration period expires in July 2014. Prior to the expiration of this 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.

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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 third 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 $9.2 million net to the Company on a discounted basis. 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. The $9.2 million abandonment liability is $5.4 million less than previous abandonment cost estimates of $14.6 million at March 31, 2012. The changes in estimates are the result of the Company’s reassessment of the mobilization/demobilization cost estimates as well as alternative abandonment procedures. 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 impact of the change in estimate on the results from operations for the three months ended June 30, 2012 was a $0.7 million reduction in operating costs due to decreased depletion expense, resulting in a $0.01 increase in per share amounts on a fully diluted basis.

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. The Mutamba Iroru block contains an exploration area of approximately 270,000 acres. Under the terms of the agreement, the Company and Total Gabon committed to reprocess 400 kilometers of 2-D seismic data and drill one exploration well. The seismic work was substantially completed in 2011 and drilling of the exploration well is expected in the second half of 2012. In return for funding 75% of the work commitment (seismic reprocessing and exploration well costs), Total Gabon will receive a 50% interest on the permit.

A third exploration period extension was signed in April 2012 extending the contract until the end of February 2013. The latest extension requires the Company to reprocess an additional 350 kilometers of 2-D seismic by the end of February 2013. The seismic reprocessing is expected to begin in the third quarter of 2012.

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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 awards 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. While waiting on a response to the offer, the Company identified a potential partner to participate in the block during the second quarter of 2012. The Angolan government and the potential partner are in discussions regarding the working interest acquisition. The Company believes the Angolan government will not respond to the Company’s written offer made in the first quarter of 2012 until the outcome of the discussions with the potential partner are concluded.

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 in a financial institution located in the United States.

Because of the continuing uncertainty with the Angolan government providing a replacement partner, the Company has recorded a full allowance totaling $5.0 million as of June 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 six months ended June 30, 2012 totaled $0.6 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 obtained.

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International – Outside Operated

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

Onshore Domestic - 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 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. During the second quarter of 2012, both wells were shut-in for approximately six weeks due to lightning damage to non-Company owned processing facilities. Both wells resumed production in June 2012.

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

Onshore Domestic - Montana

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. The Company plans to drill two wells on this prospective Bakken/Three Forks acreage in the second half of 2012.

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 be 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, finished drilling in June 2012 after penetrating the Bakken/Three Forks formation and several deeper intervals. However, the well did not discover commercial quantities of hydrocarbons in 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 convert the well to either a vertical or horizontal Bakken/Three Forks producing well. A second well was spudded in June 2012 to be completed as a horizontal well in the Bakken/Three Forks formation. In the fourth quarter of 2012, a third well is expected to be drilled horizontally and will satisfy the drilling obligation.

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 six months ended June 30, 2012.

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CAPITAL RESOURCES AND LIQUIDITY

Cash Flows

Net cash provided by operating activities for the six months ended June 30, 2012 was $28.0 million, as compared to $41.1 million for the six months ended June 30, 2011. The decrease in cash provided by operating activities for the six months ended June 30, 2012 compared to the six months ended June 30, 2011 was primarily due to a $11.9 million negative variance in changes in operating assets and liabilities in the six months ended June 30, 2012 compared to the six months ended June 30, 2011. This $11.9 million negative variance was primarily due to two Gabon oil liftings that occurred in the second quarter of 2012, but that were not yet due for payment by the buyer as of June 30, 2012.

Net cash used in investing activities for the six months ended June 30, 2012 was $27.1 million, compared to net cash used in investing activities for the six months ended June 30, 2011 of $7.4 million. For the six months ended June 30, 2012 the Company paid $27.2 million for capital expenditures, which was partially offset by a $0.1 million release of restricted cash in Gabon. For the six months ended June 30, 2011 the Company paid $11.3 million for capital expenditures, which was partially offset by the release of restricted cash in Gabon of $3.9 million.

For the six months ended June 30, 2012, cash used in financing activities was $0.2 million consisting of distributions to a noncontrolling interest of $3.6 million, which was partially offset by the receipt of $3.4 million in proceeds from the issuance of common stock upon the exercise of stock options. For the six months ended June 30, 2011, cash used in financing activities was $0.4 million consisting of distributions to a noncontrolling interest of $1.5 million, which was partially offset by the receipt of $1.1 million in proceeds from the issuance of common stock upon the exercise of stock options.

Capital Expenditures

During the six months ended June 30, 2012, the Company incurred $23.5 million of net property and equipment additions, primarily associated with drilling a well in the Texas Granite Wash formation (at a cost of $9.6 million), two wells in the Montana East Poplar Dome unit (at a cost of $6.8 million), advance purchases for the upcoming onshore drilling program in Gabon (at a cost of $0.3 million), and $6.7 million for offshore platform modifications and advance purchases for the upcoming drilling program in Gabon. During the second half of 2012, the Company anticipates its share of capital expenditures will approximate $43.0 million for drilling three wells in the United States, plus wells and offshore infrastructure projects in 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 exploratory wells are charged as an expense when incurred. The costs of exploratory 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 six months ended June 30, 2012, exploration expense was $4.3 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 a well drilled in the East Poplar Dome field in Montana. Additional exploration costs incurred in the six months ended June 30, 2012 were $0.4 million in North America, $0.1 million in the United Kingdom, $0.4 million onshore Gabon, and $0.5 million offshore Gabon.

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For the six months ended June 30, 2011, exploration expense was $2.3 million primarily comprised of $1.4 million spent in North America, $0.3 million onshore Gabon, $0.3 million in Angola and $0.2 million in the United Kingdom.

Liquidity

The Company’s primary source of capital has been cash flows from operations. At June 30, 2012, the Company had unrestricted cash of $137.8 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 additional investments in working capital resulting from potential growth. As operator of the Etame Marin and Mutamba Iroru blocks in Gabon, Block 5 in Angola, and the two Bakken/Three Forks formation properties in Montana, 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.

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 Cokinos Energy and Eagle Rock Field Services, LP, respectively. Starting August 1, 2012, the Company will sell its oil condensate in the United States to Sunoco Partners Marketing & Terminals L.P. (“Sunoco”). While the loss of Cokinos Energy or Eagle Rock Field Services, LP as current buyers, or Sunoco as a buyer beginning August 1, 2012, 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 June 30, 2012 compared to three months ended June 30, 2011

Total Revenues

Total oil and natural gas revenues were $58.8 million for the three months ended June 30, 2012 compared to $58.5 million for the same period of 2011.

Oil Revenues

Gabon

Crude oil revenues for the three months ended June 30, 2012 were $57.9 million, a $0.6 million decrease from revenues of $58.5 million for the same period of 2011. In the three months ended June 30, 2012, the Company sold approximately 538,000 net barrels of oil from four liftings at an average price of $107.51/Bbl., while in the three months ended June 30, 2011 it sold approximately 489,000 net barrels of oil equivalent from three liftings at an average price of $119.61/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 facility (“FPSO”) and thus crude oil sales do not always coincide with volumes produced in any given quarter.

United States

Condensate sales from the Granite Wash formation wells, located in Hemphill County, Texas for the period ended June 30, 2012 were $0.3 million, resulting from the sale of approximately 4,000 net barrels of oil condensate at an average price of $83.25/Bbl. For the same period in 2011, there were no condensate sales as the Company did not commence condensate sales from this property until August 2011.

Natural Gas Revenues

United States

Natural gas revenues including revenues from natural gas liquids for the three months ended June 30, 2012 were $0.6 million compared to $16,000 for the comparable period in 2011. The increase in natural gas revenues is due to production from the Company’s property in the Granite Wash formation, located in Hemphill County, Texas. Natural gas sales were 158 MMcf at an average price of $3.90/Mcf for the three months ended June 30, 2012. For the same period of 2011 natural gas sales were 7 MMcf at an average price of $2.35/Mcf.

Operating Costs and Expenses

Total production expenses for the three months ended June 30, 2012 were $6.5 million compared to $5.8 million for the three months ended June 30, 2011. The Company matches production expenses with crude oil sales. Any production expenses associated with unsold crude oil inventory are capitalized. The higher production expenses were primarily due to $1.2 million additional and retroactive FPSO costs as a result of a contract revision and extension, which were partially offset by $0.2 million lower expenses for the Domestic Market Obligation to the Republic of Gabon, and lower variable production costs. For the three months ended

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June 30, 2012, the Company’s Gabon production was approximately 20,100 BOPD (4,900 BOPD net to the Company), as compared to approximately 22,200 BOPD (5,300 BOPD net to the Company) for the three months ended June 30, 2011.

For the three months ended June 30, 2012, exploration expenses were $3.5 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 three months ended June 30, 2012 were $0.3 million in North America, and $0.2 million offshore Gabon.

For the three months ended June 30, 2011, exploration expenses were $1.2 million primarily comprised of $0.6 million for exploration activities in North America, $0.2 million for seismic reprocessing onshore Gabon and $0.3 million for exploration activities in Angola.

Depreciation, depletion and amortization expenses were $6.9 million in the three months ended June 30, 2012 compared to $6.5 million in the three months ended June 30, 2011. The higher depreciation, depletion and amortization expense during the three months ended June 30, 2012 compared to the three months ended June 30, 2011 was primarily due to higher sales volumes partially offset by lower depletion rates caused by the changes in estimates of our asset retirement obligation costs.

General and administrative expenses for the three months ended June 30, 2012 and 2011 were $3.0 million and $2.5 million, respectively. The increase in general and administrative costs in the three months ended June 30, 2012 compared to the same period in 2011 was primarily due to the Company’s recent office and staffing expansions in anticipation of the various planned increased exploration and development activities. During the three months ended June 30, 2012 and 2011, the Company incurred non-cash stock based compensation expense of $0.4 million and $0.3 million, respectively. In the three months ended June 30, 2012 and 2011, the Company benefited from overhead reimbursement associated with production and development operations on the Etame Marin block of $0.6 million and $0.3 million respectively.

Other Income

Other income for the three months ended June 30, 2012 was $0.4 million, comprised primarily of a foreign exchange gain of $0.4 million. Other income for the three months ended June 30, 2011 was $0.6 million, comprised primarily of $0.6 million foreign exchange gain.

Income Taxes

Income tax expense amounted to $26.7 million and $29.6 million for the three months ended June 30, 2012 and 2011, respectively. In the three months ended June 30, 2012 and 2011, the income taxes were all paid in Gabon. Income taxes in the three months ended June 30, 2012 were lower 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.

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Net Income

Net income, including the noncontrolling interest, for the three months ended June 30, 2012 was $12.3 million, compared to $13.5 million for the same period in 2011. Net income allocated to the noncontrolling interest was $1.9 million and $1.7 million in the three months ended June 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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Six months ended June 30, 2012 compared to six months ended June 30, 2011

Total Revenues

Total oil and natural gas revenues were $104.1 million for the six months ended June 30, 2012 compared to $105.3 million for the same period of 2011.

Oil Revenues

Gabon

Crude oil revenues for the six months ended June 30, 2012 were $102.6 million, a $2.7 million decrease from revenues of $105.3 million for the same period of 2011. The Company sold approximately 906,000 net barrels of oil equivalent from six liftings at an average price of $113.25/Bbl. in the six months ended June 30, 2012. The Company sold approximately 938,000 net barrels of oil equivalent from six liftings at an average price of $112.18/Bbl. in the six months ended June 30, 2011. 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 facility and thus crude oil sales do not always coincide with volumes produced in any given quarter

United States

Condensate sales from the Granite Wash wells, located in Hemphill County, Texas for the six months ended June 30, 2012 were $0.4 million, resulting from approximately 5,000 barrels at an average price of $85.25/Bbl. For the same period in 2011, there were no condensate sales as the Company did not commence condensate sales from this property until August 2011.

Natural Gas Revenues

United States

Natural gas revenues including revenues from natural gas liquids for the six months ended June 30, 2012 were $1.0 million compared to $0.1 million for the comparable 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 274 MMcf at an average price of $3.82/Mcf for the six months ended June 30, 2012. For the same period of 2011, natural gas sales were 17 MMcf at an average price of $2.99/Mcf.

Operating Costs and Expenses

Total production expenses for the six months ended June 30, 2012 were $12.1 million compared to $11.0 million in the six months ended June 30, 2011. The Company matches production expenses with crude oil sales. Any production expenses associated with unsold crude oil inventory are capitalized. The higher production expenses were primarily due to $1.2 million additional and retroactive FPSO costs as a result of a contract revision and extension, which were partially offset by $0.1 million decrease in production expenses in the six months ended June 30, 2012 compared to the same period in 2011.

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For the six months ended June 30, 2012 the Company’s Gabon production was approximately 20,700 BOPD (5,000 BOPD net to the Company), as compared to approximately 22,700 BOPD (5,400 BOPD net to the Company) for the six months ended June 30, 2011.

For the six months ended June 30, 2012, exploration expense was $4.3 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 six months ended June 30, 2012 were $0.4 million in North America, $0.1 million in the United Kingdom, $0.4 million onshore Gabon, and $0.5 million offshore Gabon.

For the six months ended June 30, 2011, exploration expense was $2.3 million primarily comprised of $1.4 million spent in North America, $0.3 million onshore Gabon, $0.3 million in Angola and $0.2 million in the United Kingdom.

Depreciation, depletion and amortization expenses were $11.9 million in the six months ended June 30, 2012 compared to $12.6 million in the six months ended June 30, 2011. The lower depreciation, depletion and amortization expense during the six months ended June 30, 2012 compared to the six months ended June 30, 2011 was primarily due to lower crude oil sales volumes in Gabon and lower depletion rates due to our changes in estimates of our asset retirement obligation costs, which were partially offset by higher gas volumes in the United States.

General and administrative expenses for the six months ended June 30, 2012 and 2011 were $6.5 million and $5.5 million, respectively. The increase in general and administrative costs in the six months ended June 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 six months ended June 30, 2012, the Company incurred $1.7 million of stock based compensation expense compared to $1.6 million incurred in the six months ended June 30, 2011. In both of the six months ended June 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 six months ended June 30, 2012 was $1.2 million compared to $1.1 million in the same period in 2011.

Other Income

Other income for the six months ended June 30, 2012 was $0.7 million income compared to $0.5 million for the six months ended June 30, 2011. The other income recorded in the six months ended June 30, 2012 was primarily due to a foreign exchange gain of $0.6 million, compared to a foreign exchange gain of $0.4 million for the same period in 2011. Interest income received on amounts on deposit was $0.1 million in each of the six months ended June 30, 2012 and June 30, 2011.

Income Taxes

Income tax expense amounted to $46.5 million and $47.9 million for the six months ended June 30, 2012 and 2011, respectively. In the six months ended June 30, 2012 and 2011, the income taxes were all paid in Gabon. Income taxes in the six months ended June 30, 2012 were lower due to a lower percentage of oil allocated as “profit oil” versus “cost oil”. The income taxes the consortium

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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 six months ended June 30, 2012 was $22.8 million, compared to a net income of $26.4 million for the same period in 2011. Net income allocated to the noncontrolling interest in each of the six months ended June 30, 2012 and 2011 was $3.4 million. 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.

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

Section 1350 Certificates

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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.

Dated: August 7, 2012

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EXHIBIT INDEX

Exhibits

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

Section 1350 Certificates

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