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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, 2013

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, 2013, there were outstanding 56,662,294 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, 2012, 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 an operator in Gabon, West Africa, conducts exploration activities as an operator in Angola, West Africa, and conducts exploration activities as a non-operator in Equatorial Guinea, West Africa. VAALCO is the operator of unconventional and conventional resource properties in the United States located in Montana and North Texas. The Company also owns minor interests in conventional production activities as a non-operator in the United States.

VAALCO’s international subsidiaries are VAALCO Gabon (Etame), Inc., VAALCO Production (Gabon), Inc., VAALCO Angola (Kwanza), Inc., VAALCO UK (North Sea), Ltd., VAALCO International, Inc., VAALCO Energy (EG), Inc. and VAALCO Energy Mauritius (EG) Limited. VAALCO Energy (USA), Inc. holds interests in properties located in the United States.

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.

Diluted shares consist of the following:

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Options to purchase 3,205,865 and 2,135,300 shares were excluded in the three months and six months ended June 30, 2013, respectively, because they would have been anti-dilutive. 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.

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. A portion of the stock options granted in March 2013 and 2012 vested immediately with the remainder 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, 2013, there were 2,127,046 shares subject to options authorized but not granted.

For the three months and six months ended June 30, 2013, the Company recognized non-cash compensation expense of $0.8 million and $2.2 million, respectively, related to stock options. 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. 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, 2013 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.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

As of June 30, 2013, 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 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 2012. The remaining obligation is the drilling of one exploration well which is scheduled to be drilled in the third quarter of 2013. The well to be drilled is the Ovoka 1 well located approximately 5 miles northeast of the Ebouri field and 6 miles north of the Etame field.

As part of securing the second ten-year production license with the government of Gabon, the Company agreed in principle to a cash funding arrangement for the eventual abandonment of the offshore wells, platforms and facilities. The agreement is not yet finalized, but 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 and are non-refundable to the Company. The funding will begin after the agreement is finalized. The abandonment estimate for this purpose is approximately $10.1 million net to the Company on an undiscounted basis. The obligation for abandonment of the Gabon offshore facilities is included in the asset retirement obligation shown on the Company’s balance sheet.

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). Each of the two exploration commitment wells 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. Additional time extensions have been granted by the Angolan government to drill the two exploration commitment wells, the latest extension providing until November 30, 2014.

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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. Following the decree, the Company and the government of Angola have been working together to obtain a replacement partner.

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 July 2013, the Angolan government informed the Company that it should first proceed to acquire the available working interest per the provisions of the Joint Operating Agreement and then enter into a farm-out agreement with the potential partner. The Company is working to accomplish the two-step process outlined by the Angolan government. The Company cannot provide a time estimate for completing these activities as it involves actions by the Angolan government as well as the potential partner.

Due to the continuing circumstances regarding the available 40% working interest, the Company has recorded a full allowance totaling $7.2 million as of June 30, 2013, 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 three and six months ended June 30, 2013 totaled $0.3 million and $1.1 million, respectively. The farm-out agreement, to be executed by the counterparty, provides for the Company to be reimbursed for the gross receivable amount. The timing of this event cannot be reasonably predicted at the present time.

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 column of oil in the Gamba sand reservoir. Additional evaluation of the well and sidetrack information was conducted to determine options for developing the discovery. 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, where a discovery was made on the block prior to VAALCO’s block participation. The final investment decision was approved in the fourth quarter of 2012 for the construction of the platform. Construction began in the first quarter of 2013 and the platform is expected to be transported and installed in the first half of 2014. 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

In the third and fourth quarters of 2012, the Company drilled the N’Gongui No. 2 well with three sidetracks in the Mutamba Iroru block onshore Gabon. Application of the discovery was made timely to the government of Gabon, but the permit has yet to be issued. The Company has capitalized $7.9 million for this well in accordance with the criteria contained in ASC Topic 932.

On June 6, 2013, the Company announced that its Board of Directors has authorized the repurchase of up to $25 million of the Company’s common stock over the next 12 months. Under the share buyback program, shares of common stock will be purchased on the open market or through privately negotiated transactions from time-to-time. The share buyback program does not obligate the Company to acquire any specific number of shares in any period, and may be modified, suspended, extended or discontinued at any time without prior notice. During the quarter ended June 30, 2013, the Company repurchased 233,400 shares at an average price of $5.74 per share totaling $1.3 million.

As of August 1, 2013, the Company repurchased an additional 1,125,706 shares bringing the total amount of shares repurchased in this program to 1,359,106 shares. The average price paid for all shares was $6.00 per share totaling $8.2 million.

The Company’s main operations are based in Gabon, Angola, Equatorial Guinea, and in the United States. Minor activities for the Company’s United Kingdom subsidiary is included in the “Corporate and Other” column in the table. 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.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The Company evaluates each segment based on income (loss) from operations. Segment activity for the three months and six months ended June 30, 2013 and 2012 are as follows:

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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, derivatives 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, 2012.

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

VAALCO owns producing properties and conducts exploration activities as an operator in Gabon, West Africa, conducts exploration activities as an operator in Angola, West Africa, and conducts exploration activities as a non-operator in Equatorial Guinea, West Africa. VAALCO is the operator of unconventional and conventional resource properties in the United States located in Montana and North Texas. The Company also owns minor interests in conventional production activities as a non-operator in the United States.

A significant component of the Company’s results of operations is dependent upon the difference between prices received for its offshore Gabon oil production and the costs to find and produce such oil. 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. Similarly, the costs to find and produce oil and gas are largely not within the control of the Company, particularly in regard to the cost of leasing drilling rigs to drill and maintain offshore wells.

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 five. 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 Southeast Etame and North Tchibala fields, each of which is also located on the Etame Marine block, are in the process of being developed and will also be subject to a 7.5% back-in by the Government of Gabon.

A key focus of the Company is to maintain oil production from the Etame Marin block at optimal levels within the constraints of the existing infrastructure. Five subsea wells plus production from two platforms are tied back by pipelines to deliver oil and associated gas through a riser system to allow for delivery, processing, storage and ultimately offloading the oil from a leased Floating, Production, Storage and Offloading vessel (“FPSO”) anchored to the seabed on the block. With the FPSO limitations of approximately 25,000 BOPD and 30,000 barrels of total fluids per day, the challenge is to optimize production on both a near and long-term basis subject to investment and operational agreements between the Company and the consortium. The Company produces from the Etame, Avouma, South Tchibala and Ebouri fields on the block. During the three and six months ending June 30, 2013, these fields produced approximately 1.5 million Bbls (0.4 million Bbls net to the Company) and 3.0 million Bbls (0.7 million Bbls net to the Company), respectively. The Company’s share of barrels sold reflects an allocation of cost oil and profit oil, and a reduction for royalty of 13%.

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During 2011 and 2012, the Company invested in platform modifications to both the Ebouri and Avouma offshore platforms to accommodate the drilling of additional wells in addition to upgrading the electrical and power generation systems on both platforms. A new personnel accommodation module was installed during 2012 at the Avouma platform. Water knock-out facilities at the Avouma platform are expected to go on-line in the second half of 2013.

The Company has developed a drilling and workover campaign to drill new wells and to perform workovers to replace electrical submersible pumps in existing wells. Late in 2012, the Company commenced work on this campaign with the arrival of a drilling rig to conduct a six well program, with an option to extend the program to a total of eight wells. The six well program included three successful well recompletions to replace electrical submersible pumps, a development well that was successfully drilled and put on production in the Avouma field in April 2013, an unsuccessful exploration appraisal well drilled in the Ebouri field, and an exploration well which is expected to be drilled in the third quarter of 2013 on the Ovoka prospect. The Company and its partners expect to exercise the rig option in the third quarter of 2013 for the additional two wells in the program.

Long-term optimization progress was made in 2012 by the Company and its partners approving the construction of two additional production platforms. The two production platforms are part of the future development plans for the Etame Marin block. One platform will be located in the Etame field and the second platform will be located in-between the Southeast Etame and North Tchibala fields. Multiple wells are expected to be drilled from each of the platforms as part of the future development plans for the Etame Marin block. The Company drilled a successful exploration well in the Southeast Etame area in 2010 which will be developed from the second platform. The expected cost to build and install the platforms in the 2013/2014 timeframe is $325.0 million ($91.0 million net to the Company). The cost of the wells is not included in the platform costs. Construction of the two production platforms began in the first quarter of 2013.

In 2012, the presence of hydrogen sulfide (H2S) from two of the three producing wells in the Ebouri field was discovered. The wells were shut-in for safety reasons resulting in a decrease of approximately 2,000 BOPD or approximately 10% of the gross daily production from the Etame Marin block. Analysis and options for re-establishing production from the impacted area was undertaken in the second half of 2012. The expected outcome is that additional capital investment will be required, which is likely to include a new platform-type structure with H2S processing capability, and new wells to re-establish production from the impacted area. The design, cost projections and final investment decisions by the Company and its partners are expected to be made in the second half of 2013. Re-establishing production from the area impacted by H2S is expected in the first half of 2016. In the second quarter of 2013, the Company spent $0.5 million ($0.2 million net to the Company) to temporarily suspend the two affected wells.

Onshore Gabon

Besides the offshore Etame Marin block in Gabon, the Company operates 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. The Company currently has a 50% working interest in the block. The Company entered into an agreement with Total Gabon in 2010 to continue the exploration

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activities. 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 reprocessing work was completed in 2012.

The exploration well was drilled in 2012 resulting in a discovery at a cost of $19.6 million ($7.9 million net to the Company). Application of the discovery was made timely to the government of Gabon, but the permit has yet to be issued. Development of the onshore block is expected to capitalize on synergies such as office space, warehouse and open yard space and experienced personnel from our operating base in Port Gentil, Gabon.

In 2010, the exploration permit was successfully extended until May 2012 and an application for a further nine-month extension was made in early 2012. The Company and Total Gabon are working with the Gabon government to finalize the extension and to obtain a further exploration extension. The negotiations have continued without reaching agreement. The government of Gabon has proposed new financial and other terms which have not been accepted by the Company. The Company can provide no assurances that an agreement for an extension of the exploration permit will be reached with the government of Gabon.

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%.

By a governmental decree, dated December 1, 2010, the former partner was removed from the production sharing contract. Following the decree, the Company and the government of Angola have been working together to obtain a replacement partner. Additional time extensions have been granted by the Angolan government to drill the two exploration commitment wells, the latest extension providing until November 30, 2014 to drill.

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 July 2013, the Angolan government informed the Company that it should first proceed to acquire the available working interest per the provisions of the Joint Operating Agreement and then enter into a farm-out agreement with the potential partner. The Company is working to accomplish the two-step process outlined by the Angolan government. The Company cannot provide a time estimate for completing these activities as it involves actions by the Angolan government as well as the potential partner.

Due to the continuing circumstances regarding the available 40% working interest, the Company has recorded a full allowance totaling $7.2 million as of June 30, 2013, 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 three and six months ended June 30, 2013 totaled $0.3 million and $1.1 million, respectively. The farm-out agreement, to be executed by the counterparty, provides for the Company to be reimbursed for the gross receivable amount. The timing of this event cannot be reasonably predicted at the present time.

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Offshore Equatorial Guinea

An important goal for the Company is establishing meaningful production operations in more than one country. The Company routinely evaluates working interest opportunities primarily in the West African geographic area where the Company has significant expertise and where the base of the foreign operations is located.

During 2012, the Company identified an opportunity to purchase a working interest in Block P, Equatorial Guinea. In November 2012, the Company completed the acquisition of a 31% working interest in the block at a cost of $10.0 million. Prior to the Company’s acquisition, two oil discoveries had been made on the block, and there is exploration potential on other areas of the block.

Onshore Domestic - Texas

The Company acquired a 640 acre lease, the Hefley field, in the Granite Wash formation in North Texas in December 2010 and a 480 acre lease in the same formation in July 2011. Two wells have been drilled on the Hefley lease acreage and brought on production. The second well began production in March 2012. During the three months ended June 30, 2013, the two wells produced approximately 1,600 Bbls of oil and 87 million cubic feet of gas net to the Company after deduction of royalty and severance taxes. During the six months ended June 30, 2013, the two wells produced approximately 2,400 Bbls of oil and 180 million cubic feet of gas net to the Company after deduction of royalty and severance taxes The Hefley field acreage is held by production. In the second quarter 2013, the Company decided it was unlikely to conduct further exploratory activities on the unevaluated portion of the Hefley field. Accordingly, the Company charged $0.7 million to exploration expense, which represented the remaining book value of the unevaluated Hefley leasehold. The expiration date of the primary term of the 480 acre 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 Sheridan County, Montana in the Middle Bakken formation. The Company drilled two wells on this acreage in 2012. After completion testing beginning in the fourth quarter of 2012 using electrical submersible pumps (ESP’s), both of the wells drilled were determined to be unsuccessful as the operating and water disposal costs exceeded the value of the gas and condensate produced from the wells. Dry-hole cost and leasehold impairment totaling $15.7 million was recognized for these two wells ($14.2 million in the fourth quarter of 2012 and $1.5 million in the first quarter 2013). Leasehold cost of $0.5 million remains capitalized for the acreage in Sheridan County, Montana.

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In September 2011, the Company acquired a 65% working interest in approximately 22,000 gross acres (14,300 net acres) covering the Middle Bakken and deeper formations in the East Poplar unit and the Northwest Poplar field in Roosevelt County, Montana. Pursuant to the terms of the acquisition, the Company was required to drill three wells at its sole cost, one of which was required to be drilled by June 1, 2012 and the remaining two wells were required to be drilled by the end of 2012. A vertical exploration well, which met the time requirement for drilling the first well, was spudded in December 2011 to evaluate the formations. The second exploration well was drilled and completed in the Bakken/Three Forks formations. Both of these wells were unsuccessful efforts, resulting in dry-hole costs and leasehold impairment totaling $18.4 million recorded in the fourth quarter of 2012. The third obligatory well was drilled in the fourth quarter of 2012 at a cost of $2.7 million. Additional completion activities on this well are expected in the second half of 2013 following an expected assumption of operatorship by the other partner in the venture. Leasehold cost of $1.3 million remains capitalized for this acreage in Roosevelt County, Montana.

CAPITAL RESOURCES AND LIQUIDITY

Cash Flows

Net cash used by operating activities for the six months ended June 30, 2013 was $9.5 million, as compared to net cash provided by operating activities of $28.0 million for the six months ended June 30, 2012. The decrease in cash from operations for the six months ended June 30, 2013 compared to the six months ended June 30, 2012 was primarily due to a $8.5 million reduction in net income and a $31.7 million negative variance in changes in operating assets and liabilities, partially offset by a $2.7 million positive variance in non-cash adjustments. The $31.7 million negative variance in changes in operating assets and liabilities was primarily due to two Gabon oil liftings totaling $26.1 million that occurred in the second quarter of 2013, but were not yet due for payment by the buyer as of June 30, 2013, and the repayment of joint venture partner cash call amounts that were billed in excess.

Net cash used in investing activities for the six months ended June 30, 2013 was $41.3 million, compared to net cash used in investing activities for the six months ended June 30, 2012 of $27.1 million. For the six months ended June 30, 2013 the Company paid $40.8 million for capital expenditures, and added $0.5 million to its restricted cash balance in Gabon. 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, 2013, net cash used in financing activities was $1.2 million consisting of treasury stock purchases of $1.3 million, partially offset by the receipt of $0.1 million in proceeds from the issuance of common stock upon the exercise of stock options. 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.

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Capital Expenditures

During the six months ended June 30, 2013, the Company incurred $34.3 million of net property and equipment additions, primarily associated with $19.9 million for the construction of two new platforms offshore Gabon, $10.5 million for two development wells offshore Gabon, and $2.5 million to complete the exploratory well onshore Gabon.

During the second half of 2013, the Company anticipates its share of capital expenditures will approximate $45.0 million primarily associated with the offshore Gabon block for the construction of two platforms and the drilling of two exploration wells.

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 natural 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, 2013, exploration expense was $10.4 million, including $6.4 million related principally to the Company’s dry-hole costs in its United States properties, and $3.0 million of dry-hole costs related to the unsuccessful Ebouri appraisal well. Additional exploration costs incurred in the six months ended June 30, 2013 were $0.4 million onshore Gabon, $0.3 million offshore Gabon, and $0.2 million in Equatorial Guinea.

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

Liquidity

The Company’s primary source of capital has been cash flows from operations. At June 30, 2013, the Company had unrestricted cash of $78.7 million. The Company believes that this cash combined with cash flow from operations will be sufficient to fund the Company’s remaining 2013 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, 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 natural 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.

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Domestic operated production in Texas is sold via two contracts, one for oil and one for gas and natural gas liquids. The Company has access to several alternative buyers for oil, gas, and natural gas liquids domestically.

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VAALCO ENERGY, INC. AND SUBSIDIARIES

RESULTS OF OPERATIONS

Three months ended June 30, 2013 compared to three months ended June 30, 2012

Total Revenues

Total oil and natural gas revenues were $29.1 million for the three months ended June 30, 2013 compared to $58.8 million the same period of 2012.

Oil Revenues

Gabon

Crude oil revenues for the three months ended June 30, 2013 were $28.6 million, a $29.3 million decrease from revenues of $57.9 million for the same period in 2012. In the three months ended June 30, 2013, the Company sold approximately 280,000 net barrels of oil at an average price of $102.21/Bbl., while in the three months ended June 30, 2012 it sold approximately 538,000 net barrels of oil at an average price of $107.51/Bbl. Sales volumes declined in the three months ended June 30, 2013 as compared to the same period in 2012 due to temporary production stoppages resulting from workover activities for replacing electrical submersible pumps on three offshore Gabon wells, as well as the July 2012 shut-in of two of the three producing wells in the Ebouri field, offshore Gabon, as a precaution after detecting H2S.

United States

Condensate sales from the Granite Wash formation wells, located in Hemphill County, Texas for the period ended June 30, 2013 were $0.1 million, resulting from the sale of approximately 1,600 net barrels of oil at an average price of $84.99. For the same period in 2012, condensate sales 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.

Natural Gas Revenues

United States

Natural gas revenues including revenues from natural gas liquids for the three months ended June 30, 2013 were $0.4 million compared to $0.6 million for the same period in 2012. Natural gas sales volumes were 88 MMcf at an average price of $4.60/Mcf for the three months ended June 30, 2013, compared to sales volumes of 158 MMcf at an average price of $3.90/Mcf for the same period in 2012.

Operating Costs and Expenses

Total production expenses for the three months ended June 30, 2013 were $7.0 million compared to $6.5 million for the same period in 2012. The higher production expenses in the three months ended June 30, 2013 compared to the same period in 2012 were primarily due to $4.5 million of well workover costs to replace electrical submersible pumps on three offshore Gabon wells, partially

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offset by $2.2 million lower production costs resulting from higher expenses capitalized associated with unsold crude oil inventory, $1.3 million lower operating expenses for the FPSO facility, and $0.8 million lower expenses for the Domestic Market Obligation (“DMO”) to the Republic of Gabon. For the three months ended June 30, 2013, the Company’s Gabon production was approximately 16,900 BOPD (4,100 BOPD net to the Company), as compared to approximately 20,100 BOPD (4,900 BOPD net to the Company) for the same period in 2012.

Exploration expenses for the three months ended June 30, 2013 was $4.3 million, compared to $3.5 million for the same period in 2012. For the three months ended June 30, 2013, exploration expenses consisted primarily of $3.0 million dry-hole costs related to the unsuccessful Ebouri appraisal well offshore Gabon, $0.7 million to expense the remaining unevaluated leasehold cost of the Hefley lease in the Texas Granite Wash area, and $0.5 million additional dry-hole costs related to other United States properties that were previously deemed unsuccessful. For the three months ended June 30, 2012, exploration expenses consisted 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.

Depreciation, depletion and amortization expenses were $3.4 million in the three months ended June 30, 2013 compared to $6.9 million in the three months ended June 30, 2012. The lower depreciation, depletion and amortization expenses during the three months ended June 30, 2013 compared to the same period in 2012 were primarily due to lower sales volumes in Gabon as a result of the two wells shut-in for the H2S issue in July 2012 and three wells that underwent replacement of electrical submersible pumps.

General and administrative expenses for the three months ended June 30, 2013 and 2012 were $2.5 million and $3.0 million, respectively. The decrease in general and administrative costs in the three months ended June 30, 2013 compared to the same period in 2012 was primarily due to a $1.7 million cost reduction due to higher overhead reimbursements resulting from the active development program offshore Gabon, partially offset by higher stock compensation expenses of $0.4 million, and higher support services costs of $0.5 million.

Other Income

Other income for the three months ended June 30, 2013 was $14,000, comprised principally of interest 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.

Income Taxes

Income tax expense amounted to $4.6 million and $26.7 million for the three months ended June 30, 2013 and 2012, respectively. In the three months ended June 30, 2013 and 2012, the income taxes were all paid in Gabon. Income taxes in the three months ended June 30, 2013 were lower due to lower sales volumes and 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 for the three months ended June 30, 2013 was $7.1 million, compared to $12.3 million for the same period in 2012. Net income allocated to the noncontrolling interest was $1.9 million in the three months ended June 30, 2012.

The noncontrolling interest, which was associated with VAALCO Energy (International), Inc., a subsidiary that was 90.01% owned by the Company, was acquired by the Company at a cost of $26.2 million effective October 1, 2012.

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Six months ended June 30, 2013 compared to six months ended June 30, 2012

Total Revenues

Total oil and natural gas revenues were $73.3 million for the six months ended June 30, 2013 compared to $104.1 million for the same period of 2012.

Oil Revenues

Gabon

Crude oil revenues for the six months ended June 30, 2013 were $72.2 million, a $30.4 million decrease from revenues of $102.6 million for the same period of 2012. The Company sold approximately 676,000 net barrels of oil equivalent at an average price of $106.82/Bbl. in the six months ended June 30, 2013. The Company sold approximately 906,000 net barrels of oil equivalent at an average price of $113.25/Bbl. in the six months ended June 30, 2012. Sales volumes declined in the six months ended June 30, 2013 as compared to the same period in 2012 due to temporary production stoppages resulting from workover activities for replacing electrical submersible pumps on three offshore Gabon wells, as well as the July 2012 shut-in of two wells in the Ebouri field, offshore Gabon, as a precaution after detecting H2S.

United States

Condensate sales from the Granite Wash wells, located in Hemphill County, Texas for the six months ended June 30, 2013 were $0.2 million, resulting from approximately 2,400 barrels at an average price of $80.67/Bbl. Condensate sales 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.

Natural Gas Revenues

United States

Natural gas revenues, including revenues from natural gas liquids, for the six months ended June 30, 2013 were $0.8 million compared to $1.0 million for the comparable period in 2012. Natural gas sales volumes were 183 MMcf at an average price of $4.47/Mcf for the six months ended June 30, 2013, compared to sales volumes of 274 MMcf at an average price of $3.82/Mcf for the same period in 2012.

Operating Costs and Expenses

Total production expenses for the six months ended June 30, 2013 were $15.4 million compared to $12.1 million in the six months ended June 30, 2012. The higher production expenses in the six months ended June 30, 2013 were primarily associated with $ 5.7 million of workover costs to replace failed electrical submersible pumps, partially offset by $1.5 million lower production costs resulting from higher expenses capitalized associated with unsold crude oil inventory, $1.1 million lower expenses for the DMO payable to the Republic of Gabon. For the six months ended June 30, 2013, the Company’s Gabon production was approximately 16,700 BOPD (4,100 BOPD net to the Company), as compared to approximately 20,700 BOPD (5,000 BOPD net to the Company) for the six months ended June 30, 2012.

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For the six months ended June 30, 2013, exploration expense was $10.4 million, including $6.4 million related principally to the Company’s dry-hole costs in its United States properties, and $3.0 million dry-hole costs related to the unsuccessful Ebouri appraisal well. Additional exploration costs incurred in the six months ended June 30, 2013 were $0.4 million onshore Gabon, $0.3 million offshore Gabon, and $0.2 million in Equatorial Guinea.

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.

Depreciation, depletion and amortization expenses were $7.1 million in the six months ended June 30, 2013 compared to $11.9 million in the six months ended June 30, 2012. The lower depreciation, depletion and amortization expenses during the six months ended June 30, 2013 compared to the same period in 2012 were primarily due to lower sales volumes in Gabon as a result of two wells shut-in for the H2S issue in July 2012 and three wells that underwent replacement of electrical submersible pumps.

General and administrative expenses for the six months ended June 30, 2013 and 2012 were $6.1 million and $6.5 million, respectively. During the six months ended June 30, 2013, the Company incurred $2.2 million of stock based compensation expense compared to $1.7 million incurred in the six months ended June 30, 2012. In both of the six month periods ended June 30, 2013 and 2012, 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, 2013 was $2.2 million compared to $1.2 million in the same period in 2012.

Other Income (expense)

Other expense for the six months ended June 30, 2013 was $55,000, compared to other income of $0.7 million for the same period in 2012. The other expense and other income recorded in each of the six months ended June 30, 2013 and 2012 were primarily attributable to foreign exchange transactions.

Income Taxes

Income tax expense amounted to $18.8 million and $46.5 million for the six months ended June 30, 2013 and 2012, respectively. In the six months ended June 30, 2013 and 2012, the income taxes were all paid in Gabon. Income taxes in the six months ended June 30, 2013 were lower due to lower sales volumes and 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 for the six months ended June 30, 2013 was $14.3 million, compared to a net income of $22.8 million for the same period in 2012. Net income allocated to the noncontrolling interest for the six months ended June 30, 2012 was $3.4 million.

The noncontrolling interest, which was associated with VAALCO Energy (International), Inc., a subsidiary that was 90.01% owned by the Company, was acquired by the Company at a cost of $26.2 million effective October 1, 2012.

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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

Other than as described below, there have been no material changes to the disclosure on this matter in our annual report on form 10-K for the year ended December 31, 2012.

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

Our international assets and operations are subject to various political, economic and other uncertainties, including, among other things, the risks of war, expropriation, nationalization, renegotiation or nullification of existing contracts, taxation policies, foreign exchange restrictions, changing political conditions, international monetary fluctuations, currency controls and foreign governmental regulations that favor or require the awarding of drilling contracts to local contractors or require foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. For example, the Gabonese government has recently audited the accounts of a number of energy companies that has led to disputes and may have caused the cancellation of a contract with an operator and is currently in the process of auditing our accounts, the Gabonese government has formed a new oil company that may seek to participate in oil and gas projects in a manner that could be dilutive to the interest of current license holders and the Gabonese government is under pressure from the Gabonese labor union to require companies to hire Gabonese citizens. In addition, if a dispute arises with foreign operations, we may be subject to the exclusive jurisdiction of foreign courts or may not be successful in subjecting foreign persons, especially foreign oil ministries and national oil companies, to the jurisdiction of the United States. Private ownership of oil and gas reserves under oil and gas leases in the United States differs distinctly from our ownership of foreign oil and gas properties. In the foreign countries in which we do business, the state generally retains ownership of the minerals and consequently retains control of, and in many cases participates in, the exploration and production of hydrocarbon reserves. Accordingly, operations outside the United States may be materially affected by host governments through royalty payments, export taxes and regulations, surcharges, value added taxes, production bonuses and other charges.

Almost all of our proven reserves are located offshore of the Republic of Gabon. We have operated in Gabon since 1995 and believe we have good relations with the current Gabonese government. However, there can be no assurance that present or future administrations or governmental regulations in Gabon will not materially adversely affect our operations or cash flows.

There has been a recent surge in piracy in the Gulf of Guinea region including waters off Gabon. Unlike waters off the coast of East Africa, where ships can move past at high speed with armed guards on board, many vessels, including our productions platforms, have to anchor off West African coastal nations, with little protection. Our offshore operations and personnel may therefore be subject to armed robbery, hijack and kidnap for ransom, which could result in a cessation of operations.

(a) Exhibits

3. Articles of Incorporation and Bylaws

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

Section 1350 Certificates

101.INS XBRL Instance Document. *

101.SCH XBRL Taxonomy Schema Document. *

101.CAL XBRL Calculation Linkbase Document. *

101.DEF XBRL Definition Linkbase Document. *

101.LAB XBRL Label Linkbase Document. *

101.PRE XBRL Presentation Linkbase Document. *

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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: August 8, 2013

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EXHIBIT INDEX

Exhibits

3. Articles of Incorporation and Bylaws

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

Section 1350 Certificates

101.INS XBRL Instance Document. *

101.SCH XBRL Taxonomy Schema Document. *

101.CAL XBRL Calculation Linkbase Document. *

101.DEF XBRL Definition Linkbase Document. *

101.LAB XBRL Label Linkbase Document. *

101.PRE XBRL Presentation Linkbase Document. *

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