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 x 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, 2014, there were outstanding 56,958,108 shares of common stock, $0.10 par value per share, of the registrant.

	June 30, 2014			December 31, 2013
Current Assets:
Cash and cash equivalent	$	118,567		$	130,529
Restricted cash		12,301			12,366
Receivables:
Trade		21,585			16,972
Accounts with partners, net of allowance of zero at June 30, 2014 and $7.6 million at December 31, 2013		1,490			307
Other		5,494			4,435
Crude oil inventory		305			352
Materials and supplies		503			164
Prepayments and others		2,528			2,339
Total current assets		162,773			167,464

Property and equipment - successful efforts method
Wells, platforms and other production facilities		218,422			215,701
Undeveloped acreage		22,133			23,705
Work in progress		102,858			64,489
Equipment and other		6,864			6,831
		350,277			310,726
Accumulated depreciation, depletion and amortization		(182,825	)		(172,202	)
Net property and equipment		167,452			138,524

Other assets:
Restricted cash		830			830
Deferred tax assets		1,349			1,349
Deferred finance charge		1,913			-

Total Assets	$	334,317		$	308,167

Current Liabilities:
Accounts payable and other liabilities	$	49,739		$	42,561
Accounts with partners		1,618			3,268
Total current liabilities		51,357			45,829

Asset retirement obligations		11,732			11,464
Total Liabilities		63,089			57,293
Commitments and Contingencies (note 4)
Owners' Equity
Common stock, $0.10 par value, 100,000,000 authorized shares, 64,052,813 and 64,012,914 shares issued with 7,094,705 and 7,162,573 shares in treasury at June 30, 2014 and December 31, 2013 respectively		6,415			6,408
Additional paid-in capital		57,755			55,455
Retained earnings		242,118			224,442
Less treasury stock, at cost		(35,061	)		(35,431	)
Total Equity		271,227			250,874
Total Liabilities and Owners' Equity	$	334,317		$	308,167

	Three months ended June 30,						Six months ended June 30,
	2014			2013			2014			2013
Revenues:
Oil and gas sales	$	52,098		$	29,118		$	80,172		$	73,255

Operating costs and expenses
Production expense		4,848			7,015			14,498			15,399
Exploration expense		3,293			4,280			14,616			10,386
Depreciation, depletion and amortization		6,995			3,431			11,155			7,057
General and administrative expense		3,134			2,464			6,722			6,102
Bad debt expense and other expense		-			262			-			1,141
Total operating cost and expenses		18,270			17,452			46,991			40,085

Operating income		33,828			11,666			33,181			33,170

Other income (expenses):
Interest income		17			16			46			41
Other, net		(125	)		(2	)		(416	)		(96	)
Total other income (expenses)		(108	)		14			(370	)		(55	)
Income before income taxes		33,720			11,680			32,811			33,115
Income tax expense		(9,009	)		(4,559	)		(15,135	)		(18,805	)

Net income		24,712			7,121			17,676			14,310

Earnings per share - basic:
Basic net income per share attributable to VAALCO Energy, Inc. common shareholders	$	0.43		$	0.12		$	0.31		$	0.25

Earnings per share - diluted:
Diluted net income per share attributable to VAALCO Energy, Inc. common shareholders	$	0.43		$	0.12		$	0.31		$	0.24
Basic weighted-average shares outstanding		56,951			57,901			56,906			57,904
Diluted weighted-average shares outstanding		57,537			58,560			57,393			58,786

	VAALCO ENERGY, Inc. Shareholders
	Common		Additional Paid-In			Retained		Treasury
	Stock		Capital			Earnings		Stock			Total
Balance at January 1, 2014	$	6,408	$	55,455		$	224,442	$	(35,431	)	$	250,874
Proceeds from stock issuance		7		613								620
Stock based compensation				2,057					-			2,057
Reissuance of treasury stock under stock based compensation plans				(370	)		-		370			-
Net income							17,676					17,676
Ending balance at June 30, 2014		6,415		57,755			242,118		(35,061	)		271,227

	Six months ended June 30,
	2014			2013
Operating Activities:
Net income	$	17,676		$	14,310
Adjustments to reconcile net income to net cash used in operating activities
Depreciation, depletion and amortization		11,155			7,057
Unrealized foreign exchange loss		22			22
Dry hole costs and impairment loss on unproved leasehold		13,273			8,836
Stock based compensation		2,057			2,238
Bad debt expense		-			1,141
Change in operating assets and liabilities:
Trade receivables		(4,613	)		(18,266	)
Accounts with partners		(2,834	)		(20,010	)
Other receivables		(1,140	)		(3,306	)
Crude oil inventory		(216	)		(1,944	)
Materials and supplies		(339	)		(305	)
Prepayment and other		(191	)		(1,166	)
Accounts payable and other liabilities		5,710			1,848
Net cash provided by (used in) operating activities		40,560			(9,545	)

Cash Flows from Investing Activities
Decrease (increase) in restricted cash		65			(510	)
Property and equipment expenditures		(51,292	)		(40,833	)
Net cash used in investing activities		(51,227	)		(41,343	)

Cash Flows from Financing Activities
Proceeds from the issuance of common stock		620			135
Debt issuance costs		(1,914	)		-
Purchase of treasury shares		-			(1,339	)
Net cash used in financing activities		(1,295	)		(1,204	)

Net Change in Cash and Cash Equivalents		(11,962	)		(52,092	)

Cash and Cash Equivalent at Beginning of Period		130,529			130,800

Cash and Cash Equivalent at End of Period	$	118,567		$	78,708

Supplemental disclosure of cash flow information
Income taxes paid	$	15,122		$	18,416
Investment in property and equipment not paid	$	14,971		$	11,238

1. UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND ACCOUNTING POLICIES

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, 2013, 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 Energy, Inc., a Delaware corporation, is a Houston-based independent energy company principally engaged in the acquisition, exploration, development and production of crude oil and natural gas. VAALCO owns producing properties and conducts exploration activities as operator of consortiums internationally in Gabon and Angola and has conducted exploration activities as a non-operator in Equatorial Guinea, West Africa. Domestically, the Company has interests in Texas, Montana, Alabama, and the Louisiana Gulf Coast area.

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.

In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” The new standard converged guidance on recognizing revenues in contracts with customers under accounting principles generally accepted in the United States and International Financial Reporting Standards. This ASU is intended to improve comparability of revenue recognition practices across entities, industries, jurisdictions and capital markets. ASU 2014-09 is effective for annual and quarterly reporting periods of public entities beginning after December 15, 2016. Early application for public entities is not permitted. We are currently evaluating the provisions of ASU 2014-09 and assessing the impact, if any, it may have on our financial position and results of operations.

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, restricted and unrestricted shares having exercise prices less than the average market price of the common stock using the treasury stock method.

Options to purchase 2,207,224 and 2,407,224 share were excluded in the three months and six months ended June 30, 2014, because they would have been anti-dilutive. Options to purchase 3,205,865 and 2,135,300 shares were excluded in the three months and six months ended June 30, 2013, 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 to employees 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 the six months ended June 30, 2014 and 2013 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 of our Board of Directors. At June 30, 2014, there were 4,284,693 shares subject to options authorized but not granted.

For the three months and six months ended June 30, 2014, the Company recognized non-cash compensation expense of $0.6 million and $2.0 million, respectively, related to stock options and restricted stock grants. 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. 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.

A summary of the stock option activity for the six months ended June 30, 2014 is provided below:

	Number of Shares Underlying Options (in thousands)			Weighted Average Exercise Price Per Share		Weighted Average Remaining Contractual Term		Aggregate Intrinsic Value (in millions)
Outstanding at the beginning of period		4,927		$	6.95		2.85	$	2.81
Granted		1,118		$	7.05		4.68
Exercised		(76	)	$	8.16		3.27
Forfeited		(31	)	$	8.51		2.70
Outstanding at the end of period		5,938		$	6.95		2.78	$	3.93
Vested and expected to vest - end of period		5,888		$	6.95		2.78	$	3.92

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.

Shares of restricted stock are granted under the Company’s long-term incentive plan using the fair market value of the underlying shares on the date of grant. In general, restricted stocks granted to employees will vest over a period determined by the Compensation Committee which is generally a three year period, with the initial one-third vesting on the first grant date anniversary.

No restricted stocks were granted in the three months ended June 30, 2014. A summary of the restricted stock activity for the six months ended June 30, 2014 is provided below:

As of June 30, 2014, unrecognized compensation costs totaled $4.2 million. The expense is expected to be recognized over a weighted average period of 2.7 years.

As part of securing the second ten year production license with the government of Gabon for the Etame Marin block, the Company agreed to a cash funding arrangement for the eventual abandonment of the offshore wells, platforms and facilities. The agreement is pending final approval and will provide for annual funding over the remaining life of the production license. The amounts paid will be reimbursed through the cost account and are non-refundable to the Company. The funding is expected to begin in the third quarter of 2014. As in prior periods, the obligation for abandonment of the Gabon offshore facilities is included in the asset retirement obligation shown on the Company’s balance sheet.

The sixth exploration license for the Etame Marin block expired on July 7, 2014. In the second quarter of 2014 and prior to the deadline, the Company submitted a proposal for a seventh exploration license and is in negotiations with the Republic of Gabon to obtain the extension. The balance of undeveloped leasehold costs of $0.8 million was recorded as exploration expense in the second quarter of 2014 due to the uncertainty of entering into a seventh exploration license on the block.

The Company is the operator of Block 5, offshore Angola, a 1.4 million acre property. 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. The Company has a two well exploration commitment. The Company’s two year extension to drill the wells expires on November 30, 2014. In April 2014, the Company received a letter and contractual amendment proposal from Sonangol E.P., which is expected to be approved prior to the expiration of the extension, by the government of Angola. The contractual amendment provides for a three year time extension for the exploration permit until November 30, 2017. The amendment also outlines the timing for the drilling of the two exploration wells, which was an obligation under the terms of the original agreement. The amendment provides for the commencement of one exploration well prior to November 30, 2014 and the commencement of a second well by early 2016. Each well is subject to a $5.0 million penalty net to the Company, if not drilled during the contract term. The $10.0 million non-performance commitment is currently recorded as restricted cash and is held at a financial institution located in the United States.

In the first quarter of 2014, the Company purchased 3D seismic in the outboard segment of the block which is currently being processed. The seismic processing is expected to be completed in the first quarter of 2015. In the second quarter of 2014, the Company secured for a jack-up drilling rig to drill an exploration well on the Kindele prospect, a post-salt objective. The drilling rig contract was signed in July 2014, and the well is expected to be drilled in the fourth quarter of 2014. Drilling this well will satisfy the well commitment required by the proposed extension.

The Company is carrying $11.7 million of asset retirement obligation as of June 30, 2014, representing the present value of our future obligations for the future abandonment costs of tangible assets such as platforms, well, pipelines and other facilities.

ASC Topic 932—Extractive Industries provides that the cost of 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 that is not brought on to production would be assumed to be impaired and its costs would be charged to expense.

Offshore Gabon: In the second and third quarters of 2010, the Company drilled an exploratory well in the Southeast Etame field. In the second quarter of 2012, the Company and its partners approved a development plan featuring a fixed leg platform for developing both the Southeast Etame discovery area and the North Tchibala field. A platform is scheduled for installation in the second half of 2014 and a rig has been contracted to drill development wells targeting both fields in 2015. The Company has capitalized $7.8 million for the discovery well in accordance with the criteria contained in the ASC Topic 932.

Onshore Gabon: In the third and fourth quarters of 2012, the Company drilled an exploratory well (N’Gongui No. 2) in the Mutamba Iroru block onshore Gabon. A revised production sharing contract (“PSC”) including exploration rights was submitted in April 2014 for approval by the Republic of Gabon. The term sheet, which specifies financial and other obligations to be included in the PSC, was agreed to and signed by the Gabon government, the Company and its joint venture partner on July 31, 2014. After the PSC is approved, an application for a development area is expected to be issued without further delay. At that point, a plan of development will be submitted to the Republic of Gabon. However, the Company can provide no assurances that such a request will be granted. The Company has capitalized $8.9 million for the discovery well in accordance with the criteria contained in ASC Topic 932.

In January 2014, the Company executed a loan agreement with the International Finance Corporation (“IFC”) for a $65.0 million revolving credit facility, which is secured by the assets of the Company’s Gabon subsidiary. The revolving facility matures in January 2019 at which point it can be extended or converted to a term loan. The Company has had no borrowing under the IFC loan to date.

Under the terms of the IFC loan executed in 2014, the Company is required to pay a commitment fee on the undrawn component of the credit facility.

The Company capitalizes interest costs and commitment fees to oil and natural gas properties on expenditures made in connection with exploration and development projects that are not subject to current depletion. Interest and commitment fees are capitalized only for the period that activities are in progress to bring these projects to their intended use. For the three months and six months ended June 30, 2014, the Company incurred interest expense of $0.3 million and 0.5 million, respectively, in connection with our IFC loan. The entire expense was capitalized in the period.

The Company’s operations are based in Gabon, Angola, Equatorial Guinea and 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. The accounting policies of the reportable segments are the same as in Note 1. 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 and six months ended June 30, 2014 and 2013 are as follows:

												Corporate
	Gabon		Angola			Equatorial Guinea			USA			and Other			Total
Three Months Ended June 30,
2014
Revenues	$	51,631	$	-		$	-		$	467					$	52,098
Income (loss) from operations		36,223		(721	)		(139	)		130			(1,666	)	$	33,828


2013
Revenues	$	28,574	$	-		$	-		$	544		$	-		$	29,118
Income (loss) from operations		14,853		(379	)		(165	)		(1,336	)		(1,307	)	$	11,666

												Corporate
	Gabon		Angola			Equatorial Guinea			USA			and Other			Total
Six Months Ended June 30,
2014
Revenues	$	79,375	$	-		$	-		$	797		$	-		$	80,172
Income (loss) from operations		38,913		(1,847	)		(339	)		67			(3,614	)		33,181


2013
Revenues	$	72,229	$	-		$	-		$	1,026		$	-		$	73,255
Income (loss) from operations		45,717		(1,582	)		(455	)		(7,028	)		(3,482	)		33,170

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 future financial position, capitalization of exploration and interest expense, future operating performance and results, reserve quantities and net present values, future commodity prices, business strategy, derivatives activities, the amount and nature of future 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,” “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, 2013.

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 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.

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 Texas and Montana. 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.

A key focus of the Company is to maintain oil production from the Etame Marin block, located offshore Gabon, at optimal levels within the constraints of the existing infrastructure. The Company operates the Etame, Avouma, South Tchibala and Ebouri fields on behalf of a consortium of five companies. Three 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.

As part of the near-term optimization, drilling and workover campaigns are developed and executed to drill new wells, replace maturing wells, develop bypassed oil and perform workovers to replace electrical submersible pumps (“ESP’s”) in existing wells. In the first quarter of 2014, the Company drilled an unsuccessful exploratory well offshore Gabon and performed a workover to replace the ESP’s on a well on the Avouma field. In April 2014, the Company commenced drilling a development well in the South Tchibala field to replace a well with damaged casing. The well was successfully brought on production in May 2014.

Long-term optimization progress was made by the Company and its partners approving the construction of two additional production platforms for installation in 2014. 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 between the Southeast Etame and North Tchibala fields. The Company drilled a successful exploration well in the Southeast Etame area in 2010 which will be developed from the second platform. The Company has contracted a drilling rig to commence, at a minimum, a six development well drilling program, which is expected to begin in the fourth quarter of 2014. The total cost to build and install the platforms is expected to be $325.0 million ($91.0 million net to the Company). The cost of the wells is not included in the platform costs. At the end of June 30, 2014, the platform jackets were completed and en route to Gabon for installation. The deck sections are substantially complete and began their journey to Gabon in July 2014.

In July 2012, the Company discovered the presence of hydrogen sulfide (“H₂S”) from two of the three producing wells in the Ebouri field. The wells were shut-in for safety reasons resulting in a decrease of approximately 2,000 BOPD on a gross basis or approximately 10% of the gross daily production from the Etame Marin block. In addition, field testing conducted in the second quarter of 2014 confirmed the Etame 5-H well produces low levels of H₂S. This well, which was producing approximately 300 BOPD on a gross basis, has been temporarily shut-in pending laboratory analysis expected in the third quarter of 2014. Analysis and options for re-establishing production from the impacted areas continued through the second quarter of 2014. To re-establish and maximize production from the impacted areas, additional capital investment will be required, including a new centralized platform processing facility capable of removing H₂S from Etame Marin block production, recompletion of the temporarily abandoned wells, and potentially additional new wells. The design, cost projections and final investment decisions by the Company and its partners are expected to be completed in the first quarter of 2015. Re-establishing production from the areas impacted by H₂S is expected in the first half of 2017.

The sixth exploration license for the Etame Marin block expired on July 7, 2014. In the second quarter of 2014, the Company submitted a proposal for a seventh exploration license and is in negotiations with the Republic of Gabon to obtain the extension. The balance of undeveloped leasehold costs of $0.8 million was recorded as exploration expense in the second quarter of 2014 due to the uncertainty of entering into a seventh exploration license on the block.

The Company operates in the Mutamba Iroru block located onshore Gabon. The Company has a 50% working interest in the block (41% net working interest assuming the Republic of Gabon exercises its back-in rights). The N’Gongui discovery well was drilled in 2012 and the Company is currently finalizing a revised production sharing contract (“PSC”) with the government of Gabon. The term sheet, which specifies financial and other obligations to be included in the PSC, was agreed to and signed by the Gabon government, the Company and its joint venture partner on July 31, 2014. After the PSC is approved, an application to the Republic of Gabon for a development area will be made followed by the submission of a plan of development. However, the Company can provide no assurances that the PSC will be finalized nor that the development area will be granted. 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 the first quarter of 2014, the Company purchased 3D seismic in the outboard segment of the block which is currently being processed. The seismic processing is expected to be completed in the first quarter of 2015. In the second quarter of 2014, the Company secured for a jack-up drilling rig to drill an exploration well on the Kindele prospect, a post-salt objective. The drilling rig contract was signed in July 2014 and the well is expected to be drilled in the fourth quarter of 2014. Drilling this well will satisfy the well commitment required by the proposed extension.

The Company has a 31% working interest in Block P, offshore Equatorial Guinea. Prior to the Company’s acquisition in the block, two oil discoveries had been made on the block, and there is exploration potential on other areas of the block. The Company continues to work with GEPetrol, the block operator, on a joint operatorship model and with the Ministry of Mines, Industry and Energy regarding timing and budgeting for development and exploration activities.

The Company operates two producing wells in the Granite Wash formation in Texas and has a leasehold position in Montana. The Company is not expecting to focus on further domestic activities or property acquisitions in the near term. The Company also owns minor interests in conventional production activities as a non-operator in the United States.

Net cash provided by operating activities for the six months ended June 30, 2014 was $40.6 million, as compared to net cash used in operating activities of $9.5 million for the six months ended June 30, 2013. The increase in cash from operations for the six months

ended June 30, 2014 compared to the six months ended June 30, 2013 was primarily due to a $39.5 million positive variance in changes in operating assets and liabilities, partially offset by a $6.1 million negative variance in non-cash adjustments. The $39.5 million positive variance in changes in operating assets and liabilities was primarily due to decrease in receivables from trade and partner receivable balances. The decrease in non-cash adjustments is due to an increase in depreciation, depletion and amortization costs along with an increase in dry hole expenses related to the unsuccessful well offshore Gabon. In the six months ended June 30, 2014, the company incurred $11.7 million in dry hole cost and $1.6 million in leasehold impairments, compared to $8.8 million in dry hole cost in the six months ended June 30, 2013.

Net cash used in investing activities for the six months ended June 30, 2014 was $51.3 million, compared to net cash used in investing activities for the six months ended June 30, 2013 of $41.3 million. For the six months ended June 30, 2014 the Company paid $51.3 million for capital expenditures. 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, 2014, net cash used in financing activities was $1.3 million consisting of $1.9 million related to the debt issuance cost for attaining a loan from the International Finance Corporation (“IFC”) in the amount of $65.0 million partially offset by proceeds from the issuance of common stock upon the exercise of options of $0.6 million. 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.

During the six months ended June 30, 2014, the Company incurred $39.6 million of net property and equipment additions, primarily associated with $32.8 million for the construction of two new platforms. Additionally, the Company spent $5.8 million related to the drilling of a replacement development well in South Tchibala field, offshore Gabon and paid an initial payment of approximately $1.0 million towards the purchase of an office building in Gabon. In the second half of 2014, the Company anticipates its share of capital expenditures will approximate $66.0 million primarily associated with the offshore Gabon block for the construction of the two platforms.

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, 2014, exploration expense was $14.6 million, primarily comprised of $11.7 million related to the unsuccessful offshore Gabon exploration well, $1.6 million related to the impairment of leasehold costs offshore Gabon, and $1.0 million in Angola for seismic processing.

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.

The Company’s primary sources of capital have historically been from cash flows from operations and a strong cash balance on hand. The Company also has access to capital through the IFC loan facility as well as future sales of the Company’s debt and equity securities.

At June 30, 2014, the Company had unrestricted cash of $118.6 million. The Company believes that this cash combined with cash flow from operations and the IFC loan facility will be sufficient to fund the Company’s remaining 2014 capital expenditure budget, and additional working capital requirements 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.

In January 2014, the Company entered into the $65.0 million revolving credit facility with IFC, secured by the assets of the Company’s Gabon subsidiary. The revolving facility matures in January 2019 at which point it can be extended or converted to a term loan. To date, the Company had not borrowed under the loan.

The IFC loan also requires the Company to maintain the following financial ratios:

Amounts outstanding under the IFC Loan bear interest at the London InterBank Offered Rate plus 3.75% for the senior tranche and LIBOR plus 5.75 for the subordinated tranche. The Company is also required to pay a commitment fee in respect of unutilized commitments which is equal to 1.5% on the senior tranche and 2.3% on the subordinated tranche. The Company paid a 2.5% closing fee in connection with the loan.

Beginning in the second quarter of 2014, the Company markets its oil from Gabon with a third party on a fixed barrel fee for selling on the spot market.

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.

Total oil and natural gas revenues were $52.1 million for the three months ended June 30, 2014 compared to $29.1 million for the same period in 2013. The increase in revenue is primarily related to the higher number of barrels lifted from the Company’s offshore Gabon operations and an increase in sales price per barrel in the three months ended June 30, 2014 compared to the same period in 2013.

Crude oil revenues for the three months ended June 30, 2014 were $51.6 million, a $22.7 million increase from revenues of $28.6 million for the same period in 2013. In the three months ended June 30, 2014, the Company sold approximately 480,000 net barrels of oil at an average price of $108.24 per Bbl, while in the three months ended June 30, 2013 it sold approximately 280,000 net barrels of oil at an average price of $102.21 per Bbl. Sales volumes increased in the three months ended June 30, 2014 as compared to the same period in 2013, due to higher number of barrels lifted.

In the three months ended June 30, 2014, the Company produced approximately 446,000 barrels compared to approximately 432,000 barrels for the same period ended June 30, 2013. Crude oil sales are a function of the number and size of crude oil liftings in each quarter from the FPSO and thus crude oil sales do not always coincide with volumes produced in any given quarter.

Condensate sales from the Granite Wash formation wells, located in Hemphill County, Texas for the three months ended June 30, 2014 were $0.2 million, resulting from the sale of approximately 1,400 net barrels of oil at an average price of $107.64. For the same period in 2013, condensate sales were $0.1 million, resulting from the sale of approximately 1,600 net barrels of oil condensate at an average price of $84.99 per Bbl.

Natural gas revenues including revenues from natural gas liquids for the three months ended June 30, 2014 were $0.3 million compared to $0.4 million for the same period in 2013. Natural gas sales volumes were 56 MMcf at an average price of $5.61/Mcf for the three months ended June 30, 2014, compared to sales volumes of 88 MMcf at an average price of $4.60Mcf for the same period in 2013.

Total production expenses for the three months ended June 30, 2014 were $4.8 million compared to $7.0 million for the same period in 2013. The lower production expenses in the three months ended June 30, 2014 compared to the same period in 2013 were due to non-operational adjustments recorded in the second quarter of 2014 including an accrual true-up.

Exploration expenses for the three months ended June 30, 2014 was $3.3 million, compared to $4.2 million for the same period in 2013. For the three months ended June 30, 2014, exploration expenses consisted primarily of $2.0 million related to an unsuccessful offshore Gabon exploration well and $0.8 million related to the impairment of unevaluated leasehold costs offshore Gabon. Additional exploration costs incurred in the three months ended June 30, 2014 were $0.3 million in Angola related to seismic processing.

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.

Depreciation, depletion and amortization expenses were $7.0 million for the three months ended June 30, 2014 compared to $3.4 million for the three months ended June 30, 2013. The higher depreciation, depletion and amortization expenses during the three months ended June 30, 2014 compared to the same period in 2013 were primarily due to higher sales volumes in Gabon and due to higher depletion rates. Depletion rates increased from $9.92 per Bbl for the three months ended June 30, 2013 to $12.43 per Bbl for the three months ended June 30, 2014.

General and administrative expenses for the three months ended June 30, 2014 and 2013 were $3.1 million and $2.5 million, respectively. The increase in general and administrative costs for the three months ended June 30, 2014 compared to the same period in 2013 was primarily due to increased personnel, and higher support services costs. For three month ended June 30, 2014 and 2013, the Company benefited from overhead reimbursement associated with production and development operations on the Etame Marin block.

Other expenses for the three months ended June 30, 2014 was $0.1 million, comprised principally of foreign exchange loss. Other income for the three months ended June 30, 2013 was $14,000, comprised primarily of a foreign interest income.

Income tax expense amounted to $9.0 million and $4.6 million for the three months ended June 30, 2014 and 2013, respectively. For the three months ended June 30, 2014 and 2013, the income taxes were all paid in Gabon. Income taxes for the three months ended June 30, 2014 were higher due to higher sales volumes and a higher ratio of profit oil barrels versus cost oil barrels. 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 for the three months ended June 30, 2014 was $24.7 million, compared to $7.1 million for the same period in 2013. Net income increased due to an increase in revenue as a result of higher sales volumes lifted in the three months ended June 30, 2014.

Total oil and natural gas revenues were $80.2 million for the six months ended June 30, 2014 compared to $73.3 million for the same period in 2013. The increase in revenue is primarily due to an increase in sales volumes and oil prices per barrel.

Crude oil revenues for the six months ended June 30, 2014 were $79.4 million, a $7.2 million increase from revenues of $72.2 million for the same period of 2013. The Company sold approximately 734,000 net barrels of oil equivalent at an average price of $108.14 per Bbl for the six months ended June 30, 2014. The Company sold approximately 676,000 net barrels of oil equivalent at an average price of $106.82 per Bbl. for the six months ended June 30, 2013.

For the six months ended June 30, 2014, the Company produced approximately 836,000 barrels compared to approximately 851,000 net barrels for the same period ended June 30, 2013. Crude oil sales are a function of the number and size of crude oil liftings in each quarter from the FPSO and thus crude oil sales do not always coincide with volumes produced in any given quarter.

Condensate sales from the Granite Wash wells, located in Hemphill County, Texas for the six months ended June 30, 2014 were $0.2 million, resulting from approximately 1,800 barrels at an average price of $107.64 per Bbl. Condensate sales 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 per Bbl.

Natural gas revenues, including revenues from natural gas liquids, for the six months ended June 30, 2014 were $0.6 million compared to $0.8 million for the comparable period in 2013. Natural gas sales volumes were 126 MMcf at an average price of $4.70/Mcf for the six months ended June 30, 2014, compared to sales volumes of 183 MMcf at an average price of $4.47/Mcf for the same period in 2013.

Total production expenses for the six months ended June 30, 2014 were $14.5 million compared to $15.4 million for the six months ended June 30, 2013. The lower production expenses for the six months ended June 30, 2014 compared to 2013 were primarily associated with lower workover costs to replace electrical submersible pumps on offshore Gabon wells.

For the six months ended June 30, 2014, exploration expense was $14.6 million, primarily comprised of $11.7 million related to an unsuccessful offshore Gabon exploration well and $1.6 million related to the impairment of leasehold costs offshore Gabon. Additional exploration costs incurred for the three months ended June 30, 2014 were $1.0 million in Angola related to seismic processing.

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.

Depreciation, depletion and amortization expenses were $11.2 million for the six months ended June 30, 2014 compared to $7.1 million for the six months ended June 30, 2013. The higher depreciation, depletion and amortization expenses during the six months ended June 30, 2014 compared to the same period in 2013 were primarily due to higher sales volumes in Gabon and an increase in depletion rates.

General and administrative expenses for the six months ended June 30, 2014 and 2013 were $6.7 million and $6.1 million, respectively. The increase in general and administrative costs for the six months ended June 30, 2014 compared to the same period in 2013 was primarily due to increased personnel, and higher support services costs. For six month ended June 30, 2014 and 2013, the Company benefited from overhead reimbursements associated with production and development operations on the Etame Marin block.

Other expense for the six months ended June 30, 2014 was $0.4 million, compared to other expense of $55,000 for the same period in 2013. The other expense is comprised principally of foreign exchange loss recorded in the six months ended June 30, 2014 and 2013.

Income tax expense amounted to $15.1 million and $18.8 million for the six months ended June 30, 2014 and 2013, respectively. In the six months ended June 30, 2014 and 2013, the income taxes were all paid in Gabon. Income taxes in the six months ended June 30, 2014 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.

Net income for the six months ended June 30, 2014 was $17.7 million, compared to a net income of $14.3 million for the same period in 2013. Net income increased due to increase in revenue as a result of higher sales volumes lifted in the six months ended June 30, 2014.

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.

On May 14, 2013, the Committee of Sponsoring Organizations of the Treadway Commission (COSO) issued an updated version of its Internal Control – Integrated Framework (2013 Framework). Originally issued in 1992 (1992 Framework), the framework helps organizations design, implement and evaluate the effectiveness of internal control concepts and simplify their use and application. The 1992 Framework remains available during the transition period, which extends to December 15, 2014, after which time COSO will consider it as superseded by the 2013 Framework. As of June 30, 2014, the Company continues to utilize the 1992 Framework during the transition to the 2013 Framework by the end of 2014.

Other than as described below, there have been no material changes with respect to the risk factors disclosed in our annual report on Form 10-K for the year ended December 31, 2013.

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.

Delaware		76-0274813
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

4600 Post Oak Place Suite 300 Houston, Texas		77027
(Address of principal executive offices)		(Zip code)

Large accelerated filer	¨	Accelerated filer	x

Non-accelerated filer	¨	Smaller reporting company	¨

PART I. FINANCIAL INFORMATION

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

Condensed Consolidated Balance Sheets June 30, 2014 and December 31, 2013	3

Condensed Statements of Consolidated Operations Three and Six months ended June 30, 2014 and 2013	4

Condensed Consolidated Statements of Changes in Equity Six months ended June 30, 2014	5

Condensed Statements of Consolidated Cash Flows Six months ended June 30, 2014 and 2013	6

Notes to Unaudited Condensed Consolidated Financial Statements	7

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	11
-

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	17

ITEM 4. CONTROLS AND PROCEDURES	17

PART II. OTHER INFORMATION	19

ITEM 1A. RISK FACTORS	19

ITEM 6. EXHIBITS	19

	Three months ended June 30,				Six months ended June 30,
	2014		2013		2014		2013
Basic weighted average common stock issued and outstanding		56,950,678		57,900,809		56,905,675		57,903,871
Dilutive options		586,040		659,475		487,442		881,937
Total dilutive shares		57,536,718		58,560,284		57,393,117		58,785,808

	Restricted Stock			Grant Date Fair Value per Share
Outstanding at the beginning of period		100,000		$	5.89
Granted		99,468		$	6.98
Vested		(31,600	)	$	6.98
Forfeited		-		$	-
Outstanding at the end of period		167,868		$	6.32