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 April 30, 2015, there were outstanding 58,314,647 shares of common stock, $0.10 par value per share, of the registrant.

	March 31, 2015			December 31, 2014
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	46,552		$	69,051
Restricted cash		1,197			1,584
Receivables:
Trade		19,209			19,527
Accounts with partners, net of allowance $7.6 million at March 31, 2015 and December 31, 2014		30,283			10,903
Other, net of allowance of $2.4 million at March 31, 2015 and December 31, 2014		6,089			3,285
Crude oil inventory		1,692			1,905
Materials and supplies		233			286
Prepayments and other		5,854			6,509
Total current assets		111,109			113,050
Property and equipment - successful efforts method:
Wells, platforms and other production facilities		359,105			338,641
Undeveloped acreage		19,412			22,133
Work in progress		17,213			25,157
Equipment and other		11,290			11,907
		407,020			397,838
Accumulated depreciation, depletion and amortization		(300,014	)		(289,714	)
Net property and equipment		107,006			108,124
Other assets:
Restricted cash		15,830			20,830
Deferred tax asset		1,349			1,349
Deferred finance charge		1,799			1,959
Abandonment funding		3,537			3,537
Total Assets	$	240,630		$	248,849
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	61,942		$	38,540
Accounts with partners		4,812			-
Total current liabilities		66,754			38,540
Asset retirement obligations		15,290			14,846
Long term debt		15,000			15,000
Total liabilities		97,044			68,386
Commitments and contingencies (Note 4)
VAALCO Energy Inc. shareholders’ equity:
Common stock, $0.10 par value, 100,000,000 authorized shares, 65,823,346 and 65,194,828 shares issued with 7,508,699 and 7,393,714 shares in treasury at March 31, 2015 and December 31, 2014, respectively		6,554			6,519
Additional paid-in capital		67,016			64,351
Retained earnings		107,887			146,892
Less treasury stock, at cost		(37,871	)		(37,299	)
Total Equity		143,586			180,463
Total Liabilities and Equity	$	240,630		$	248,849

	Three Months Ended March 31,
	2015			2014
Revenues:
Oil and gas sales	$	18,239		$	28,071
Operating costs and expenses:
Production expense		9,911			9,650
Exploration expense		27,459			11,323
Depreciation, depletion and amortization		5,935			4,160
General and administrative expense		4,873			3,588
Other, net		280			-
Impairment of proved properties		5,399			-
Total operating costs and expenses		53,857			28,721
Other operating income, net		340			-

Operating income (loss)		(35,278	)		(650	)
Other income (expense):
Interest income		4			29
Interest expense		(310	)		-
Other, net		(56	)		(291	)
Total other income (expense)		(362	)		(262	)
Income (loss) before income taxes		(35,640	)		(912	)
Income tax expense		3,365			6,126
Net income (loss) attributable to VAALCO Energy, Inc.	$	(39,005	)	$	(7,038	)

Basic net income (loss) per share attributable to VAALCO Energy, Inc. common shareholders	$	(0.67	)	$	(0.12	)
Diluted net income (loss) per share attributable to VAALCO Energy, Inc. common shareholders	$	(0.67	)	$	(0.12	)
Basic weighted average shares outstanding		57,981			56,860
Diluted weighted average shares outstanding		57,981			56,860

	VAALCO ENERGY, Inc. Shareholders
	Common Stock		Additional Paid- In Capital		Retained Earnings			Treasury Stock			Total
Balance at December 31, 2014	$	6,519	$	64,351	$	146,892		$	(37,299	)	$	180,463
Stock issuance		35		1,011		-			-			1,046
Stock based compensation		-		1,654		-			-			1,654
Treasury stock purchases		-		-		-			(572	)		(572	)
Net loss		-		-		(39,005	)		-			(39,005	)
Balance at March 31, 2015	$	6,554	$	67,016	$	107,887		$	(37,871	)	$	143,586

	Three Months Ended March 31,
	2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(39,005	)	$	(7,038	)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		5,935			4,160
Amortization of debt issuance cost		160			-
Unrealized foreign exchange (gain) loss		-			22
Dry hole costs and impairment loss on unproved leasehold		27,222			10,505
Stock based compensation		1,654			1,417
Gains on disposal of oil and gas properties		(340	)		-
Impairment loss		5,399			-
Change in operating assets and liabilities:
Trade receivables		318			16,885
Accounts with partners		(14,568	)		(42,192	)
Other receivables		(2,774	)		(108	)
Crude oil inventory		213			(996	)
Materials and supplies		53			(304	)
Prepayments and other		655			(3,975	)
Accounts payable and other liabilities		14,477			(1,918	)
Net cash provided by (used in) operating activities		(601	)		(23,542	)
CASH FLOWS FROM INVESTING ACTIVITIES
Decrease/(increase) in restricted cash		5,387			207
Property and equipment expenditures		(28,070	)		(24,751	)
Proceeds from sales of oil and gas properties		340			-
Net cash used in investing activities		(22,343	)		(24,544	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of common stock		1,017			-
Debt issuance costs		-			(1,722	)
Purchase of treasury stock		(572	)		-
Net cash provided by (used in) financing activities		445			(1,722	)
NET CHANGE IN CASH AND CASH EQUIVALENTS		(22,499	)		(49,808	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		69,051			130,529
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	46,552		$	80,721
Supplemental disclosure of cash flow information:
Cash paid for income taxes	$	3,403		$	9,538
Supplemental disclosure of non-cash investing and financing activities:
Property and equipment additions incurred during the period but not paid at period end	$	27,907		$	11,304
Receivable from employees for stock option exercise	$	29		$	-

The condensed consolidated financial statements of VAALCO Energy, Inc., a Delaware corporation, 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, 2014, which also contains a summary of the significant accounting policies followed by the Company in the preparation of its consolidated financial statements. These policies were also followed in preparing the quarterly report included herein. The Company follows the successful efforts method of accounting for oil and gas exploration and development costs.

VAALCO is a Houston-based independent energy company principally engaged in the acquisition, exploration, development and production of crude oil and natural gas. VAALCO owns producing properties and conducts exploration activities as operator in Gabon, West Africa, conducts exploration activities as an operator in Angola, West Africa, and participates in exploration and development activities as a non-operator in Equatorial Guinea, West Africa. VAALCO is the operator of unconventional resource properties in the United States in North Texas and leasehold in Montana. 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.

Revenue Recognition- In May 2014, the Financial Accounting Standards Board ("FASB") issued revised guidance on revenue from contracts with customers, Accounting Standards Update (“ASU”) No. 2014-09, “Revenue from Contracts with Customers” that will supersede most current revenue recognition guidance, including industry-specific guidance. The core principle of the revenue model is that an entity will recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The new standard provides a five-step analysis for transactions to determine when and how revenue is recognized. The guidance permits the use of either a full retrospective or a modified retrospective approach. In April 2015, the FASB proposed deferring the effective date of this standard by one year from annual reporting periods beginning after December 15, 2016 to annual reporting periods beginning after December 15, 2017. The FASB also proposed permitting early adoption of the standard, but not before the original effective date of December 15, 2016. We are evaluating the transition methods and the impact of the amended guidance on our financial position, results of operations and related disclosures.

Deferred Financing- In April 2015, the FASB issued guidance that will require the presentation of debt issuance costs in financial statements as a direct reduction of the related debt liabilities with amortization of debt issuance costs reported as interest expense. Under current United States generally accepted accounting principles, debt issuance costs are reported as deferred charges (i.e., as an asset). This guidance is effective for annual periods, and interim periods within those fiscal years, beginning after December 15, 2015 and is to be applied retrospectively upon adoption. Early adoption is permitted, including adoption in an interim period for financial statements that have not been previously issued. We are currently evaluating this guidance.

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

As the Company recognized a net loss for the three months ended March 31, 2015 and 2014, there were no dilutive options. Options to purchase 5,772,271 and 4,542,350 shares were excluded in the three months ended March 31, 2015, and 2014, 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 to participants will become exercisable over a period determined by the Compensation Committee of the Company’s Board of Directors, which in the past has been a five year term, with the options vesting over a service period of two to five years. A portion of the stock options granted in the three months ended March 31, 2015 and 2014 were 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 March 31, 2015, there were 2,954,293 shares subject to options authorized but not granted under the 2014 Long Term Incentive Plan and 212,065 shares authorized under the prior existing long term incentive plans from which no options can be granted.

For the three months ended March 31, 2015 and 2014, the Company recognized non-cash compensation expense of $1.7 million and $1.4 million, respectively, related to stock-based compensation. 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 three months ended March 31, 2015 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 thousands)
Outstanding at beginning of period		4,765		$	7.41		2.62	$	1,610
Granted		1,339			4.98		4.93
Exercised		(245	)		4.28		0.00
Forfeited		(88	)		7.33		3.41
Outstanding at end of period		5,772			6.98		3.06	$	-
Vested and expected to vest - end of period		5,720		6.98			3.06	$	-

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.

In the three months ended March 31, 2015, the Company repurchased 114,985 shares at an average price of $4.98 per shares totaling $0.6 million. The shares repurchased were related to options exercised by employees which are approved under the long term incentive plans as disclosed in our proxy filings. The Company did not repurchase any shares in the three months ended March 31, 2014.

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 stock granted to employees will vest over a period determined by the Compensation Committee which is generally a three year period, vesting in three equal parts on the first three anniversaries of the date of the grant.

There were restricted stock grants in the three months ended March 31, 2015. A summary of the restricted stock activity for the three months ended March 31, 2015 is provided below:

As of March 31, 2015, unrecognized compensation costs totaled $4.8 million. The expense is expected to be recognized over a weighted average period of 2.43 years.

The Company contracted for two drilling rigs during the year ended December 31, 2014. In the third quarter of 2014, the Company contracted with a drilling rig to begin a multi- well development drilling campaign offshore Gabon. The campaign includes drilling of wells from the Etame platform and wells from the Southeast Etame/North Tchibala (“SEENT”) platform. The rig commenced drilling activities in October 2014 and continues under a contract until July 2016, at a day rate of approximately $168,000 on a gross basis. The Company’s share of the initial total commitment related to this rig is $25.8 million. As a result of drilling activity through March 31, 2015, the remaining commitment was $21.2 million. The second drilling rig contract was signed in July 2014 for a semi-submersible rig to drill an exploration well on the Kindele prospect, a post-salt objective on Block 5, offshore Angola. The drilling rig provided a forty-five day commitment at a day rate of approximately $338,000 on a gross basis. The Company’s share of the initial total commitment related to this rig is $7.6 million. The well began drilling in the first quarter of 2015. With the drilling of the Kindele well and the release of the rig on April 19, 2015, there is no further commitment under this contract.

As part of securing the first of two-five year extensions to the Etame field production license to which the Company is entitled from the government of Gabon, the Company agreed to a cash funding arrangement for the eventual abandonment of all offshore wells, platforms and facilities on the Etame Marin Block. The agreement was finalized in the first quarter of 2014 (effective 2011) providing for annual funding over a period of ten years at 12.14% of the total abandonment estimate for the first seven years 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 initial funding took place in October 2014 for calendar years 2012 and 2013 totaling $8.4 million ($2.3 million net to the Company). The funding for calendar year 2014 was paid in the first quarter of 2015 in the amount of $4.2 million ($1.2 million net to the Company). The abandonment estimate for this purpose is estimated to be approximately $10.1 million net to the Company on an undiscounted basis. 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 cash funding is reflected under other long term assets as “Abandonment Funding”.

In October 2014, the Company received a provisional audit report related to the Etame Marin block operations from the Gabon Taxation Department as part of a special industry-wide audit of business practices and financial transactions in the Republic of Gabon. In November 2014, the Company responded to the Gabon Taxation Department requesting joint meetings to advance the

resolution of this matter and later provided a formal reply to the provisional audit report in February 2015. Based on a tentative agreement reached with the Gabon Taxation Department in April 2015, the Company expects that the audit exceptions will not result in a material impact to the Company’s financial position or results of operations.

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 had commitments to acquire and process seismic and drill two exploration wells. The seismic commitments were met within the time period, but the wells were not drilled due to partner non-performance.

The government-assigned working interest partner was delinquent in paying their share of the costs several times in 2009 and consequently was placed in a default position. By a governmental decree dated December 1, 2010, the former partner was removed from the production sharing contract, and a one year time extension was granted for drilling the two exploration commitment wells. Additional extensions were subsequently granted by the Angolan government until November 30, 2014 to drill the two exploration commitment wells.

In the fourth quarter of 2013, the Company received a written confirmation from The Ministry of Petroleum of Angola that the available 40% working interest in Block 5, offshore Angola, has been assigned to Sonangol E.P., the National Concessionaire. The Ministry of Petroleum also confirmed that Sonangol E.P. would assign the aforementioned participating interest to its exploration and production affiliate, Sonangol P&P. The assignment was made effective on January 1, 2014. The Company’s position is that the unpaid amounts from the defaulted partner plus the amounts incurred on the partner’s behalf during the period prior to assignment of the working interest to Sonangol P&P are the responsibility of the acquirer of the working interest. The Company invoiced Sonangol P&P for these amounts totaling $7.6 million plus interest in April 2014. Due to the uncertainty of collection, the Company has recorded a full allowance totaling $7.6 million during 2011 through 2013 for the amount owed to the Company above its 40% working interest plus the 10% carried interest. Because this amount continues to be owed and due to slow payment history of the monthly cash call invoices since their assignment date of January 1, 2014, the Company placed Sonangol P&P in default in the first quarter of 2015. Meetings were held in April 2014 with Sonangol E.P. regarding the amounts owed and the slow payment history. Sonangol E.P. acknowledged the legitimacy of the amounts owed and pledged to work to bring the Sonangol P&P account to a current status. Sonangol P&P continues to be in default as of May 7, 2015 due to non-payment of the pre-assignment costs and unpaid recent cash call invoices.

In April 2014, the Company received a letter and contractual amendment proposal from Sonangol E.P., related to the extension of the two well drilling commitment, prior to the expiration of the extension on November 30, 2014. Due to the uncertainty that the primary term of the exploration license would be extended by the Republic of Angola before the November 30, 2014 expiration date, in October 2014, the Company entered into the Subsequent Exploration Phase (“SEP”), together with its working interest partner, Sonangol P&P. The SEP extends the exploration period for an additional three year period such that the new expiry date for exploration activities is November 30, 2017. Entering the SEP requires the Company and its partner to acquire 3D seismic covering a total of six hundred square kilometers and to drill two additional exploration wells.

Late in 2013, the Company obtained additional seismic data covering the deeper segment of the block. The seismic data was processed during 2014 and continues to be processed and evaluated in 2015. With the purchase of the additional seismic data, the Company has already satisfied the seismic obligation of the SEP.

By entering into the SEP, the Company is required to drill a total of four exploration wells during the exploration extension period. The four well obligations include the two well commitments under the primary exploration period that carries over to the SEP period. A $10.0 million dollar assessment ($5.0 million dollars net to VAALCO) applies to each of the four commitment exploration wells, if any, that remain undrilled at the end of the exploration period in November 2017. Additional restricted cash of $10.0 million for the two new commitment wells was recorded in the fourth quarter of 2014. With the drilling of the Kindele well, the Company has satisfied the drilling commitment for the first exploratory well, and therefore restricted cash decreased by $5.0 million in the first quarter of 2015. At March 31, 2015 the Company had $15.0 million in restricted cash related to the remaining commitment under the offshore Angola exploration agreement.

2015. Additionally, in the first quarter of 2015, the Company recognized exploration expenses of $2.7 million related to a portion of the capitalized leasehold costs for its interests in Angola which were determined to be impaired as a result of the unsuccessful well.

The Company is carrying $15.3 million of asset retirement obligation as of March 31, 2015, representing the present value of our future obligations for the future abandonment costs of tangible assets such as platforms, well, pipelines and other facilities.

A summary of the recording of the estimated fair value of the Company’s asset retirement obligations is presented as follows:

In the three months ended March 31, 2015, the Company increased the asset retirement obligation to recognize the abandonment liability for an additional development well offshore Gabon.

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 for which 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.

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. The Company is currently finalizing a revised production sharing contract (“PSC”) with the government of Gabon to allow for development of the discovery. The term sheet, which specifies financial and other obligations to be included in the PSC, was agreed to and signed by the Company, its joint venture partner, and the Gabon government on July 31, 2014. The joint venture partner has withheld its approval of the new PSC pending resolution of certain legal aspects of the new agreement with the Government of Gabon. In March 2015, the joint venture partner indicated to the Company that the legal aspects have not yet been resolved to their satisfaction and are considering other options. Further meetings of the joint venture partner and the Government of Gabon occurred in the second quarter of 2015 to work on the issues.

Upon PSC approval, the next step is an application by the Company for a development area. After issuance of a development area, the submittal of the plan of development to the Government of Gabon can be made by the Company. The Company remains committed to this block and further meetings of the parties are expected to occur in the first half of 2015.

The Company can provide no assurance as to the joint venture partner approving the PSC. The Company can provide no assurances as to either the approval of the PSC by the Government of Gabon, or the subsequent approval of a development area by the Government of Gabon. 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. Borrowings under the credit facility totaled $15.0 million as of March 31, 2015 and are due in full upon maturity in December 2019. The borrowings approximate fair value as the interest approximates current market rates for similar instruments.

Our borrowing base under the IFC credit facility is based upon our proved reserves and risk adjusted probable reserves and is re-determined semi-annually by the IFC. In addition, the borrowing base may be adjusted pursuant to certain non-scheduled re-determinations. However, the credit facility contains a covenant that prevents us from borrowing any amounts that would cause our debt to equity ratio to exceed 60:40. As of March 31, 2015, we calculate that this covenant would restrict our total borrowing capacity to less than $5.0 million above the $15.0 million borrowed.

Under the IFC credit facility, we are required to maintain a ratio of our net debt to EBITDAX (each as defined in the credit agreement) of not more than 3.0 to 1.0 and a ratio of debt to equity at or below 60:40. Forecasting our compliance with the financial covenant in future periods is inherently uncertain. Factors that could impact our debt to EBITDAX in future periods include future realized prices for sales of oil and natural gas, estimated future production, returns generated by our capital program, and future interest costs, among others. The Company is in compliance with all financial covenants at the end of March 31, 2015.

The Company capitalizes interest costs and commitment fees 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 March 31, 2015, the Company incurred interest expense of $0.5 million, $0.2 million of which was capitalized.

The Company reviews its oil and gas producing properties for impairment whenever events or changes in circumstances indicate that the carrying amount of such properties may not be recoverable. When it is determined that an oil and gas property’s estimated future net cash flows will not be sufficient to recover its carrying amount, an impairment charge is recorded to reduce the carrying amount of the asset to its estimated fair value.

Accordingly, impairment evaluation was performed using the year end 2014 independently prepared reserve report and forward price curves as of March 31, 2015. The Company performed a recoverability test as defined under ASC 932 and ASC 360, noting that the undiscounted cash flows related to the Southeast Etame and North Tchibala fields were less than the carrying value for these fields resulting in the Company recording an impairment loss of $5.4 million. The impairment is a result of recent decline in the forecasted oil prices as well as higher costs for planned development wells used in the impairment evaluation. The $5.4 million write off in the Southeast Etame and North Tchibala field results in zero recorded value remaining in those fields.

The measurement of these assets at fair value is calculated using discounted cash flow techniques and based on estimates of future revenues and costs associated with Southeast Etame and North Tchibala fields. Significant Level 3 assumptions associated with the calculation of discounted cash flows used in the impairment analysis include the Company’s estimate of future crude oil and natural gas prices, production costs, and anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data. For crude oil, estimates were based on NYMEX Brent prices, adjusted for quality, transportation fees, and market differential.

In the three months ended March 31, 2014, the Company determined no impairment charge was necessary.

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 2 of the financial statements included in the Company’s Form 10-K for the year ended December 31, 2014. Revenues are based on the location of hydrocarbon production. The Company evaluates each segment based on income (loss) from operations.

Segment activity for the three months ended March 31, 2015 and 2014 and segment assets as of March 31, 2015 and December 31, 2014 are as follows:

This Report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, which are intended to be covered by the safe harbors created by those laws. The Company has based these forward-looking statements on its current expectations and projections about future events. These forward-looking statements include information about possible or assumed future results of the Company’s operations. All statements, other than statements of historical facts, included in this Report that address activities, events or developments that the Company expects or anticipates may occur in the future, including without limitation, statements regarding the Company’s financial position, operating performance and results, reserve quantities and net present values, market prices, business strategy, derivative activities, the amount and nature of capital expenditures, plans and objectives of the Company’s management for future operations are forward-looking statements. When the Company uses words such as “anticipate,” “believe,” “estimate,” “expect,” “intend,” “forecast,” “outlook,” “aim,” “will,” “could,” “should,” “may,” “likely,” “plan,” “probably” or similar expressions, the Company is making forward-looking statements. Many risks and uncertainties that could affect the Company’s future results and could cause results to differ materially from those expressed in the Company’s forward-looking statements include, but are not limited to:

The information contained in this report and the information set forth under the heading “Risk Factors” set forth in the Company’s Annual Report on Form 10-K for the year ended December 31, 2014 identifies additional factors that could cause the Company’s results or performance to differ materially from those the Company expresses in its forward-looking statements. 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. When you consider the Company’s forward-looking statements, you should keep in mind these risk factors and the other cautionary statements in this report.

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 participates in exploration and development activities as a non-operator in Equatorial Guinea, West Africa. VAALCO is the operator of unconventional resource properties in the United States in North Texas and leasehold in 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 natural 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. Beginning in the third quarter of 2014, the prices for oil and natural gas began a dramatic decline, and current prices are significantly less than they have been over the last several years. Sustained low oil and gas prices could have a material adverse effect on the Company’s financial condition, the carrying value of its proved reserves and the amount of its borrowing base under the Company’s credit facility. As with prices for oil production, the costs to find and produce oil and natural 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. The Company operates the Etame, Avouma/South Tchibala, Ebouri, Southeast Etame and the North Tchibala fields on behalf of a consortium of five companies. As part of the future development plans for the Etame Marin block, two new production platforms, Etame and Southeast Etame/North Tchibala (“SEENT”) were installed in the offshore waters of Gabon in the third quarter of 2014. As of March 31, 2015 production from three subsea wells and five platform wells 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 (“ESPs”) in existing wells. In the first quarter of 2015, the Company drilled two new development wells offshore Gabon from the recently installed Etame platform. The Etame 10-H well was brought on production in the first quarter of 2015. The Etame 10-H well confirmed the presence of an undrained lower lobe of the Gamba reservoir in this fault block. The Company began drilling the Etame 12-H in March 2015, and the well was subsequently completed in the second quarter of 2015.

After the completion of the Etame 12-H well early in the second quarter of 2015, the drilling rig currently under contract was moved to begin drilling additional development wells from the recently installed SEENT platform. The Company began drilling a development well in the Southeast Etame Field in April 2015, and after completion, expects to drill a development well in the North Tchibala field. The Company drilled a successful exploration well in the Southeast Etame area in 2010 which will be developed from the second platform. An oil discovery was made in the North Tchibala field in the Dentale formation prior to the Company acquiring the lease of the Etame Marin block in 1995.

With respect to longer-term optimization, the Company and the other members of the consortium are evaluating options for handling oil containing hydrogen sulfide (“H₂S”) that has impacted certain wells in the Ebouri and Etame fields. In July 2012, the Company discovered the presence of H₂S from two of the three producing wells in the Ebouri field. The wells were shut-in for safety and marketability 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 at that time. In addition, H₂S was first detected in January 2014 and later confirmed in July

2014 in the Etame 5-H well in the Etame field, and this well was shut-in at that time. In the fourth quarter of 2014, the Company drilled the Etame 8-H well. Initial testing of the well indicated the presence of H₂S in this well, and the well was shut-in pending an extended testing of the well. The extended test of the well was performed in the first quarter of 2015 confirming the presence of H₂S, and the well remains shut-in.

To re-establish and maximize production from the impacted areas, additional capital investment will be required, including one or more processing facilities capable of removing H₂S, recompletion of the temporarily abandoned wells, and potentially, additional new wells. Considering the substantial recent fall in oil prices, the Company and its partners are focusing on more cost efficient options for one or more processing facilities (e.g. chemical removal options, construction of a smaller facility on existing structures, or the use of surplus equipment and used structures). There can be no assurances that any processing facilities will be completed by 2017, if at all, or that a more cost effective facility will cover all affected areas of the Ebouri and Etame fields. It is expected that the timing of the project startup will be known as early as the fourth quarter of 2015 with a goal of re-establishing production from the area impacted by H₂S as soon as practicable. Should the evaluation result in no economic alternative, a decrease of as much as 2.4 million barrels of proved undeveloped reserves could result.

In the fourth quarter of 2014, the Company recorded an impairment loss of $98.3 million to write down its investment in certain fields comprising the Etame Marin Block, offshore Gabon to its fair value. An impairment of $38.5 million was recorded in the Etame field, $5.9 million in the Ebouri field and $53.9 million in the Southeast Etame/North Tchibala field. The impairment is a result of the recent decline in the forecasted oil prices used in the impairment testing and calculation. As a result of further declines in prices during the three months ended March 31, 2015, the Company evaluated whether any additional impairment was required during the period. In the three months ended March 31, 2015, the Company recorded an impairment loss of $5.4 million to write down its investment in the Southeast Etame and North Tchibala fields offshore Gabon, to its fair value. The $5.4 million write off in the Southeast Etame and North Tchibala field results in zero recorded value remaining in those fields.

The Company operates 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). After drilling two unsuccessful exploration wells on the block in 2009, the Company entered into an agreement with Total Gabon to continue the exploration activities. Following seismic reprocessing, a discovery well was drilled in 2012. A revised production sharing contract (“PSC”) including exploration rights is in the approval process. The term sheet, which specifies financial and other obligations to be included in the PSC, was agreed to and signed by the Company, its joint venture partner, and the Gabon government on July 31, 2014. The joint venture partner has withheld its approval of the new PSC pending resolution of certain legal aspects of the new agreement with the Government of Gabon. In March 2015, the joint venture partner indicated to the Company that the legal aspects have not yet been resolved to their satisfaction and are considering other options. Further meetings of the joint venture partner and the Government of Gabon occurred in the second quarter of 2015 to work on the issues.

The Company can provide no assurance as to the joint venture partner approving the PSC. The Company can provide no assurances as to the either the approval of the PSC by the Government of Gabon, or the subsequent approval of a development area by the Government of Gabon.

In November 2006, the Company signed a production sharing contract for Block 5, offshore Angola. The four year primary term, with an optional three year extension, awarded the Company exploration rights to 1.4 million acres offshore central Angola. The Company’s working interest is 40%. Additionally, the Company is required to carry the Angolan national oil company, Sonangol P&P, for 10% of the work program. During the first four years of the contract, the Company had commitments to acquire and process seismic and drill two exploration wells. The seismic commitments were met within the time period, but the wells were not drilled due to partner non-performance.

In the fourth quarter of 2013, the Company received a written confirmation from The Ministry of Petroleum of Angola that the available 40% working interest in Block 5, offshore Angola, has been assigned to Sonangol E.P., the National Concessionaire. The Ministry of Petroleum also confirmed that Sonangol E.P. would assign the aforementioned participating interest to its exploration and production affiliate, Sonangol P&P. The assignment was made effective on January 1, 2014. The Company’s position is that the unpaid amounts from the defaulted partner plus the amounts incurred on the partner’s behalf during the period prior to assignment of the working interest to Sonangol P&P are the responsibility of the acquirer of the working interest. The Company invoiced Sonangol P&P for these amounts totaling $7.6 million plus interest in April 2014. Due to the uncertainty of collection, the Company has recorded a full allowance totaling $7.6 million during 2011 through 2013 for the amount owed to the Company above its 40% working interest plus the 10% carried interest. Because this amount continues to be owed and due to slow payment history of the monthly cash call invoices since their assignment date of January 1, 2014, the Company placed Sonangol P&P in default in the first quarter of 2015. Meetings were held in April 2014 with Sonangol E.P. regarding the amounts owing and the slow payment history. Sonangol E.P. acknowledged the legitimacy of the amounts owed and pledged to work to bring the Sonangol P&P account to a current status. Sonangol P&P continues to be in default as of May 7, 2015 due to non-payment of the pre-assignment costs and unpaid recent cash call invoices.

A drilling rig contract was signed in July 2014 for a semi-submersible rig to drill the exploration well on the Kindele prospect, a post-salt objective. The well began drilling in the first quarter of 2015, and while thick, well-developed sands were encountered in the primary objectives, the sands were determined to be water-bearing, and the well was plugged and abandoned. Accordingly, the Company has expensed $24.5 million related to the Kindele prospect to exploration expense during the three months ended March 31, 2015. Additionally, in the first quarter of 2015, the Company recognized exploration expense of $2.7 million related to a portion of the capitalized leasehold costs for its interests in Angola which were determined to be impaired as a result of the unsuccessful well.

The Company has a 31% working interest in a portion of Block P, offshore Equatorial Guinea. Prior to the Company’s acquisition in the block, two oil discoveries had been made on the block, establishing a development and production area in the block (the “PDA”). There is also exploration potential on other areas of the PDA. At the time the PDA was established, the block was divided into PDA and non-PDA portions, and the Company does not have participating interest in the non-PDA 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 in the PDA, including the approval of a development and production plan. Development project economics are being re-evaluated considering the recent dramatic fall in oil prices and the expected decrease in development costs resulting from decreased demand associated with the fall in oil prices. The production sharing contract covering the PDA provides for a development and production period of twenty-five years from the date of approval of a development and production plan.

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. During the three months ended March 31, 2015, the Company sold certain of these minor interests for $0.3 million.

Net cash used in operating activities for the three months ended March 31, 2015 was $0.6 million, as compared to net cash used in operating activities of $23.5 million for the three months ended March 31, 2014. The $22.9 million increase in cash from operations was primarily due to an increase in cash from changes in working capital and other operating assets and liabilities of $31.0 million and an increase in changes from non-cash adjustments to net loss for depreciation, depletion and amortization, dry hole costs and impairment loss on unproved property of $23.9 million offset by an increase in the net loss of $32.0 million. The increase in net loss is related to a decrease in revenues resulting from lower prices for oil and gas sales, impairment loss in the Etame Marin block, offshore Gabon of $5.4 million and due to higher dry hole costs and expensing of leasehold costs totaling $27.2 million related to an unsuccessful exploration well offshore Angola. Dry hole and expensed leasehold costs for the three month ended March 31, 2014 were $10.5 related to the unsuccessful well offshore Gabon.

Net cash used in investing activities for the three months ended March 31, 2015 was $22.3 million, compared to net cash used in investing activities for the three months ended March 31, 2014 of $24.5 million. While cash used for additions to property and equipment increased by $3.3 million as a result of higher level of drilling activity, the change in restricted cash decreased by $5.2 million as a result of fulfilling the commitment for one of the four exploration wells in Angola.

For the three months ended March 31, 2015, net cash provided in financing activities was $0.5 million consisting of $1.0 million in proceeds from the issuance of common stock upon the exercise of stock options offset by $0.6 million in purchase of treasury stock resulting for the exercise of stock options. For the three months ended March 31, 2014, net cash used in financing activities was $1.7 million related to the debt issuance cost for attaining the loan.

During the three months ended March 31, 2015, the Company had cash expenditures of $28.1 million related to property and equipment additions, primarily associated with the drilling of development wells from the new Etame platform offshore Gabon and costs related to the drilling of the Kindele well offshore Angola which was determined to be a dry hole during the first quarter of 2015. During the second quarter of 2015, the Company anticipates its share of capital expenditures will approximate $13.6 million primarily associated with the offshore Gabon block for the drilling of the development wells from the two new platforms in the Etame and Southeast Etame fields.

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 three months ended March 31, 2014, exploration expense was $11.3 million, primarily comprised of $9.7 million related to an unsuccessful offshore Gabon exploration well and $0.8 million related to the expensing of leasehold costs offshore Gabon. Additional exploration costs incurred in the three months ended March 31, 2014 were $0.6 million in Angola related to seismic processing.

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

The Company has a $65.0 million revolving credit facility with the IFC, secured by the assets of the Company’s Gabon subsidiary. Borrowings under the credit facility totaled $15.0 million as of March 31, 2015 and are due in full upon maturity in January 2019 at which point it can be extended or converted to a term loan. The Company was in compliance with all covenants at March 31, 2015 and is required to maintain the following ratios:

As of March 31, 2015, any further borrowings under the facility would be subject to a re-determination. Amounts outstanding under the IFC Loan bear interest at the London InterBank Offered Rate (“LIBOR”) 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.

At March 31, 2015, the Company had unrestricted cash of $46.6 million. The Company believes that this cash, combined with cash flow from operations will be sufficient to fund the Company’s remaining 2015 capital expenditure budget expected to be in the range of $65 million to $75 million and additional working capital requirements resulting from potential growth. As operator of the Etame Marin and Mutamba Iroru blocks in Gabon, and 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.

The Company currently sells its crude oil using an agency model. The Company has contracted with a third party in order to sell, based on a fixed barrel fee, on the spot market. For the first quarter of 2015, the Company sold its oil under the agency model 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 $18.2 million for the three months ended March 31, 2015, compared to $28.1 million for the same period of 2014. The decrease in revenue is primarily related to a decrease in the realized price of oil per barrel.

Crude oil revenues for the three months ended March 31, 2015 were $18.1 million, as compared to revenues of $27.7 million for the same period of 2014. In the three months ended March 31, 2015, the Company sold approximately 372,000 net barrels of oil from two liftings at an average price of $48.66/Bbl, while in the three months ended March 31, 2014 it sold approximately 257,000 net barrels of oil from two liftings at an average price of $107.97/Bbl. Crude oil sales are a function of the number and size of crude oil liftings in each quarter from the FPSO facility, and thus crude oil sales do not always coincide with volumes produced in any given quarter. Production for the three months ended March 31, 2015 was approximately 380,000 net barrels as compared to approximately 360,000 net barrels in the three months ended March 31, 2014.

The Company’s share of oil in inventory aboard the FPSO, excluding royalty barrels, was approximately 85,000 barrels and 83,000 barrels at March 31, 2015 and 2014, respectively.

Natural gas revenues, including revenues from natural gas liquids, were approximately $0.1 million in the three months ended March 31, 2015 and $0.3 million in the three months ended 2014. Net natural gas sales were 46 MMcf for the three months ended March 31, 2015. For the same period of 2014, net natural gas sales were 69 MMcf.

Total production expenses for the three months ended March 31, 2015 were $9.9 million compared to $9.7 million in the three months ended March 31, 2014. In the three months ended March 31, 2015, the Company expensed $1.4 million related to preconstruction costs for a processing facility to remove H₂S from production in the Ebouri field as the Company now anticipates implementing a

different solution. In the three months ended March 31, 2014 the Company expensed $2.1 million to replace electrical submersible pumps on an offshore Gabon well.

For the three months ended March 31, 2015, exploration expense was $27.5 million, primarily comprised of $24.5 million related to the unsuccessful offshore Angola exploration well and $2.7 million related to the impairment of leasehold costs offshore Angola. Additional exploration costs incurred in the three months ended March 31, 2015 were $0.3 million in Angola related to seismic processing. For the three months ended March 31, 2014, exploration expense was $11.3 million, primarily comprised of $9.7 million related to the unsuccessful offshore Gabon exploration well and $0.8 million related to the impairment of leasehold costs offshore Gabon. Additional exploration costs incurred in the three months ended March 31, 2014 were $0.6 million in Angola related to seismic processing.

Depreciation, depletion and amortization expenses were $5.9 million in the three months ended March 31, 2015 compared to $4.2 million in the three months ended March 31, 2014. The higher depreciation, depletion and amortization expenses during the three months ended March 31, 2015 compared to the three months ended March 31, 2014 was primarily due to higher sales volumes.

General and administrative expenses for the three months ended March 31, 2015 was $4.9 million as compared to $3.6 million in the three months ended 2014. The increase in general and administrative cost was primarily due to increased personnel costs, higher stock compensation and professional support services costs in the three months ended March 31, 2015.

In the three months ended March 31, 2015, the Company recorded an impairment loss of $5.4 million to write down its investment in the Southeast Etame and North Tchibala fields in the Etame Marin Block offshore Gabon to its fair value. The impairment is a result of the further decline in the forecasted oil prices used in the impairment evaluation. The $5.4 million write off in the Southeast Etame and North Tchibala field results in zero recorded value remaining in those fields. In the three months ended March 31, 2014, the Company recorded no impairment losses.

Other operating income for the three months ended March 31, 2015 was $0.3 million related gain on the sale of oil and gas properties. The Company sold some of its minor interests in its non-operated properties in Alabama and the Gulf of Mexico.

Other expenses for the first three months ended March 31, 2015 was $0.4 million and $0.3 million, respectively. The increase in other expenses is due to an increase in foreign currency transaction losses of $0.1 million from the Company’s foreign operations and interest expense of $0.3 million related to the IFC credit facility.

Income tax expenses were $3.4 million and $6.1 million for the three months ended March 31, 2015 and 2014, respectively. The income taxes were all paid in Gabon in both periods. The decrease in income tax expenses was primarily associated with the decrease in revenue due to the lower realized price of oil per barrel. Taxes were also lower due to a significant increase in costs incurred due to the construction of two new platforms and cost incurred associated with active rigs under contract for the majority of 2015 in the Etame Marin block. Income taxes paid to the government of Gabon are a function of taxation on the remaining profit oil value after deducting the royalty and the cost oil values.

Net loss was $39.0 million for the three months ended March 31, 2015, compared to net loss of $7.0 million for the same period in 2014. The net loss in 2015 is primarily attributable to an increase in exploration expense related to the unsuccessful exploration well drilled in Angola, a non-cash impairment in the Etame Marin Block offshore Gabon, and lower revenues resulting from lower realized oil prices.

The Company’s major market risk exposure continues to be the prices applicable to its oil and gas production. Sales prices are primarily driven by the prevailing market price. Historically, prices received for oil and gas production have been volatile and unpredictable.

Our results of operations and financial condition are affected by currency exchange rates. While oil sales are denominated in U.S. dollars, portions of our operating costs in Gabon are denominated in the local currency. A weakening U.S. dollar will have the effect of increasing operating costs while a strengthening U.S. dollar will have the effect of reducing operating costs. The Gabon local currency is tied to the Euro. The exchange rate between the Euro and the U.S. dollar has fluctuated widely in response to international political conditions, general economic conditions and other factors beyond our control.

Our floating rate credit facility exposes us to risks associated with changes in interest rates and as such, future earnings are subject to change due to changes in this interest rate. At March 31, 2015, the Company has borrowed $15.0 million under the credit facility. Fluctuations in floating interest rates will cause the Company’s annual interest costs to fluctuate. During the first quarter of 2015, the interest rate on the Company’s bank debt averaged 4.32%. If the balance of the bank debt at March 31, 2015 were to remain constant, a 1% change in market interest rates would impact our cash flow by an estimated $37,500 per quarter.

The Company had no derivatives in place as of the date of this report, or throughout 2015 and 2014.

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. As described in the Company’s Annual Report on Form 10-K for the year ended December 31, 2014, material weaknesses were identified in our internal control over financial reporting related to (1) internal control over the preparation and review of the impairment evaluation of oil and gas properties and (2) the control environment, risk assessment and internal controls over financial reporting due to insufficient financial reporting resources. 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 not effective as of the end of the period covered by this Quarterly Report on Form 10-Q as a result of these material weaknesses.

In response to the identified material weaknesses, our management, with oversight from our Audit Committee, is taking certain actions to remediate the material weaknesses described above. In March 2015, the Company hired an experienced corporate controller to fill a vacancy created during the fourth quarter of 2014. In connection with this filing, our management has redesigned controls over management’s review of the evaluation of impairment testing of oil and gas properties to address the associated risks and further expanded the procedures for reviewing data used as inputs into the oil and gas properties impairment calculation. Our management is evaluating the need for any additional resources to supplement the existing corporate accounting and/or financial reporting team. In addition, our management is developing a plan to manage the impact of recent significant turnover by enhancing the business understanding and relevant knowledge possessed by those responsible for ensuring proper management review and effective financial reporting controls.

Management is committed to improving the Company’s internal control processes and believes that the measures described above should remediate the material weaknesses identified and strengthen the Company’s internal control over financial reporting. As the Company continues to evaluate and improve its internal control over financial reporting, additional measures to remediate the material weaknesses or modifications to certain of the remediation procedures described above may be necessary. The Company expects to complete the required remedial actions during fiscal year 2015. While senior management and our audit committee are closely monitoring the implementation of these remediation plans, the Company cannot provide any assurance that these remediation efforts will be successful or that its internal control over financial reporting will be effective as a result of these efforts. Until the remediation steps set forth above are fully implemented and operating for a sufficient period of time, the material weaknesses described above will continue to exist.

Except for the activities taken related to the remediation of the material weakness described above, there were no changes in the Company’s internal controls over financial reporting that occurred during the three months ended March 31, 2015 that have materially affected, or are reasonably likely to materially affect the Company’s internal control over financial reporting.

The Company is subject to litigation claims and governmental and regulatory proceedings arising in the ordinary course of business. It is management’s opinion that all claims and litigation we are involved in are not likely to have a material adverse effect on our consolidated financial position, cash flows or results of operations.

Our business faces many risks. Any of the risks discussed elsewhere in this Form 10-Q and our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently know to us or that we currently believe to be immaterial may also impair our business operations. For a discussion of our potential risks and uncertainties, see the information in Item 1A “Risk Factors” in our 2014 Annual Report on Form 10-K.

We make, and will continue to make, substantial capital expenditures for the acquisition, exploitation, development, exploration and production of oil and natural gas reserves. In Gabon and Angola, we are the operator of the blocks and are thus responsible for contracting on behalf of the parties participating in block operations. We rely on the timely payment of cash calls by our partners to pay for approximately 70% of the offshore Gabon block budget, 50% of the onshore Gabon block budget and 50% of the offshore Angola block budget. If our partners fail to pay their share of costs, we may have a limited ability to expend the capital necessary to undertake or complete future drilling programs and our financial results and liquidity may be negatively affected.

In the fourth quarter of 2013, The Ministry of Petroleum of Angola advised the Company that the available 40% working interest in Block 5, offshore Angola, had been assigned to Sonangol E.P., the National Concessionaire, who assigned the aforementioned participating interest to its exploration and production affiliate, Sonangol P&P. The unpaid amounts from the defaulted prior partner, plus the amounts incurred on the partner’s behalf during the period prior to the assignment of the working interest to Sonangol P&P (the “Pre-Assignment Costs”) are believed by the Company to be the responsibility of the acquirer of the working interest. The Company invoiced Sonangol P&P for the Pre-Assignment Costs totaling $7.6 million, plus interest, in April 2014. Due to the uncertainty of the collection, the Company previously recorded a full valuation allowance totaling $7.6 million for the amount owed to the Company above its 40% working interest plus the 10% carried interest.

With the exception of a single payment in October 2014, Sonangol P&P failed to pay cash call invoices associated with its working interest for 2014 costs. In January 2015, the Company delivered Sonangol P&P a default notice pursuant to the joint operating agreement for the failure to pay amounts owing. Later in January 2015 and subsequent to the issuance of the default notice, Sonangol P&P paid the Company $12.4 million to satisfy its obligations with respect to costs incurred in 2014, but did not satisfy the obligations with respect to the Pre-Assignment Costs and thus remained in default. Sonangol P&P has not made any further payments for cash call invoices issued by the Company subsequent to Sonangol P&P’s January 2015 payments and remains in default under the joint operating agreement. The Company met with Sonangol E.P. in April 2015 concerning the amount owing and was assured that payment would be forthcoming from Sonangol P&P for these costs incurred by the Company; however, we can provide no assurance as to when and whether these amounts will be paid.

We rely on the timely payment of cash calls by our partners to pay for their share of joint operations. If Sonangol P&P or any other partner fails to pay their share of costs, we may have a limited ability to expend the capital necessary to undertake or complete future drilling programs and our financial results and liquidity may be negatively affected.

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.)

9800 Richmond Avenue Suite 700 Houston, Texas		77042
(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 March 31, 2015 and December 31, 2014	3

Condensed Statements of Consolidated Operations Three months ended March 31, 2015 and 2014	4

Condensed Consolidated Statements of Changes in Equity Three months ended March 31, 2015	5

Condensed Statements of Consolidated Cash Flows Three months ended March 31, 2015 and 2014	6

Notes to Unaudited Condensed Consolidated Financial Statements	7

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	13

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	19

ITEM 4. CONTROLS AND PROCEDURES	20

PART II. OTHER INFORMATION	21

ITEM 1A. RISK FACTORS	21

ITEM 6. EXHIBITS	22

	Three Months Ended March 31,
	2015		2014
Basic weighted average common stock issued and outstanding		57,981,347		56,860,172
Dilutive options and restricted stock		-		-
Total diluted shares		57,981,347		56,860,172

	Restricted Stock			Weighted Average Grant Price
Non-Vested Shares Outstanding December 31, 2014		147,868		$	6.39
Awards granted		238,783		$	4.98
Awards vested		(105,529	)	$	5.40
Awards forfeited		-			-
Non-Vested Shares Outstanding March 31, 2015		281,122		$	5.56

(In Thousands)	Three months ended March 31,
	2015
Balances at January 1,	$	14,846
Accretion Expense		241
Additions		203
Balance March 31,	$	15,290

3.1	Certificate of Incorporation as amended through May 7, 2014 (filed as Exhibit 3.1 to the Company's Quarterly Report on Form 10-Q filed on November 10, 2014, and incorporated herein by reference).
3.2	Amended and Restated Bylaws (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on September 23, 2013, and incorporated herein by reference).
10.1*	Form of Consulting Agreement between the Company and W. Russell Scheirman, (filed as Exhibit 10.1 to the Company’s current report on Form 8-K filed on April 16, 2015, and incorporated herein by reference).
31.1(a)	Sarbanes-Oxley Section 302 certification of Principal Executive Officer.
31.2(a)	Sarbanes-Oxley Section 302 certification of Principal Financial Officer.
32.1(b)	Sarbanes-Oxley Section 906 certification of Principal Executive Officer.
32.2(b)	Sarbanes-Oxley Section 906 certification of Principal Financial Officer.
101.INS(a)	XBRL Instance Document.
101.SCH(a)	XBRL Taxonomy Schema Document.
101.CAL(a)	XBRL Calculation Linkbase Document.
101.DEF(a)	XBRL Definition Linkbase Document.
101.LAB(a)	XBRL Label Linkbase Document.
101.PRE(a)	XBRL Presentation Linkbase Document.