VAALCO Energy (EGY) 10-K 13 Mar 14 2013 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2013	Feb. 28, 2014	Jun. 30, 2013
Document Document And Entity Information [Line Items]	'	'	'
Entity Registrant Name	'VAALCO ENERGY INC /DE/	'	'
Entity Central Index Key	'0000894627	'	'
Document Type	'10-K	'	'
Document Period End Date	31-Dec-13	'	'
Amendment Flag	'false	'	'
Document Fiscal Year Focus	'2013	'	'
Document Fiscal Period Focus	'FY	'	'
Current Fiscal Year End Date	'--12-31	'	'
Entity Well-known Seasoned Issuer	'No	'	'
Entity Voluntary Filers	'No	'	'
Entity Current Reporting Status	'Yes	'	'
Entity Filer Category	'Accelerated Filer	'	'
Entity Public Float	'	'	$329,908,008
Entity Common Stock, Shares Outstanding	'	56,850,341	'

CONSOLIDATED_BALANCE_SHEETS_Un

CONSOLIDATED BALANCE SHEETS (Unaudited) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Current assets:	'	'
Cash and cash equivalents	$130,529	$130,800
Restricted cash	12,366	1,257
Receivables:	'	'
Trade	16,972	7,961
Accounts with partners, net of allowance of $7.6 million in 2013 and $6.0 million in 2012	307	689
Other	4,435	4,463
Crude oil inventory	352	683
Materials and supplies	164	337
Prepayments and other	2,339	2,935
Total current assets	167,464	149,125
Property and equipment - successful efforts method:	'	'
Wells, platforms and other production facilities	215,701	188,208
Undeveloped acreage	23,705	28,657
Work in progress	64,489	38,137
Equipment and other	6,831	7,574
Property, plant and equipment, gross, Total	310,726	262,576
Accumulated depreciation, depletion and amortization	-172,202	-155,968
Net property and equipment	138,524	106,608
Other assets:	'	'
Deferred tax asset	1,349	1,349
Restricted cash	830	10,874
Total Assets	308,167	267,956
Current liabilities:	'	'
Accounts payable and accrued liabilities	42,561	30,326
Accounts with partners	3,268	14,737
Total current liabilities	45,829	45,063
Asset retirement obligations	11,464	10,368
Total liabilities	57,293	55,431
Commitments and contingencies (Note 6)	'	'
VAALCO Energy Inc. shareholders’ equity:	'	'
Common stock, $0.10 par value, 100,000,000 authorized shares, 64,012,914 and 63,135,772 shares issued with 7,162,573 and 5,257,638 shares in treasury at Dec. 31, 2013 and 2012, respectively	6,408	6,314
Additional paid-in capital	55,455	48,816
Retained earnings	224,442	181,370
Less treasury stock, at cost	-35,431	-23,975
Total Equity	250,874	212,525
Total Liabilities and Equity	$308,167	$267,956

CONDENSED_CONSOLIDATED_BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, except Share data, unless otherwise specified
Statement Of Financial Position [Abstract]	'	'
Allowance for accounts with partners	$7.60	$6
Common stock, par value	$0.10	$0.10
Common stock, shares authorized	100,000,000	100,000,000
Common stock, shares issued	64,012,914	63,135,772
Treasury stock, shares	7,162,573	5,257,638

STATEMENTS_OF_CONSOLIDATED_OPE

STATEMENTS OF CONSOLIDATED OPERATIONS (Unaudited) (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Revenues:	'	'	'
Oil and gas sales	$169,277	$195,287	$210,436
Operating costs and expenses:	'	'	'
Production expense	36,615	26,724	26,731
Exploration expense	23,928	41,037	5,708
Depreciation, depletion and amortization	16,929	19,913	25,596
General and administrative expense	11,254	11,779	10,417
Bad debt and other expenses	3,326	1,621	4,448
Impairment of proved properties	'	7,620	4,975
Total operating costs and expenses	92,052	108,694	77,875
Operating income	77,225	86,593	132,561
Other income (expense):	'	'	'
Interest income	73	145	184
Other, net	-111	414	1,285
Total other income (expense)	-38	559	1,469
Income before income taxes	77,187	87,152	134,030
Income tax expense	34,115	81,813	93,468
Net income	43,072	5,339	40,562
Less net income attributable to noncontrolling interest	'	-4,708	-6,417
Net income attributable to VAALCO Energy, Inc.	$43,072	$631	$34,145
Basic net income per share atributable to VAALCO Energy, Inc. common shareholders	$0.75	$0.01	$0.60
Diluted net income per share attributable to VAALCO Energy, Inc. common shareholders	$0.74	$0.01	$0.59
Basic weighted average shares outstanding	57,298,910	57,673,342	57,047,531
Diluted weighted average shares outstanding	57,925,001	58,832,059	57,972,581

CONDENSED_CONSOLIDATED_STATEME

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited) (USD $)	Total	Common Stock	Additional Paid-In Capital	Retained Earnings	Treasury Stock	Noncontrolling Interest
In Thousands
Beginning Balance at Dec. 31, 2010	$196,243	$6,282	$64,314	$146,594	($25,665)	$4,718
Stock issuance	1,237	30	1,207	0	0	0
Stock based compensation	2,217	0	2,217	0	0	0
Constructive retirement of treasury stock	0	-74	-1,616	0	1,690	0
Net income (loss)	40,562	0	0	34,145	0	6,417
Distribution to noncontrolling interest	-7,192	0	0	0	0	-7,192
Ending Balance at Dec. 31, 2011	233,067	6,238	66,122	180,739	-23,975	3,943
Stock issuance	3,508	76	3,432	0	0	0
Stock based compensation	2,406	0	2,406	0	0	0
Net income (loss)	5,339	0	0	631	0	4,708
Distribution to noncontrolling interest	-5,595	0	0	'	0	-5,595
Acquisition of noncontrolling interest	-26,200	0	-23,144	0	0	-3,056
Ending Balance at Dec. 31, 2012	212,525	6,314	48,816	181,370	-23,975	0
Stock issuance	3,728	94	3,634	'	'	'
Stock based compensation	3,005	'	3,005	'	'	'
Net income (loss)	43,072	'	'	43,072	'	'
Treasury stock purchase	-11,456	'	'	'	-11,456	'
Ending Balance at Dec. 31, 2013	$250,874	$6,408	$55,455	$224,442	($35,431)	$0

CONDENSED_STATEMENTS_OF_CONSOL

CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS (Unaudited) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
CASH FLOWS FROM OPERATING ACTIVITIES	'	'	'
Net income	$43,072	$5,339	$40,562
Adjustments to reconcile net income to net cash provided by operating activities	'	'	'
Depreciation, depletion and amortization	16,929	19,913	25,596
Unrealized foreign exchange (gain) loss	22	-245	25
Dry hole costs and impairment loss on unproved leasehold	22,490	37,289	60
Stock based compensation	3,005	2,406	2,217
Bad debt provision	1,562	1,621	4,448
Impairment of proved properties	'	7,620	4,975
Gain on disposal of assets	'	'	4
Change in operating assets and liabilities:	'	'	'
Trade receivables	-9,011	2,126	3,981
Accounts with partners	-12,649	18,988	5,171
Other receivables	-53	-199	5,560
Crude oil inventory	279	-71	176
Materials and supplies	173	-102	266
Other long term assets	'	'	'
Prepayments and other	594	-766	-886
Accounts payable and other liabilities	8,988	39	-2,570
Net cash provided by operating activities	75,401	93,958	89,585
CASH FLOWS FROM INVESTING ACTIVITIES	'	'	'
Decrease/(increase) in restricted cash	-1,065	78	3,597
Property and equipment expenditures	-66,879	-71,915	-31,973
Net cash used in investing activities	-67,944	-71,837	-28,376
CASH FLOWS FROM FINANCING ACTIVITIES	'	'	'
Proceeds from the issuance of common stock	3,729	3,335	1,888
Purchase of treasury stock	-11,456	'	'
Distribution to noncontrolling interest	'	-5,595	-7,192
Acquisition of noncontrolling interest	'	-26,200	'
Net cash used in financing activities	-7,727	-28,460	-5,304
NET CHANGE IN CASH AND CASH EQUIVALENTS	-270	-6,339	55,905
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	130,800	137,139	81,234
CASH AND CASH EQUIVALENTS AT END OF PERIOD	130,529	130,800	137,139
Supplemental disclosure of cash flow information	'	'	'
Cash paid for Income taxes	34,444	83,306	92,275
Supplemental disclosure of non cash investing and financing activities	'	'	'
Property and equipment additions incurred during the period but not paid at period end	13,440	9,814	6,450
Receivable from employees for stock option exercise	'	$173	'

Organization

Organization	12 Months Ended
	Dec. 31, 2013
Organization	'
	1	ORGANIZATION
	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. As used herein, the terms “Company” and “VAALCO” mean VAALCO Energy, Inc. and its subsidiaries, unless the context otherwise requires. 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, South Dakota, 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.

Summary_of_Significant_Account

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2013
Summary of Significant Accounting Policies	'
	2	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
	Principles of Consolidation - The accompanying consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries.The portion of the income and net assets applicable to the non-controlling interest in the majority-owned operations of the Company’s Gabon subsidiary has been reflected as noncontrolling interest. All intercompany transactions within the consolidated group have been eliminated in consolidation.
	In December 2012, the Company acquired the noncontrolling interest in VAALCO International, Inc., for $26.2 million, with an effective date of October 1, 2012. Prior to the acquisition, the noncontrolling interest owned 9.99% of the issued and outstanding common stock of VAALCO International, Inc., a Delaware corporation of which VAALCO Gabon Etame, Inc. is the wholly owned subsidiary.
	Cash and Cash Equivalents - For purposes of the statements of consolidated cash flows, the Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash and cash equivalents.
	Restricted Cash – Restricted cash includes cash that is contractually restricted. Restricted cash is classified as a current or non-current asset based on its designated purpose and time duration. Current amounts at December 31, 2013 each include an escrow amount representing the Company’s bank guarantees for customs clearance in Gabon ($2.4 million) and funds restricted to secure the Company’s drilling obligation in Block 5 in Angola ($10.0 million). Long term amounts at December 31, 2013 and 2012 each include the Company’s charter payment escrow for the Floating Production Storage and Offloading tanker (“FPSO”) in Gabon ($0.8 million) and 2012 includes the funds restricted to secure the Company’s drilling obligation in Block 5 in Angola ($10.0 million).
	The Company invests restricted and excess cash in certificates of deposit and commercial paper issued by banks with maturities typically not exceeding 90 days.
	Inventory - Materials and supplies are valued at the lower of cost, determined by the weighted-average method, or market. Crude oil inventories are carried at the lower of cost or market and represent the Company’s share of crude oil produced and stored on the FPSO, but unsold. Inventory cost represents the production expenses including depletion.
	Income Taxes – VAALCO accounts for income taxes under an asset and liability approach that recognizes deferred income tax assets and liabilities for the estimated future tax consequences of differences between the financial statements and tax bases of assets and liabilities. Valuation allowances are provided against deferred tax assets that are not likely to be realized.
	Property and Equipment - The Company follows the successful efforts method of accounting for exploration and development costs. Under this method, exploration costs, other than the cost of exploratory wells, are charged to expense as incurred. Exploratory well costs are initially capitalized until a determination as to whether proved reserves have been discovered. If an exploratory well is deemed to not have found proved reserves, the associated costs are expensed at that time. Other exploration costs, including geological and geophysical expenses applicable to undeveloped leasehold, leasehold expiration costs and delay rentals are expensed as incurred. All development costs, including developmental dry hole costs, are capitalized.
	The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred by capitalizing the corresponding cost as part of the carrying amount of the long-lived assets.
	The Company reviews its oil and gas 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 must be recorded to reduce the carrying amount of the asset to its estimated fair value. Provisions for impairment of undeveloped oil and gas leases are based on periodic evaluations and other factors.
	Depletion of wells, platforms, and other production facilities are calculated on a field basis under the unit-of-production method based upon estimates of proved developed producing reserves. Depletion of developed leasehold acquisition costs are provided on a field basis under the unit-of-production method based upon estimates of proved reserves. Undeveloped leasehold acquisition costs are not subject to depletion, but are subject to impairment testing. Provision for depreciation of other property is made primarily on a straight-line basis over the estimated useful life of the property. The annual rates of depreciation are as follows:
	Office and miscellaneous equipment:	3 - 5 years
	Leasehold improvements:	8 - 12 years
	Foreign Exchange Transactions - For financial reporting purposes, the subsidiaries use the United States Dollar as their functional currency. Gains and losses on foreign currency transactions are included in income currently. The Company recognized loss on foreign currency transactions of $0.1 million in 2013 and gains of $0.4 million, and $1.0 million in 2012 and 2011, respectively.
	Accounts With Partners - Accounts with partners represent cash calls due or excess cash calls paid by the partners for exploration, development and production expenditures made by VAALCO Gabon (Etame), Inc. and VAALCO Angola (Kwanza), Inc., and VAALCO (USA), Inc.
	Bad Debt – On a quarterly basis, the Company evaluates its accounts receivable balances to confirm collectability. Where collectability is in doubt, the Company records an allowance against the accounts receivable balance with a corresponding charge to net income as bad debt expense. The majority of the Company’s accounts receivable balances are with its joint venture partners and purchasers of its oil, natural gas and natural gas liquids.  Collection efforts, including remedies provided for in the contracts, are pursued to collect overdue amounts owed to the Company.
	During 2013 and 2012, the Company recorded a bad debt allowance of $1.6 million and $1.6 million, respectively, related to the uncertainty in collecting its joint venture receivable in Angola. The table below shows a rollforward analysis of the allowance against the partner accounts receivable balance: (in thousands)
	Description		Balance			Charged			Balance
			at			to Costs			at End
			Beginning			and			of
			of Period			Expenses			Period
	Allowance for Doubtful Accounts
	Year Ended December 31, 2013			(6,069	)		(1,562	)		(7,631	)
	Year Ended December 31, 2012			(4,448	)		(1,621	)		(6,069	)
	Revenue Recognition - The Company recognizes revenues from crude oil and natural gas sales upon delivery to the buyer.
	Stock Based Compensation - The Company measures the cost of employee services received in exchange for an award of equity instruments based on the fair value of the award on the date of the grant. Grant date fair value for options is estimated using an option-pricing model which is consistent with the terms of the award. For restricted stock, grant date fair value is determined using the grant date price of the company’s shares. Such cost is recognized over the period during which an employee is required to provide service in exchange for the award (which is usually the vesting period). The Company estimates the number of instruments that will ultimately be issued, rather than accounting for forfeitures as they occur.
	Fair Value of Financial Instruments - The Company’s financial instruments consist primarily of cash, restricted cash, trade receivables and trade payables. The book values of cash, restricted cash, trade receivables, and trade payables are representative of their respective fair values due to the short-term maturity of these instruments.
	Fair Value – Fair value is defined as the price that would be received to sell an asset or the price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Inputs used in determining fair value are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. The three input levels of the fair-value hierarchy are as follows:
	Level 1 – Inputs represent quoted prices in active markets for identical assets or liabilities (for example, exchange-traded commodity derivatives).
	Level 2 – Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs).
	Level 3 – Inputs that are not observable from objective sources, such as the Company’s internally developed assumptions used in pricing an asset or liability (for example, an estimate of future cash flows used in the Company’s internally developed present value of future cash flows model that underlies the fair-value measurement).
	Risks and Uncertainties - The Company’s interests are located overseas in onshore and offshore Gabon, offshore in Angola and Equatorial Guinea, and domestically in Texas, Montana, Alabama, South Dakota, and the Louisiana Gulf Coast area.
	Substantially all of the Company’s oil and gas is sold at the well head at posted or indexed prices under short-term contracts, as is customary in the industry.
	In Gabon, the Company sold oil under contracts with Mercuria Trading NV (“Mercuria”) beginning with the calendar year 2011. For the first quarter of 2014, the Company will also sell its oil under a contract with Mercuria. While the loss of Mercuria as a buyer might have material effect on the Company in the short term, management believes that the Company would be able to obtain other customers for its crude oil.
	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.
	Use of Estimates in Financial Statement Preparation - The preparation of financial statements in conformity with generally accepted accounting principles requires estimates and assumptions that affect the reported amounts of assets and liabilities as well as certain disclosures. The Company’s consolidated financial statements include amounts that are based on management’s best estimates and judgments. Actual results could differ from those estimates.
	Estimates of oil and gas reserves used in the consolidated financial statements to estimate depletion expense and impairment charges require extensive judgments and are generally less precise than other estimates made in connection with financial disclosures. The Company considers its estimates to be reasonable; however, due to inherent uncertainties and the limited nature of data, estimates are imprecise and subject to change over time as additional information become available.
	Asset Retirement Obligations (“ARO”) - The Company has significant obligations to remove tangible equipment and restore land or seabed at the end of oil and gas production operations. The Company’s removal and restoration obligations are primarily associated with plugging and abandoning wells, removing and disposing of all or a portion of offshore oil and gas platforms, and capping pipelines. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety, and public relations considerations.
	ARO associated with retiring tangible long-lived assets is recognized as a liability in the period in which the legal obligation is incurred and becomes determinable. The liability is offset by a corresponding increase in the underlying asset. The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with The Company’s oil and gas properties. The Company utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value.
	Subsequent Events – In January 2014, the Company executed a loan agreement with the International Finance Corporation (IFC) for a $65.0 million reserve based loan facility (“RBL”) secured by the assets of the Company’s Gabon subsidiary.  The RBL provides for an availability period that expires on December 31, 2019. Borrowings under the loan agreement are limited to a borrowing base, initially established as $65.0 million ($50.0 million senior loan and a $15.0 million subordinate tranche) and scheduled to be re-determined every six months starting June 30, 2014.  RBL will bear interest at LIBOR plus 3.75% for the senior loan and LIBOR plus 5.75% for the subordinate tranche and is to be paid quarterly. The Company is also required to pay a commitment fee in respect of unutilized commitments, which is equal to 1.5% per annum on the senior loan and 2.3% per annum on the subordinate tranche. In addition, upon the signing of the RBL, the Company paid 2.5% in closing fees to the IFC. As of the date of these consolidated financial statements, the Company has no outstanding borrowings under the RBL.

StockBased_Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2013
Stock-Based Compensation	'
	3	STOCK BASED COMPENSATION
	Stock options are granted under the Company’s long-term incentive plan and have an exercise price that may not be less than the fair market value of the underlying shares on the date of grant. In general, stock options granted will become exercisable over a period determined by the Compensation Committee which in the past has been a five year life, with the options vesting over a service period of three to five years. A portion of the stock options granted in March 2013, 2012, and 2011 were vested immediately with the others vesting over a three year period. In addition, stock options will become exercisable upon a change in control, unless provided otherwise by the Compensation Committee. At December 31, 2013, there were 1,523,713 shares subject to options authorized but not granted.
	On October 21, 2013, the Company issued 100,000 shares of service based restricted stock with a grant date fair value of $5.89 per share. The vesting of these shares is dependent upon the employee’s continued service with the Company. The shares will vest evenly over a service period of 4 years. As of December 31, 2013, no shares have vested or been forfeited.
	For the years ended December 31, 2013, 2012 and 2011, the Company recognized non-cash compensation expense of $3.0 million, $2.4 million and $2.2 million, respectively. These amounts were recorded as general and administrative expense. Because the Company does not pay significant United States taxes, no amounts were recorded for tax benefits.
	A summary of the stock option activity for the year ended December 31, 2013 is provided below:
		Number of				Weighted			Weighted		Aggregate
		Shares				Average			Average		Intrinsic
		Underlying				Exercise			Remaining		Value (in
		Options (in				Price Per			Contractual		millions)
		thousands)				Share			Term
	Outstanding at beginning of period		4,065			$	6.12			2.65
	Granted		1,836			$	7.55			4.08
	Exercised		(877	)		$	4.25			0
	Forfeited		(97	)		$	7.51			3.57
	Outstanding at end of period		4,927			$	6.95			2.85	$	2.81
	Vested - end of period		3,459			$	6.58			2.44	$	2.66
	Vested and expected to vest - end of period		4,854			$	6.95			2.85	$	2.81
	The intrinsic value of a stock option is the amount by which the current market value of the underlying stock exceeds the exercise price of the option.
	As of December 31, 2013, unrecognized compensation costs totaled $2.6 million. The expense is expected to be recognized over a weighted average period of 2.0 years.
	A summary of the values of options granted and exercised for each of the years ended December 31, 2013, 2012 and 2011 is provided below:
		2013				2012			2011
	Options granted - (thousands)		1,836				1,024			1,169
	Weighted average grant date fair value - ($/share)	$	2.45			$	3.49		$	2.09
	Weighted average exercise price - ($/share)	$	4.25			$	4.62		$	4.12
	Options exercised (thousands)		877				759			302
	Total intrinsic value of options exercised - ($thousands)	$	1,201			$	3,267		$	859
	The Company received cash proceeds of $3.7 million, $3.3 million and $1.9 million from issuance of stock related to options exercised in 2013, 2012 and 2011, respectively.
	The valuation of the options granted is based upon a Black Scholes model. The table below summarizes the assumptions used to value the options issued in 2013 and 2012.
	Year		Options Issued		Weighted Avg.		Expected Term	Risk Free		Expected
					Volatility			Interest Rate		Dividend Yield
			(in thousands)
	2013		1,836		51%		2.5 years	0.30%		0%
	2012		1,024		65%		2.5 years	0.50%		0%
	2011		1,169		47%		2.5 years	0.80%		0%
	The Company has no set policy for sourcing shares for options grants. Historically the shares issued under options grants have been new shares.

Stockholders_Equity_and_Earnin

Stockholders' Equity and Earnings Per Share	12 Months Ended
	Dec. 31, 2013
Stockholders' Equity and Earnings Per Share	'
	STOCKHOLDERS’ EQUITY AND EARNINGS PER SHARE
	The Company is authorized to issue up to 100 million shares of common stock. 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 the 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.
	A reconciliation of diluted shares consists of the following:
		Year Ended December 31,
		2013		2012		2011
	Item
	Basic weighted average common stock issued and outstanding		57,298,910		57,673,342		57,047,531
	Dilutive options and restricted stock		626,091		1,158,717		925,050
	Total diluted shares		57,925,001		58,832,059		57,972,581
	A total of 3,508,865, 1,018,900, and 1,169,064 shares under option were not included because they were anti-dilutive during the years ended December 31, 2013, 2012 and 2011, respectively.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2013
Income Taxes	'
	5	INCOME TAXES
	The Company and its domestic subsidiaries file a consolidated United States income tax return. Certain subsidiaries’ operations are also subject to foreign income taxes.
	Provision for income taxes consists of the following:
	(in thousands)	Year Ended December 31,
		2013			2012			2011
	U.S. Federal:
	Current	$	-		$	-		$	-
	Deferred		-			-			-
	Foreign:
	Current		34,115			81,813			93,468
	Deferred		-			-			-
	Total	$	34,115		$	81,813		$	93,468
	The primary differences between the financial statement and tax bases of assets and liabilities at December 31, 2013 and 2012 are as follows: (In thousands)
		2013			2012
	Deferred Tax Assets:
	Basis difference in fixed assets	$	31,440		$	30,619
	Foreign tax credit carry forward		55,908			23,836
	Alternative minimum tax credit carryover		1,349			1,349
	Foreign net operating losses		42,688			38,782
	Asset retirement obligations		4,012			3,629
	Other		3,300			2,731
		$	138,697		$	100,946
	Valuation allowance		(137,348	)		(99,597	)
	Total deferred tax asset	$	1,349		$	1,349
	The Company’s unused foreign tax credits will start to expire between the years 2017 and 2023. The alternative minimum tax credits do not expire, and foreign net operating losses (“NOL”) are not subject to expiry dates. The NOL for the Company’s UK subsidiary can be carried forward indefinitely, while the NOLs for the Company’s Gabon and Angola subsidiaries are included in the respective subsidiaries’ cost oil accounts, which will be offset against future taxable revenues.  Management assesses the available positive and negative evidence to estimate if existing deferred tax assets will be utilized.  The Company does not anticipate utilization of the foreign tax credits prior to expiration nor does the Company expect to generate sufficient taxable income to utilize other deferred tax assets.  On the basis of this evaluation, a valuation allowance of $137.3 million and $99.6 million has been recorded as of December 31, 2013 and 2012, respectively, to reduce the deferred tax asset to the amount that is more likely than not to be realized.
	Under U.S. tax law, certain foreign taxes paid under arrangements such as the Company’s Production Sharing Contracts (“PSCs”) may not be eligible to be claimed as foreign tax credits and are instead treated as deductible royalties.  During the year, the Company engaged outside advisors to analyze the facts and circumstances surrounding the creditability of the foreign taxes paid to the Republic of Gabon pursuant to its PSC. Based on the advice provided by these outside advisors, the Company has revised its estimate of foreign tax credit carryovers to reflect an increase of $28.0 million. The increase in deferred tax asset for foreign tax credits was fully offset by an increase in the valuation allowance.
	Pretax income (loss) is comprised of the following:
	(in thousands)	Year Ended December 31,
		2013			2012			2011
	United States	$	(17,649	)	$	(56,979	)	$	(16,282	)
	Foreign		94,836			144,131			150,312
		$	77,187		$	87,152		$	134,030
	The statutory rate reconciliation is as follows:
	(In Thousands)	Year Ended December 31,
		2013			2012			2011
	Tax Provision Computed at Statutory Rate		27,015		$	30,503		$	46,911
	Foreign taxes not offset in U.S. by foreign tax credits		(2,072	)		25,266			28,414
	Permanent Differences		973			2,370			-
	Foreign Tax Credit Adjustments		(28,027	)
	Change in Tax Rate on Deferred		(0	)		0			-2,889
	Increase/(Decrease) in Valuation Allowance		37,752			23,675			22,038
	Other		(1,526	)		(0	)		-1,006
	Total Tax Expense	$	34,115		$	81,813		$	93,468
	At December 31, 2013, the Company was subject to foreign and United States federal taxes only, with no allocations made to state and local taxes.
	The following table summarizes the tax years that remain subject to examination by major tax jurisdictions:
	United States	2008-2013
	Gabon	2007-2013

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2013
Commitments and Contingencies	'
	6	COMMITMENTS AND CONTINGENCIES
	FPSO Charter
	In October 2012, the Company entered into an amendment with the owner of the FPSO chartered for the Etame field to extend the contract until September 2020. In connection with the charter of the FPSO, the Company, as operator of the Etame field, guaranteed the charter payments through the same period. The charter continues for two years beyond that period unless one year’s prior notice is given to the owner of the FPSO. The Company obtained several guarantees from its partners for their share of the charter payment. The Company’s share of the charter payment is 28.1%. The Company believes the need for performance under the charter guarantee is remote.
	The estimated obligations for the annual charter payment and the Company’s share of the charter payments through the end of the charter are as follows: (in thousands)
	Year		Full		Company
			Charter		Share
			Payment
	2014		$	25,843	$	7,255
	2015			25,843		7,255
	2016			25,914		7,275
	2017			25,843		7,255
	2018			25,843		7,255
	Thereafter			51,757		14,530
	Total		$	181,043	$	50,825
	The Company has recorded a liability of $1.1 million and $1.2 million at December 31, 2013 and 2012, respectively, representing the guarantee’s fair value.
	The Company’s share of charter expense, including a $0.93 per Bbl ($0.25 per Bbls in 2011) charter fee for production up to 20,000 BOPD and a $2.50 per Bbl charter fee for those Bbls produced in excess of 20,000 BOPD, was $10.4 million, $9.7 million and $7.3 million for the years ended December 31, 2013, 2012 and 2011, respectively.
	Other Lease Obligations
	In addition to the FPSO, the Company has operating lease obligations for rentals as follows: (in thousands)
	Year		Gross		Company
			Obligation		Share
	2014		$	7,927	$	2,697
	2015			5,963		2,121
	2016			3,962		1,422
	2017			434		434
	2018			36		36
	Thereafter			217		217
	Total		$	18,539	$	6,927
	The 2014 lease obligation amounts are higher than amounts for years beyond 2014 due to short term contracts for helicopter and marine vessels supporting the offshore Gabon operations.
	The Company incurred rent expense of $4.1 million, $4.4 million and $3.6 million under operating leases for the years ended December 31, 2013, 2012 and 2011, respectively.
	Gabon Obligation
	Under the terms of the Etame Production Sharing Contract, the consortium is required to provide to the local government refinery a volume of crude at a 25% discount to market price (the “Gabon Obligation”). The volume required to be furnished is the amount of the Etame Marin block production divided by the total Gabon production times the volume of oil refined by the refinery per year. In 2013, the Company paid $3.0 million for its share of the 2012 obligation. In 2012, the Company paid $3.7 million for its share of the 2011 obligation. In 2011, the Company paid $2.8 million for its share of the 2010 obligation. The Company accrues an amount for the Gabon Obligation based on management’s best estimate of the volume of crude required, because the refinery does not publish its throughput figures. The amount accrued at December 31, 2013, for the Company’s share of the 2013 obligation is $2.9 million. These costs are deemed cost recoverable under the terms of the production sharing contract.
	Offshore Gabon
	In addition to the contractual obligations described above, the Company entered into a sixth exploration period extension during 2009 and was required to spend $5.3 million for its share of two exploration wells and to acquire and process 150 square kilometers of 3-D seismic on the Etame Marin block by July 2014. One of the two exploration commitment wells was drilled in 2010 on the Omangou prospect at a cost of $8.6 million ($2.6 million net to the Company).  The second exploration commitment well was drilled in 2013 on the Ovaka prospect at a cost of $17.2 million ($5.9 million net to the Company). The seismic obligation was met with the acquisition of 223 square kilometers of 3-D seismic in 2012.  Thus, all obligations under the sixth exploration extension have been satisfied.
	As part of securing the second ten year production license with the government of Gabon, the Company agreed to a cash funding arrangement for the eventual abandonment of the offshore wells, platforms and facilities. The agreement was finalized in the first quarter of 2014 providing for annual funding for the next seven years at 12.14% of the total abandonment estimate per year and 5.0% per year for the last three years of the production license. The amounts paid will be reimbursed through the cost account and are non-refundable to the Company. The funding is expected to begin in the first half of 2014. 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.
	Angola
	In November 2006, the Company signed a production sharing contract for Block 5 offshore Angola. The four year primary term with an optional three year extension awards the Company exploration rights to 1.4 million acres offshore central Angola. The Company’s working interest is 40%. Additionally, the Company is required to carry the Angolan national oil company, Sonangol P&P, for 10% of the work program. During the first four years of the contract the Company was required to acquire and process 1,000 square kilometers of 3-D seismic data, drill two exploration wells and expend a minimum of $29.5 million ($14.8 million net to the Company). The Company fulfilled its seismic obligation when it acquired 1,175 square kilometers of 3-D seismic data at a cost of $7.5 million ($3.75 million net to the Company) in January 2007 and 524 square kilometers of 3-D seismic data during the fourth quarter of 2008 at a cost of $6.0 million ($3.0 million net to the Company).
	The government-assigned working interest partner was delinquent paying their share of the costs several times in 2009 and consequently was placed in a default position. By a governmental decree dated December 1, 2010, the former partner was removed from the production sharing contract, and a one year time extension was granted for drilling the two exploration commitment wells. In early 2012, the Angolan government granted a further one year extension to November 30, 2012 for drilling the two exploration commitment wells in accordance with the production sharing contract. In July 2012, the Angolan government granted an additional two year extension until November 30, 2014 to drill the two exploration commitment wells.
	In the fourth quarter of 2013, the Company received 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. will assign the aforementioned participating interest to its exploration and production affiliate, Sonangol P&P. The remaining obligation is a two well exploration commitment. Together with Sonangol P&P, a further time extension has been requested to allow for a proper assessment on the recently acquired seismic data and for drilling the two exploration commitment wells.   However, the Company can provide no assurances that such a request will be granted.  Each well is subject to a $5.0 million penalty ($10.0 million in aggregate for both wells) if not drilled during the contract term. The $10.0 million is currently recorded as restricted cash and is held at a financial institution located in the United States.
	Because of the continuing uncertainty with the Angolan government, the Company has recorded a full allowance totaling $7.6 million as of December 31, 2013, against the accounts receivable from partners for the amounts owed to the Company above its 40% working interest plus the 10% carried interest. The allowance recorded in the twelve months ended December 31, 2013 totaled $1.6 million with the remainder having been recorded in 2012 and 2011.  The Company invoiced its new partner, Sonangol P&P, for the cumulative accounts receivable amount in the first quarter of 2014.
	United States
	In September 2012, the Company acquired a 100% working interest in approximately 10,000 acres in Harding County, South Dakota. The primary objective for this property was the Red River formation. Pursuant to the terms of the acquisition, the Company was obligated to drill and complete a well, or reenter and complete an existing well within twelve months of the acquisition date. Once this obligation was met and within sixteen months of the acquisition date, the Company must elect to proceed or withdraw from the transaction. Should the Company elect to proceed, it must pay an additional amount of approximately $3.6 million and commit to drill and complete an additional well, or reenter and complete another existing well within twelve months of the date the Company elects to proceed with the transaction. The Company drilled the initial well on the property in the first quarter of 2013, an unsuccessful effort, at a cost of approximately $2.9 million. The Company recorded this amount as dry hole cost in the first quarter of 2013. The Company does not have plans to proceed with additional investments on this property.

Capitalization_of_Exploratory_

Capitalization of Exploratory Well Costs	12 Months Ended
	Dec. 31, 2013
Capitalization of Exploratory Well Costs	'
	7	CAPITALIZATION OF EXPLORATORY WELL COSTS
	ASC Topic 932 - Extractive Industries provides that an exploratory well shall be capitalized as part of the entity’s uncompleted wells pending the determination of whether the well has found proved reserves. Further, an exploration well that discovers oil and gas reserves, but those reserves cannot be classified as proved when drilling is completed, shall be capitalized if the well has found a sufficient quantity of reserves to justify its completion as a producing well and the entity is making sufficient progress assessing the reserves and the economic and operating viability of the project. If either condition is not met, the exploration well would be assumed to be impaired and its costs would be charged to expense.
		2013		2012		2011
	Capitalized exploratory well costs that have been capitalized for a period less than one year		-		5.9		8
	Capitalized exploratory well costs that have been capitalized for a period greater than one year		16.7		8.1		-
	Total		16.7		14		8
	Number of exploratory wells that have been capitalized for a period greater than one year		2		1		1
	In the second and third quarters of 2010, the Company drilled the Southeast Etame No. 1 well with two sidetracks in the Etame Marin block offshore Gabon. The well discovered five meters of oil-sand. Additional evaluation of the well and sidetrack information was conducted to facilitate options for developing the discovery. The Company and its joint venture partners evaluated the merits of two development options. One option involved a sub sea well to develop the Southeast Etame discovery only, whereas the second option envisioned a platform development to access both the Southeast Etame area as well as the North Tchibala field, where a discovery was made on the block prior to VAALCO’s block participation. In the second quarter of 2012, the Company and its partners agreed to proceed with the development plan featuring a fixed leg platform for developing the Southeast Etame discovery area and the North Tchibala field and the final investment decision was approved in the fourth quarter of 2012 for the construction of the platform. The Company has capitalized $7.8 million for this well in accordance with the criteria contained in the ASC Topic 932.
	In the third and fourth quarters of 2012, the Company drilled the N’Gongui No. 2 well with three sidetracks in the Mutamba Iroru block onshore Gabon. Evaluation of the well and sidetrack information is expected to continue through the second quarter of 2013. A revised production sharing contract (“PSC”) including exploration rights is in the approval process by the Republic of Gabon.  Once the PSC is approved, the application for a development area is expected to be approved without further delay.  After both approvals are obtained, a plan of development, which will include the drilling of wells and the installation of pipelines, will be submitted to the Republic of Gabon for approval. The Company has capitalized $8.9 million for this well in accordance with the criteria contained in ASC Topic 932.

Employee_Benefit_Plans

Employee Benefit Plans	12 Months Ended
	Dec. 31, 2013
Employee Benefit Plans	'
	8	EMPLOYEE BENEFIT PLANS
	The Company sponsors a 401(k) plan, with a Company match feature, for its employees. Costs incurred in 2013, 2012 and 2011 for administering the plan, including the Company match feature, were approximately $182,500, $204,000 and $172,000, respectively.

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligations	'
	9	ASSET RETIREMENT OBLIGATIONS
	The fair value of a liability for an asset retirement obligation is recognized in the period in which it is incurred by capitalizing it as part of the carrying amount of the long-lived assets. The Company records asset retirement obligations for the future abandonment costs of tangible assets such as platforms, wells, pipelines and other facilities. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.
	As part of securing the second ten year production license with the government of Gabon, the Company agreed to a cash funding arrangement for the eventual abandonment of the offshore wells, platforms and facilities. The agreement was finalized in the first quarter of 2014 providing 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 first half of 2014.  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.
	A summary of the recording of the estimated fair value of the Company’s asset retirement obligations is presented as follows:
	(In Thousands)	Year Ended December 31,
		2013		2012			2011
	Balances at January 1,	$	10,368	$	14,528		$	13,425
	Accretion Expense		643		814			1,014
	Additions		453		770			96
	Revisions		0		(5,744	)		(7	)
	Balance December 31,	$	11,464	$	10,368		$	14,528
	During the year ended December 31, 2013, the Company increased the asset retirement obligations to recognize the abandonment liability for two wells offshore Gabon.  The 2012 cost revision of $5.7 million was primarily due to changes in asset retirement cost estimates on the Etame block offshore Gabon. The increase in the asset retirement obligation in 2011 was due to the first development well in the Granite Wash formation in North Texas.
	The Company does not plan to abandon any material assets over the next five years.

Segment_Information

Segment Information	12 Months Ended
	Dec. 31, 2013
Segment Information	'
	10	SEGMENT INFORMATION
	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.  Revenues are based on the location of hydrocarbon production. The Company evaluates each segment based on income (loss) from operations. Segment activity for the years ended December 31, 2013, 2012 and 2011 are as follows: (in thousands)
	2013	Gabon		Angola			Equatorial			USA			Corporate			Total
							Guinea						and Other
	Revenues	$	167,386	$	-		$	-		$	1,891		$	-		$	169,277
	Depreciation, depletion and amortization		15,310		28			-			1,528			63			16,929
	Operating income (loss)		98,795		-3,018			(768	)		(11,869	)		(5,915	)		77,225
	Interest income		40		-			-			-			33			73
	Income taxes		34,115		-			-			-			-			34,115
	Bad debt and other expenses		1,764		1,562			-			-			-			3,326
	Additions to properties and equipment		53,015		629			-			-			47			53,691
	Long lived assets		109,597		11,540			10,000			7,235			152			138,524
	Total assets		256,033		12,204			10,059			9,660			20,211			308,167
	2012	Gabon		Angola			Equatorial			USA			Corporate			Total
							Guinea						and Other
	Revenues	$	192,489	$	-		$	-		$	2,798		$	-		$	195,287
	Depreciation, depletion and amortization		15,954		28			-			3,872			59			19,913
	Operating income (loss)		147,985		(3,293	)		(754	)		(48,940	)		(8,405	)		86,593
	Interest income		60		(1	)		-			-			86			145
	Income taxes		81,813		-			-			-			-			81,813
	Bad debt and other expenses		-		1,621			-			-			-			1,621
	Impairment of proved properties		-		-			-			7,620			-			7,620
	Additions to properties and equipment		22,731		-			10,000			13,558			77			46,366
	Long lived assets		71,225		10,938			10,000			14,279			166			106,608
	Total assets		190,652		11,405			10,000			17,314			38,585			267,956
	2011	Gabon		Angola			Equatorial			USA			Corporate			Total
							Guinea						and Other
	Revenues	$	208,781	$	-		$	-		$	1,655		$	-		$	210,436
	Depreciation, depletion and amortization		23,604		20			-			1,922			50			25,596
	Operating income (loss)		155,550		(6,221	)		-			(7,680	)		(9,088	)		132,561
	Interest income		80		-			-			-			104			184
	Income taxes		93,468		-			-			-			-			93,468
	Bad debt and expenses		-		4,448			-			-			-			4,448
	Impairment of proved properties		-		-			-			4,975			-			4,975
	Additions to properties and equipment		8,528		7			-			24,371			60			32,966
	Long lived assets		68,965		10,964			-			19,772			147			99,848
	Total assets		185,341		21,452			-			22,236			45,986			275,015
	Information about our most significant customers
	In Gabon, the Company sold oil under contracts with Mercuria Trading NV (“Mercuria”) in 2013, 2012 and 2011.

Impairment_of_Proved_Propertie

Impairment of Proved Properties	12 Months Ended
	Dec. 31, 2013
Impairment of Proved Properties	'
	11	IMPAIRMENT OF PROVED PROPERTIES
	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 must be recorded to reduce the carrying amount of the asset to its estimated fair value.
	The Company determined no impairment charge was necessary in 2013.  In 2012, the Company recorded an impairment loss of $7.6 million in the United States to write down the value of its Hefley field in the Granite Wash formation to its estimated fair value. A combination of continued production declines from both producing wells and low natural gas prices had a negative impact on the fair value of the assets and an impairment charge was warranted.
	The initial measurement of these assets at fair value is calculated using discounted cash flow techniques and based on estimates of future revenues and costs associated with the Granite Wash formation well. Significant Level 3 assumptions associated with the calculation of discounted cash flows used in the impairment analysis include the Company’s estimate of future crude oil and natural gas prices, production costs, development expenditures, and anticipated production of proved and probable reserves, appropriate risk-adjusted discount rates and other relevant data. For crude oil, estimates were based on NYMEX West Texas Intermediate prices, adjusted for quality, transportation fees, and a regional price differential. For natural gas, estimates were based on NYMEX Henry Hub prices, adjusted for energy content, transportation fees, and a regional price differential.

Quarterly_Financial_Informatio

Quarterly Financial Information (Unaudited)	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Information (Unaudited)	'
	12	QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
	The following represents our unaudited quarterly results for years ended December 31, 2013 and 2012. The quarterly results were prepared in accordance with accounting principles generally accepted in the United States of America, and reflect all adjustments that are, in the opinion of management, necessary for a fair statement of the results. These adjustments are of a normal recurring nature.
	(In thousands of dollars except per share information)	1st Quarter			2nd Quarter			3rd Quarter			4th Quarter
	2013
	Total revenues (1)	$	44,137		$	29,118		$	37,740		$	58,282
	Total operating costs and expenses		22,634			17,452			29,636			22,331
	Operating income		21,503			11,666			8,104			35,951
	Net income		7,188			7,121			2,386			26,377
	Basic net income per share.	$	0.12		$	0.12		$	0.4		$	0.46
	Diluted net income per share.	$	0.12		$	0.12		$	0.4		$	0.46
	(In thousands of dollars except per share information)	1st Quarter			2nd Quarter			3rd Quarter			4th Quarter
	2012
	Total revenues (1)	$	45,286		$	58,818		$	37,630		$	53,553
	Total operating costs and expenses		15,180			20,186			22,036			51,292
	Operating income		30,106			38,632			15,594			2,261
	Net income		10,527			12,317			1,412			(18,917	)
	Net income attributable to noncontrolling interest		(1,509	)		(1,893	)		(1,306	)		-
	Net income attributable to VAALCO Energy, Inc.		9,018			10,424			106			(18,917	)
	Basic net income per share attributable to VAALCO Energy, Inc.	$	0.16		$	0.18		$	-		$	(0.33	)
	Diluted net income per share attributable to VAALCO Energy, Inc.	$	0.15		$	0.18		$	-		$	(0.32	)
	-1	Gabon crude oil sales are a function of the number and size of crude oil liftings in each quarter from the floating production, storage and offloading (“FPSO”) facility.
	Quarterly income per share is based on the weighted average number of shares outstanding during the quarter. Because of changes in the number of shares outstanding during the quarters due to the exercise of stock options and issuance of common stock, the sum of quarterly earnings per share may not equal earnings per share for the year.

Supplemental_Information_on_Oi

Supplemental Information on Oil and Gas Producing Activities	12 Months Ended
	Dec. 31, 2013
Supplemental Information on Oil and Gas Producing Activities	'
	13	SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
	The following information is being provided as supplemental information in accordance with certain provisions of ASC Topic 932 – Extractive Activities- Oil and Gas. The Company’s reserves are located offshore of Gabon and in Texas. The following tables set forth costs incurred, capitalized costs, and results of operations relating to oil and natural gas producing activities for each of the periods. (See Footnote 1 – “ORGANIZATION”)
	Costs Incurred in Oil and Gas Property
	Acquisition, Exploration and Development Activities
	(In thousands)	United States
		2013			2012			2011
	Costs incurred during the year:
	Exploration - capitalized	$	-			2,602		$	-
	Exploration - expensed		11,497			38,159			2,083
	Acquisition		-			1,630			9,495
	Development		113			9,689			14,936
	Total	$	11,610			52,080		$	26,514
	(In thousands)	International
		2013			2012			2011
	Costs incurred during the year:
	Exploration - capitalized	$	2,942		$	5,916		$	69
	Exploration - expensed		12,431			2,878			3,625
	Acquisition		-			10,000			455
	Development		54,420			4,022			8,011
	Total	$	69,793		$	22,816		$	12,160
	Exploration expense includes $23.9 million, $37.3 million and $0.1 million for dry hole expense in 2013, 2012 and 2011, respectively. The dry hole expense for 2013 was attributable to two unsuccessful exploration wells drilled in the United States and three unsuccessful exploration wells drilled in Gabon.
	In November 2012, the Company completed the acquisition of a 31% working interest in Block P located offshore in Equatorial Guinea at a cost of $10.0 million.
	Capitalized Costs Relating to Oil and Gas Producing Activities:
		December 31,
		2013			2012			2011
	Capitalized costs -
	Properties not being amortized	$	88,194		$	66,794		$	46,047
	Properties being amortized (1)		222,032			195,329			182,820
	Total capitalized costs	$	310,226		$	262,123		$	228,867
	Less accumulated depreciation, depletion, and amortization		(171,854	)		(155,681	)		(129,166	)
	Net capitalized costs	$	138,372		$	106,442		$	99,701
	-1	Includes $5.2 million, $4.7 million, and $10.4 million asset retirement cost in 2013, 2012, and 2011, respectively.
	The capitalized costs pertain to the Company’s producing activities in Gabon, leasehold acreage in Gabon, Angola, and Equatorial Guinea, and U.S. activities.
	Results of Operations for Oil and Gas Producing Activities:
		United States									International
		2013			2012			2011			2013			2012			2011
											Gabon			Gabon			Gabon
	Crude oil and gas sales	$	1,891		$	2,798		$	1,655		$	167,386		$	192,489		$	208,781
	Production, G&A and other expense		(12,232	)		(47,866	)		(7,413	)		(52,776	)		(27,425	)		(27,471	)
	Depreciation, depletion and amortization		(1,528	)		(3,872	)		(1,922	)		(15,302	)		(15,954	)		(23,604	)
	Income tax		-			-			-			(34,115	)		(81,813	)		(93,468	)
	Results from oil and gas producing activities	$	(11,869	)	$	(48,940	)	$	(7,680	)	$	65,193		$	67,297		$	64,238
	Proved Reserves
	Reserve reports as of December 31, 2013, 2012, and 2011 have been prepared by Netherland, Sewell & Associates, Inc., independent petroleum engineers. The following tables set forth the net proved reserves of the Company as of December 31, 2013, 2012 and 2011, and the changes during such periods.
	Proved Reserves:	Oil (MBbls)			Gas (MMCF)
	Balance at Janaury 1, 2011		6,922			23
	Production		(1,868	)		(255	)
	Revisions of previous estimates		959			31
	Extensions and discoveries		35			2,126
	Balance at December 31, 2011		6,048			1,925
	Production		(1,741	)		(532	)
	Revisions of previous estimates		2,200			151
	Extensions and discoveries		981			-
	Balance at December 31, 2012		7,488			1,544
	Production		(1,549	)		(325	)
	Revisions of previous estimates		771			114
	Extensions and discoveries		522			-
	Balance at December 31, 2013		7,232			1,333
	Proved Developed Reserves	Oil (MBbls)			Gas (MMCF)
	Balance at January 1, 2011		5,029			23
	Balance at December 31, 2011		3,854			856
	Balance at December 31, 2012		3,750			1,544
	Balance at December 31, 2013		3,305			1,333
The Company’s proved developed reserves are located offshore Gabon and in Texas. Revisions in 2011 were attributable to better reservoir performance at the Etame, Avouma, South Tchibala and Ebouri fields. In 2011, discoveries were attributable to the Granite Wash formation leases in North Texas. Revisions in 2012 were attributable to better reservoir performance at the Etame, Avouma, South Tchibala and Ebouri fields. In 2012, discoveries were attributable to the South-East Etame and North Tchibala fields offshore Gabon. Revisions in 2013 were attributable to better reservoir performance from the Etame, Avouma, South Tchibala and Ebouri fields. In 2013, discoveries were attributable to the Avouma 5-H development well in the Avouma field, offshore Gabon.
The Company maintains a policy of not booking proved reserves on discoveries until such time as a development plan has been prepared for the discovery. Additionally, the development plan is required to have the approval of the Company’s partners in the discovery. Furthermore, if a government agreement that the reserves are commercial is required to develop the field, this approval must have been received prior to booking any reserves.
Standardized Measure of Discounted Future Net Cash
Flows Relating to Proved Oil Reserves
The information that follows has been developed pursuant to procedures prescribed by ASC Topic 932 and utilizes reserve and production data estimated by independent petroleum consultants. The information may be useful for certain comparison purposes, but should not be solely relied upon in evaluating VAALCO Energy, Inc. or its performance.
In accordance with the guidelines of the SEC, the Company’s estimates of future net cash flow from the Company’s properties and the present value thereof are made using oil and gas contract prices using a twelve month average of beginning of month prices and are held constant throughout the life of the properties except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. The future cash flows are also based on costs in existence at the dates of the projections, excluding Gabon royalties, and the interests of other consortium members. Future production costs do not include overhead charges allowed under joint operating agreements or headquarters general and administrative overhead expenses. Future development costs include $52.8 million ($14.8 million net to the Company) attributable to future abandonment when the wells become uneconomic to produce.
(In thousands)	United States									International									Total
	December 31,									December 31,									December 31,
	2013			2012			2011			2013			2012			2011			2013			2012			2011
Future cash inflows	$	8,276		$	8,260		$	13,274		$	725,485		$	776,646		$	623,546		$	733,761		$	784,906		$	636,820
Future production costs		(3,038	)		(3,194	)		(1,661	)		(223,643	)		(203,490	)		(154,020	)		(226,681	)		(206,684	)		(155,681	)
Future development costs		-			-			(4,180	)		(164,142	)		(186,982	)		(85,528	)		(164,142	)		(186,982	)		(89,708	)
Future income tax expense		(825	)		(807	)		(1,347	)		(154,519	)		(181,194	)		(181,886	)		(155,344	)		(182,001	)		(183,233	)
Future net cash flows	$	4,413		$	4,259		$	6,086		$	183,181		$	204,980		$	202,112		$	187,594		$	209,239		$	208,198
Discount to present value at 10% annual rate		(1,299	)		(1,028	)		(3,150	)		(48,859	)		(55,309	)		(38,861	)		(50,158	)		(56,337	)		(42,011	)
Standardized measure of discounted future net cash flows	$	3,114		$	3,231		$	2,936		$	134,322		$	149,671		$	163,251		$	137,436		$	152,902		$	166,187
International income taxes represent amounts payable to the Government of Gabon on profit oil as final payment of corporate income taxes, and domestic income taxes represent amounts payable for severance taxes in Texas.
Changes in Standardized Measure of Discounted Future Net Cash Flows:
The following table sets forth the changes in standardized measure of discounted future net cash flows as follows:
(In thousands)	December 31,
	2013			2012			2011
Balance at Beginning of Period	$	152,902		$	166,187		$	124,824
Sales of oil and gas, net of production costs		(132,662	)		(168,563	)		(183,705	)
Net changes in prices and production costs		(52,056	)		(11,223	)		194,633
Revisions of previous quantity estimates		43,815			155,111			75,713
Additions		29,620			69,092			7,742
Changes in estimated future development costs		(5,345	)		(67,834	)		(5,831	)
Development costs incurred during the period		44,389			34,944			31,913
Accretion of discount		15,290			16,619			12,482
Net change of income taxes		26,120			7,445			4,455
Change in production rates (timing) and other		15,363			(48,876	)		(96,039	)
Balance at End of Period	$	137,436		$	152,902		$	166,187
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the Company. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of oil and gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and gas sales prices may all differ from those assumed in these estimates. The standardized measure of discounted future net cash flow should not be construed as the current market value of the estimated oil and natural gas reserves attributable to the Company’s properties. The information set forth in the foregoing tables includes revisions for certain reserve estimates attributable to proved properties included in the preceding year’s estimates. Such revisions are the result of additional information from subsequent completions and production history from the properties involved or the result of a decrease (or increase) in the projected economic life of such properties resulting from changes in product prices. Moreover, crude oil amounts shown for Gabon are recoverable under a service contract and the reserves in place remain the property of the Gabon government.
In accordance with the guidelines of the Securities and Exchange Commission, the Company’s estimates of future net cash flow from the Company’s properties and the present value thereof are made using oil and gas contract prices using a twelve month average of beginning of month prices and are held constant throughout the life of the properties except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. In Gabon, the weighted average price was $107.69 per Bbl. In the United States, the weighted average price was $87.61 per Bbl of oil and $4.51 per Mcf of gas.
Under the Production Sharing Contract in Gabon, the Gabonese government is the owner of all oil and gas mineral rights. The right to produce the oil and gas is stewarded by the Directorate Generale de Hydrocarbures and the Production Sharing Contract was awarded by a decree from the State. Pursuant to the service contract, the Gabon government receives a fixed royalty rate of 13%.
The consortium maintains a Cost Account, which entitles it to receive 70% of the production remaining after deducting the royalty so long as there are amounts remaining in the Cost Account. At December 31, 2013, there was $30.1 million in the cost account net to the Company. As payment of corporate income taxes the consortium pays the government an allocation of the remaining “profit oil” production from the contract area ranging from 50% to 60% of the oil remaining after deducting the royalty and the cost oil. The percentage of “profit oil” paid to the government as tax is a function of production rates. So long as amounts remain in the Cost Account, the net share that the consortium receives from production can range from a low of 67.7% of production at production rate in excess of 25,000 BOPD to a high of 82.5% of production at rates below 5,000 BOPD. However, when the Cost Account becomes substantially recovered, the Company only recovers ongoing operating expenses and new project capital expenditures, resulting in a higher tax rate. The Cost Account has been substantially recovered since the first quarter of 2005. In 2011, the Company cost recovered 304,000 barrels out of a theoretical 1,303,000 barrels which would have been recoverable if the Cost Account was full. In 2012, the Company cost recovered 367,000 barrels out of a theoretical 1,197,000 barrels which would have been recoverable if the Cost Account was full.  In 2013, the Company cost recovered 929,400 barrels out of a theoretical 1,079,300 barrels which would have been recoverable if the Cost Account was full.
Also because of the nature of the Cost Account, increases in oil prices result in a lesser number of barrels required to recover costs, therefore at higher oil prices, the Company’s net reserves after taxes would decrease, but at lower prices the Company’s Cost Oil barrels increase.
The Etame Production Sharing Contract allows for the carve-out of a development area, which was performed for the Etame, Avouma and Ebouri fields. The Etame development area has a term of 20 years and will expire in 2021. The Avouma field development area has a term of 20 years and will expire in 2025. The Ebouri field development area has a term of 20 years and will expire in 2026. The Company expects to apply for development areas in 2013 for the Southeast Etame and North Tchibala fields. The balance of the Etame Marin block comprises the exploration area, which expires in July 2014.
Under the service contract, it is not anticipated that the Gabonese government will take physical delivery of its allocated production. Instead, the Company is authorized to sell the Gabonese government’s share of production and remit the proceeds to the Gabonese government.
The Mutamba Iroru production sharing contract entitles the Company to receive 70% of any future production remaining after deducting the royalty so long as there are amounts remaining in the Cost Account. At December 31, 2013 there was $36.4 million in the Cost Account. As payment of corporate income taxes the consortium pays the government an allocation of the remaining “profit oil” production from the contract area ranging from 50% to 63% of the oil remaining after deducting the royalty and the cost oil. The percentage of “profit oil” paid to the government as tax is a function of production rates. So long as amounts remain in the Cost Account, the net share that the consortium receives from production can range from a low of 72% of production at production rate in excess of 20,000 BOPD to a high of 85% of production at rates below 7,500 Bbl per day. However, when the Cost Account becomes substantially recovered, the Company only recovers ongoing operating expenses and new project capital expenditures, resulting in a higher tax rate. The Mutamba Iroru service contract provides for all commercial discoveries to be reclassified into a development area with a term of twenty years. At December 31, 2013, the Company has no proved reserves related to the Mutamba Iroru block.
The Block 5 production sharing contract in Angola entitles the Company to receive 50% of the any future production so long as there are amounts remaining in the Cost Account. There are no royalty payments under the contract. The consortium pays the government an allocation of the remaining “profit oil” production from the contract area ranging from 30% to 90% of the oil remaining after deducting the cost oil. The percentage of “profit oil” paid to the government as tax is a function of the Company’s rate of return for each development area. The Block 5 production sharing contract provides for a discovery to be reclassified into a development area with a term of twenty years. At December 31, 2013, the Company has no proved reserves related to Block 5 in Angola.
The Block P production sharing contract in Equatorial Guinea entitles the Company to receive up to 70% of the any future production after royalty deduction so long as there are amounts remaining in the Cost Account. Royalty rates are 10-16% depending on production rates. The consortium pays the government an allocation of the remaining “profit oil” production from the contract area ranging from 10% to 60% of the oil remaining after deducting the royalty and cost oil. The percentage of “profit oil” paid to the government as tax is a function of cumulative production. In addition, Equatorial Guinea imposes a 25% income tax on net profits. The Block P production sharing contract provides for a discovery to be reclassified into a development area with a term of twenty five years. At December 31, 2013, the Company has no proved reserves related to Block P in Equatorial Guinea.

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2013
Subsequent Events	'
	Credit Facility
	In January 2014, the Company executed a loan agreement with the International Finance Corporation (IFC) for a $65.0 million reserve based loan facility (“RBL”) secured by the assets of the Company’s Gabon subsidiary. The RBL provides for an availability period that expires on December 31, 2019. Borrowings under the loan agreement are limited to a borrowing base, initially established as $65.0 million ($50.0 million senior loan and a $15.0 million subordinate tranche) and scheduled to be re-determined every six months starting June 30, 2014. RBL will bear interest at LIBOR plus 3.75% for the senior loan and LIBOR plus 5.75% for the subordinate tranche and is to be paid quarterly. The Company is also required to pay a commitment fee in respect of unutilized commitments, which is equal to 1.5% per annum on the senior loan and 2.3% per annum on the subordinate tranche. In addition, upon the signing of the RBL, the Company paid 2.5% in closing fees to the IFC. As of the date of this report, the Company has no outstanding borrowings under the RBL.
Principles of Consolidation	'
	Principles of Consolidation - The accompanying consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries.The portion of the income and net assets applicable to the non-controlling interest in the majority-owned operations of the Company’s Gabon subsidiary has been reflected as noncontrolling interest. All intercompany transactions within the consolidated group have been eliminated in consolidation.
	In December 2012, the Company acquired the noncontrolling interest in VAALCO International, Inc., for $26.2 million, with an effective date of October 1, 2012. Prior to the acquisition, the noncontrolling interest owned 9.99% of the issued and outstanding common stock of VAALCO International, Inc., a Delaware corporation of which VAALCO Gabon Etame, Inc. is the wholly owned subsidiary.
Cash and Cash Equivalents	'
	Cash and Cash Equivalents - For purposes of the statements of consolidated cash flows, the Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash and cash equivalents.
Restricted Cash	'
	Restricted Cash – Restricted cash includes cash that is contractually restricted. Restricted cash is classified as a current or non-current asset based on its designated purpose and time duration. Current amounts at December 31, 2013 each include an escrow amount representing the Company’s bank guarantees for customs clearance in Gabon ($2.4 million) and funds restricted to secure the Company’s drilling obligation in Block 5 in Angola ($10.0 million). Long term amounts at December 31, 2013 and 2012 each include the Company’s charter payment escrow for the Floating Production Storage and Offloading tanker (“FPSO”) in Gabon ($0.8 million) and 2012 includes the funds restricted to secure the Company’s drilling obligation in Block 5 in Angola ($10.0 million).
	The Company invests restricted and excess cash in certificates of deposit and commercial paper issued by banks with maturities typically not exceeding 90 days.
Inventory	'
	Inventory - Materials and supplies are valued at the lower of cost, determined by the weighted-average method, or market. Crude oil inventories are carried at the lower of cost or market and represent the Company’s share of crude oil produced and stored on the FPSO, but unsold. Inventory cost represents the production expenses including depletion.
Income Taxes	'
	Income Taxes – VAALCO accounts for income taxes under an asset and liability approach that recognizes deferred income tax assets and liabilities for the estimated future tax consequences of differences between the financial statements and tax bases of assets and liabilities. Valuation allowances are provided against deferred tax assets that are not likely to be realized.
Property and Equipment	'
	Property and Equipment - The Company follows the successful efforts method of accounting for exploration and development costs. Under this method, exploration costs, other than the cost of exploratory wells, are charged to expense as incurred. Exploratory well costs are initially capitalized until a determination as to whether proved reserves have been discovered. If an exploratory well is deemed to not have found proved reserves, the associated costs are expensed at that time. Other exploration costs, including geological and geophysical expenses applicable to undeveloped leasehold, leasehold expiration costs and delay rentals are expensed as incurred. All development costs, including developmental dry hole costs, are capitalized.
	The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred by capitalizing the corresponding cost as part of the carrying amount of the long-lived assets.
	The Company reviews its oil and gas 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 must be recorded to reduce the carrying amount of the asset to its estimated fair value. Provisions for impairment of undeveloped oil and gas leases are based on periodic evaluations and other factors.
	Depletion of wells, platforms, and other production facilities are calculated on a field basis under the unit-of-production method based upon estimates of proved developed producing reserves. Depletion of developed leasehold acquisition costs are provided on a field basis under the unit-of-production method based upon estimates of proved reserves. Undeveloped leasehold acquisition costs are not subject to depletion, but are subject to impairment testing. Provision for depreciation of other property is made primarily on a straight-line basis over the estimated useful life of the property. The annual rates of depreciation are as follows:
	Office and miscellaneous equipment:	3 - 5 years
	Leasehold improvements:	8 - 12 years
Foreign Exchange Transactions	'
	Foreign Exchange Transactions - For financial reporting purposes, the subsidiaries use the United States Dollar as their functional currency. Gains and losses on foreign currency transactions are included in income currently. The Company recognized loss on foreign currency transactions of $0.1 million in 2013 and gains of $0.4 million, and $1.0 million in 2012 and 2011, respectively.
Accounts with Partners	'
	Accounts With Partners - Accounts with partners represent cash calls due or excess cash calls paid by the partners for exploration, development and production expenditures made by VAALCO Gabon (Etame), Inc. and VAALCO Angola (Kwanza), Inc., and VAALCO (USA), Inc.
Bad Debt	'
	Bad Debt – On a quarterly basis, the Company evaluates its accounts receivable balances to confirm collectability. Where collectability is in doubt, the Company records an allowance against the accounts receivable balance with a corresponding charge to net income as bad debt expense. The majority of the Company’s accounts receivable balances are with its joint venture partners and purchasers of its oil, natural gas and natural gas liquids.  Collection efforts, including remedies provided for in the contracts, are pursued to collect overdue amounts owed to the Company.
	During 2013 and 2012, the Company recorded a bad debt allowance of $1.6 million and $1.6 million, respectively, related to the uncertainty in collecting its joint venture receivable in Angola. The table below shows a rollforward analysis of the allowance against the partner accounts receivable balance: (in thousands)
	Description		Balance			Charged			Balance
			at			to Costs			at End
			Beginning			and			of
			of Period			Expenses			Period
	Allowance for Doubtful Accounts
	Year Ended December 31, 2013			(6,069	)		(1,562	)		(7,631	)
	Year Ended December 31, 2012			(4,448	)		(1,621	)		(6,069	)
Revenue Recognition	'
	Revenue Recognition - The Company recognizes revenues from crude oil and natural gas sales upon delivery to the buyer.
Stock Based Compensation	'
	Stock Based Compensation - The Company measures the cost of employee services received in exchange for an award of equity instruments based on the fair value of the award on the date of the grant. Grant date fair value for options is estimated using an option-pricing model which is consistent with the terms of the award. For restricted stock, grant date fair value is determined using the grant date price of the company’s shares. Such cost is recognized over the period during which an employee is required to provide service in exchange for the award (which is usually the vesting period). The Company estimates the number of instruments that will ultimately be issued, rather than accounting for forfeitures as they occur.
Fair Value of Financial Instruments	'
	Fair Value of Financial Instruments - The Company’s financial instruments consist primarily of cash, restricted cash, trade receivables and trade payables. The book values of cash, restricted cash, trade receivables, and trade payables are representative of their respective fair values due to the short-term maturity of these instruments.
Fair Value	'
	Fair Value – Fair value is defined as the price that would be received to sell an asset or the price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Inputs used in determining fair value are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. The three input levels of the fair-value hierarchy are as follows:
	Level 1 – Inputs represent quoted prices in active markets for identical assets or liabilities (for example, exchange-traded commodity derivatives).
	Level 2 – Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs).
	Level 3 – Inputs that are not observable from objective sources, such as the Company’s internally developed assumptions used in pricing an asset or liability (for example, an estimate of future cash flows used in the Company’s internally developed present value of future cash flows model that underlies the fair-value measurement).
Risks and Uncertainties	'
	Risks and Uncertainties - The Company’s interests are located overseas in onshore and offshore Gabon, offshore in Angola and Equatorial Guinea, and domestically in Texas, Montana, Alabama, South Dakota, and the Louisiana Gulf Coast area.
	Substantially all of the Company’s oil and gas is sold at the well head at posted or indexed prices under short-term contracts, as is customary in the industry.
	In Gabon, the Company sold oil under contracts with Mercuria Trading NV (“Mercuria”) beginning with the calendar year 2011. For the first quarter of 2014, the Company will also sell its oil under a contract with Mercuria. While the loss of Mercuria as a buyer might have material effect on the Company in the short term, management believes that the Company would be able to obtain other customers for its crude oil.
	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.
Use of Estimates in Financial Statement Preparation	'
	Use of Estimates in Financial Statement Preparation - The preparation of financial statements in conformity with generally accepted accounting principles requires estimates and assumptions that affect the reported amounts of assets and liabilities as well as certain disclosures. The Company’s consolidated financial statements include amounts that are based on management’s best estimates and judgments. Actual results could differ from those estimates.
	Estimates of oil and gas reserves used in the consolidated financial statements to estimate depletion expense and impairment charges require extensive judgments and are generally less precise than other estimates made in connection with financial disclosures. The Company considers its estimates to be reasonable; however, due to inherent uncertainties and the limited nature of data, estimates are imprecise and subject to change over time as additional information become available.
Asset Retirement Obligations ("ARO")	'
	Asset Retirement Obligations (“ARO”) - The Company has significant obligations to remove tangible equipment and restore land or seabed at the end of oil and gas production operations. The Company’s removal and restoration obligations are primarily associated with plugging and abandoning wells, removing and disposing of all or a portion of offshore oil and gas platforms, and capping pipelines. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety, and public relations considerations.
	ARO associated with retiring tangible long-lived assets is recognized as a liability in the period in which the legal obligation is incurred and becomes determinable. The liability is offset by a corresponding increase in the underlying asset. The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with The Company’s oil and gas properties. The Company utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value.

Capitalization_of_Exploratory_1

Capitalization of Exploratory Well Costs (Policies)	12 Months Ended
	Dec. 31, 2013
Extractive Industries	'
	ASC Topic 932 - Extractive Industries provides that an exploratory well shall be capitalized as part of the entity’s uncompleted wells pending the determination of whether the well has found proved reserves. Further, an exploration well that discovers oil and gas reserves, but those reserves cannot be classified as proved when drilling is completed, shall be capitalized if the well has found a sufficient quantity of reserves to justify its completion as a producing well and the entity is making sufficient progress assessing the reserves and the economic and operating viability of the project. If either condition is not met, the exploration well would be assumed to be impaired and its costs would be charged to expense.
		2013		2012		2011
	Capitalized exploratory well costs that have been capitalized for a period less than one year		-		5.9		8
	Capitalized exploratory well costs that have been capitalized for a period greater than one year		16.7		8.1		-
	Total		16.7		14		8
	Number of exploratory wells that have been capitalized for a period greater than one year		2		1		1
	In the second and third quarters of 2010, the Company drilled the Southeast Etame No. 1 well with two sidetracks in the Etame Marin block offshore Gabon. The well discovered five meters of oil-sand. Additional evaluation of the well and sidetrack information was conducted to facilitate options for developing the discovery. The Company and its joint venture partners evaluated the merits of two development options. One option involved a sub sea well to develop the Southeast Etame discovery only, whereas the second option envisioned a platform development to access both the Southeast Etame area as well as the North Tchibala field, where a discovery was made on the block prior to VAALCO’s block participation. In the second quarter of 2012, the Company and its partners agreed to proceed with the development plan featuring a fixed leg platform for developing the Southeast Etame discovery area and the North Tchibala field and the final investment decision was approved in the fourth quarter of 2012 for the construction of the platform. The Company has capitalized $7.8 million for this well in accordance with the criteria contained in the ASC Topic 932.
	In the third and fourth quarters of 2012, the Company drilled the N’Gongui No. 2 well with three sidetracks in the Mutamba Iroru block onshore Gabon. Evaluation of the well and sidetrack information is expected to continue through the second quarter of 2013. A revised production sharing contract (“PSC”) including exploration rights is in the approval process by the Republic of Gabon.  Once the PSC is approved, the application for a development area is expected to be approved without further delay.  After both approvals are obtained, a plan of development, which will include the drilling of wells and the installation of pipelines, will be submitted to the Republic of Gabon for approval. The Company has capitalized $8.9 million for this well in accordance with the criteria contained in ASC Topic 932.

Summary_of_Significant_Account2

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2013
Estimated Useful Life of Property Plant and Equipment	'
	Office and miscellaneous equipment:	3 - 5 years
	Leasehold improvements:	8 - 12 years
Rollforward Analysis of the Allowance Against the Partner Accounts Receivable Balance	'
	Description		Balance			Charged			Balance
			at			to Costs			at End
			Beginning			and			of
			of Period			Expenses			Period
	Allowance for Doubtful Accounts
	Year Ended December 31, 2013			(6,069	)		(1,562	)		(7,631	)
	Year Ended December 31, 2012			(4,448	)		(1,621	)		(6,069	)

Stock_Based_Compensation_Table

Stock Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2013
Stock Option Activity	'
	A summary of the stock option activity for the year ended December 31, 2013 is provided below:
		Number of				Weighted			Weighted		Aggregate
		Shares				Average			Average		Intrinsic
		Underlying				Exercise			Remaining		Value (in
		Options (in				Price Per			Contractual		millions)
		thousands)				Share			Term
	Outstanding at beginning of period		4,065			$	6.12			2.65
	Granted		1,836			$	7.55			4.08
	Exercised		(877	)		$	4.25			0
	Forfeited		(97	)		$	7.51			3.57
	Outstanding at end of period		4,927			$	6.95			2.85	$	2.81
	Vested - end of period		3,459			$	6.58			2.44	$	2.66
	Vested and expected to vest - end of period		4,854			$	6.95			2.85	$	2.81
A Summary of the Values of Options Granted and Exercised	'
	A summary of the values of options granted and exercised for each of the years ended December 31, 2013, 2012 and 2011 is provided below:
		2013				2012			2011
	Options granted - (thousands)		1,836				1,024			1,169
	Weighted average grant date fair value - ($/share)	$	2.45			$	3.49		$	2.09
	Weighted average exercise price - ($/share)	$	4.25			$	4.62		$	4.12
	Options exercised (thousands)		877				759			302
	Total intrinsic value of options exercised - ($thousands)	$	1,201			$	3,267		$	859
The Valuation of the Options Granted	'
	The valuation of the options granted is based upon a Black Scholes model. The table below summarizes the assumptions used to value the options issued in 2013 and 2012.
	Year		Options Issued		Weighted Avg.		Expected Term	Risk Free		Expected
					Volatility			Interest Rate		Dividend Yield
			(in thousands)
	2013		1,836		51%		2.5 years	0.30%		0%
	2012		1,024		65%		2.5 years	0.50%		0%
	2011		1,169		47%		2.5 years	0.80%		0%

Stockholders_Equity_and_Earnin1

Stockholders' Equity and Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2013
Schedule of Diluted Shares	'
	A reconciliation of diluted shares consists of the following:
		Year Ended December 31,
		2013		2012		2011
	Item
	Basic weighted average common stock issued and outstanding		57,298,910		57,673,342		57,047,531
	Dilutive options and restricted stock		626,091		1,158,717		925,050
	Total diluted shares		57,925,001		58,832,059		57,972,581

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2013
Provision for Income Taxes	'
	Provision for income taxes consists of the following:
	(in thousands)	Year Ended December 31,
		2013			2012			2011
	U.S. Federal:
	Current	$	-		$	-		$	-
	Deferred		-			-			-
	Foreign:
	Current		34,115			81,813			93,468
	Deferred		-			-			-
	Total	$	34,115		$	81,813		$	93,468
Summary of Differences between the Financial Statement and Tax Bases of Assets and Liabilities	'
	The primary differences between the financial statement and tax bases of assets and liabilities at December 31, 2013 and 2012 are as follows: (In thousands)
		2013			2012
	Deferred Tax Assets:
	Basis difference in fixed assets	$	31,440		$	30,619
	Foreign tax credit carry forward		55,908			23,836
	Alternative minimum tax credit carryover		1,349			1,349
	Foreign net operating losses		42,688			38,782
	Asset retirement obligations		4,012			3,629
	Other		3,300			2,731
		$	138,697		$	100,946
	Valuation allowance		(137,348	)		(99,597	)
	Total deferred tax asset	$	1,349		$	1,349
Pretax Income	'
	Pretax income (loss) is comprised of the following:
	(in thousands)	Year Ended December 31,
		2013			2012			2011
	United States	$	(17,649	)	$	(56,979	)	$	(16,282	)
	Foreign		94,836			144,131			150,312
		$	77,187		$	87,152		$	134,030
Statutory Rate Reconciliation	'
	The statutory rate reconciliation is as follows:
	(In Thousands)	Year Ended December 31,
		2013			2012			2011
	Tax Provision Computed at Statutory Rate		27,015		$	30,503		$	46,911
	Foreign taxes not offset in U.S. by foreign tax credits		(2,072	)		25,266			28,414
	Permanent Differences		973			2,370			-
	Foreign Tax Credit Adjustments		(28,027	)
	Change in Tax Rate on Deferred		(0	)		0			-2,889
	Increase/(Decrease) in Valuation Allowance		37,752			23,675			22,038
	Other		(1,526	)		(0	)		-1,006
	Total Tax Expense	$	34,115		$	81,813		$	93,468
Income Tax Years Subject to Examination by Major Tax Jurisdictions	'
	The following table summarizes the tax years that remain subject to examination by major tax jurisdictions:
	United States	2008-2013
	Gabon	2007-2013

Commitments_and_Contingencies_

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2013
Estimated Obligations and Companies Share for the Annual Charter Payment	'
	The estimated obligations for the annual charter payment and the Company’s share of the charter payments through the end of the charter are as follows: (in thousands)
	Year	Full		Company
		Charter		Share
		Payment
	2014	$	25,843	$	7,255
	2015		25,843		7,255
	2016		25,914		7,275
	2017		25,843		7,255
	2018		25,843		7,255
	Thereafter		51,757		14,530
	Total	$	181,043	$	50,825
Operating Lease Obligations for Rentals	'
	In addition to the FPSO, the Company has operating lease obligations for rentals as follows: (in thousands)
	Year	Gross		Company
		Obligation		Share
	2014	$	7,927	$	2,697
	2015		5,963		2,121
	2016		3,962		1,422
	2017		434		434
	2018		36		36
	Thereafter		217		217
	Total	$	18,539	$	6,927

Capitalization_of_Exploratory_2

Capitalization of Exploratory Well Costs (Tables)	12 Months Ended
	Dec. 31, 2013
Schedule of Capitalized Exploratory Well Costs	'
		2013		2012		2011
	Capitalized exploratory well costs that have been capitalized for a period less than one year		-		5.9		8
	Capitalized exploratory well costs that have been capitalized for a period greater than one year		16.7		8.1		-
	Total		16.7		14		8
	Number of exploratory wells that have been capitalized for a period greater than one year		2		1		1

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2013
Estimated Fair Value of Company's Asset Retirement Obligations	'
	A summary of the recording of the estimated fair value of the Company’s asset retirement obligations is presented as follows:
	(In Thousands)	Year Ended December 31,
		2013		2012			2011
	Balances at January 1,	$	10,368	$	14,528		$	13,425
	Accretion Expense		643		814			1,014
	Additions		453		770			96
	Revisions		0		(5,744	)		(7	)
	Balance December 31,	$	11,464	$	10,368		$	14,528

Segment_Information_Tables

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2013
Segment Activity	'
	2013	Gabon		Angola			Equatorial			USA			Corporate			Total
							Guinea						and Other
	Revenues	$	167,386	$	-		$	-		$	1,891		$	-		$	169,277
	Depreciation, depletion and amortization		15,310		28			-			1,528			63			16,929
	Operating income (loss)		98,795		-3,018			(768	)		(11,869	)		(5,915	)		77,225
	Interest income		40		-			-			-			33			73
	Income taxes		34,115		-			-			-			-			34,115
	Bad debt and other expenses		1,764		1,562			-			-			-			3,326
	Additions to properties and equipment		53,015		629			-			-			47			53,691
	Long lived assets		109,597		11,540			10,000			7,235			152			138,524
	Total assets		256,033		12,204			10,059			9,660			20,211			308,167
	2012	Gabon		Angola			Equatorial			USA			Corporate			Total
							Guinea						and Other
	Revenues	$	192,489	$	-		$	-		$	2,798		$	-		$	195,287
	Depreciation, depletion and amortization		15,954		28			-			3,872			59			19,913
	Operating income (loss)		147,985		(3,293	)		(754	)		(48,940	)		(8,405	)		86,593
	Interest income		60		(1	)		-			-			86			145
	Income taxes		81,813		-			-			-			-			81,813
	Bad debt and other expenses		-		1,621			-			-			-			1,621
	Impairment of proved properties		-		-			-			7,620			-			7,620
	Additions to properties and equipment		22,731		-			10,000			13,558			77			46,366
	Long lived assets		71,225		10,938			10,000			14,279			166			106,608
	Total assets		190,652		11,405			10,000			17,314			38,585			267,956
	2011	Gabon		Angola			Equatorial			USA			Corporate			Total
							Guinea						and Other
	Revenues	$	208,781	$	-		$	-		$	1,655		$	-		$	210,436
	Depreciation, depletion and amortization		23,604		20			-			1,922			50			25,596
	Operating income (loss)		155,550		(6,221	)		-			(7,680	)		(9,088	)		132,561
	Interest income		80		-			-			-			104			184
	Income taxes		93,468		-			-			-			-			93,468
	Bad debt and expenses		-		4,448			-			-			-			4,448
	Impairment of proved properties		-		-			-			4,975			-			4,975
	Additions to properties and equipment		8,528		7			-			24,371			60			32,966
	Long lived assets		68,965		10,964			-			19,772			147			99,848
	Total assets		185,341		21,452			-			22,236			45,986			275,015

Quarterly_Financial_Informatio1

Quarterly Financial Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2013
Summary of Quarterly Financial Information	'
	(In thousands of dollars except per share information)	1st Quarter			2nd Quarter			3rd Quarter			4th Quarter
	2013
	Total revenues (1)	$	44,137		$	29,118		$	37,740		$	58,282
	Total operating costs and expenses		22,634			17,452			29,636			22,331
	Operating income		21,503			11,666			8,104			35,951
	Net income		7,188			7,121			2,386			26,377
	Basic net income per share.	$	0.12		$	0.12		$	0.4		$	0.46
	Diluted net income per share.	$	0.12		$	0.12		$	0.4		$	0.46
	(In thousands of dollars except per share information)	1st Quarter			2nd Quarter			3rd Quarter			4th Quarter
	2012
	Total revenues (1)	$	45,286		$	58,818		$	37,630		$	53,553
	Total operating costs and expenses		15,180			20,186			22,036			51,292
	Operating income		30,106			38,632			15,594			2,261
	Net income		10,527			12,317			1,412			(18,917	)
	Net income attributable to noncontrolling interest		(1,509	)		(1,893	)		(1,306	)		-
	Net income attributable to VAALCO Energy, Inc.		9,018			10,424			106			(18,917	)
	Basic net income per share attributable to VAALCO Energy, Inc.	$	0.16		$	0.18		$	-		$	(0.33	)
	Diluted net income per share attributable to VAALCO Energy, Inc.	$	0.15		$	0.18		$	-		$	(0.32	)
	-1	Gabon crude oil sales are a function of the number and size of crude oil liftings in each quarter from the floating production, storage and offloading (“FPSO”) facility.

Supplemental_Information_on_Oi1

Supplemental Information on Oil and Gas Producing Activities (Tables)	12 Months Ended
	Dec. 31, 2013
Costs Incurred in Oil and Gas Property - Acquisition, Exploration and Development Activities	'
	(In thousands)	United States
		2013			2012			2011
	Costs incurred during the year:
	Exploration - capitalized	$	-			2,602		$	-
	Exploration - expensed		11,497			38,159			2,083
	Acquisition		-			1,630			9,495
	Development		113			9,689			14,936
	Total	$	11,610			52,080		$	26,514
	(In thousands)	International
		2013			2012			2011
	Costs incurred during the year:
	Exploration - capitalized	$	2,942		$	5,916		$	69
	Exploration - expensed		12,431			2,878			3,625
	Acquisition		-			10,000			455
	Development		54,420			4,022			8,011
	Total	$	69,793		$	22,816		$	12,160
Capitalized Costs Relating to Oil and Gas Producing Activities	'
		December 31,
		2013			2012			2011
	Capitalized costs -
	Properties not being amortized	$	88,194		$	66,794		$	46,047
	Properties being amortized (1)		222,032			195,329			182,820
	Total capitalized costs	$	310,226		$	262,123		$	228,867
	Less accumulated depreciation, depletion, and amortization		(171,854	)		(155,681	)		(129,166	)
	Net capitalized costs	$	138,372		$	106,442		$	99,701
	-1	Includes $5.2 million, $4.7 million, and $10.4 million asset retirement cost in 2013, 2012, and 2011, respectively.
Results of Operations for Oil and Gas Producing Activities	'
		United States									International
		2013			2012			2011			2013			2012			2011
											Gabon			Gabon			Gabon
	Crude oil and gas sales	$	1,891		$	2,798		$	1,655		$	167,386		$	192,489		$	208,781
	Production, G&A and other expense		(12,232	)		(47,866	)		(7,413	)		(52,776	)		(27,425	)		(27,471	)
	Depreciation, depletion and amortization		(1,528	)		(3,872	)		(1,922	)		(15,302	)		(15,954	)		(23,604	)
	Income tax		-			-			-			(34,115	)		(81,813	)		(93,468	)
	Results from oil and gas producing activities	$	(11,869	)	$	(48,940	)	$	(7,680	)	$	65,193		$	67,297		$	64,238
Net Proved Reserves	'
	Proved Reserves:	Oil (MBbls)			Gas (MMCF)
	Balance at Janaury 1, 2011		6,922			23
	Production		(1,868	)		(255	)
	Revisions of previous estimates		959			31
	Extensions and discoveries		35			2,126
	Balance at December 31, 2011		6,048			1,925
	Production		(1,741	)		(532	)
	Revisions of previous estimates		2,200			151
	Extensions and discoveries		981			-
	Balance at December 31, 2012		7,488			1,544
	Production		(1,549	)		(325	)
	Revisions of previous estimates		771			114
	Extensions and discoveries		522			-
	Balance at December 31, 2013		7,232			1,333
	Proved Developed Reserves	Oil (MBbls)			Gas (MMCF)
	Balance at January 1, 2011		5,029			23
	Balance at December 31, 2011		3,854			856
	Balance at December 31, 2012		3,750			1,544
	Balance at December 31, 2013		3,305			1,333
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil Reserves	'
	(In thousands)	United States									International									Total
		December 31,									December 31,									December 31,
		2013			2012			2011			2013			2012			2011			2013			2012			2011
	Future cash inflows	$	8,276		$	8,260		$	13,274		$	725,485		$	776,646		$	623,546		$	733,761		$	784,906		$	636,820
	Future production costs		(3,038	)		(3,194	)		(1,661	)		(223,643	)		(203,490	)		(154,020	)		(226,681	)		(206,684	)		(155,681	)
	Future development costs		-			-			(4,180	)		(164,142	)		(186,982	)		(85,528	)		(164,142	)		(186,982	)		(89,708	)
	Future income tax expense		(825	)		(807	)		(1,347	)		(154,519	)		(181,194	)		(181,886	)		(155,344	)		(182,001	)		(183,233	)
	Future net cash flows	$	4,413		$	4,259		$	6,086		$	183,181		$	204,980		$	202,112		$	187,594		$	209,239		$	208,198
	Discount to present value at 10% annual rate		(1,299	)		(1,028	)		(3,150	)		(48,859	)		(55,309	)		(38,861	)		(50,158	)		(56,337	)		(42,011	)
	Standardized measure of discounted future net cash flows	$	3,114		$	3,231		$	2,936		$	134,322		$	149,671		$	163,251		$	137,436		$	152,902		$	166,187
Changes in Standardized Measure of Discounted Future Net Cash Flows	'
	The following table sets forth the changes in standardized measure of discounted future net cash flows as follows:
	(In thousands)	December 31,
		2013			2012			2011
	Balance at Beginning of Period	$	152,902		$	166,187		$	124,824
	Sales of oil and gas, net of production costs		(132,662	)		(168,563	)		(183,705	)
	Net changes in prices and production costs		(52,056	)		(11,223	)		194,633
	Revisions of previous quantity estimates		43,815			155,111			75,713
	Additions		29,620			69,092			7,742
	Changes in estimated future development costs		(5,345	)		(67,834	)		(5,831	)
	Development costs incurred during the period		44,389			34,944			31,913
	Accretion of discount		15,290			16,619			12,482
	Net change of income taxes		26,120			7,445			4,455
	Change in production rates (timing) and other		15,363			(48,876	)		(96,039	)
	Balance at End of Period	$	137,436		$	152,902		$	166,187

Summary_of_Significant_Account3

Summary of Significant Accounting Policies - Estimated Useful Life of Property Plant and Equipment (Detail)	12 Months Ended
	Dec. 31, 2013
Office Equipment | Minimum	'
Property Plant And Equipment [Line Items]	'
Estimated useful life	'3 years
Office Equipment | Maximum	'
Property Plant And Equipment [Line Items]	'
Estimated useful life	'5 years
Leasehold Improvements | Minimum	'
Property Plant And Equipment [Line Items]	'
Estimated useful life	'8 years
Leasehold Improvements | Maximum	'
Property Plant And Equipment [Line Items]	'
Estimated useful life	'12 years

Summary_of_Significant_Account4

Summary of Significant Accounting Policies - Rollforward Analysis of the Allowance Against the Partner Accounts Receivable Balance (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Rollforward analysis of the allowance against the partner accounts receivable	'	'
Allowance for doubtful accounts, Beginning Balance	($6,069)	($4,448)
Allowance for doubtful accounts, Charged to Costs and Expenses	-1,562	-1,621
Allowance for doubtful accounts, Ending Balance	($7,631)	($6,069)

Summary_of_Significant_Account5

Summary of Significant Accounting Policies - Additional Information (Detail) (USD $)	12 Months Ended			1 Months Ended			12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Jan. 31, 2014	Jan. 31, 2014	Jan. 31, 2014	Dec. 31, 2012
				Subsequent Events	Senior Loan	Subordinate Tranche	Vaalco International
					Subsequent Events	Subsequent Events
Property Plant And Equipment [Line Items]	'	'	'	'	'	'	'
Company acquired the noncontrolling interest amount	'	'	'	'	'	'	$26,200,000
Noncontrolling interest owned issued and outstanding common stock	'	'	'	'	'	'	9.99%
Summary of Significant Accounting Policies (Textual) [Abstract]	'	'	'	'	'	'	'
Maturity period of cash and cash equivalents	'three months or less	'	'	'	'	'	'
Company's bank guarantees for customs clearance	2,400,000	2,400,000	'	'	'	'	'
Company's charter payment escrow	800,000	800,000	'	'	'	'	'
Funds restricted to secure the Company's drilling obligation	10,000,000	10,000,000	'	'	'	'	'
Date of maturity of certificates of deposit and commercial paper	'not exceeding 90 days	'	'	'	'	'	'
Gains or Loss on foreign currency transactions	-100,000	400,000	1,000,000	'	'	'	'
Bad debt expenses	1,562,000	1,621,000	4,448,000	'	'	'	'
Loan agreement	'	'	'	$65,000,000	$50,000,000	$15,000,000	'
Expiration date of availability period	'	'	'	31-Dec-19	'	'	'
Interest rate, Description	'	'	'	'RBL will bear interest at LIBOR plus 3.75% for the senior loan and LIBOR plus 5.75% for the subordinate tranche and is to be paid quarterly.	'	'	'
Interest rate at LIBOR plus	'	'	'	'	3.75%	5.75%	'
Commitment fee in respect of unutilized commitments	'	'	'	'	1.50%	2.30%	'
Closing fees	'	'	'	2.50%	'	'	'

Stock_Based_Compensation_Stock

Stock Based Compensation - Stock Option Activity (Detail) (USD $)	12 Months Ended
In Millions, except Share data in Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]	'	'	'
Number of Shares Underlying Options, Outstanding at beginning of period	4,065	'	'
Number of Shares Underlying Options, Granted	1,836	1,024	1,169
Number of Shares Underlying Options, Exercised	-877	-759	-302
Number of Shares Underlying Options, Forfeited	-97	'	'
Number of Shares Underlying Options, Outstanding at end of period	4,927	4,065	'
Number of Shares Underlying Options, Vested - end of period	3,459	'	'
Number of Shares Underlying Options, Vested and expected to vest - end of period	4,854	'	'
Weighted Average Exercise Price Per Share, Outstanding at beginning of period	$6.12	'	'
Weighted Average Exercise Price Per Share, Granted	$7.55	'	'
Weighted Average Exercise Price Per Share, Exercised	$4.25	$4.62	$4.12
Weighted Average Exercise Price Per Share, Forfeited	$7.51	'	'
Weighted Average Exercise Price Per Share, Outstanding at end of period	$6.95	$6.12	'
Weighted Average Exercise Price Per Share, Vested - end of period	$6.58	'	'
Weighted Average Exercise Price Per Share, Vested and expected to vest - end of period	$6.95	'	'
Weighted Average Remaining Contractual Term, Outstanding balance	'2 years 10 months 6 days	'2 years 7 months 24 days	'
Weighted Average Remaining Contractual Term, Granted	'4 years 29 days	'	'
Weighted Average Remaining Contractual Term, Exercised	'0 years	'	'
Weighted Average Remaining Contractual Term, Forfeited	'3 years 6 months 26 days	'	'
Weighted Average Remaining Contractual Term, Exercisable at end of period	'2 years 10 months 6 days	'2 years 7 months 24 days	'
Weighted Average Remaining Contractual Term, Vested - end of period	'2 years 5 months 9 days	'	'
Weighted Average Remaining Contractual Term, Vested and expected to vest - end of period	'2 years 10 months 6 days	'	'
Aggregate Intrinsic Value, Outstanding at end of period	$2.81	'	'
Aggregate Intrinsic Value, Vested - end of period	2.66	'	'
Aggregate Intrinsic Value, Vested and expected to vest - end of the period	$2.81	'	'

Stock_Based_Compensation_A_Sum

Stock Based Compensation - A Summary of the Values of Options Granted and Exercised (Detail) (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Summary of the values of options granted and exercised	'	'	'
Number of Shares Underlying Options, Granted	1,836	1,024	1,169
Weighted average grant date fair value - ($/share)	$2.45	$3.49	$2.09
Weighted average exercise price - ($/share)	$4.25	$4.62	$4.12
Options exercised (thousands)	877	759	302
Total intrinsic value of options exercised - ($thousands)	$1,201	$3,267	$859

Stock_Based_Compensation_The_V

Stock Based Compensation - The Valuation of the Options Granted (Detail)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Valuation of the options granted	'	'	'
Options Issued	1,836	1,024	1,169
Weighted Avg. Volatility	51.00%	65.00%	47.00%
Expected Term	'2 years 6 months	'2 years 6 months	'2 years 6 months
Risk Free Interest Rate	0.30%	0.50%	0.80%
Expected Dividend Yield	0.00%	0.00%	0.00%

Stock_Based_Compensation_Addit

Stock Based Compensation - Additional Information (Detail) (USD $)	12 Months Ended			1 Months Ended	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Oct. 21, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013
				Restricted Stock	Restricted Stock	Minimum	Maximum
Stock Based Compensation (Textual) [Abstract]	'	'	'	'	'	'	'
Stock options granted, exercisable life	'5 years	'	'	'	'	'	'
Stock options vested period	'	'	'	'4 years	'	'3 years	'5 years
Stock options remainder vesting period	'3 years	'	'	'	'	'	'
Stock options, authorized	1,523,713	'	'	'	'	'	'
Restricted stock, Issued	'	'	'	100,000	'	'	'
Restricted stock, grant date fair value	$2.45	$3.49	$2.09	$5.89	'	'	'
Restricted stock, vested or forfeited	'	'	'	'	0	'	'
Non-cash compensation expense	$3,005,000	$2,406,000	$2,217,000	'	'	'	'
Tax benefits related to stock based compensation	0	'	'	'	'	'	'
Unrecognized compensation costs	2,600,000	'	'	'	'	'	'
Compensation costs expected to be recognized	'2 years	'	'	'	'	'	'
Cash proceeds from Stock options exercised	$3,700,000	$3,300,000	$1,900,000	'	'	'	'

Stockholders_Equity_and_Earnin2

Stockholders' Equity and Earnings Per Share - Schedule of Diluted Shares (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Schedule of Diluted shares	'	'	'
Basic weighted average common stock issued and outstanding	57,298,910	57,673,342	57,047,531
Dilutive options and restricted stock	626,091	1,158,717	925,050
Total diluted shares	57,925,001	58,832,059	57,972,581

Stockholders_Equity_and_Earnin3

Stockholders' Equity and Earnings Per Share - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Stockholders' Equity and Earnings Per Share (Textual) [Abstract]	'	'	'
Common stock, shares authorized	100,000,000	100,000,000	'
Option to purchase shares, anti-dilutive	3,508,865	1,018,900	1,169,064

Income_Taxes_Provision_for_Inc

Income Taxes - Provision for Income Taxes (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
U.S. Federal:	'	'	'
Current	'	'	'
Deferred	'	'	'
Foreign:	'	'	'
Current	34,115	81,813	93,468
Deferred	'	'	'
Total	$34,115	$81,813	$93,468

Income_Taxes_Summary_of_Differ

Income Taxes - Summary of Differences between the Financial Statement and Tax Bases of Assets and Liabilities (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Deferred Tax Assets:	'	'
Basis difference in fixed assets	$31,440	$30,619
Foreign tax credit carry forward	55,908	23,836
Alternative minimum tax credit carryover	1,349	1,349
Foreign net operating losses	42,688	38,782
Asset retirement obligations	4,012	3,629
Other	3,300	2,731
Deferred Tax Assets, Gross	138,697	100,946
Valuation allowance	-137,348	-99,597
Total deferred tax asset	$1,349	$1,349

Income_Taxes_Pretax_Income_Det

Income Taxes - Pretax Income (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Pretax income	'	'	'
United States	($17,649)	($56,979)	($16,282)
Foreign	94,836	144,131	150,312
Income before income taxes	$77,187	$87,152	$134,030

Income_Taxes_Income_Tax_Years_

Income Taxes - Income Tax Years Subject to Examination by Major Tax Jurisdictions (Detail)	12 Months Ended
	Dec. 31, 2013
United States	'
Income Tax years subject to examination by major tax jurisdictions	'
Income tax examination year under examination range start	'
Income tax examination year under examination range end	'
Gabon	'
Income Tax years subject to examination by major tax jurisdictions	'
Income tax examination year under examination range start	'
Income tax examination year under examination range end	'

Income_Taxes_Statutory_Rate_Re

Income Taxes - Statutory Rate Reconciliation (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Statutory rate reconciliation	'	'	'
Tax Provision Computed at Statutory Rate	$27,015	$30,503	$46,911
Foreign taxes not offset in U.S. by foreign tax credits	-2,072	25,266	28,414
Permanent Differences	973	2,370	'
Foreign Tax Credit Adjustments	-28,027	'	'
Change in Tax Rate on Deferred	0	0	-2,889
Increase/(Decrease) in Valuation Allowance	37,752	23,675	22,038
Other	-1,526	0	-1,006
Total	$34,115	$81,813	$93,468

Income_Taxes_Additional_Inform

Income Taxes - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Income Taxes (Textual) [Abstract]	'	'
Valuation allowance	$137,348,000	$99,597,000
Increase in deferred tax assets, tax credit carryforwards, foreign	$28,000,000	'

Commitments_and_Contingencies_1

Commitments and Contingencies - Additional Information (Detail) (USD $)

1 Months Ended

12 Months Ended

3 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

1 Months Ended

3 Months Ended

48 Months Ended

1 Months Ended

12 Months Ended

In Millions, unless otherwise specified

Jul. 31, 2012

Dec. 31, 2010

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Dec. 31, 2013

Nov. 30, 2006

Dec. 31, 2013

Dec. 31, 2012

Jan. 31, 2007

Dec. 31, 2008

Nov. 01, 2010

Sep. 30, 2012

Dec. 31, 2013

Well

Ovaka Well

Gabon Obligation

Gabon Obligation

Gabon Obligation

Offshore Gabon

Offshore Gabon

Offshore Gabon

Offshore Gabon

Angola

Angola

Angola

Angola

Angola

Angola

South Dakota

South Dakota

Sqkms

Subsequent Events

Seismic Obligation

Omangou Prospect

Well

acre

Seismic Obligation

Seismic Obligation

Seismic Obligation

acre

Sqkms

Well

Well

Sqkms

Sqkms

Sqkms

Well

Commitments And Contingencies Textual Abstract

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Period of Charter

'

'

'

'2 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Company s share of the charter payment

'

'

'

28.10%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Charter fee for production up to 20,000 BOPD

'

'

0.93

'

0.25

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Charter fee for those bbls produced in excess of 20,000 BOPD

'

'

2.5

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Company's share of charter expense

'

'

$10.40

$9.70

$7.30

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Rent expense, operating leases

'

'

4.1

4.4

3.6

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Extended drilling period

'2 years

'1 year

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Liabilities, guarantees' fair value

'

'

1.1

1.2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Discount

'

'

'

'

'

'

25.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Contractual Obligation Company Share

'

'

'

'

'

'

3

3.7

2.8

'

'

'

'

'

'

'

'

'

'

'

'

Contractual Obligation accrued amount

'

'

'

'

'

'

2.9

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Cost for acquire property

'

'

'

'

'

'

'

'

'

5.3

'

'

'

'

'

'

'

'

'

'

'

Length of acquired property

'

'

'

'

'

'

'

'

'

150

'

'

'

'

'

'

'

'

'

'

'

Number of exploration wells

'

'

'

'

'

'

'

'

'

'

'

2

1

2

'

'

'

'

'

'

'

Cost related to drilling

'

'

'

'

'

17.2

'

'

'

'

'

'

8.6

29.5

'

'

'

'

'

'

'

Cost related to share of drilling

'

'

'

'

'

5.9

'

'

'

'

'

'

2.6

'

'

'

'

'

'

'

'

Cost related to drilling

'

'

'

'

'

17.2

'

'

'

'

'

'

8.6

29.5

'

'

'

'

'

'

'

Cost related to share of drilling

'

'

'

'

'

5.9

'

'

'

'

'

'

2.6

'

'

'

'

'

'

'

'

Acquisition related to obligation

'

'

'

'

'

'

'

'

'

'

'

223

'

'

'

'

'

'

'

'

'

Number of exploration wells drilling required to pay remaining obligation

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Annual funding related to production license, term

'

'

'

'

'

'

'

'

'

'

'7 years

'

'

'

'

'

'

'

'

'

'

Percentage of annual funding over seven years

'

'

'

'

'

'

'

'

'

'

12.14%

'

'

'

'

'

'

'

'

'

'

Percentage of annual funding over last three years

'

'

'

'

'

'

'

'

'

'

5.00%

'

'

'

'

'

'

'

'

'

'

Abandonment cost related to annual funding

'

'

10.1

'

'

'

'

'

'

10.1

'

'

'

'

'

'

'

'

'

'

'

Length of acquired property

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,175

524

1,000

'

'

Area under acquire property exploration rights agreement term

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,400,000

'

'

'

'

'

'

Joint operation agreement related to third party in working interest percentage

'

'

'

'

'

'

'

'

'

'

'

'

'

40.00%

'

'

'

'

'

'

'

Additional joint operation agreement related to third party in working interest percentage

'

'

'

'

'

'

'

'

'

'

'

'

'

10.00%

'

'

'

'

'

'

'

Production license agreement term

'

'

'

'

'

'

'

'

'

'

'

'

'

'4 years

'

'

'

'

'

'

'

Production license agreement term extended by government

'

'

'

'

'

'

'

'

'

'

'

'

'

'3 years

'

'

'

'

'

'

'

Drilling cost to company

'

'

'

'

'

'

'

'

'

'

'

'

'

14.8

'

'

'

'

'

'

'

Seismic obligation cost to company

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3.75

3

'

'

'

Cost related to seismic obligation, gross

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

7.5

6

'

'

'

Percentage of working interest for amounts owned

'

'

'

'

'

'

'

'

'

'

'

'

'

'

40.00%

'

'

'

'

100.00%

'

Percentage of carried interest

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10.00%

'

'

'

'

'

'

Allowance for accounts with partners

'

'

7.6

6

'

'

'

'

'

'

'

'

'

'

'

7.6

'

'

'

'

'

Allowance recorded for accounts receivable with remainder

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1.6

'

'

'

'

'

'

Gross area of acquired property

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10,000

'

Additional amount to drill and complete additional well

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3.6

Dry hole Costs (Drilling Expenses)

'

'

23.9

37.3

0.1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2.9

Percentage of working interest for amounts owned

'

'

'

'

'

'

'

'

'

'

'

'

'

'

40.00%

'

'

'

'

100.00%

'

Well penalty, minimum

'

'

5

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Well penalty, maximum

'

'

10

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Recorded restricted cash

'

'

$10

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of exploration wells intended for drilling after working interest assignment completed

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2

'

'

'

'

'

'

Commitments_and_Contingencies_2

Commitments and Contingencies - Estimated Obligations and Companies Share for the Annual Charter Payment (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013
Estimated obligation and company share for annual charter payment	'
Full Charter Payment, 2014	$25,843
Full Charter Payment, 2015	25,843
Full Charter Payment, 2016	25,914
Full Charter Payment, 2017	25,843
Full Charter Payment, 2018	25,843
Full Charter Payment, Thereafter	51,757
Full Charter Payment, Total	$181,043
Company Share, 2014	7,255
Company Share, 2015	7,255
Company Share, 2016	7,275
Company Share, 2017	7,255
Company Share, 2018	7,255
Company Share, Thereafter	14,530
Company Share, Total	50,825

Commitments_and_Contingencies_3

Commitments and Contingencies - Operating Lease Obligations for Rentals (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013
Other Lease Obligations for rentals	'
Gross Obligation, 2014	$7,927
Gross Obligation, 2015	5,963
Gross Obligation, 2016	3,962
Gross Obligation, 2017	434
Gross Obligation, 2018	36
Gross Obligation, Thereafter	217
Gross Obligation, Total	$18,539
Company Share, 2014	2,697
Company Share, 2015	2,121
Company Share, 2016	1,422
Company Share, 2017	434
Company Share, 2018	36
Company Share, Thereafter	217
Company Share, Total	6,927

Capitalization_of_Exploratory_3

Capitalization of Exploratory Well Costs - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
Accounting Standards Update 2010-03	'
Capitalized Costs Relating To Oil And Gas Producing Activities By Geographic Area [Line Items]	'
Accounting Standard Code for Extractive Industries followed for capitalization purposes - ASC Topic 932	'ASC Topic 932 - Extractive Industries provides that an exploratory well shall be capitalized as part of the entity’s uncompleted wells pending the determination of whether the well has found proved reserves. Further, an exploration well that discovers oil and gas reserves, but those reserves cannot be classified as proved when drilling is completed, shall be capitalized if the well has found a sufficient quantity of reserves to justify its completion as a producing well and the entity is making sufficient progress assessing the reserves and the economic and operating viability of the project. If either condition is not met, the exploration well would be assumed to be impaired and its costs would be charged to expense.
Etame Marin	'
Capitalized Costs Relating To Oil And Gas Producing Activities By Geographic Area [Line Items]	'
Number of side tracks	2
Area of sand of oil	5
North Tchibala	'
Capitalized Costs Relating To Oil And Gas Producing Activities By Geographic Area [Line Items]	'
Capitalization on development plan	7.8
Mutamba Iroru	'
Capitalized Costs Relating To Oil And Gas Producing Activities By Geographic Area [Line Items]	'
Number of side tracks	3
Capitalization on development plan	8.9

Capitalization_of_Exploratory_4

Capitalization of Exploratory Well Costs - Schedule of Capitalized Exploratory Well Costs (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Millions, unless otherwise specified	Well	Well	Well
Projects With Exploratory Well Costs Capitalized For More Than One Year [Line Items]	'	'	'
Capitalized exploratory well costs that have been capitalized for a period less than one year	'	$5.90	$8
Capitalized exploratory well costs that have been capitalized for a period greater than one year	16.7	8.1	'
Total	$16.70	$14	$8
Number of exploratory wells that have been capitalized for a period greater than one year	2	1	1

Employee_Benefit_Plans_Additio

Employee Benefit Plans - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Employee Benefit Plans (Textual) [Abstract]	'	'	'
Costs incurred for administering employee plan	$182,500	$204,000	$172,000

Asset_Retirement_Obligations_A

Asset Retirement Obligations - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	Well
Asset Retirement Obligations (Textual) [Abstract]	'	'	'
Number of wells	2	'	'
Revisions	$0	($5,744,000)	($7,000)
Abandoned Period Of Material Assets	'P5Y	'	'
Abandonment cost related to annual funding	$10,100,000	'	'

Asset_Retirement_Obligations_E

Asset Retirement Obligations - Estimated Fair Value of Company's Asset Retirement Obligations (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Estimated fair value of the Company's asset retirement obligations	'	'	'
Balances at January 1,	$10,368	$14,528	$13,425
Accretion Expense	643	814	1,014
Additions	453	770	96
Revisions	0	-5,744	-7
Balance December 31,	$11,464	$10,368	$14,528

Segment_Information_Segment_Ac

Segment Information - Segment Activity (Detail) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Revenues	$58,282	$37,740	$29,118	$44,137	$53,553	$37,630	$58,818	$45,286	$169,277	$195,287	$210,436
Depreciation, depletion and amortization	'	'	'	'	'	'	'	'	16,929	19,913	25,596
Operating income (loss)	35,951	8,104	11,666	21,503	2,261	15,594	38,632	30,106	77,225	86,593	132,561
Interest income	'	'	'	'	'	'	'	'	73	145	184
Income taxes	'	'	'	'	'	'	'	'	34,115	81,813	93,468
Bad debt and other expenses	'	'	'	'	'	'	'	'	3,326	1,621	4,448
Impairment of proved properties	'	'	'	'	'	'	'	'	'	7,620	4,975
Additions to properties and equipment	'	'	'	'	'	'	'	'	53,691	46,366	32,966
Long lived assets	138,524	'	'	'	106,608	'	'	'	138,524	106,608	99,848
Total assets	308,167	'	'	'	267,956	'	'	'	308,167	267,956	275,015
Operating Segments | Corporate and Other	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Depreciation, depletion and amortization	'	'	'	'	'	'	'	'	63	59	50
Operating income (loss)	'	'	'	'	'	'	'	'	-5,915	-8,405	-9,088
Interest income	'	'	'	'	'	'	'	'	33	86	104
Additions to properties and equipment	'	'	'	'	'	'	'	'	47	77	60
Long lived assets	152	'	'	'	166	'	'	'	152	166	147
Total assets	20,211	'	'	'	38,585	'	'	'	20,211	38,585	45,986
Operating Segments | Gabon	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Revenues	'	'	'	'	'	'	'	'	167,386	192,489	208,781
Depreciation, depletion and amortization	'	'	'	'	'	'	'	'	15,310	15,954	23,604
Operating income (loss)	'	'	'	'	'	'	'	'	98,795	147,985	155,550
Interest income	'	'	'	'	'	'	'	'	40	60	80
Income taxes	'	'	'	'	'	'	'	'	34,115	81,813	93,468
Bad debt and other expenses	'	'	'	'	'	'	'	'	1,764	'	'
Additions to properties and equipment	'	'	'	'	'	'	'	'	53,015	22,731	8,528
Long lived assets	109,597	'	'	'	71,225	'	'	'	109,597	71,225	68,965
Total assets	256,033	'	'	'	190,652	'	'	'	256,033	190,652	185,341
Operating Segments | Angola	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Depreciation, depletion and amortization	'	'	'	'	'	'	'	'	28	28	20
Operating income (loss)	'	'	'	'	'	'	'	'	-3,018	-3,293	-6,221
Interest income	'	'	'	'	'	'	'	'	'	-1	'
Bad debt and other expenses	'	'	'	'	'	'	'	'	1,562	1,621	4,448
Additions to properties and equipment	'	'	'	'	'	'	'	'	629	'	7
Long lived assets	11,540	'	'	'	10,938	'	'	'	11,540	10,938	10,964
Total assets	12,204	'	'	'	11,405	'	'	'	12,204	11,405	21,452
Operating Segments | Equatorial Guinea	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Operating income (loss)	'	'	'	'	'	'	'	'	-768	-754	'
Additions to properties and equipment	'	'	'	'	'	'	'	'	'	10,000	'
Long lived assets	10,000	'	'	'	10,000	'	'	'	10,000	10,000	'
Total assets	10,059	'	'	'	10,000	'	'	'	10,059	10,000	'
Operating Segments | USA	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Revenues	'	'	'	'	'	'	'	'	'	2,798	1,655
Depreciation, depletion and amortization	'	'	'	'	'	'	'	'	'	3,872	1,922
Operating income (loss)	'	'	'	'	'	'	'	'	'	-48,940	-7,680
Impairment of proved properties	'	'	'	'	'	'	'	'	'	7,620	4,975
Additions to properties and equipment	'	'	'	'	'	'	'	'	'	13,558	24,371
Long lived assets	'	'	'	'	14,279	'	'	'	'	14,279	19,772
Total assets	'	'	'	'	$17,314	'	'	'	'	$17,314	$22,236

Impairment_of_Proved_Propertie1

Impairment of Proved Properties - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012
Impairment of Proved Properties (Textual) [Abstract]	'
Company recognized an impairment loss	$7.60

Quarterly_Financial_Informatio2

Quarterly Financial Information (Unaudited) (Detail) (USD $)	3 Months Ended								12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Quarterly Financial Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Revenues	$58,282	$37,740	$29,118	$44,137	$53,553	$37,630	$58,818	$45,286	$169,277	$195,287	$210,436
Total operating costs and expenses	22,331	29,636	17,452	22,634	51,292	22,036	20,186	15,180	92,052	108,694	77,875
Operating income	35,951	8,104	11,666	21,503	2,261	15,594	38,632	30,106	77,225	86,593	132,561
Net income	26,377	2,386	7,121	7,188	-18,917	1,412	12,317	10,527	43,072	5,339	40,562
Basic net income per share	$0.46	$0.40	$0.12	$0.12	($0.33)	'	$0.18	$0.16	$0.75	$0.01	$0.60
Diluted net income per share	$0.46	$0.40	$0.12	$0.12	($0.32)	'	$0.18	$0.15	$0.74	$0.01	$0.59
Less net income attributable to noncontrolling interest	'	'	'	'	'	-1,306	-1,893	-1,509	'	-4,708	-6,417
Net income attributable to VAALCO Energy, Inc.	'	'	'	'	($18,917)	$106	$10,424	$9,018	$43,072	$631	$34,145

Supplemental_Information_on_Oi2

Supplemental Information on Oil and Gas Producing Activities - Costs Incurred in Oil and Gas Property - Acquisition, Exploration and Development Activities (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities	'	'	'
Exploration - expensed	$23,928	$41,037	$5,708
Development	52,800	'	'
United States	'	'	'
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities	'	'	'
Exploration - capitalized	'	2,602	'
Exploration - expensed	11,497	38,159	2,083
Acquisition	'	1,630	9,495
Development	113	9,689	14,936
Total	11,610	52,080	26,514
Foreign Tax Authority	'	'	'
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities	'	'	'
Exploration - capitalized	2,942	5,916	69
Exploration - expensed	12,431	2,878	3,625
Acquisition	'	10,000	455
Development	54,420	4,022	8,011
Total	$69,793	$22,816	$12,160

Supplemental_Information_on_Oi3

Supplemental Information on Oil and Gas Producing Activities - Capitalized Costs Relating to Oil and Gas Producing Activities (Detail) (USD $)	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
In Thousands, unless otherwise specified
Capitalized Costs Relating to Oil and Gas Producing Activities:	'		'		'
Properties not being amortized	$88,194		$66,794		$46,047
Properties being amortized	222,032	[1]	195,329	[1]	182,820	[1]
Total capitalized costs	310,226		262,123		228,867
Less accumulated depreciation, depletion, and amortization	-171,854		-155,681		-129,166
Net capitalized costs	$138,372		$106,442		$99,701
[1]	Includes $5.2 million, $4.7 million, and $10.4 million asset retirement cost in 2013, 2012, and 2011, respectively.

Supplemental_Information_on_Oi4

Supplemental Information on Oil and Gas Producing Activities - Results of Operations for Oil and Gas Producing Activities (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
United States	'	'	'
Results of Operations for Oil and Gas Producing Activities:	'	'	'
Crude oil and gas sales	$1,891	$2,798	$1,655
Production, G&A and other expense	-12,232	-47,866	-7,413
Depreciation, depletion and amortization	-1,528	-3,872	-1,922
Income tax	'	'	'
Results from oil and gas producing activities	-11,869	-48,940	-7,680
Gabon	'	'	'
Results of Operations for Oil and Gas Producing Activities:	'	'	'
Crude oil and gas sales	167,386	192,489	208,781
Production, G&A and other expense	-52,776	-27,425	-27,471
Depreciation, depletion and amortization	-15,302	-15,954	-23,604
Income tax	-34,115	-81,813	-93,468
Results from oil and gas producing activities	$65,193	$67,297	$64,238

Supplemental_Information_on_Oi5

Supplemental Information on Oil and Gas Producing Activities - Net Proved Reserves (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
	MBbls	MBbls	MBbls	MBbls
Oil	'	'	'	'
Proved Reserves:	'	'	'	'
Beginning Balance	7,488	6,048	6,922	'
Production	-1,549	-1,741	-1,868	'
Revisions of previous estimates	771	2,200	959	'
Extensions and discoveries	522	981	35	'
Ending Balance	7,232	7,488	6,048	'
Proved Developed Reserves	3,305	3,750	3,854	5,029
Gas	'	'	'	'
Proved Reserves:	'	'	'	'
Beginning Balance	1,544,000	1,925,000	23,000	'
Production	-325,000	-532,000	-255,000	'
Revisions of previous estimates	114,000	151,000	31,000	'
Extensions and discoveries	'	'	2,126,000	'
Ending Balance	1,333,000	1,544,000	1,925,000	'
Proved Developed Reserves	1,333,000	1,544,000	856,000	23,000

Supplemental_Information_on_Oi6

Supplemental Information on Oil and Gas Producing Activities - Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil Reserves (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil Reserves	'	'	'
Future cash inflows	$733,761	$784,906	$636,820
Future production costs	-226,681	-206,684	-155,681
Future development costs	-164,142	-186,982	-89,708
Future income tax expense	-155,344	-182,001	-183,233
Future net cash flows	187,594	209,239	208,198
Discount to present value at 10% annual rate	-50,158	-56,337	-42,011
Standardized measure of discounted future net cash flows	137,436	152,902	166,187
United States	'	'	'
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil Reserves	'	'	'
Future cash inflows	8,276	8,260	13,274
Future production costs	-3,038	-3,194	-1,661
Future development costs	'	'	-4,180
Future income tax expense	-825	-807	-1,347
Future net cash flows	4,413	4,259	6,086
Discount to present value at 10% annual rate	-1,299	-1,028	-3,150
Standardized measure of discounted future net cash flows	3,114	3,231	2,936
Gabon	'	'	'
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil Reserves	'	'	'
Future cash inflows	725,485	776,646	623,546
Future production costs	-223,643	-203,490	-154,020
Future development costs	-164,142	-186,982	-85,528
Future income tax expense	-154,519	-181,194	-181,886
Future net cash flows	183,181	204,980	202,112
Discount to present value at 10% annual rate	-48,859	-55,309	-38,861
Standardized measure of discounted future net cash flows	$134,322	$149,671	$163,251

Supplemental_Information_on_Oi7

Supplemental Information on Oil and Gas Producing Activities - Changes in Standardized Measure of Discounted Future Net Cash Flows (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Changes in Standardized Measure of Discounted Future Net Cash Flows:	'	'	'
Balance at Beginning of Period	$152,902	$166,187	$124,824
Sales of oil and gas, net of production costs	-132,662	-168,563	-183,705
Net changes in prices and production costs	-52,056	-11,223	194,633
Revisions of previous quantity estimates	43,815	155,111	75,713
Additions	29,620	69,092	7,742
Changes in estimated future development costs	-5,345	-67,834	-5,831
Development costs incurred during the period	44,389	34,944	31,913
Accretion of discount	15,290	16,619	12,482
Net change of income taxes	26,120	7,445	4,455
Change in production rates (timing) and other	15,363	-48,876	-96,039
Balance at End of Period	$137,436	$152,902	$166,187

Supplemental_Information_on_Oi8

Supplemental Information on Oil and Gas Producing Activities - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]	'	'	'
Exploration expense	$23,900,000	$37,300,000	$100,000
Percentage of working interest acquired	31.00%	'	'
Acquisition of Working Interest, cost	10,000,000	'	'
Asset retirement cost	5,200,000	4,700,000	10,400,000
Future development costs	52,800,000	'	'
Development cost to company	14,800,000	'	'
Minimum	'	'	'
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]	'	'	'
Net share that the consortium receives from production, Minimum	67.70%	'	'
Maximum	'	'	'
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]	'	'	'
Net share that the consortium receives from production, Maximum	82.50%	'	'
United States	'	'	'
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]	'	'	'
Unsuccessful exploration wells	2	'	'
Future development costs	113,000	9,689,000	14,936,000
United States | Oil	'	'	'
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]	'	'	'
Contractual price	87.61	'	'
United States | Gas	'	'	'
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]	'	'	'
Contractual price	4.51	'	'
Foreign Tax Authority	'	'	'
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]	'	'	'
Unsuccessful exploration wells	3	'	'
Future development costs	54,420,000	4,022,000	8,011,000
Contractual price	107.69	'	'
Fixed royalty rate	13.00%	'	'
Consortium	'	'	'
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]	'	'	'
Percentage of production	70.00%	'	'
Net cost account	30,100,000	'	'
Production Rate Maximum	25,000	'	'
Production rate, Minimum	5,000	'	'
Cost Recovered	929,400	367,000	304,000
Theoretical Cost	1,079,300	1,197,000	1,303,000
Consortium | Minimum	'	'	'
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]	'	'	'
Percentage of contract area, Minimum	50.00%	'	'
Consortium | Maximum	'	'	'
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]	'	'	'
Percentage of contract area, Maximum	60.00%	'	'
Etame	'	'	'
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]	'	'	'
Period of development	'20 years	'	'
Expiration of development	'expire in 2021	'	'
Exploration area expiration year	'expires in July 2014	'	'
Avouma	'	'	'
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]	'	'	'
Period of development	'20 years	'	'
Expiration of development	'expire in 2025	'	'
Ebouri	'	'	'
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]	'	'	'
Period of development	'20 years	'	'
Expiration of development	'expire in 2026	'	'
Mutamba Iroru	'	'	'
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]	'	'	'
Percentage of production	70.00%	'	'
Net cost account	36,400,000	'	'
Production Rate Maximum	20,000	'	'
Production rate, Minimum	7,500	'	'
Proved reserves	0	'	'
Mutamba Iroru | Minimum	'	'	'
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]	'	'	'
Percentage of contract area, Minimum	50.00%	'	'
Net share that the consortium receives from production, Minimum	72.00%	'	'
Mutamba Iroru | Maximum	'	'	'
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]	'	'	'
Percentage of contract area, Maximum	63.00%	'	'
Net share that the consortium receives from production, Maximum	85.00%	'	'
Block 5 Production	'	'	'
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]	'	'	'
Percentage of production	50.00%	'	'
Period of development	'20 years	'	'
Proved reserves	0	'	'
Royalty Payments	0	'	'
Block 5 Production | Minimum	'	'	'
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]	'	'	'
Percentage of contract area, Minimum	30.00%	'	'
Block 5 Production | Maximum	'	'	'
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]	'	'	'
Percentage of contract area, Maximum	90.00%	'	'
Block P Production	'	'	'
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]	'	'	'
Percentage of production	70.00%	'	'
Period of development	'25 years	'	'
Proved reserves	$0	'	'
Income tax on net profits	25.00%	'	'
Block P Production | Minimum	'	'	'
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]	'	'	'
Fixed royalty rate	10.00%	'	'
Percentage of contract area, Minimum	10.00%	'	'
Block P Production | Maximum	'	'	'
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]	'	'	'
Fixed royalty rate	16.00%	'	'
Percentage of contract area, Maximum	60.00%	'	'