Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the past 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨.

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨.

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Indicate by a check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2). Yes ¨ No x.

As of October 31, 2013, there were outstanding 56,900,141 shares of common stock, $0.10 par value per share, of the registrant.

	September 30, 2013			December 31, 2012
ASSETS
Current assets:
Cash and cash equivalents	$	100,465		$	130,800
Restricted cash		2,180			1,257
Receivables:
Trade		486			7,961
Accounts with partners, net of allowance of $7.4 million and $6.0 million at September 30, 2013 and December 31, 2012, respectively		4,799			689
Other		10,527			4,463
Crude oil inventory		3,503			683
Materials and supplies		224			337
Prepayments and other		4,689			2,935
Total current assets		126,873			149,125
Property and equipment—successful efforts method:
Wells, platforms and other production facilities		204,903			188,208
Undeveloped acreage		23,945			28,657
Work in progress		66,737			38,137
Equipment and other		6,512			7,574
		302,097			262,576
Accumulated depreciation, depletion and amortization		(167,528	)		(155,968	)
Net property and equipment		134,569			106,608
Other assets:
Deferred tax asset		1,349			1,349
Restricted cash		10,830			10,874
Total Assets	$	273,621		$	267,956
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	35,563		$	30,326
Accounts with partners		4,885			14,737
Total current liabilities		40,448			45,063
Asset retirement obligations		11,298			10,368
Total Liabilities		51,746			55,431
Commitments and Contingencies (Note 4)
VAALCO Energy, Inc. shareholders’ equity:
Common stock, $0.10 par value, 100,000,000 authorized shares, 63,308,938 and 63,135,772 shares issued with 7,022,808 and 5,257,638 shares in treasury at September 30, 2013 and December 31, 2012, respectively		6,331			6,314
Additional paid-in capital		52,133			48,816
Retained earnings		198,066			181,370
Less treasury stock, at cost		(34,655	)		(23,975	)
Total VAALCO Energy, Inc. shareholders’ equity		221,875			212,525
Total Liabilities and Equity	$	273,621		$	267,956

	Three months ended September 30,						Nine months ended September 30,
	2013			2012			2013			2012
Revenues:
Oil and gas sales	$	37,740		$	37,630		$	110,995		$	141,734
Operating costs and expenses:
Production expenses		12,576			5,941			27,975			18,004
Exploration expense		11,070			699			21,456			5,036
Depreciation, depletion and amortization		3,954			4,861			11,011			16,715
General and administrative expenses		1,893			2,546			7,995			9,067
Bad debt expenses		143			369			1,284			959
Impairment of proved properties		—			7,620			—			7,620
Total operating costs and expenses		29,636			22,036			69,721			57,401
Operating income		8,104			15,594			41,274			84,333
Other income (expense):
Interest income		16			36			57			109
Other, net		(72	)		(27	)		(168	)		556
Total other income (expense), net		(56	)		9			(111	)		665
Income before income taxes		8,048			15,603			41,163			84,998
Income tax expense		5,662			14,191			24,467			60,740
Net income		2,386			1,412			16,696			24,258
Less net income attributable to noncontrolling interest		—			(1,306	)		—			(4,708	)
Net income attributable to VAALCO Energy, Inc.	$	2,386		$	106		$	16,696		$	19,550
Basic net income per share attributable to VAALCO Energy, Inc. common shareholders	$	0.04		$	0.00		$	0.29		$	0.34
Diluted net income per share attributable to VAALCO Energy, Inc. common shareholders	$	0.04		$	0.00		$	0.29		$	0.33
Basic weighted shares outstanding		56,601			57,846			57,465			57,614
Diluted weighted shares outstanding		57,116			58,947			58,200			58,785

Nine Months Ended September 30, 2013
	VAALCO Energy, Inc. Shareholders
	Common Stock		Additional Paid-In Capital		Retained Earnings		Treasury Stock			Noncontrolling Interest		Total
Balance at January 1, 2013	$	6,314	$	48,816	$	181,370	$	(23,975	)	$	—	$	212,525
Proceeds from stock issuance		17		717		—		—			—		734
Stock based compensation		—		2,600		—		—			—		2,600
Treasury stock purchase		—		—		—		(10,680	)		—		(10,680	)
Net income		—		—		16,696		—			—		16,696
Balance at September 30, 2013	$	6,331	$	52,133	$	198,066	$	(34,655	)	$	—	$	221,875

Nine Months Ended September 30, 2012
	VAALCO Energy, Inc. Shareholders
	Common Stock		Additional Paid-In Capital		Retained Earnings		Treasury Stock			Noncontrolling Interest			Total
Balance at January 1, 2012	$	6,238	$	66,122	$	180,739	$	(23,975	)	$	3,943		$	233,067
Proceeds from stock issuance		72		3,297		—		—			—			3,369
Stock based compensation		—		2,055		—		—			—			2,055
Net income		—		—		19,550		—			4,708			24,258
Distribution to noncontrolling interest		—		—		—		—			(5,595	)		(5,595	)
Balance at September 30, 2012	$	6,310	$	71,474	$	200,289	$	(23,975	)	$	3,056		$	257,154

	Nine Months Ended September 30,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	16,696		$	24,258
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization		11,011			16,715
Unrealized foreign exchange loss (gain)		22			(358	)
Dry hole costs		20,190			2,853
Stock based compensation		2,600			2,055
Bad debt provision		1,284			959
Impairment of proved properties		—			7,620
Change in operating assets and liabilities:
Trade receivables		7,475			(1,660	)
Accounts with partners		(15,246	)		(2,543	)
Other receivables		(5,967	)		980
Crude oil inventory		(1,793	)		(1,105	)
Materials and supplies		113			(141	)
Prepayments and other		(1,756	)		(2,847	)
Accounts payable, accrued liabilities and other liabilities		2,176			(1,983	)
Net cash provided by operating activities		36,805			44,803
CASH FLOWS FROM INVESTING ACTIVITIES
Restricted cash, net		(879	)		55
Property and equipment expenditures		(56,138	)		(43,507	)
Net cash used in investing activities		(57,017	)		(43,452	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of common stock		557			3,369
Purchase of treasury shares		(10,680	)		—
Distribution to noncontrolling interest		—			(5,595	)
Net cash used in financing activities		(10,123	)		(2,226	)
NET CHANGE IN CASH AND CASH EQUIVALENTS		(30,335	)		(875	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		130,800			137,139
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	100,465		$	136,264
Supplemental disclosure of cash flow information
Income taxes paid	$	28,157		$	59,486
Supplemental disclosure of non-cash transactions
Property and equipment additions incurred during the period but not paid at period end	$	13,254		$	9,775
Property and equipment reduction as the result of changes in asset retirement cost estimates	$	—		$	5,463
Receivable from employees for stock option exercise	$	177		$	—

1. UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND ACCOUNTING POLICIES

The condensed consolidated financial statements of VAALCO Energy, Inc. and subsidiaries (collectively, “VAALCO” or the “Company”), included herein are unaudited, but include all adjustments consisting of normal recurring accruals which the Company deems necessary for a fair presentation of its financial position, results of operations and cash flows for the interim period. Such results are not necessarily indicative of results to be expected for the full year. These financial statements should be read in conjunction with the financial statements and notes thereto included in the Company’s Form 10-K for the year ended December 31, 2012, which also contains a summary of the significant accounting policies followed by the Company in the preparation of its consolidated financial statements. These policies were also followed in preparing the quarterly report included herein. The Company follows the successful efforts method of accounting for oil and gas exploration and development costs.

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

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

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

Options to purchase 3,204,865 and 2,134,300 shares were excluded in the three months and nine months ended September 30, 2013, respectively, because they would have been anti-dilutive. Options to purchase 1,018,900 and 1,018,900 shares were excluded in the three months and nine months ended September 30, 2012, respectively, because they would have been anti-dilutive.

Stock options are granted under the Company’s long-term incentive plan and have an exercise price that may not be less than the fair market value of the underlying shares on the date of grant. In general, stock options granted will become exercisable over a period determined by the Compensation Committee which in the past has been a five year life. A portion of the stock options granted in March 2013 and 2012 vested immediately with the remainder vesting over a two year period. In addition, stock options will become exercisable upon a change in control, unless provided otherwise by the Compensation Committee. At September 30, 2013, there were 2,128,046 shares subject to options authorized but not granted.

For the three months and nine months ended September 30, 2013, the Company recognized non-cash compensation expense of $0.4 million and $2.6 million, respectively, related to stock options. For the three months and nine months ended September 30, 2012, the Company recognized non-cash compensation expense of $0.4 million and $2.1 million, respectively, related to stock

options. These amounts were recorded as general and administrative expense. Because the Company does not pay significant United States federal income taxes, no amounts were recorded for tax benefits related to excess stock based compensation deductions.

A summary of the stock option activity for the nine months ended September 30, 2013 is provided below:

	Number of Shares Underlying Options (in thousands)			Weighted Average Exercise Price Per Share		Weighted Average Remaining Contractual Term		Aggregate Intrinsic Value (in millions)
Outstanding at beginning of period		4,065		$	6.12		2.65
Granted		1,236			7.59		4.46
Exercised		(173	)		4.24		0.03
Forfeited		(1	)		7.75		4.43
Outstanding at end of period		5,127		$	6.53		2.58	$	4.82
Exercisable at end of period		4,245		$	6.21		2.27	$	4.82

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 September 30, 2013, unrecognized compensation costs totaled $1.4 million. The expense is expected to be recognized over a weighted average period of 1.2 years.

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 seismic obligation was met with the acquisition of 223 square kilometers of 3-D seismic in 2012. The remaining exploration well commitment was met with the drilling of the Ovoka 1 well in the third quarter of 2013 at a cost of $19.8 million ($6.0 million net to the Company). The well located approximately five miles northeast of the Ebouri field and six miles north of the Etame field was found to be water bearing and was abandoned as an unsuccessful effort.

As part of securing the second ten-year production license with the government of Gabon, the Company agreed in principle to a cash funding arrangement for the eventual abandonment of the offshore wells, platforms and facilities. The agreement is not yet finalized, but calls for annual funding for the next seven years at 12.14% of the total abandonment estimate per year and 5.0% per year for the last three years of the production license. The amounts paid will be reimbursed through the cost account and are non-refundable to the Company. The funding will begin after the agreement is finalized. The abandonment estimate for this purpose is approximately $10.1 million net to the Company on an undiscounted basis. The obligation for abandonment of the Gabon offshore facilities is included in the asset retirement obligation shown on the Company’s balance sheet.

In November 2006, the Company signed a production sharing contract for Block 5 offshore Angola. The four year primary term with an optional three year extension awards the Company exploration rights to 1.4 million acres offshore central Angola. The Company’s working interest is 40%. Additionally, the Company is required to carry the Angolan national oil company, Sonangol P&P, for 10% of the work program. During the first four years of the contract, the Company was required to acquire and process 1,000 square kilometers of 3-D seismic data, drill two exploration wells and expend a minimum of $29.5 million ($14.8 million net to the Company). The Company fulfilled its seismic obligation when it acquired 1,175 square kilometers of 3-D seismic data at a cost of $7.5 million ($3.75 million net to the Company) in January 2007 and 524 square kilometers of 3-D seismic data during the fourth quarter of 2008 at a cost of $6.0 million ($3.0 million net to the Company). Each of the two exploration commitment wells is subject to a $5.0 million penalty ($10.0 million in aggregate for both wells) if not drilled during the contract term. The $10.0 million is currently recorded as restricted cash and is held at a financial institution located in the United States. Additional time extensions have been granted by the Angolan government to drill the two exploration commitment wells, the latest extension providing until November 30, 2014.

The government-assigned working interest partner was delinquent paying their share of the costs several times in 2009 and consequently was placed in a default position. By a governmental decree, dated December 1, 2010, the former partner was

removed from the production sharing contract. Following the decree, the Company and the government of Angola have been working to obtain a replacement partner.

In the second quarter of 2012, the Company identified a potential partner to acquire the available 40% working interest and submitted the name of the interested party to the Angolan government for approval. In July 2013, the Angolan government informed the Company that it should first proceed to acquire the available working interest per the provisions of the Joint Operating Agreement and then enter into a farm-out agreement with the potential partner. After requesting the assignment of the available working interest, the Company received correspondence from the Angolan government in November 2013 whereby they notified the Company of their plan to effect the working interest assignment directly to a third party. The Company cannot provide a time estimate for completing the working interest assignment, or whether the assignment will occur at all, as it involves actions by the Angolan government. After the assignment of the 40% is completed, the Company intends to commence drilling two exploration wells as soon as practical.

Due to the continuing circumstances regarding the available 40% working interest, the Company has recorded a full allowance totaling $7.4 million as of September 30, 2013, against the accounts receivable from partners for the amounts owed to the Company above its 40% working interest plus the 10% carried interest. The allowance recorded in the three and nine months ended September 30, 2013 totaled $0.1 million and $1.3 million, respectively. The farm-out agreement provides for the Company for being reimbursed for the gross receivable amount. The timing of this event cannot be reasonably predicted at the present time.

ASC Topic 932—Extractive Industries provides that an exploratory well shall be capitalized as part of the entity’s uncompleted wells pending the determination of whether the well has found proved reserves. Further, an exploration well that discovers oil and gas reserves, but those reserves cannot be classified as proved when drilling is completed, shall be capitalized if the well has found a sufficient quantity of reserves to justify its completion as a producing well and the entity is making sufficient progress assessing the reserves and the economic and operating viability of the project. If either condition is not met, the exploration well would be assumed to be impaired and its costs would be charged to expense.

In the second and third quarters of 2010, the Company drilled the Southeast Etame No. 1 well with two sidetracks in the Etame Marin block offshore Gabon. The well discovered a five meter column of oil in the Gamba sand reservoir. Additional evaluation of the well and sidetrack information was conducted to determine options for developing the discovery. In the second quarter of 2012, the Company and its partners agreed to proceed with the development plan featuring a fixed leg platform for developing the Southeast Etame discovery area and the North Tchibala field, where a discovery was made on the block prior to VAALCO’s block participation. The final investment decision was approved in the fourth quarter of 2012 for the construction of the platform. Construction began in the first quarter of 2013 and the platform is expected to be transported and installed in 2014. The Company has capitalized $7.7 million for this well in accordance with the criteria contained in ASC Topic 932.

In the third and fourth quarters of 2012, the Company drilled the N’Gongui 2 well with three sidetracks in the Mutamba Iroru block onshore Gabon. Application of the discovery was made timely to the government of Gabon and the issuance of the development permit is pending finalization of financial terms. The Company has capitalized $8.8 million for this well in accordance with the criteria contained in ASC Topic 932.

On June 6, 2013, the Company announced that its Board of Directors has authorized the repurchase of up to $25 million of the Company’s common stock over the next 12 months. Under the share buyback program, shares of common stock are to be purchased on the open market or through privately negotiated transactions from time-to-time. The share buyback program does not obligate the Company to acquire any specific number of shares in any period, and may be modified, suspended, extended or discontinued at any time without prior notice. During the quarter ended September 30, 2013, the Company repurchased 1,531,770 shares at an average price of $6.10 per share totaling $9.3 million.

For the nine months ended September 30, 2013, the total number of shares repurchased by the Company under this program was 1,765,170 shares. The average price paid for all shares was $6.05 per share totaling $10.7 million.

The Company’s main operations are based in Gabon, Angola, Equatorial Guinea, and in the United States. Minor activities for the Company’s United Kingdom subsidiary are included in the “Corporate and Other” column in the table. Management reviews and evaluates the operation of each geographic segment separately. Segments include exploration for and production of hydrocarbons where commercial reserves have been found and developed. Revenues are recognized at the geographical location of hydrocarbon production. The Company evaluates each segment based on operating income (loss).

Segment activity for the three months and nine months ended September 30, 2013 and 2012 are as follows:

($ thousands)	Gabon		Angola			EG			USA			Corporate and Other			Total
Three months ended September 30,
2013
Revenues	$	37,253	$	—		$	—		$	487		$	—		$	37,740
Operating income (loss)		14,156		(538	)		(149	)		(4,754	)		(611	)		8,104
2012
Revenues	$	36,950	$	—		$	—		$	680		$	—		$	37,630
Operating income (loss)		27,248		(781	)		—			(8,994	)		(1,879	)		15,594

($ thousands)	Gabon		Angola			EG			USA			Corporate and Other			Total
Nine months ended September 30,
2013
Revenues	$	109,482	$	—		$	—		$	1,513		$	—		$	110,995
Operating income (loss)		59,871		(2,120	)		(604	)		(11,782	)		(4,091	)		41,274
2012
Revenues	$	139,563	$	—		$	—		$	2,171			—		$	141,734
Operating income (loss)		106,852		(1,980	)		—			(13,599	)		(6,940	)		84,333

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

This Report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, which are intended to be covered by the safe harbors created by those laws. The Company has based these forward-looking statements on its current expectations and projections about future events. These forward-looking statements include information about possible or assumed future results of the Company’s operations. All statements, other than statements of historical facts, included in this Report that address activities, events or developments that the Company expects or anticipates may occur in the future, including without limitation, statements regarding the Company’s financial position, operating performance and results, reserve quantities and net present values, market prices, business strategy, derivatives activities, the amount and nature of capital expenditures, plans and objectives of the Company’s management for future operations are forward-looking statements. When the Company uses words such as “anticipate,” “believe,” “estimate,” “expect,” “intend,” “forecast,” “outlook,” “aim,” “will,” “could,” “should,” “may,” “likely,” “plan,” “probably” or similar expressions, the Company is making forward-looking statements. Many risks and uncertainties that could affect the Company’s future results and could cause results to differ materially from those expressed in the Company’s forward-looking statements include, but are not limited to: the volatility of oil and natural gas prices; the uncertainty of estimates of oil and natural gas reserves; the impact of competition; the availability and cost of seismic, drilling and other equipment; operating hazards inherent in the exploration for and production of oil and natural gas; difficulties encountered during the exploration for and production of oil and natural gas; difficulties encountered in delivering oil to commercial markets; discovery, acquisition, development and replacement of oil and gas reserves; timing and amount of future production of oil and gas; hedging decisions, including whether or not to enter into derivative financial instruments; our ability to effectively integrate companies and properties that we acquire; general economic conditions, including any future economic downturn, disruption in financial markets and the availability of credit; changes in customer demand and producers’ supply; future capital requirements and the Company’s ability to attract capital; currency exchange rates; actions by the governments and events occurring in the countries in which we operate; actions by our venture partners; compliance with, or the effect of changes in, governmental regulations regarding the Company’s exploration and production, including those related to climate change; actions of operators of the Company’s oil and gas properties; weather conditions; and statements set forth in the Company’s Annual Report on Form 10-K for the year ended December 31, 2012 and subsequent Quarterly Reports on Form 10-Q.

Although the Company believes that the assumptions underlying its forward-looking statements are reasonable, any of these assumptions and therefore also the forward-looking statements based on these assumptions, could themselves prove to be inaccurate. In light of the significant uncertainties inherent in the forward-looking statements which are included in this Report, the Company’s inclusion of this information is not a representation by the Company or any other person that the Company’s objectives and plans will be achieved.

The Company’s forward-looking statements speak only as of the date made and the Company will not update these forward-looking statements unless the securities laws require the Company to do so. The Company’s forward-looking statements are expressly qualified in their entirety by this cautionary statement. In light of these risks, uncertainties and assumptions, any forward-looking events discussed in this Report may not occur.

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

A significant component of the Company’s results of operations is dependent upon the difference between prices received for its offshore Gabon oil production and the costs to find and produce such oil. Oil (and gas) prices have been and are expected in the future to be volatile and subject to fluctuations based on a number of factors beyond the control of the Company. Similarly, certain costs to find and produce oil and gas are largely not within the control of the Company, particularly in regard to the cost of leasing drilling rigs to drill and maintain offshore wells.

The Company’s primary source of revenue is from the Etame Production Sharing Contract related to the Etame Marin block located offshore the Republic of Gabon. VAALCO operates the Etame Marin block on behalf of a consortium of five. VAALCO owns a 30.35% interest in the exploration acreage within the Etame Marin block. The Company owns a 28.1% interest in the development areas in and surrounding the Etame, Avouma, South Tchibala, and Ebouri fields, each of which is located on the Etame Marin block. The development areas were subject to a 7.5% back-in by the Government of Gabon, which occurred for these fields after their successful development. The Southeast Etame and North Tchibala fields, each of which is also located on the Etame Marine block, are in the process of being developed and will also be subject to a 7.5% back-in by the Government of Gabon.

A key focus of the Company is to maintain oil production from the Etame Marin block at optimal levels within the constraints of the existing infrastructure. Five subsea wells plus production from two platforms are tied back by pipelines to deliver oil and associated gas through a riser system to allow for delivery, processing, storage and ultimately offloading the oil from a leased Floating, Production, Storage and Offloading vessel (“FPSO”) anchored to the seabed on the block. With the FPSO limitations of approximately 25,000 BOPD and 30,000 barrels of total fluids per day, the challenge is to optimize production on both a near and long-term basis subject to investment and operational agreements between the Company and the consortium. The Company produces from the Etame, Avouma, South Tchibala and Ebouri fields on the block. During the three and nine months ending September 30, 2013, these fields produced approximately 1.6 million Bbls (0.4 million Bbls net to the Company) and 4.6 million Bbls (1.3 million Bbls net to the Company), respectively. The Company’s share of barrels sold reflects an allocation of cost oil and profit oil, and a reduction for royalty of 13%.

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

Late in 2012, the Company commenced work on a drilling and recompletion campaign with the arrival of a drilling rig to conduct a six well program, with an option to extend the program to a total of eight wells. The six well program included three well recompletions to replace electrical submersible pumps, a development well that was successfully drilled and put on production in the Avouma field in April 2013, an unsuccessful exploration appraisal well drilled in the Ebouri field in the second quarter of 2013, and an unsuccessful exploration well drilled on the Ovoka prospect in the third quarter of 2013. The Company and its partners exercised the rig option in the third quarter of 2013 for the additional two wells in the program. The rig is scheduled to commence the two well program in late-December 2013, which will be comprised of an exploration well in the Dimba prospect and a well recompletion in the Avouma field to replace electrical submersible pumps.

Long-term optimization progress was made in 2012 by the Company and its partners approving the construction of two additional production platforms. The two production platforms are part of the future development plans for the Etame Marin block. One platform will be located in the Etame field and the second platform will be located in-between the Southeast Etame and North Tchibala fields. Multiple wells are expected to be drilled from each of the platforms as part of the future development plans for the Etame Marin block. The Company drilled a successful exploration well in the Southeast Etame area in 2010. The Southeast Etame discovery will be developed from the second platform. The expected cost to build and install the platforms in the 2013/2014 timeframe is $325.0 million ($91.0 million net to the Company). The cost of the wells is not included in the platform costs. Constructions of the two production platforms began in the first quarter of 2013 and are scheduled for installation in 2014. The Company’s share of the total construction costs of the two platforms to-date is $37.8 million, of which $30.4 million was spent in the nine months ended September 30, 2013.

In 2012, the presence of hydrogen sulfide (H2S) from two of the three producing wells in the Ebouri field was discovered. The wells were shut-in for safety reasons resulting in a decrease of approximately 2,000 BOPD or approximately 10% of the gross daily production from the Etame Marin block. In the second quarter of 2013, the Company spent $0.5 million ($0.2 million net to the Company) to temporarily suspend the two affected wells. Analysis and options for re-establishing production from the impacted area began in the second half of 2012 and has continued through the third quarter of 2013. Engineering and flow assurance work will continue through at least the end of 2013 to further develop solution options. The expected outcome is that additional capital investment will be required, which is likely to include a new platform-type structure with H2S processing capability, recompletion of the shut-in wells and potentially additional new wells to re-establish and maximize production from the impacted area. The design, cost projections and final investment decisions by the Company and its partners are expected to be made in the first half of 2014. Re-establishing production from the area impacted by H2S is expected in the first half of 2016.

Besides the offshore Etame Marin block in Gabon, the Company operates the Mutamba Iroru block located onshore near the coast in central Gabon. The Mutamba Iroru block contains an exploration area of approximately 270,000 acres. The Company currently has a 50% working interest in the block. The Company entered into an agreement with Total Gabon in 2010 to continue the exploration activities. Under the terms of the agreement, the Company and Total Gabon committed to reprocess 400 kilometers of 2-D seismic data and drill one exploration well. The seismic reprocessing work was completed in 2012.

The N’Gongui 2 exploration well was drilled in 2012 resulting in a discovery at a cost of $19.7 million ($8.8 million net to the Company). Application of the discovery was made timely to the government of Gabon and the issuance of the development permit is pending finalization of financial terms. Development of the onshore block is expected to capitalize on synergies such as office space, warehouse and open yard space and experienced personnel from our operating base in Port Gentil, Gabon.

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

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

Due to the continuing circumstances regarding the available 40% working interest, the Company has recorded a full allowance totaling $7.4 million as of September 30, 2013, against the accounts receivable from partners for the amounts owed to the Company above its 40% working interest plus the 10% carried interest. The allowance recorded in the three and nine months ended September 30, 2013 totaled $0.1 million and $1.3 million, respectively. The farm-out agreement provides for the Company to be reimbursed for the gross receivable amount. The timing of this event cannot be reasonably predicted at the present time.

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

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

The Company and its partners are proceeding with plans to drill two exploration wells in 2014.

The Company acquired a 640 acre lease, the Hefley field, in the Granite Wash formation in North Texas in December 2010 and a 480 acre lease in the same formation in July 2011. Two wells have been drilled on the Hefley lease acreage and brought on production. The second well began production in March 2012. During the three months ended September 30, 2013, the two wells produced approximately 1,600 Bbls of oil and 74 million cubic feet of gas net to the Company after deduction of royalty and severance taxes. During the nine months ended September 30, 2013, the two wells produced approximately 4,000 Bbls of oil and 257 million cubic feet of gas net to the Company after deduction of royalty and severance taxes The Hefley field acreage is held by production. In the second quarter 2013, the Company decided it was unlikely to conduct further exploratory activities on the unevaluated portion of the Hefley field. Accordingly, the Company charged $0.7 million to exploration expense, which represented the remaining cost of the unevaluated Hefley leasehold.

The expiration date of the primary term of the 480 acre Granite Wash lease is August 2014. In the third quarter of 2013, the Company decided to not proceed with drilling wells on this acreage and has recognized the leasehold investment as an asset held for sale. Based on recent market transactions for leases in the area, the Company incurred exploration expense of $1.6 million to write-down the investment to its market value of $0.2 million.

In May 2011, the Company acquired a 70% working interest in approximately 5,200 acres (3,640 net acres) in Sheridan County, Montana in the Middle Bakken formation. The Company drilled two wells on this acreage in 2012. After completion testing beginning in the fourth quarter of 2012 using electrical submersible pumps (ESP’s), both of the wells drilled were determined to be unsuccessful as the operating and water disposal costs exceeded the value of the gas and condensate produced from the wells. Dry-hole cost and leasehold impairment totaling $15.7 million was recognized for these two wells ($14.2 million in the fourth quarter of 2012 and $1.5 million in the first quarter 2013). As the Company does not intend to drill any further wells on this acreage expiring, for the most part, within a year, the remaining leasehold cost of $0.5 million was charged to exploration expense in the third quarter of 2013.

In September 2011, the Company acquired a 65% working interest in approximately 22,000 gross acres (14,300 net acres) covering the Middle Bakken and deeper formations in the East Poplar unit and the Northwest Poplar field in Roosevelt County, Montana. Pursuant to the terms of the acquisition, the Company was required to drill three wells at its sole cost, one of which was required to be drilled by September 1, 2012 and the remaining two wells were required to be drilled by the end of 2012. A vertical exploration well, which met the time requirement for drilling the first well, was spudded in December 2011 to evaluate the formations. The second exploration well was drilled and completed in the Bakken/Three Forks formations. Both of these wells were unsuccessful efforts, resulting in dry-hole costs and leasehold impairment totaling $18.4 million recorded in the fourth quarter of 2012. The third obligatory well, which was drilled in the fourth quarter of 2012 at a cost of $3.0 million, was charged to dry-hole expense in the third quarter of 2013. Leasehold cost of $1.3 million remains capitalized for this acreage in Roosevelt County, Montana.

Net cash provided by operating activities for the nine months ended September 30, 2013 was $36.8 million, as compared to net cash provided by operating activities of $44.8 million for the nine months ended September 30, 2012. The $8.0 million decrease in cash from operations for the nine months ended September 30, 2013 compared to the nine months ended September 30, 2012 was primarily due to a $7.6 million reduction in net income, a $5.7 million negative variance in changes in operating assets and liabilities, partially offset by a $5.3 million positive variance in non-cash adjustments. The $5.7 million negative variance in changes in operating assets and liabilities was primarily due to a higher underpaid position from the Company’s joint venture partners.

Net cash used in investing activities for the nine months ended September 30, 2013 was $57.0 million, compared to net cash used in investing activities for the nine months ended September 30, 2012 of $43.5 million. For the nine months ended September 30, 2013 the Company paid $56.1 million for capital expenditures, and added $0.9 million to its restricted cash balance in Gabon. For the nine months ended September 30, 2012 the Company paid $43.5 million for capital expenditures, which was partially offset by a $0.1 million release of restricted cash in Gabon.

For the nine months ended September 30, 2013, net cash used in financing activities was $10.1 million consisting of treasury stock purchases of $10.7 million, partially offset by the receipt of $0.6 million in proceeds from the issuance of common stock upon the exercise of stock options. For the nine months ended September 30, 2012, cash used in financing activities was $2.2 million consisting of distributions to a noncontrolling interest of $5.6 million, which was partially offset by the receipt of $3.4 million in proceeds from the issuance of common stock upon the exercise of stock options.

During the nine months ended September 30, 2013, the Company incurred $44.6 million of net property and equipment additions, primarily associated with $30.4 million for the construction of two new platforms offshore Gabon, $10.9 million for two development wells offshore Gabon, $1.8 million for production facilities improvements offshore Gabon, and $1.0 million for the onshore Gabon exploratory well. During the fourth quarter of 2013, the Company anticipates its share of capital expenditures will approximate $17.0 million primarily associated with the offshore Gabon block for the construction of two platforms and the drilling of one exploration well.

The Company uses the “successful efforts” method of accounting for its oil and gas exploration and development costs. All expenditures related to exploration, with the exception of costs of drilling exploratory wells, are charged as an expense when incurred. The costs of exploratory wells are capitalized pending determination of whether commercially producible oil and natural gas reserves have been discovered. If the determination is made that a well did not encounter potentially economic oil and gas quantities, the well costs are charged as an expense.

For the nine months ended September 30, 2013, exploration expense was $21.5 million, primarily comprised of $11.2 million related to the Company’s unsuccessful exploration activities in the United States, $9.0 million of dry-hole costs related to two unsuccessful offshore Gabon exploration wells. Additional exploration costs incurred in the nine months ended September 30, 2013 were $0.5 million onshore Gabon, $0.5 million offshore Gabon, and $0.2 million in Equatorial Guinea.

For the nine months ended September 30, 2012, exploration expense was $5.0 million, consisting primarily of a $2.9 million dry-hole charge to write-off the exploratory costs associated with drilling and testing of several intervals below the Bakken/Three Forks formation on the EPU-120 well drilled in the East Poplar Dome field in Montana. Additional exploratory costs incurred in the nine months ended September 30, 2012 were $0.7 million for North America, $0.4 million onshore Gabon, $0.6 million offshore Gabon, $0.2 million in Angola and $0.2 million in the United Kingdom.

The Company’s primary source of capital has been cash flows from operations. At September 30, 2013, the Company had unrestricted cash of $100.5 million. The Company believes that this cash combined with cash flow from operations will be sufficient to fund the Company’s remaining 2013 and the 2014 capital expenditure budget, and additional investments in working capital resulting from potential growth. As operator of the Etame Marin and Mutamba Iroru blocks in Gabon, Block 5 in Angola, the Company enters into project related activities on behalf of its working interest partners. The Company generally obtains advances from its partners prior to significant funding commitments.

Substantially all of the Company’s crude oil and natural gas is sold at the well head at posted or index prices under short-term contracts. In Gabon, the Company markets its crude oil under an agreement with Mercuria Trading NV (“Mercuria”). While the loss of Mercuria as a buyer might have a material adverse effect on the Company in the near term, management believes that the Company would be able to obtain other customers for its crude oil in Gabon.

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.

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

Total oil and natural gas revenues were $37.7 million for the three months ended September 30, 2013 compared to $37.6 million the same period of 2012.

Crude oil revenues for the three months ended September 30, 2013 were $37.3 million, as compared to $37.0 million for the same period in 2012. In the three months ended September 30, 2013, the Company sold approximately 337,000 net barrels of oil at an average price of $110.54/Bbl, while in the three months ended September 30, 2012 it sold approximately 342,000 net barrels of oil at an average price of $107.94/Bbl.

Condensate sales from the Granite Wash formation wells, located in Hemphill County, Texas for the period ended September 30, 2013 were $0.1 million, resulting from the sale of approximately 1,600 net barrels of oil condensate at an average price of $88.83. For the same period in 2012, condensate sales were $0.2 million, resulting from the sale of approximately 2,300 net barrels of oil condensate at an average price of $77.48/Bbl.

Natural gas revenues including revenues from natural gas liquids for the three months ended September 30, 2013 were $0.3 million compared to $0.5 million for the same period in 2012. Natural gas sales volumes were 74 MMcf at an average price of $4.57/Mcf for the three months ended September 30, 2013, compared to sales volumes of 147 MMcf at an average price of $3.32/Mcf for the same period in 2012.

Production expenses for the three months ended September 30, 2013 were $12.6 million compared to $5.9 million for the same period in 2012. The higher production expenses in the three months ended September 30, 2013 compared to the same period in 2012 were attributable to offshore Gabon operations which included $2.1 million of well workover costs to replace electrical submersible pumps in an offshore Gabon well, $0.6 million of higher FPSO operating costs, $1.0 million related to deck boiler repairs onboard the FPSO, $0.8 million incurred for generator repairs on the Avouma platform, $0.7 million of costs to temporarily suspend the two Ebouri wells affected by elevated levels of H2S, and $0.8 million in higher costs resulting from crude oil inventory adjustments.

For the three months ended September 30, 2013, the Company’s Gabon production was approximately 16,900 BOPD (4,100 BOPD net to the Company), as compared to approximately 19,000 BOPD (4,600 BOPD net to the Company) for the same period in 2012.

Exploration expenses for the three months ended September 30, 2013 was $11.1 million, compared to $0.7 million for the same period in 2012. For the three months ended September 30, 2013, exploration expenses consisted primarily of dry hole costs of $6.0 million related to two offshore Gabon unsuccessful exploration wells, $3.0 million of dry hole costs related to a well drilled in the fourth quarter of 2012 in Roosevelt County, Montana where it was decided in the third quarter of 2013 to not proceed with additional completion activities, and $2.0 million to expense portions of undeveloped leaseholds held in Texas and Montana, United States. For the three months ended September 30, 2012, exploration expenses consisted primarily $0.3 million for activities in North America, $0.1 million for activities offshore Gabon, and $0.2 million for activities in Angola.

Depreciation, depletion and amortization expenses were $4.0 million in the three months ended September 30, 2013 compared to $4.9 million in the three months ended September 30, 2012. The lower depreciation, depletion and amortization expenses during the three months ended September 30, 2013 compared to the same period in 2012 were primarily due to both lower average depletion rates and lower sales volumes.

General and administrative expenses for the three months ended September 30, 2013 and 2012 were $1.9 million and $2.5 million, respectively. The decrease in general and administrative costs in the three months ended September 30, 2013 compared to the same period in 2012 was primarily due to higher overhead reimbursements resulting from the active development program offshore Gabon.

During the three months ended September 30, 2012, the Company recorded an impairment loss of $7.6 million to write down its investment in the Granite Was formation of North Texas to its fair value. The impairment charge was due to a combination of continued production declines from both wells and low natural gas prices.

Other expense for the three months ended September 30, 2013 was $56,000, comprised principally of losses on foreign exchange transactions. Other income for the three months ended September 30, 2012 was $9,000.

Income tax expense amounted to $5.7 million and $14.2 million for the three months ended September 30, 2013 and 2012, respectively. In the three months ended September 30, 2013 and 2012, the income taxes were all paid in Gabon. Income taxes in the three months ended September 30, 2013 were lower due to a lower percentage of oil allocated as “profit oil” versus “cost oil”. The income taxes the consortium pays the government of Gabon is an allocation of the remaining profit oil production from a specific contract area ranging from 50% to 60% of the oil remaining after deducting the royalty and the cost oil.

Net income for the three months ended September 30, 2013 was $2.4 million, compared to $0.1 million for the same period in 2012. Net income allocated to the noncontrolling interest was $1.3 million in the three months ended September 30, 2012.

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

Nine months ended September 30, 2013 compared to nine months ended September 30, 2012

Total oil and natural gas revenues were $111.0 million for the nine months ended September 30, 2013 compared to $141.7 million for the same period of 2012.

Crude oil revenues for the nine months ended September 30, 2013 were $109.5 million, a $30.1 million decrease from revenues of $139.6 million for the same period of 2012. The Company sold approximately 1,013,000 net barrels of oil at an average price of $108.06/Bbl. in the nine months ended September 30, 2013. The Company sold approximately 1,248,000 net barrels of oil at an average price of $111.79/Bbl. in the nine months ended September 30, 2012. Sales volumes declined in the nine months ended September 30, 2013 as compared to the same period in 2012 primarily due to temporary production stoppages resulting from workover activities for replacing electrical submersible pumps on three offshore Gabon wells, as well as the July 2012 shut-in of two wells in the Ebouri field, offshore Gabon, as a precaution after detecting H2S.

Condensate sales from the Granite Wash wells, located in Hemphill County, Texas for the nine months ended September 30, 2013 were $0.3 million, resulting from approximately 4,000 barrels of oil condensate at an average price of $83.88/Bbl. Condensate sales for the nine months ended September 30, 2012 were $0.6 million, resulting from approximately 7,300 barrels of oil condensate at an average price of $82.81/Bbl.

Natural gas revenues, including revenues from natural gas liquids, for the nine months ended September 30, 2013 were $1.2 million compared to $1.5 million for the comparable period in 2012. Natural gas sales volumes were 257 MMcf at an average price of $4.50/Mcf for the nine months ended September 30, 2013, compared to sales volumes of 421 MMcf at an average price of $3.65/Mcf for the same period in 2012.

Production expenses for the nine months ended September 30, 2013 were $28.0 million compared to $18.0 million in the nine months ended September 30, 2012. The higher production expenses in the nine months ended September 30, 2013 compared to the same period in 2012 were attributable to offshore Gabon operations which included $7.3 million of well workover costs to replace electrical submersible pumps in three offshore Gabon wells, $1.0 million related to deck boiler repairs onboard the FPSO, $0.8 million incurred for generator repairs on the Avouma platform, and $0.7 million to temporarily suspend the two Ebouri wells affected by elevated levels of H2S. The higher production expenses were partially offset by $0.7 million lower production costs resulting from crude oil inventory adjustments.

For the nine months ended September 30, 2013, the Company’s Gabon production was approximately 16,800 BOPD (4,100 BOPD net to the Company), as compared to approximately 20,100 BOPD (4,900 BOPD net to the Company) for the nine months ended September 30, 2012.

For the nine months ended September 30, 2013, exploration expense was $21.5 million, primarily including $11.4 million related to the Company’s unsuccessful exploration activities in the United States properties and $9.0 million dry-hole costs related to two unsuccessful offshore Gabon exploration wells. Additional exploration costs incurred in the nine months ended September 30, 2013 were $0.5 million onshore Gabon, $0.5 million offshore Gabon, and $0.2 million in Equatorial Guinea.

For the nine months ended September 30, 2012, exploration expense was $5.0 million, consisting primarily of a $2.9 million dry-hole charge to write-off the exploratory costs associated with the drilling and testing of several intervals below the Bakken/Three Forks formation on a well drilled in the East Poplar Dome field in Montana. Additional exploratory costs incurred in the nine months ended September 30, 2012 were $0.7 million in North America, $0.4 million onshore Gabon, and $0.6 million offshore Gabon, $0.2 million in Angola, and $0.2 million in the United Kingdom.

Depreciation, depletion and amortization expenses were $11.0 million in the nine months ended September 30, 2013 compared to $16.7 million in the nine months ended September 30, 2012. The lower depreciation, depletion and amortization expenses during the nine months ended September 30, 2013 compared to the same period in 2012 were primarily due to lower sales volumes in Gabon as a result of two wells shut-in for the H2S issue in July 2012 and three wells that underwent replacement of electrical submersible pumps.

General and administrative expenses for the nine months ended September 30, 2013 and 2012 were $8.0 million and $9.1 million, respectively. During the nine months ended September 30, 2013, the Company incurred $1.5 million higher administrative costs to support the increased overseas operations, offset by $2.7 million net credits from higher overhead reimbursements associated with production development operations on the Etame Marin block.

During the nine months ended September 30, 2012, the Company recorded an impairment loss of $7.6 million to write down its investment in the Granite Was formation of North Texas to its fair value. The impairment charge was due to a combination of continued production declines from both wells and low natural gas prices.

Other expense for the nine months ended September 30, 2013 was $0.1 million, compared to other income of $0.7 million for the same period in 2012. The other expense and other income recorded in each of the nine months ended September 30, 2013 and 2012 were primarily attributable to foreign exchange transactions.

Income tax expense amounted to $24.5 million and $60.7 million for the nine months ended September 30, 2013 and 2012, respectively. In the nine months ended September 30, 2013 and 2012, the income taxes were all paid in Gabon. Income taxes in the nine months ended September 30, 2013 were lower due to lower sales volumes and a lower percentage of oil allocated as “profit oil” versus “cost oil.” The income taxes the consortium pays the government of Gabon is an allocation of the remaining profit oil production from a specific contract area ranging from 50% to 60% of the oil remaining after deducting the royalty and the cost oil.

Net income for the nine months ended September 30, 2013 was $16.7 million, compared to a net income of $19.6 million for the same period in 2012. Net income allocated to the noncontrolling interest for the nine months ended September 30, 2012 was $4.7 million.

On June 6, 2013 the Company announced that its Board of Directors authorized a 12-month share repurchase program for up to an aggregate $25 million of the Company’s outstanding common stock.

The Company’s results of operations are dependent upon the difference between prices received for its oil and gas production and the costs to find and produce such oil and gas. Oil and gas prices have been and are expected in the future to be volatile and subject to fluctuations based on a number of factors beyond the control of the Company. The Company does not presently have any active hedges in place, but may do so in the future.

The Company maintains disclosure controls and procedures that are designed to provide reasonable assurance that information required to be disclosed by the Company in the reports it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to the Company’s management, including the Chief Executive Officer and Chief Financial Officer to allow timely decisions regarding required disclosure. The Company’s management, including the Company’s principal executive officer and principal financial officer, has evaluated the effectiveness of the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this Quarterly Report on Form 10-Q. Based on that evaluation, the Company’s principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures were effective as of the end of the period covered by this Quarterly Report on Form 10-Q. There were no changes in the Company’s internal controls over financial reporting that occurred during the Company’s last fiscal quarter that have materially affected, or are reasonably likely to materially affect the Company’s internal control over financial reporting.

There have been no material changes to the disclosure on this matter in our annual report on form 10-K for the year ended December 31, 2012 and our quarterly reports for the quarters ended March 31, 2013 and June 30, 2013.

In accordance with the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

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

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

Large accelerated filer	¨	Accelerated filer	x

Non-accelerated filer	¨	Smaller reporting company	¨

PART I. FINANCIAL INFORMATION

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

Condensed Consolidated Balance Sheets September 30, 2013 and December 31, 2012	3

Condensed Statements of Consolidated Operations Three months and Nine months ended September 30, 2013 and 2012	4

Condensed Consolidated Statements of Changes in Equity Nine months ended September 30, 2013 and 2012	5

Condensed Statements of Consolidated Cash Flows Nine months ended September 30, 2013 and 2012	6

Notes to Unaudited Condensed Consolidated Financial Statements	7

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	11

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	19

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	19

CONTROLS AND PROCEDURES	19

PART II. OTHER INFORMATION	20

ITEM 1A. RISK FACTORS	20

ITEM 6. EXHIBITS	20

	Three months ended				Nine months ended
	September 30, 2013		September 30, 2012		September 30, 2013		September 30, 2012
Basic weighted average common stock issued and outstanding		56,600,866		57,845,800		57,464,763		57,613,624
Dilutive options		514,748		1,101,371		735,445		1,171,015
Total dilutive shares		57,115,614		58,947,171		58,200,208		58,784,639