16.	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
		2011				2010				2009
Costs incurred during the year:
Exploration—capitalized		$	—				—			$	—
Exploration—expensed			2,083				392				47
Acquisition			9,495				2,240				—
Development			14,936				—				—
Total		$	26,514				2,632			$	47
(In thousands)						International
		2011				2010				2009
Costs incurred during the year:
Exploration—capitalized		$	69			$	8,020			$	2,257
Exploration—expensed			3,625				6,421				36,417
Acquisition			455				1,200				—
Development			8,011				29,927				12,143
Total		$	12,160			$	45,568			$	50,817

Exploration expense includes $0.1 million, $2.6 million and $33.4 million for dry hole expense in 2011, 2010 and 2009, respectively.

 

Capitalized Costs Relating to Oil and Gas Producing Activities:

		December 31,
		2011				2010				2009
Capitalized costs— Properties not being amortized		$	46,047			$	25,504			$	15,036
Properties being amortized(1)			182,820				170,457				140,555
Total capitalized costs		$	228,867			$	195,961			$	155,591
Less accumulated depreciation, depletion, and amortization			(129,166	)			(99,277	)			(80,127	)
Net capitalized costs		$	99,701			$	96,684			$	75,464

(1)	Includes $10.4 million, $10.3 million, and $8.4 million asset retirement cost in 2011, 2010, and 2009, respectively.

 

The capitalized costs pertain to the Company's producing activities in Gabon, leasehold acreage in Gabon and Angola, and U.S. activities.

 

Results of Operations for Oil and Gas Producing Activities:

		United States												International
		2011				2010				2009				2011				2010				2009
														Gabon				Gabon				Gabon
Crude oil and gas sales		$	1,655			$	126			$	84			$	208,781			$	134,346			$	115,214
Production, G&A and other expense			(7,413	)			(495	)			(103	)			(27,471	)			(28,614	)			(20,506	)
Depreciation, depletion and amortization			(1,922	)			(11	)			(11	)			(23,604	)			(19,946	)			(20,321	)
Income tax			—				(7	)			(8	)			(93,468	)			(35,260	)			(36,902	)
Results from oil and gas producing activities		$	(7,680	)		$	(387	)		$	(38	)		$	64,238			$	50,526			$	37,485

 

Proved Reserves

 

Reserve reports as of December 31, 2011, 2010, and 2009 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, 2011, 2010 and 2009, and the changes during such periods.

		Oil (MBbls)				Gas (MMCF)
PROVED RESERVES:
BALANCE AT JANUARY 1, 2009			7,422				30
Production			(1,936	)			(6	)
Revisions of previous estimates			783				(1	)
Extensions and discoveries			1,094				—
BALANCE AT DECEMBER 31, 2009			7,363				23
Production			(1,715	)			(38	)
Revisions of previous estimates			1,274				38
Extensions and discoveries			—				—
BALANCE AT DECEMBER 31, 2010			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
		Oil (MBbls)				Gas (MMCF)
PROVED DEVELOPED RESERVES
Balance at January 1, 2009			4,751				30
Balance at December 31, 2009			4,795				23
Balance at December 31, 2010			5,029				23
Balance at December 31, 2011			3,854				856

The Company's proved developed reserves are located offshore Gabon and in Texas. The reserves in Gabon include the minority interest share of reserves held by the 9.99% owner of VAALCO International, Inc., which owns VAALCO Gabon (Etame), Inc.

 

Revisions in 2009 were attributable to better reservoir performance at the Etame field. Extensions and discoveries in 2009 were the result of successful drilling of step out wells at the Ebouri field that increased the amount of proven acreage for the field. Revisions in 2010 were primarily associated with better reservoir performance in several of the Etame Marin block fields. 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.

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 $22.5 million attributable to future abandonment when the wells become uneconomic to produce.

(In thousands)		United States												International												Total
		December 31,												December 31,												December 31,
		2011				2010				2009				2011				2010				2009				2011				2010				2009
Future cash inflows		$	13,274			$	407			$	316			$	623,546			$	517,051			$	394,500			$	636,820			$	517,458			$	394,816
Future production costs			(1,661	)			(203	)			(179	)			(154,020	)			(140,470	)			(84,154	)			(155,681	)			(140,673	)			(84,333	)
Future development costs			(4,180	)			—				—				(85,528	)			(71,190	)			(59,054	)			(89,708	)			(71,190	)			(59,054	)
Future income tax expense			(1,347	)			(34	)			(27	)			(181,886	)			(159,811	)			(130,732	)			(183,233	)			(159,845	)			(130,759	)
Future net cash flows		$	6,086			$	170			$	110			$	202,112			$	145,580			$	120,560			$	208,198			$	145,750			$	120,670
Discount to present value at 10% annual rate			(3,150	)			(41	)			(19	)			(38,861	)			(20,885	)			(18,132	)			(42,011	)			(20,926	)			(18,151	)
Standardized measure of discounted future net cash flows		$	2,936			$	129			$	90			$	163,251			$	124,695			$	102,428			$	166,187			$	124,824			$	102,518

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,
		2011				2010				2009
BALANCE AT BEGINNING OF PERIOD		$	124,824			$	102,518			$	64,953
Sales of oil and gas, net of production costs			(183,705	)			(112,360	)			(93,321	)
Net changes in prices and production costs			194,633				139,810				148,174
Revisions of previous quantity estimates			75,713				71,600				30,178
Additions			7,742				—				42,106
Changes in estimated future development costs			(5,831	)			(5,337	)			(21,969	)
Development costs incurred during the period			31,913				37,531				22,229
Accretion of discount			12,482				10,252				6,495
Net change of income taxes			4,455				(31,482	)			(66,702	)
Change in production rates (timing) and other			(96,039	)			(87,708	)			(29,625	)
BALANCE AT END OF PERIOD		$	166,187			$	124,824			$	102,518

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 price was $110.08 per bbl. In the United States, the price was $78.89 per bbl of oil and $5.439 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 variable royalty depending on production rate.

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, 2011, there was $3.8 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 2009, the Company cost recovered 812,000 barrels out of a theoretical 1,391,000 barrels which would have been recoverable if the Cost Account was full. In 2010, the Company cost recovered 838,000 barrels out of a theoretical 1,200,000 barrels which would have been recoverable if the Cost Account was full. 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.

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 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, 2011 there was $28.2 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, 2011, 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, 2011, the Company has no proved reserves related to Block 5 in Angola.