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Supplemental Information on Oil and Gas Producing Activities | 12 Months Ended
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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 re serve 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.

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- Definition The entire disclosure for oil and gas producing industries. + References Reference 1: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Accounting Standards Codification -Topic 932 -SubTopic 235 -Section 50 -URI http://asc.fasb.org/section&trid=2145543 + Details
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