Document_and_Entity_Informatio
Document and Entity Information (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Feb. 28, 2015 | Jun. 30, 2014 | |
Document Document And Entity Information [Abstract] | |||
Entity Registrant Name | VAALCO ENERGY INC /DE/ | ||
Entity Central Index Key | 894627 | ||
Document Type | 10-K | ||
Document Period End Date | 31-Dec-14 | ||
Amendment Flag | FALSE | ||
Document Fiscal Year Focus | 2014 | ||
Document Fiscal Period Focus | FY | ||
Current Fiscal Year End Date | -19 | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Filer Category | Accelerated Filer | ||
Entity Public Float | $411,807,121 | ||
Entity Common Stock, Shares Outstanding | 57,880,481 |
CONSOLIDATED_BALANCE_SHEETS
CONSOLIDATED BALANCE SHEETS (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Current assets: | ||
Cash and cash equivalents | $69,051 | $130,529 |
Restricted cash | 1,584 | 12,366 |
Receivables: | ||
Trade | 19,527 | 16,972 |
Accounts with partners, net of allowance $7.6 million in 2014 and 2013 | 10,903 | 307 |
Other, net of allowance of $2.4 million in 2014, and zero in 2013 | 3,285 | 4,435 |
Crude oil inventory | 1,905 | 352 |
Materials and supplies | 286 | 164 |
Prepayments and other | 6,509 | 2,339 |
Total current assets | 113,050 | 167,464 |
Property and equipment - successful efforts method: | ||
Wells, platforms and other production facilities | 338,641 | 215,701 |
Undeveloped acreage | 22,133 | 23,705 |
Work in progress | 25,157 | 64,489 |
Equipment and other | 11,907 | 6,831 |
Property, plant and equipment, gross, Total | 397,838 | 310,726 |
Accumulated depreciation, depletion and amortization | -289,714 | -172,202 |
Net property and equipment | 108,124 | 138,524 |
Other assets: | ||
Restricted cash | 20,830 | 830 |
Deferred tax asset | 1,349 | 1,349 |
Deferred finance charge | 1,959 | |
Abandonment funding | 3,537 | |
Total Assets | 248,849 | 308,167 |
Current liabilities: | ||
Accounts payable and accrued liabilities | 38,540 | 42,561 |
Accounts with partners | 3,268 | |
Total current liabilities | 38,540 | 45,829 |
Asset retirement obligations | 14,846 | 11,464 |
Long term debt | 15,000 | |
Total liabilities | 68,386 | 57,293 |
Commitments and contingencies (Note 6) | ||
VAALCO Energy Inc. shareholders’ equity: | ||
Common stock, $0.10 par value, 100,000,000 authorized shares, 65,194,828 and 64,012,914 shares issued with 7,393,714 and 7,162,573 shares in treasury at Dec. 31, 2014 and 2013, respectively | 6,519 | 6,408 |
Additional paid-in capital | 64,351 | 55,455 |
Retained earnings | 146,892 | 224,442 |
Less treasury stock, at cost | -37,299 | -35,431 |
Total Equity | 180,463 | 250,874 |
Total Liabilities and Equity | $248,849 | $308,167 |
CONSOLIDATED_BALANCE_SHEETS_Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Millions, except Share data, unless otherwise specified | ||
Balance Sheet Related Disclosures [Abstract] | ||
Allowance for accounts with partners | $7.60 | $7.60 |
Allowance for other receivable | $2.40 | $0 |
Common stock, par value | $0.10 | $0.10 |
Common stock, shares authorized | 100,000,000 | 100,000,000 |
Common stock, shares issued | 65,194,828 | 64,012,914 |
Treasury stock, shares | 7,393,714 | 7,162,573 |
STATEMENTS_OF_CONSOLIDATED_OPE
STATEMENTS OF CONSOLIDATED OPERATIONS (USD $) | 12 Months Ended | ||
In Thousands, except Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Revenues: | |||
Oil and gas sales | $127,691 | $169,277 | $195,287 |
Operating costs and expenses: | |||
Production expense | 31,718 | 36,615 | 26,724 |
Exploration expense | 15,358 | 23,928 | 41,037 |
Depreciation, depletion and amortization | 20,086 | 16,929 | 19,913 |
General and administrative expense | 14,194 | 11,254 | 11,779 |
Bad debt and other expenses | 2,400 | 3,326 | 1,621 |
Impairment of proved properties | 98,341 | 7,620 | |
Total operating costs and expenses | 182,097 | 92,052 | 108,694 |
Operating income (loss) | -54,406 | 77,225 | 86,593 |
Other income (expense): | |||
Interest income | 75 | 73 | 145 |
Other, net | -733 | -111 | 414 |
Total other income (expense) | -658 | -38 | 559 |
Income (loss) before income taxes | -55,064 | 77,187 | 87,152 |
Income tax expense | 22,486 | 34,115 | 81,813 |
Net income (loss) | -77,550 | 43,072 | 5,339 |
Less net income attributable to noncontrolling interest | -4,708 | ||
Net income (loss) attributable to VAALCO Energy, Inc. | ($77,550) | $43,072 | $631 |
Basic net income (loss) per share atributable to VAALCO Energy, Inc. common shareholders | ($1.36) | $0.75 | $0.01 |
Diluted net income (loss) per share attributable to VAALCO Energy, Inc. common shareholders | ($1.36) | $0.74 | $0.01 |
Basic weighted average shares outstanding | 57,229,435 | 57,298,910 | 57,673,342 |
Diluted weighted average shares outstanding | 57,229,435 | 57,925,001 | 58,832,059 |
STATEMENTS_OF_CONSOLIDATED_EQU
STATEMENTS OF CONSOLIDATED EQUITY (USD $) | Total | Common Stock | Additional Paid-In Capital | Retained Earnings | Treasury Stock | Noncontrolling Interest |
In Thousands | ||||||
Beginning Balance at Dec. 31, 2011 | $233,067 | $6,238 | $66,122 | $180,739 | ($23,975) | $3,943 |
Stock issuance | 3,508 | 76 | 3,432 | |||
Stock based compensation | 2,406 | 2,406 | ||||
Net income (loss) | 5,339 | 631 | 4,708 | |||
Distribution to noncontrolling interest | -5,595 | -5,595 | ||||
Acquisition of noncontrolling interest | -26,200 | -23,144 | -3,056 | |||
Ending Balance at Dec. 31, 2012 | 212,525 | 6,314 | 48,816 | 181,370 | -23,975 | |
Stock issuance | 3,728 | 94 | 3,634 | |||
Stock based compensation | 3,005 | 3,005 | ||||
Treasury stock purchase | -11,456 | -11,456 | ||||
Net income (loss) | 43,072 | 43,072 | ||||
Ending Balance at Dec. 31, 2013 | 250,874 | 6,408 | 55,455 | 224,442 | -35,431 | |
Stock issuance | 5,685 | 111 | 5,574 | |||
Stock based compensation | 3,322 | 3,322 | ||||
Treasury stock purchase | -1,868 | -1,868 | ||||
Net income (loss) | -77,550 | -77,550 | ||||
Ending Balance at Dec. 31, 2014 | $180,463 | $6,519 | $64,351 | $146,892 | ($37,299) |
STATEMENTS_OF_CONSOLIDATED_CAS
STATEMENTS OF CONSOLIDATED CASH FLOWS (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
CASH FLOWS FROM OPERATING ACTIVITIES | |||
Net income (loss) | ($77,550) | $43,072 | $5,339 |
Adjustments to reconcile net income to net cash provided by operating activities | |||
Depreciation, depletion and amortization | 20,086 | 16,929 | 19,913 |
Amortization of debt issuance cost | 328 | ||
Unrealized foreign exchange (gain) loss | -59 | 22 | -245 |
Dry hole costs and impairment loss on unproved leasehold | 13,273 | 22,490 | 37,289 |
Stock based compensation | 3,322 | 3,005 | 2,406 |
Bad debt provision | 2,400 | 1,562 | 1,621 |
Impairment loss | 98,341 | 7,620 | |
Change in operating assets and liabilities: | |||
Trade receivables | -2,555 | -9,011 | 2,126 |
Accounts with partners | -13,864 | -12,649 | 18,988 |
Other receivables | -1,250 | -53 | -199 |
Crude oil inventory | -1,748 | 279 | -71 |
Materials and supplies | -122 | 173 | -102 |
Other long term assets | -3,537 | ||
Prepayments and other | -4,172 | 594 | -766 |
Accounts payable and other liabilities | -9,503 | 8,988 | 39 |
Net cash provided by operating activities | 23,390 | 75,401 | 93,958 |
CASH FLOWS FROM INVESTING ACTIVITIES | |||
Decrease/(increase) in restricted cash | -9,219 | -1,065 | 78 |
Property and equipment expenditures | -92,179 | -66,879 | -71,915 |
Net cash used in investing activities | -101,398 | -67,944 | -71,837 |
CASH FLOWS FROM FINANCING ACTIVITIES | |||
Proceeds from the issuance of common stock | 5,685 | 3,729 | 3,335 |
Debt issuance costs | -2,287 | ||
Borrowings | 15,000 | ||
Purchase of treasury stock | -1,868 | -11,456 | |
Distribution to noncontrolling interest | -5,595 | ||
Acquisition of noncontrolling interest | -26,200 | ||
Net cash provided by (used in) financing activities | 16,530 | -7,727 | -28,460 |
NET CHANGE IN CASH AND CASH EQUIVALENTS | -61,478 | -270 | -6,339 |
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD | 130,529 | 130,800 | 137,139 |
CASH AND CASH EQUIVALENTS AT END OF PERIOD | 69,051 | 130,529 | 130,800 |
Supplemental disclosure of cash flow information | |||
Cash paid for Income taxes | 23,041 | 34,444 | 83,306 |
Supplemental disclosure of non cash investing and financing activities | |||
Property and equipment additions incurred during the period but not paid at period end | 18,983 | 13,440 | 9,814 |
Receivable from employees for stock option exercise | $173 |
Organization
Organization | 12 Months Ended | |
Dec. 31, 2014 | ||
Organization Consolidation And Presentation Of Financial Statements [Abstract] | ||
Organization | 1 | ORGANIZATION |
VAALCO Energy, Inc., a Delaware corporation, is a Houston-based independent energy company principally engaged in the acquisition, exploration, development and production of crude oil and natural gas. As used herein, the terms “Company” and “VAALCO” mean VAALCO Energy, Inc. and its subsidiaries, unless the context otherwise requires. VAALCO owns producing properties and conducts exploration activities as operator of consortiums internationally in Gabon and Angola and has conducted exploration activities as a non-operator in Equatorial Guinea, West Africa. Domestically, the Company has interests in Texas, Montana, Alabama, and the Gulf of Mexico. | ||
VAALCO’s international subsidiaries are VAALCO Gabon (Etame), Inc., VAALCO Production (Gabon), Inc., VAALCO Angola (Kwanza), Inc., VAALCO UK (North Sea), Ltd., VAALCO International, Inc., VAALCO Energy (EG), Inc. and VAALCO Energy Mauritius (EG) Limited. VAALCO Energy (USA), Inc. holds interests in properties located in the United States. |
Summary_of_Significant_Account
Summary of Significant Accounting Policies | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Accounting Policies [Abstract] | |||||||||||||
Summary of Significant Accounting Policies | 2 | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | |||||||||||
Principles of Consolidation - The accompanying consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. The portion of the income and net assets applicable to the non-controlling interest in the majority-owned operations of the Company’s Gabon subsidiary has been reflected as noncontrolling interest. All intercompany transactions within the consolidated group have been eliminated in consolidation. | |||||||||||||
In December 2012, the Company acquired the noncontrolling interest in VAALCO International, Inc., for $26.2 million, with an effective date of October 1, 2012. Prior to the acquisition, the noncontrolling interest owned 9.99% of the issued and outstanding common stock of VAALCO International, Inc., a Delaware corporation of which VAALCO Gabon Etame, Inc. is the wholly owned subsidiary. | |||||||||||||
Cash and Cash Equivalents – Cash and cash equivalent includes deposits and funds invested in highly liquid instruments with original maturities of three months or less at the date of purchase. | |||||||||||||
Restricted Cash – Restricted cash includes cash that is contractually restricted. Restricted cash is classified as a current or non-current asset based on its designated purpose and time duration. Current amounts at December 31, 2014 each include an escrow amount representing the Company’s bank guarantees for customs clearance in Gabon ($1.6 million).Long term amounts at December 31, 2014 and 2013 each include the Company’s charter payment escrow for the Floating Production Storage and Offloading tanker (“FPSO”) in Gabon ($0.8 million) and funds restricted to secure the Company’s drilling obligation in Block 5 in Angola under the original production sharing contract ($10.0 million) and an increase of $10.0 million related to the Subsequent Exploration Phase (“SEP”) entered into in October 2014 which included two additional well obligations. | |||||||||||||
The Company invests restricted and excess cash in certificates of deposit and commercial paper issued by banks with maturities typically not exceeding 90 days. | |||||||||||||
Inventory - Materials and supplies are valued at the lower of cost, determined by the weighted-average method, or market. Crude oil inventories are carried at the lower of cost or market and represent the Company’s share of crude oil produced and stored on the FPSO, but unsold. | |||||||||||||
Income Taxes – VAALCO accounts for income taxes under an asset and liability approach that recognizes deferred income tax assets and liabilities for the estimated future tax consequences of differences between the financial statements and tax bases of assets and liabilities. Valuation allowances are provided against deferred tax assets that are not likely to be realized. | |||||||||||||
Property and Equipment - The Company follows the successful efforts method of accounting for exploration and development costs. Under this method, exploration costs, other than the cost of exploratory wells, are charged to expense as incurred. Exploratory well costs are initially capitalized until a determination as to whether proved reserves have been discovered. If an exploratory well is deemed to not have found proved reserves, the associated costs are expensed at that time. Other exploration costs, including geological and geophysical expenses applicable to undeveloped leasehold, leasehold expiration costs and delay rentals are expensed as incurred. All development costs, including developmental dry hole costs, are capitalized. | |||||||||||||
The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred by capitalizing the corresponding cost as part of the carrying amount of the long-lived assets. | |||||||||||||
The Company reviews its oil and gas properties for impairment whenever events or changes in circumstances indicate that the carrying amount of such properties may not be recoverable. When it is determined that an oil and gas property’s estimated future net cash flows will not be sufficient to recover its carrying amount, an impairment charge must be recorded to reduce the carrying amount of the asset to its estimated fair value. Provisions for impairment of undeveloped oil and gas leases are based on periodic evaluations and other factors. | |||||||||||||
Depletion of wells, platforms, and other production facilities are calculated on a field basis under the unit-of-production method based upon estimates of proved developed producing reserves. Depletion of developed leasehold acquisition costs are provided on a field basis under the unit-of-production method based upon estimates of proved reserves. Undeveloped leasehold acquisition costs are not subject to depletion, but are subject to impairment testing. Provision for depreciation of other property is made primarily on a straight-line basis over the estimated useful life of the property. The annual rates of depreciation are as follows: | |||||||||||||
Office and miscellaneous equipment: | 3 - 5 years | ||||||||||||
Leasehold improvements: | 8 - 12 years | ||||||||||||
Foreign Exchange Transactions - For financial reporting purposes, the subsidiaries use the United States Dollar as their functional currency. Gains and losses on foreign currency transactions are included in income currently. The Company recognized loss on foreign currency transactions of $0.7 million in 2014. The Company recognized loss on foreign currency transactions of $0.1 million in 2013 and gains of $0.4 million in 2012, respectively. | |||||||||||||
Capitalized Interest - Interest costs from external borrowings are capitalized on major projects with an expected construction period of one year or longer. Capitalized interest is added to the cost of the underlying asset and is depleted on the unit-of-production method in the same manner as the underlying assets. | |||||||||||||
Accounts With Partners - Accounts with partners represent cash calls due or excess cash calls paid by the partners for exploration, development and production expenditures made by VAALCO Gabon (Etame), Inc. and VAALCO Angola (Kwanza), Inc., and VAALCO (USA), Inc. | |||||||||||||
Bad Debt – On a quarterly basis, the Company evaluates its accounts receivable balances to confirm collectability. Where collectability is in doubt, the Company records an allowance against the accounts receivable balance with a corresponding charge to net income as bad debt expense. The majority of the Company’s accounts receivable balances are with its joint venture partners and purchasers of its oil, natural gas and natural gas liquids and with the government of Gabon for reimbursements of Value-Added Tax (“VAT”) paid by the Company. Collection efforts, including remedies provided for in the contracts, are pursued to collect overdue amounts owed to the Company. Collection efforts, including remedies provided for in the contracts, are pursued to collect overdue amounts owed to the Company. | |||||||||||||
During 2014 and 2013, the Company recorded a bad debt allowance of $2.4 million and $1.6 million, respectively. In 2014, the bad debt allowance pertains to VAT amounts owed for more than twelve months from the government of Gabon. In 2013, the bad debt allowance was related to the uncertainty in collecting its joint venture receivable in Angola as no joint venture partner was established. In January 2014, the Angolan government appointed Sonangol P&P as the replacement joint venture partner. The table below shows a rollforward analysis of the allowance against the partner accounts receivable balance and VAT: (in thousands) | |||||||||||||
Description | Balance | Charged | Balance | ||||||||||
at | to Costs | at End | |||||||||||
Beginning | and | of | |||||||||||
of Period | Expenses | Period | |||||||||||
Allowance for Bad Debt | |||||||||||||
Year Ended December 31, 2014 | (7,631 | ) | (2,400 | ) | (10,031 | ) | |||||||
Year Ended December 31, 2013 | (6,069 | ) | (1,562 | ) | (7,631 | ) | |||||||
Revenue Recognition – In May 2014, the Financial Accounting Standards Board ("FASB") issued revised guidance on revenue from contracts with customers, Accounting Standards Update (ASU) No. 2014-09, Revenue from Contracts with Customers that will supersede most current revenue recognition guidance, including industry-specific guidance. The core principle of the revenue model is that an entity will recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The new standard provides a five-step analysis for transactions to determine when and how revenue is recognized. The guidance will be effective for us beginning January 1, 2017 and early adoption is not permitted. The guidance permits the use of either a full retrospective or a modified retrospective approach. We are evaluating the transition methods and the impact of the amended guidance on our financial position, results of operations and related disclosures. | |||||||||||||
The Company recognizes revenues from crude oil and natural gas sales upon delivery to the buyer. Oil and gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and collectability of the revenue is reasonably assured. Revenue from the production of oil, natural gas and NGLs on properties in which we have joint ownership is recorded under the sales method. Under this method, we recognize revenues on the volumes sold based on the provisional sales prices. The volumes sold may be more or less than the volumes to which we are entitled based on our ownership interest in the property. These differences result in a condition known in the industry as a production imbalance. A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves on such property. As of December 31, 2014 and 2013, we had no oil and gas imbalances recorded in our consolidated financial statements. | |||||||||||||
Stock Based Compensation - The Company measures the cost of employee services received in exchange for an award of equity instruments based on the fair value of the award on the date of the grant. Grant date fair value for options is estimated using an option-pricing model which is consistent with the terms of the award. For restricted stock, grant date fair value is determined using the grant date price of the company’s shares. Such cost is recognized over the period during which an employee is required to provide service in exchange for the award (which is usually the vesting period). The Company estimates the number of instruments that will ultimately be issued, rather than accounting for forfeitures as they occur. | |||||||||||||
Fair Value of Financial Instruments - The Company’s financial instruments consist primarily of cash, restricted cash, trade receivables and trade payables and debt. The book values of cash, restricted cash, trade receivables, and trade payables are representative of their respective fair values due to the short-term maturity of these instruments. The book value of the Company’s debt instruments are considered to approximate the fair value, as the interest rates are adjusted based on rates currently in effect. | |||||||||||||
Fair Value – Fair value is defined as the price that would be received to sell an asset or the price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Inputs used in determining fair value are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. The three input levels of the fair-value hierarchy are as follows: | |||||||||||||
Level 1 – Inputs represent quoted prices in active markets for identical assets or liabilities (for example, exchange-traded commodity derivatives). | |||||||||||||
Level 2 – Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs). | |||||||||||||
Level 3 – Inputs that are not observable from objective sources, such as the Company’s internally developed assumptions used in pricing an asset or liability (for example, an estimate of future cash flows used in the Company’s internally developed present value of future cash flows model that underlies the fair-value measurement). | |||||||||||||
Risks and Uncertainties - The Company’s interests are located overseas in onshore and offshore Gabon, offshore in Angola and Equatorial Guinea, and domestically in Texas, Montana, Alabama, and the Gulf of Mexico. | |||||||||||||
Substantially all of the Company’s oil and gas is sold at the well head at posted or indexed prices under short-term contracts, as is customary in the industry. | |||||||||||||
In Gabon, starting in the second quarter of 2014, the Company switched to an agency model to sell its crude oil. The Company contracted with a third party in order to sell, based on a fixed barrel fee, on the spot market. Prior to the second quarter in 2014, the Company sold oil under contracts with Mercuria Trading NV (“Mercuria”) beginning with the calendar year 2011. For the first quarter of 2015, the Company will also sell its oil under the agency model on the spot market. | |||||||||||||
Domestic operated production in Texas is sold via two contracts, one for oil and one for gas and natural gas liquids. The Company has access to several alternative buyers for oil, gas, and natural gas liquids domestically. | |||||||||||||
Use of Estimates in Financial Statement Preparation - The preparation of financial statements in conformity with generally accepted accounting principles requires estimates and assumptions that affect the reported amounts of assets and liabilities as well as certain disclosures. The Company’s consolidated financial statements include amounts that are based on management’s best estimates and judgments. Actual results could differ from those estimates. | |||||||||||||
Estimates of oil and gas reserves used in the consolidated financial statements to estimate depletion expense and impairment charges require extensive judgments and are generally less precise than other estimates made in connection with financial disclosures. The Company considers its estimates to be reasonable; however, due to inherent uncertainties and the limited nature of data, estimates are imprecise and subject to change over time as additional information become available. | |||||||||||||
Asset Retirement Obligations (“ARO”) - The Company has significant obligations to remove tangible equipment and restore land or seabed at the end of oil and gas production operations. The Company’s removal and restoration obligations are primarily associated with plugging and abandoning wells, removing and disposing of all or a portion of offshore oil and gas platforms, and capping pipelines. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety, and public relations considerations. | |||||||||||||
ARO associated with retiring tangible long-lived assets is recognized as a liability in the period in which the legal obligation is incurred and becomes determinable. The liability is offset by a corresponding increase in the underlying asset. The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with The Company’s oil and gas properties. The Company utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. | |||||||||||||
StockBased_Compensation
Stock-Based Compensation | 12 Months Ended | ||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract] | |||||||||||||||||
Stock-Based Compensation | 3 | STOCK BASED COMPENSATION | |||||||||||||||
Stock options are granted under the Company’s long-term incentive plan and have an exercise price that may not be less than the fair market value of the underlying shares on the date of grant. In general, stock options granted will become exercisable over a period determined by the Compensation Committee which in the past has been a five year life, with the options vesting over a service period of three to five years. A portion of the stock options granted in March 2014, 2013, and 2012 were vested immediately with the others vesting over a three year period. In addition, stock options will become exercisable upon a change in control, unless provided otherwise by the Compensation Committee. At December 31, 2014, there were 4,657,552 shares subject to options authorized but not granted. | |||||||||||||||||
For the years ended December 31, 2014, 2013 and 2012, the Company recognized non-cash compensation expense of $3.3 million, $3.0 million and $2.4 million, respectively. These amounts were recorded as general and administrative expense. Because the Company does not pay significant United States taxes, no amounts were recorded for tax benefits. | |||||||||||||||||
A summary of the stock option activity for the year ended December 31, 2014 is provided below: | |||||||||||||||||
Number of | Weighted | Weighted | Aggregate | ||||||||||||||
Shares | Average | Average | Intrinsic | ||||||||||||||
Underlying | Exercise | Remaining | Value (in | ||||||||||||||
Options (in | Price Per | Contractual | millions) | ||||||||||||||
thousands) | Share | Term | |||||||||||||||
Outstanding at beginning of period | 4,927 | $ | 6.95 | 2.85 | 2.81 | ||||||||||||
Granted | 1,118 | $ | 7.05 | 4.18 | |||||||||||||
Exercised | (1,128 | ) | $ | 5.04 | 0.69 | ||||||||||||
Forfeited | (152 | ) | $ | 7.47 | 3.54 | ||||||||||||
Outstanding at end of period | 4,765 | $ | 7.41 | 2.62 | $ | 1.61 | |||||||||||
Vested - end of period | 3,318 | $ | 7.45 | 2.22 | $ | 1.18 | |||||||||||
Vested and expected to vest - end of period | 4,728 | $ | 7.41 | 2.62 | $ | 1.6 | |||||||||||
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. | |||||||||||||||||
Shares of restricted stock are granted under the Company’s long-term incentive plan using the fair market value of the underlying shares on the date of grant. In general, restricted stock granted to employees will vest over a period determined by the Compensation Committee. Determined by the Compensation Committee, some restricted stocks granted are vested immediately while some are vested over a three year period with the initial one-third vesting at the first grant date anniversary. | |||||||||||||||||
Restricted Stock | Weighted Average Grant Price | ||||||||||||||||
Non-Vested Shares Outstanding December 31, 2013 | 100,000 | $ | 5.89 | ||||||||||||||
Awards granted | 99,468 | $ | 6.98 | ||||||||||||||
Awards vested | (51,600 | ) | $ | 6.56 | |||||||||||||
Awards forfeited | - | - | |||||||||||||||
Non-Vested Shares Outstanding December 31, 2014 | 147,868 | $ | 6.39 | ||||||||||||||
As of December 31, 2014, unrecognized compensation costs totaled $2.8 million. The expense is expected to be recognized over a weighted average period of 2.5 years. | |||||||||||||||||
A summary of the values of options granted and exercised for each of the years ended December 31, 2014, 2013 and 2012 is provided below: | |||||||||||||||||
2014 | 2013 | 2012 | |||||||||||||||
Options granted - (thousands) | 1,118 | 1,836 | 1,024 | ||||||||||||||
Weighted average grant date fair value - ($/share) | $ | 2.43 | $ | 2.45 | $ | 3.49 | |||||||||||
Weighted average exercise price - ($/share) | $ | 5.04 | $ | 4.25 | $ | 4.62 | |||||||||||
Options exercised (thousands) | 1,128 | 877 | 759 | ||||||||||||||
Total intrinsic value of options exercised - ($thousands) | $ | 4,120 | $ | 1,201 | $ | 3,267 | |||||||||||
The Company received cash proceeds of $5.7 million, $3.7 million and $3.3 million from issuance of stock related to options exercised in 2014, 2013 and 2012, respectively. | |||||||||||||||||
The valuation of the options granted is based upon a Black Scholes model. The table below summarizes the assumptions used to value the options issued in 2014 and 2013. | |||||||||||||||||
Year | Options Issued | Average | Expected Term | Risk Free | Expected | ||||||||||||
(in thousands) | Volatility | Interest Rate | Dividend Yield | ||||||||||||||
2014 | 1,118 | 58% | 2.5 years | 0.50% | 0% | ||||||||||||
2013 | 1,836 | 51% | 2.5 years | 0.30% | 0% | ||||||||||||
2012 | 1,024 | 65% | 2.5 years | 0.50% | 0% | ||||||||||||
The Company has no set policy for sourcing shares for options grants. Historically the shares issued under options grants have been new shares. |
Stockholders_Equity_and_Earnin
Stockholders' Equity and Earnings Per Share | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Earnings Per Share [Abstract] | |||||||||||||
Stockholders' Equity and Earnings Per Share | 4 | STOCKHOLDERS’ EQUITY AND EARNINGS PER SHARE | |||||||||||
The Company is authorized to issue up to 100 million shares of common stock. Basic earnings per share (“EPS”) is calculated using the average number of shares of common stock outstanding during each period. Diluted EPS assumes the restricted stock is outstanding on the date of the grant and the exercise of all stock options having exercise prices less than the average market price of the common stock using the treasury stock method. | |||||||||||||
A reconciliation of diluted shares consists of the following: | |||||||||||||
Year Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
Item | |||||||||||||
Basic weighted average common stock issued and | 57,229,435 | 57,298,910 | 57,673,342 | ||||||||||
outstanding | |||||||||||||
Dilutive options and restricted stock | - | 626,091 | 1,158,717 | ||||||||||
Total diluted shares | 57,229,435 | 57,925,001 | 58,832,059 | ||||||||||
A total of 2,329,392, 3,508,865, and 1,018,900 shares under option were not included because they were anti-dilutive during the years ended December 31, 2014, 2013 and 2012, respectively. |
Income_Taxes
Income Taxes | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Income Tax Disclosure [Abstract] | |||||||||||||
Income Taxes | 5 | INCOME TAXES | |||||||||||
The Company and its domestic subsidiaries file a consolidated United States income tax return. Certain subsidiaries’ operations are also subject to foreign income taxes. | |||||||||||||
Provision for income taxes consists of the following: | |||||||||||||
(in thousands) | Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | |||||||||||
U.S. Federal: | |||||||||||||
Current | $ | - | $ | - | $ | - | |||||||
Deferred | - | - | - | ||||||||||
Foreign: | |||||||||||||
Current | 22,486 | 34,115 | 81,813 | ||||||||||
Deferred | - | - | - | ||||||||||
Total | $ | 22,486 | $ | 34,115 | $ | 81,813 | |||||||
The primary differences between the financial statement and tax bases of assets and liabilities at December 31, 2014 and 2013 are as follows: (In thousands) | |||||||||||||
2014 | 2013 | ||||||||||||
Deferred Tax Assets: | |||||||||||||
Basis difference in fixed assets | $ | 63,931 | $ | 31,440 | |||||||||
Foreign tax credit carry forward | 48,928 | 55,908 | |||||||||||
Alternative minimum tax credit carryover | 1,349 | 1,349 | |||||||||||
Foreign net operating losses | 44,228 | 42,688 | |||||||||||
Asset retirement obligations | 5,196 | 4,012 | |||||||||||
Other | 3,828 | 3,300 | |||||||||||
$ | 167,460 | $ | 138,697 | ||||||||||
Valuation allowance | (166,111 | ) | (137,348 | ) | |||||||||
Total deferred tax asset | $ | 1,349 | $ | 1,349 | |||||||||
The Company’s unused foreign tax credits will start to expire between the years 2017 and 2023. The alternative minimum tax credits do not expire, and foreign net operating losses (“NOL”) are not subject to expiry dates. The NOL for the Company’s UK subsidiary can be carried forward indefinitely, while the NOLs for the Company’s Gabon and Angola subsidiaries are included in the respective subsidiaries’ cost oil accounts, which will be offset against future taxable revenues. Management assesses the available positive and negative evidence to estimate if existing deferred tax assets will be utilized. The Company does not anticipate utilization of the foreign tax credits prior to expiration nor does the Company expect to generate sufficient taxable income to utilize other deferred tax assets. On the basis of this evaluation, a valuation allowance of $166.1 million and $137.3 million has been recorded as of December 31, 2014 and 2013, respectively, to reduce the deferred tax asset to the amount that is more likely than not to be realized. | |||||||||||||
Under U.S. tax law, certain foreign taxes paid under arrangements such as the Company’s Production Sharing Contracts (“PSCs”) may not be eligible to be claimed as foreign tax credits and are instead treated as deductible royalties. In 2013, the Company engaged outside advisors to analyze the facts and circumstances surrounding the creditability of the foreign taxes paid to the Republic of Gabon pursuant to its PSC. Based on the advice provided by these outside advisors, the Company revised its estimate of foreign tax credit carryovers in 2013 to reflect an increase of $28.0 million. The increase in deferred tax asset for foreign tax credits was fully offset by an increase in the valuation allowance. | |||||||||||||
Pretax income (loss) is comprised of the following: | |||||||||||||
(in thousands) | Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | |||||||||||
United States | $ | (6,349 | ) | $ | (17,649 | ) | $ | (56,979 | ) | ||||
Foreign | (48,715 | ) | 94,836 | 144,131 | |||||||||
$ | (55,064 | ) | $ | 77,187 | $ | 87,152 | |||||||
The statutory rate reconciliation is as follows: | |||||||||||||
(In Thousands) | Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | |||||||||||
Tax Provision Computed at Statutory Rate | $ | (19,273 | ) | $ | 27,015 | $ | 30,503 | ||||||
Foreign taxes not offset in U.S. by foreign tax credits | 4,433 | (2,072 | ) | 25,266 | |||||||||
Permanent Differences | 135 | 973 | 2,370 | ||||||||||
Foreign Tax Credit Adjustments | 8,417 | (28,027 | ) | ||||||||||
Increase/(Decrease) in Valuation Allowance | 28,762 | 37,752 | 23,675 | ||||||||||
Other | 12 | (1,526 | ) | - | |||||||||
Total Tax Expense | $ | 22,486 | $ | 34,115 | $ | 81,813 | |||||||
At December 31, 2014, the Company was subject to foreign and United States federal taxes only, with no allocations made to state and local taxes. | |||||||||||||
The following table summarizes the tax years that remain subject to examination by major tax jurisdictions: | |||||||||||||
United States | 2008-2014 | ||||||||||||
Gabon | 2007-2014 | ||||||||||||
Commitments_and_Contingencies
Commitments and Contingencies | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
Commitments And Contingencies Disclosure [Abstract] | |||||||||
Commitments and Contingencies | 6 | COMMITMENTS AND CONTINGENCIES | |||||||
FPSO Charter | |||||||||
In October 2012, the Company entered into an amendment with the owner of the FPSO chartered for the Etame field to extend the contract until September 2020. In connection with the charter of the FPSO, the Company, as operator of the Etame field, guaranteed the charter payments through the same period. The charter continues for two years beyond that period unless one year’s prior notice is given to the owner of the FPSO. The Company obtained several guarantees from its partners for their share of the charter payment. The Company’s share of the charter payment is 28.1%. The Company believes the need for performance under the charter guarantee is remote. | |||||||||
The estimated obligations for the annual charter payment and the Company’s share of the charter payments through the end of the charter are as follows: (in thousands) | |||||||||
Year | Full | Company | |||||||
Charter | Share | ||||||||
Payment | |||||||||
2015 | $ | 25,843 | $ | 7,255 | |||||
2016 | 25,843 | 7,255 | |||||||
2017 | 25,843 | 7,255 | |||||||
2018 | 25,843 | 7,255 | |||||||
2019 | 25,843 | 7,255 | |||||||
Thereafter | 25,914 | 7,275 | |||||||
Total | $ | 155,129 | $ | 43,550 | |||||
The Company has recorded a liability of $1.0 million and $1.1 million at December 31, 2014 and 2013, respectively, representing the guarantee’s fair value. | |||||||||
The Company’s share of charter expense, including a $0.93 per Bbl ($0.25 per Bbls in 2013) charter fee for production up to 20,000 BOPD and a $2.50 per Bbl charter fee for those Bbls produced in excess of 20,000 BOPD, was $11.8 million, $10.4 million and $9.7 million for the years ended December 31, 2014, 2013 and 2012, respectively. | |||||||||
Other Lease Obligations | |||||||||
In addition to the FPSO, the Company has operating lease obligations for rentals as follows: (in thousands) | |||||||||
Year | Gross | Company | |||||||
Obligation | Share | ||||||||
2015 | $ | 90,935 | $ | 36,812 | |||||
2016 | 36,607 | 10,594 | |||||||
2017 | 441 | 441 | |||||||
2018 | 408 | 408 | |||||||
2019 | 407 | 407 | |||||||
Thereafter | 340 | 340 | |||||||
Total | $ | 129,138 | $ | 49,002 | |||||
The Company contracted with two drilling rigs in the year ended December 31, 2014. In the third quarter of 2014, the Company contracted with a drilling rig to begin a multi- well development drilling campaign offshore Gabon. The campaign includes drilling of wells from the Etame platform and wells from the South East Etame and North Tchibala platform. The drilling rig commenced in October 2014 and provides a commitment until July 2016, at a day rate of approximately $168,000. The total commitment related to this rig is $25.8 million. The second drilling rig contract was signed in July 2014 for a semi-submersible rig to drill the exploration well on the Kindele prospect, a post-salt objective. The well began drilling in the first quarter of 2015. The drilling rig provides a forty-five day commitment at a day rate of approximately $338,000. The total commitment related to this rig is $15.2 million Such rates are subject to standard reimbursement and escalation contractual provisions. | |||||||||
The 2015 lease obligation amounts are higher than amounts for years beyond 2015 due to short term contracts for helicopter and marine vessels supporting the offshore Gabon operations. | |||||||||
The Company incurred rent expense of $4.0 million, $4.1 million and $4.4 million under operating leases for the years ended December 31, 2014, 2013 and 2012, respectively. | |||||||||
Gabon Obligation | |||||||||
Under the terms of the Etame Production Sharing Contract, the consortium is required to provide to the local government refinery a volume of crude at a 25% discount to market price (the “Gabon Obligation”). The volume required to be furnished is the amount of the Etame Marin block production divided by the total Gabon production times the volume of oil refined by the refinery per year. In 2014, the Company paid $3.3 million for its share of the 2013 obligation. In 2013, the Company paid $3.0 million for its share of the 2012 obligation. In 2012, the Company paid $3.7 million for its share of the 2011 obligation. The Company accrues an amount for the Gabon Obligation based on management’s best estimate of the volume of crude required, because the refinery does not publish its throughput figures. The amount accrued at December 31, 2014, for the Company’s share of the 2014 obligation is $2.7 million. These costs are deemed cost recoverable under the terms of the production sharing contract. | |||||||||
Offshore Gabon | |||||||||
As part of securing the first of two-five year extensions to the Etame field production license to which the Company is entitled from the government of Gabon, the Company agreed to a cash funding arrangement for the eventual abandonment of all offshore wells, platforms and facilities on the Etame Marin Block. The agreement was finalized in the first quarter of 2014 (effective 2011) providing for annual funding 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 initial funding took place in October 2014 for calendar years 2012 and 2013 totaling $8.4 million ($2.3 million net to the Company). The funding for calendar year 2014 was paid in the first quarter of 2015 in the amount of $4.2 million ($1.2 million net to the Company). The abandonment estimate for this purpose is estimated to be approximately $10.1 million net to the Company on an undiscounted basis. As in prior periods, the obligation for abandonment of the Gabon offshore facilities is included in the asset retirement obligation shown on the Company’s balance sheet. The cash funding is reflected under other long term assets as “Abandonment Funding”. | |||||||||
Additionally, in October 2014, the Company received a provisional audit report related to the Etame Marin block operations from the Gabon Taxation Department as part of a special industry-wide audit of business practices and financial transactions in the Republic of Gabon. The Company currently cannot reasonably estimate a range of potential loss, if any, as a result of the audits. While the ultimate outcome of the claim and impact on VAALCO cannot be predicted, management believes that the claims are unfounded. In November 2014, we responded to the Gabon Taxation Department requesting joint meetings to advance the resolution of this matter and provided a formal reply to the provisional audit report in February 2015. | |||||||||
Angola | |||||||||
In November 2006, the Company signed a production sharing contract for Block 5 offshore Angola. The four year primary term with an optional three year extension awards the Company exploration rights to 1.4 million acres offshore central Angola. The Company’s working interest is 40%. Additionally, the Company is required to carry the Angolan national oil company, Sonangol P&P, for 10% of the work program. During the first four years of the contract the Company was required to acquire and process 1,000 square kilometers of 3-D seismic data, drill two exploration wells and expend a minimum of $29.5 million ($14.8 million net to the Company). The Company fulfilled its seismic obligation when it acquired 1,175 square kilometers of 3-D seismic data at a cost of $7.5 million ($3.75 million net to the Company) in January 2007 and 524 square kilometers of 3-D seismic data during the fourth quarter of 2008 at a cost of $6.0 million ($3.0 million net to the Company). | |||||||||
The government assigned working interest partner was delinquent paying their share of the costs several times in 2009 and consequently was placed in a default position. By a governmental decree dated December 1, 2010, the former partner was removed from the production sharing contract, and a one year time extension was granted for drilling the two exploration commitment wells. Additional extensions were subsequently granted by the Angolan government until November 30, 2014 to drill the two exploration commitment wells. | |||||||||
In the fourth quarter of 2013, the Company received written confirmation from The Ministry of Petroleum of Angola that the available 40% working interest in Block 5, offshore Angola, was assigned to Sonangol E.P., the National Concessionaire. The Ministry of Petroleum also confirmed that Sonangol E.P. would assign the aforementioned participating interest to its exploration and production affiliate, Sonangol P&P. | |||||||||
In April 2014, the Company received a letter and contractual amendment proposal from Sonangol E.P., related to the extension of the two well drilling commitment, prior to the expiration of the extension on November 30, 2014, by the government of Angola. Due to the uncertainty that the primary term of the exploration license would be extended by the Republic of Angola before the November 30, 2014 expiration date, in October 2014, the Company entered into the Subsequent Exploration Phase (“SEP”), together with its working interest partner, Sonangol P&P. The Subsequent Exploration Phase (“SEP”) provided for in the Production Sharing Agreement signed in 2006 with the Republic of Angola. The SEP extends the exploration period for an additional three year period such that the new expiry date for exploration activities is November 30, 2017. Entering the SEP requires the Company and its partner to acquire 3D seismic covering six hundred square kilometers and to drill two additional exploration wells. | |||||||||
Late in 2013, the Company proceeded to obtain additional seismic data covering the deeper segment of the block. The seismic data was reprocessed during 2014 and will continue to be reprocessed in 2015. With the purchase of the additional seismic data, the Company has already satisfied the seismic obligation of the SEP. | |||||||||
By entering into the SEP, the Company is required to drill a total of four exploration wells during the exploration extension period. The four well obligations include the two well commitments under the primary exploration period that carries over to the SEP period. A $10.0 million dollar assessment ($5.0 million dollars net to VAALCO) applies to each of the four commitment exploration wells, if any, that remain undrilled at the end of the exploration period in November 2017. Restricted cash of $10.0 million for the two new commitment wells was recorded in the fourth quarter of 2014. At December 31, 2014 the Company had $20.0 million in restricted cash related to the offshore Angola exploration agreement. | |||||||||
A drilling rig contract was signed in July 2014 for a semi-submersible rig to drill the exploration well on the Kindele prospect, a post-salt objective. The well is expected to begin drilling in the first quarter of 2015. Drilling this well will satisfy one of the four exploration well obligations and release $5.0 million of the $20.0 million recorded as restricted cash at December 31, 2014 by the Company. |
Debt
Debt | 12 Months Ended | |
Dec. 31, 2014 | ||
Debt Disclosure [Abstract] | ||
Long Term Debt | 7 | LONG TERM DEBT |
In January 2014, the Company executed a loan agreement with the International Finance Corporation (“IFC”) for a $65.0 million revolving credit facility, which is secured by the assets of the Company’s Gabon subsidiary. Borrowings under the credit facility totaled $15.0 million as of December 31, 2014 and are due in full upon maturity in December 2019. The borrowings approximate fair value as the interest approximates current market rates for similar instruments. In the year ended 2014, the interest rate on the Company’s bank debt averaged 4.32%. The debt facility is secured by the assets and ownership of the Company’s Gabon subsidiary ($58.7 million net asset value as of December 31, 2014) and include a parent company guarantee. | ||
Under the debt agreement the senior tranche decreases by $6.25 million and the subordinated tranche decreases by $1.88 million every six months beginning June 30, 2016 through December 2019. The proceeds from any borrowings under the facility are required to be used for (i) the construction of two new platforms and associated facilities in the Etame field and the South East Etame and North Tchibala fields; (ii) the drilling, completion and production of wells for the aforementioned fields; (iii) upon approval, the Ebouri Project; (iv) the costs associated with modifying the FPSO to support the new platforms, all of which are located in the Etame Block offshore of the southern coast of Gabon; and (v) general corporate purposes related to the foregoing. | ||
Interest is paid quarterly at a rate of LIBOR plus a spread of 3.75% for the senior tranche and 5.75% for the subordinated tranche. We pay commitment fees on the undrawn portion of the total commitments. Commitment fees for the lenders are equal to 1.5% of the unused balance of the senior tranche of $50.0 million and 2.3% of the unused balance of the subordinated tranche of $15.0 million when a commitment is available for utilization. | ||
Our borrowing base under the IFC credit facility is based upon our proved reserves and risk adjusted probable reserves and is re-determined semi-annually by the IFC. In addition, the borrowing base may be adjusted pursuant to certain non-scheduled re-determinations. However, the credit facility contains a covenant that prevents us from borrowing any amounts that would cause our debt to equity ratio to exceed 60:40. As of December 31, 2014, we estimate that this covenant would restrict our total borrowing capacity to approximately $25.0 million (of which $15.0 million has been borrowed as of December 31, 2014). | ||
Under the IFC credit facility, we are required to maintain a ratio of our net debt to EBITDAX (each as defined in the credit agreement) of not more than 3.0 to 1.0 and a ratio of debt to equity at or below 60:40. Forecasting our compliance with the financial covenant in future periods is inherently uncertain. Factors that could impact our debt to EBITDAX in future periods include future realized prices for sales of oil and natural gas, estimated future production, returns generated by our capital program, and future interest costs, among others. The Company is in compliance with all financial covenants at the end of December 31, 2014. | ||
The credit agreement governing the IFC credit facility contains additional customary non-financial covenants that, among other things, restrict our ability to pay dividends, restrict our ability to buy and sell assets, limit our ability to make acquisitions or investments, and restrict our ability to incur additional indebtedness. In addition, the credit agreement contains administrative requirements, including but not limited to providing financial statements, compliance certificates, and other documents to the IFC under prescribed timelines. | ||
Subject to any cure periods, the consequences of non-compliance with our debt covenants generally include, but are not limited to, the ability of the IFC to accelerate our obligation to repay amounts outstanding. | ||
Capitalization_of_Interest
Capitalization of Interest | 12 Months Ended | |
Dec. 31, 2014 | ||
Banking And Thrift [Abstract] | ||
Capitalization of Interest | 8 | CAPITALIZATION OF INTEREST |
The Company capitalizes interest costs and commitment fees on expenditures made in connection with exploration and development projects that are not subject to current depletion. Interest and commitment fees are capitalized only for the period that activities are in progress to bring these projects to their intended use. For year ended December 31, 2014, the Company incurred interest expense of $1.2 million, in connection with the IFC credit facility. All interest expense was capitalized. | ||
Capitalization_of_Exploratory_
Capitalization of Exploratory Well Costs | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Inventory Disclosure [Abstract] | |||||||||||||
Capitalization of Exploratory Well Costs | 9 | CAPITALIZATION OF EXPLORATORY WELL COSTS | |||||||||||
ASC Topic 932 - Extractive Industries provides that an exploratory well shall be capitalized as part of the entity’s uncompleted wells pending the determination of whether the well has found proved reserves. Further, an exploration well that discovers oil and gas reserves, but those reserves cannot be classified as proved when drilling is completed, shall be capitalized if the well has found a sufficient quantity of reserves to justify its completion as a producing well and the entity is making sufficient progress assessing the reserves and the economic and operating viability of the project. If either condition is not met, the exploration well would be assumed to be impaired and its costs would be charged to expense. | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
Capitalized exploratory well costs that have been | - | 5.9 | |||||||||||
capitalized for a period less than one year | |||||||||||||
Capitalized exploratory well costs that have been | 8.9 | 16.7 | 8.1 | ||||||||||
capitalized for a period greater than one year | |||||||||||||
Total | 8.9 | 16.7 | 14 | ||||||||||
Number of exploratory wells that have been | 1 | 2 | 1 | ||||||||||
capitalized for a period greater than one year | |||||||||||||
In the second and third quarters of 2010, the Company drilled the Southeast Etame No. 1 well with two sidetracks in the Etame Marin block offshore Gabon. The well discovered five meters of oil-sand. Additional evaluation of the well and sidetrack information was conducted to facilitate options for developing the discovery. The Company and its joint venture partners evaluated the merits of two development options. One option involved a subsea well to develop the Southeast Etame discovery only, whereas the second option envisioned a platform development to access both the Southeast Etame area as well as the North Tchibala field, where a discovery was made on the block prior to VAALCO’s block participation. In the second quarter of 2012, the Company and its partners agreed to proceed with the development plan featuring a fixed leg platform for developing the Southeast Etame discovery area and the North Tchibala field and the final investment decision was approved in the fourth quarter of 2012 for the construction of the platform. The platform was completed and installed in the third quarter of 2014. A drilling rig has been contracted to drill a development well in the Southeast Etame field in the first half of 2015. Due to the recent fall in oil prices, the Company recognized an impairment loss in the Southeast Etame field in the fourth quarter of 2014. The impairment resulted in a $7.8 million write off related to the Southeast Etame No.1 well. Accordingly, the well has been removed from the above schedule for 2014. | |||||||||||||
In the third and fourth quarters of 2012, the Company drilled the N’Gongui No. 2 well with three sidetracks in the Mutamba Iroru block onshore Gabon. Evaluation of the well and sidetrack information was performed in the second quarter of 2013. A revised production sharing contract (“PSC”) including exploration rights is in the approval process. The term sheet, which specifies financial and other obligations to be included in the PSC, was agreed to and signed by the Company, its joint venture partner, and the Government of Gabon on July 31, 2014. The form of the PSC has been completed and presented to the Company and its joint venture partner for execution. The joint venture partner has withheld its approval of the new PSC pending resolution of certain legal aspects of the new agreement with the Government of Gabon. In March 2015, the joint venture partner indicated to the Company that the legal aspects have not yet been resolved to their satisfaction. The Company can provide no assurance as to the joint venture partner approving the PSC. The Company remains committed to this block and further meetings of the parties are expected to occur in the first half of 2015. | |||||||||||||
After the PSC is approved, an application for a development area will be made by the Company. After issuance of a development area, the next step is the submittal of the plan of development. The Company can provide no assurances as to the either the approval of the PSC by the Government of Gabon, or the subsequent approval of a development area by the Government of Gabon. The Company has capitalized $8.9 million for the discovery well in accordance with the criteria contained in ASC Topic 932. | |||||||||||||
Employee_Benefit_Plans
Employee Benefit Plans | 12 Months Ended | |
Dec. 31, 2014 | ||
Text Block [Abstract] | ||
Employee Benefit Plans | 10 | EMPLOYEE BENEFIT PLANS |
The Company sponsors a 401(k) plan, with a Company match feature, for its employees. Costs incurred in 2014, 2013 and 2012 for administering the plan, including the Company match feature, were approximately $464,000, $182,500 and $204,000, respectively. | ||
Asset_Retirement_Obligations
Asset Retirement Obligations | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Asset Retirement Obligation Disclosure [Abstract] | |||||||||||||
Asset Retirement Obligations | 11 | ASSET RETIREMENT OBLIGATIONS | |||||||||||
The fair value of a liability for an asset retirement obligation is recognized in the period in which it is incurred by capitalizing it as part of the carrying amount of the long-lived assets. The Company records asset retirement obligations for the future abandonment costs of tangible assets such as platforms, wells, pipelines and other facilities. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. | |||||||||||||
A summary of the recording of the estimated fair value of the Company’s asset retirement obligations is presented as follows: | |||||||||||||
(In Thousands) | Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | |||||||||||
Balances at January 1, | $ | 11,464 | $ | 10,368 | $ | 14,528 | |||||||
Accretion Expense | 720 | 643 | 814 | ||||||||||
Additions | 2,526 | 453 | 770 | ||||||||||
Revisions | 136 | - | (5,744 | ) | |||||||||
Balance December 31, | $ | 14,846 | $ | 11,464 | $ | 10,368 | |||||||
During the year ended December 31, 2014, the Company increased the asset retirement obligations to recognize the abandonment liability for two new platforms and two wells offshore Gabon. In the year ended December 31, 2013, the Company increased the asset retirement obligations to recognize the abandonment liability for two wells offshore Gabon. The 2012 cost revision of $5.7 million was primarily due to changes in asset retirement cost estimates on the Etame block offshore Gabon. | |||||||||||||
The Company does not plan to abandon any material assets over the next five years. |
Segment_Information
Segment Information | 12 Months Ended | ||||||||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||||||||
Segment Reporting [Abstract] | |||||||||||||||||||||||||
Segment Information | 12 | SEGMENT INFORMATION | |||||||||||||||||||||||
The Company’s operations are based in Gabon, Angola, Equatorial Guinea and the United States. The chief operating decision maker, the CEO and management review and evaluates the operation of each geographic segment separately. The operations of all segments include exploration for and production of hydrocarbons where commercial reserves have been found and developed. The accounting policies of the reportable segments are the same as in Note 2. Revenues are based on the location of hydrocarbon production. The Company evaluates each segment based on income (loss) from operations. Segment activity for the years ended December 31, 2014, 2013 and 2012 are as follows: (in thousands) | |||||||||||||||||||||||||
2014 | Gabon | Angola | Equatorial | USA | Corporate | Total | |||||||||||||||||||
Guinea | and Other | ||||||||||||||||||||||||
Revenues | $ | 126,322 | $ | - | $ | - | $ | 1,369 | $ | - | $ | 127,691 | |||||||||||||
Depreciation, depletion and amortization | 19,079 | 12 | - | 901 | 94 | 20,086 | |||||||||||||||||||
Operating income (loss) | (42,105 | ) | (3,798 | ) | (1,525 | ) | (119 | ) | (6,859 | ) | (54,406 | ) | |||||||||||||
Interest income | 42 | - | - | - | 33 | 75 | |||||||||||||||||||
Income taxes | 22,486 | - | - | - | - | 22,486 | |||||||||||||||||||
Bad debt and other expenses | 2,400 | - | - | - | - | 2,400 | |||||||||||||||||||
Impairment of proved properties | 98,341 | - | - | - | - | 98,341 | |||||||||||||||||||
Additions to properties and equipment | 83,170 | 3,117 | - | 8 | 816 | 87,111 | |||||||||||||||||||
Long lived assets | 76,247 | 14,645 | 10,000 | 6,359 | 873 | 108,124 | |||||||||||||||||||
Total assets | 192,957 | 22,305 | 10,197 | 6,611 | 16,779 | 248,849 | |||||||||||||||||||
2013 | Gabon | Angola | Equatorial | USA | Corporate | Total | |||||||||||||||||||
Guinea | and Other | ||||||||||||||||||||||||
Revenues | $ | 167,386 | $ | - | $ | - | $ | 1,891 | $ | - | $ | 169,277 | |||||||||||||
Depreciation, depletion and amortization | 15,310 | 28 | - | 1,528 | 63 | 16,929 | |||||||||||||||||||
Operating income (loss) | 98,795 | (3,018 | ) | (768 | ) | (11,869 | ) | (5,915 | ) | 77,225 | |||||||||||||||
Interest income | 40 | - | - | - | 33 | 73 | |||||||||||||||||||
Income taxes | 34,115 | - | - | - | - | 34,115 | |||||||||||||||||||
Bad debt and other expenses | 1,764 | 1,562 | - | - | - | 3,326 | |||||||||||||||||||
Additions to properties and equipment | 53,015 | 629 | - | - | 47 | 53,691 | |||||||||||||||||||
Long lived assets | 109,597 | 11,540 | 10,000 | 7,235 | 152 | 138,524 | |||||||||||||||||||
Total assets | 256,033 | 12,204 | 10,059 | 9,660 | 20,211 | 308,167 | |||||||||||||||||||
2012 | Gabon | Angola | Equatorial | USA | Corporate | Total | |||||||||||||||||||
Guinea | and Other | ||||||||||||||||||||||||
Revenues | $ | 192,489 | $ | - | $ | - | $ | 2,798 | $ | - | $ | 195,287 | |||||||||||||
Depreciation, depletion and amortization | 15,954 | 28 | - | 3,872 | 59 | 19,913 | |||||||||||||||||||
Operating income (loss) | 147,985 | (3,293 | ) | (754 | ) | (48,940 | ) | (8,405 | ) | 86,593 | |||||||||||||||
Interest income | 60 | (1 | ) | - | - | 86 | 145 | ||||||||||||||||||
Income taxes | 81,813 | - | - | - | - | 81,813 | |||||||||||||||||||
Bad debt and expenses | - | 1,621 | - | - | - | 1,621 | |||||||||||||||||||
Impairment of proved properties | - | - | - | 7,620 | - | 7,620 | |||||||||||||||||||
Additions to properties and equipment | 22,731 | - | 10,000 | 13,558 | 77 | 46,366 | |||||||||||||||||||
Long lived assets | 71,225 | 10,938 | 10,000 | 14,279 | 166 | 106,608 | |||||||||||||||||||
Total assets | 190,652 | 11,405 | 10,000 | 17,314 | 38,585 | 267,956 | |||||||||||||||||||
Information about our most significant customers | |||||||||||||||||||||||||
In Gabon, starting in the second quarter of 2014, the Company switched to an agency model to sell its crude oil. The Company contracted with a third party in order to sell, based on a fixed barrel fee, on the spot market. Prior to the second quarter in 2014, the Company sold oil under contracts with Mercuria Trading NV (“Mercuria”) beginning with the calendar year 2011. For the first quarter of 2015, the Company will also sell its oil under the agency model on the spot market. | |||||||||||||||||||||||||
Impairment_of_Proved_Propertie
Impairment of Proved Properties | 12 Months Ended | |
Dec. 31, 2014 | ||
Goodwill And Intangible Assets Disclosure [Abstract] | ||
Impairment of Proved Properties | 13 | IMPAIRMENT OF PROVED PROPERTIES |
The Company reviews its oil and gas producing properties for impairment whenever events or changes in circumstances indicate that the carrying amount of such properties may not be recoverable. When it is determined that an oil and gas property’s estimated future net cash flows will not be sufficient to recover its carrying amount, an impairment charge is recorded to reduce the carrying amount of the asset to its estimated fair value. | ||
Accordingly, impairment testing was performed using the year end 2014 independently prepared reserve report and forward price curves. The Company performed a recoverability test as defined under ASC 932 and ASC 360, noting that the undiscounted cash flows related to the Etame, Ebouri and Southeast Etame/North Tchibala fields were less than the book values for these fields resulting in the Company recording an impairment loss of $98.3 million to write down its investment in the Etame Marine Block, offshore Gabon to its fair value. Impairment of $38.5 was recorded in the Etame field, $5.9 million in the Ebouri field and $53.9 million in the Southeast Etame/North Tchibala field. The impairment is a result of the recent decline in the forecasted oil prices used in the impairment testing and calculation. | ||
The measurement of these assets at fair value is calculated using discounted cash flow techniques and based on estimates of future revenues and costs associated with Ebouri field. Significant Level 3 assumptions associated with the calculation of discounted cash flows used in the impairment analysis include the Company’s estimate of future crude oil and natural gas prices, production costs, and anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data. For crude oil, estimates were based on NYMEX Brent Ice Intermediate prices, adjusted for quality, transportation fees, and market differential. | ||
The Company determined no impairment charge was necessary 2013. | ||
In 2012, the Company recorded an impairment loss of $7.6 million in the United States to write down the value of its Hefley field in the Granite Wash formation to its estimated fair value. The initial measurement of these assets at fair value is calculated using discounted cash flow techniques and based on estimates of future revenues and costs associated with the Granite Wash formation well. Significant Level 3 assumptions associated with the calculation of discounted cash flows used in the impairment analysis include the Company’s estimate of future crude oil and natural gas prices, production costs, development expenditures, and anticipated production of proved and probable reserves, appropriate risk-adjusted discount rates and other relevant data. For crude oil, estimates were based on NYMEX West Texas Intermediate prices, adjusted for quality, transportation fees, and a regional price differential. For natural gas, estimates were based on NYMEX Henry Hub prices, adjusted for energy content, transportation fees, and a regional price differential. |
Quarterly_Financial_Informatio
Quarterly Financial Information (Unaudited) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||
Quarterly Financial Information Disclosure [Abstract] | |||||||||||||||||
Quarterly Financial Information (Unaudited) | 14 | QUARTERLY FINANCIAL INFORMATION (UNAUDITED) | |||||||||||||||
The following represents our unaudited quarterly results for years ended December 31, 2014 and 2013. The quarterly results were prepared in accordance with accounting principles generally accepted in the United States of America, and reflect all adjustments that are, in the opinion of management, necessary for a fair statement of the results. These adjustments are of a normal recurring nature. | |||||||||||||||||
(In thousands of dollars except per share information) | 1st Quarter | 2nd Quarter | 3rd Quarter | 4th Quarter | |||||||||||||
2014 | |||||||||||||||||
Total revenues (1) | $ | 28,071 | $ | 52,098 | $ | 24,486 | $ | 23,037 | |||||||||
Total operating costs and expenses | 28,721 | 18,270 | 17,799 | 117,308 | |||||||||||||
Operating income (loss) | (650 | ) | 33,828 | 6,687 | (94,270 | ) | |||||||||||
Net income (loss) | (7,038 | ) | 24,712 | 3,109 | (98,332 | ) | |||||||||||
Basic net income (loss) per share | $ | (0.12 | ) | $ | 0.43 | $ | 0.05 | $ | (1.70 | ) | |||||||
Diluted net income (loss) per share | $ | (0.12 | ) | $ | 0.43 | $ | 0.05 | $ | (1.70 | ) | |||||||
(In thousands of dollars except per share information) | 1st Quarter | 2nd Quarter | 3rd Quarter | 4th Quarter | |||||||||||||
2013 | |||||||||||||||||
Total revenues (1) | $ | 44,137 | $ | 29,118 | $ | 37,740 | $ | 58,282 | |||||||||
Total operating costs and expenses | 22,634 | 17,452 | 29,636 | 22,331 | |||||||||||||
Operating income | 21,503 | 11,666 | 8,104 | 35,951 | |||||||||||||
Net income | 7,188 | 7,121 | 2,386 | 26,377 | |||||||||||||
Basic net income per share | $ | 0.12 | $ | 0.12 | $ | 0.04 | $ | 0.46 | |||||||||
Diluted net income per share | $ | 0.12 | $ | 0.12 | $ | 0.04 | $ | 0.46 | |||||||||
-1 | Gabon crude oil sales are a function of the number and size of crude oil liftings in each quarter from the floating production, storage and offloading (“FPSO”) facility. | ||||||||||||||||
Quarterly income per share is based on the weighted average number of shares outstanding during the quarter. Because of changes in the number of shares outstanding during the quarters due to the exercise of stock options and issuance of common stock, the sum of quarterly earnings per share may not equal earnings per share for the year. |
Supplemental_Information_on_Oi
Supplemental Information on Oil and Gas Producing Activities | 12 Months Ended | ||||||||||||||||||||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||||||||||||||||||||
Extractive Industries [Abstract] | |||||||||||||||||||||||||||||||||||||
Supplemental Information on Oil and Gas Producing Activities | 15 | 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 | ||||||||||||||||||||||||||||||||||||
2014 | 2013 | 2012 | |||||||||||||||||||||||||||||||||||
Costs incurred during the year: | |||||||||||||||||||||||||||||||||||||
Exploration - capitalized | $ | - | $ | - | $ | 2,602 | |||||||||||||||||||||||||||||||
Exploration - expensed | - | 11,497 | 38,159 | ||||||||||||||||||||||||||||||||||
Acquisition | - | - | 1,630 | ||||||||||||||||||||||||||||||||||
Development | 8 | 113 | 9,689 | ||||||||||||||||||||||||||||||||||
Total | $ | 8 | $ | 11,610 | $ | 52,080 | |||||||||||||||||||||||||||||||
(In thousands) | International | ||||||||||||||||||||||||||||||||||||
2014 | 2013 | 2012 | |||||||||||||||||||||||||||||||||||
Costs incurred during the year: | |||||||||||||||||||||||||||||||||||||
Exploration - capitalized | $ | - | $ | 2,942 | $ | 5,916 | |||||||||||||||||||||||||||||||
Exploration - expensed | 15,358 | 12,431 | 2,878 | ||||||||||||||||||||||||||||||||||
Acquisition | - | - | 10,000 | ||||||||||||||||||||||||||||||||||
Development | 79,722 | 54,420 | 4,022 | ||||||||||||||||||||||||||||||||||
Total | $ | 95,080 | $ | 69,793 | $ | 22,816 | |||||||||||||||||||||||||||||||
Exploration expense includes $13.3 million, $23.9 million and $37.3 million for dry hole expense in 2014, 2013 and 2012, respectively. The dry hole expense for 2014 was attributable to one unsuccessful exploration well spudded in the fourth quarter of 2013 and determined to be a dry hole in the first quarter of 2014 in Gabon for $11.7 million and $1.6 million in leasehold costs related to the expiration of the exploration license offshore 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, | |||||||||||||||||||||||||||||||||||||
2014 | 2013 | 2012 | |||||||||||||||||||||||||||||||||||
Capitalized costs - | |||||||||||||||||||||||||||||||||||||
Properties not being amortized | $ | 47,290 | $ | 88,194 | $ | 66,794 | |||||||||||||||||||||||||||||||
Properties being amortized (1) | 347,186 | 222,032 | 195,329 | ||||||||||||||||||||||||||||||||||
Total capitalized costs | $ | 394,476 | $ | 310,226 | $ | 262,123 | |||||||||||||||||||||||||||||||
Less accumulated depreciation, depletion, and | (289,272 | ) | (171,854 | ) | (155,681 | ) | |||||||||||||||||||||||||||||||
amortization | |||||||||||||||||||||||||||||||||||||
Net capitalized costs | $ | 105,204 | $ | 138,372 | $ | 106,442 | |||||||||||||||||||||||||||||||
-1 | Includes $5.2 million, $5.2 million, and $4.7 million asset retirement cost in 2014, 2013, and 2012, 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 | ||||||||||||||||||||||||||||||||||||
2014 | 2013 | 2012 | 2014 | 2013 | 2012 | ||||||||||||||||||||||||||||||||
Gabon | Gabon | Gabon | |||||||||||||||||||||||||||||||||||
Crude oil and gas sales | $ | 1,369 | $ | 1,891 | $ | 2,798 | $ | 126,322 | $ | 167,386 | $ | 192,489 | |||||||||||||||||||||||||
Production, G&A and other expense | (467 | ) | (12,232 | ) | (47,866 | ) | (150,602 | ) | (52,776 | ) | (27,425 | ) | |||||||||||||||||||||||||
Depreciation, depletion and amortization | (901 | ) | (1,528 | ) | (3,872 | ) | (19,079 | ) | (15,302 | ) | (15,954 | ) | |||||||||||||||||||||||||
Income tax | - | - | - | (22,486 | ) | (34,115 | ) | (81,813 | ) | ||||||||||||||||||||||||||||
Results from oil and gas producing activities | $ | 1 | $ | (11,869 | ) | $ | (48,940 | ) | $ | (65,845 | ) | $ | 65,193 | $ | 67,297 | ||||||||||||||||||||||
Proved Reserves | |||||||||||||||||||||||||||||||||||||
Reserve reports as of December 31, 2014, 2013, and 2012 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, 2014, 2013 and 2012, and the changes during such periods. | |||||||||||||||||||||||||||||||||||||
Proved Reserves: | Oil (MBbls) | Gas (MMCF) | |||||||||||||||||||||||||||||||||||
Balance at January 1, 2012 | 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 | |||||||||||||||||||||||||||||||||||
Production | (1,351 | ) | (227 | ) | |||||||||||||||||||||||||||||||||
Revisions of previous estimates | 2,312 | 300 | |||||||||||||||||||||||||||||||||||
Extensions and discoveries | 67 | - | |||||||||||||||||||||||||||||||||||
Balance at December 31, 2014 | 8,260 | 1,406 | |||||||||||||||||||||||||||||||||||
Proved Developed Reserves | Oil (MBbls) | Gas (MMCF) | |||||||||||||||||||||||||||||||||||
Balance at January 1, 2012 | 3,854 | 856 | |||||||||||||||||||||||||||||||||||
Balance at December 31, 2012 | 3,750 | 1,544 | |||||||||||||||||||||||||||||||||||
Balance at December 31, 2013 | 3,305 | 1,333 | |||||||||||||||||||||||||||||||||||
Balance at December 31, 2014 | 3,224 | 1,406 | |||||||||||||||||||||||||||||||||||
The Company’s proved developed reserves are located offshore Gabon and in Alabama, Texas and waters of the Gulf of Mexico. Revisions in 2014 were primarily due to better reservoir performance at the Avouma/South Tchibala field (1,500 MBbls) and a combination of better reservoir performance from existing wells at Etame, and revisions to proved undeveloped reserves at Etame (1,100 MBbls). Ebouri proved undeveloped reserves were revised downward (300 MBbls) due to higher costs of developing the reserves rendering them uneconomic. Revisions in 2013 were primarily due to better reservoir performance at the Etame field (800 MBbls). In 2012, the revisions were due to improved reservoir performance at the Avouma/South Tchibala field (1,200 MBbls) and improved reservoir performance at Etame (1,000 MBbls). In 2014, the extensions and discoveries were associated with the booking of the Southeast Etame/North Tchibala reserves. Extensions and discovery reserve additions in 2013 were due to the drilling of the Avouma 3H well which extended the reservoir boundary further to the north at the Avouma field. In 2012, the extensions and discoveries were associated with the booking of the Southeast Etame/North Tchibala reserves following approval of the development plans for these fields and final investment decision to install the platforms necessary to develop these fields. | |||||||||||||||||||||||||||||||||||||
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, | |||||||||||||||||||||||||||||||||||
2014 | 2013 | 2012 | 2014 | 2013 | 2012 | 2014 | 2013 | 2012 | |||||||||||||||||||||||||||||
Future cash inflows | $ | 9,598 | $ | 8,276 | $ | 8,260 | $ | 814,059 | $ | 725,485 | $ | 776,646 | $ | 823,657 | $ | 733,761 | $ | 784,906 | |||||||||||||||||||
Future production costs | (1,475 | ) | (3,038 | ) | (3,194 | ) | (307,331 | ) | (223,643 | ) | (203,490 | ) | $ | (308,806 | ) | (226,681 | ) | (206,684 | ) | ||||||||||||||||||
Future development costs | - | - | - | (136,137 | ) | (164,142 | ) | (186,982 | ) | (136,137 | ) | (164,142 | ) | (186,982 | ) | ||||||||||||||||||||||
Future income tax expense | (359 | ) | (825 | ) | (807 | ) | (177,924 | ) | (154,519 | ) | (181,194 | ) | $ | (178,283 | ) | (155,344 | ) | (182,001 | ) | ||||||||||||||||||
Future net cash flows | $ | 7,764 | $ | 4,413 | $ | 4,259 | $ | 192,667 | $ | 183,181 | $ | 204,980 | $ | 200,431 | $ | 187,594 | $ | 209,239 | |||||||||||||||||||
Discount to present value at 10% annual rate | (3,516 | ) | (1,299 | ) | (1,028 | ) | (47,528 | ) | (48,859 | ) | (55,309 | ) | $ | (51,044 | ) | (50,158 | ) | (56,337 | ) | ||||||||||||||||||
Standardized measure of discounted future | $ | 4,248 | $ | 3,114 | $ | 3,231 | $ | 145,139 | $ | 134,322 | $ | 149,671 | $ | 149,387 | $ | 137,436 | $ | 152,902 | |||||||||||||||||||
net cash flows | |||||||||||||||||||||||||||||||||||||
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 (including other expenses treated as taxes), and domestic income taxes represent amounts payable for severance and ad-valorem 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, | ||||||||||||||||||||||||||||||||||||
2014 | 2013 | 2012 | |||||||||||||||||||||||||||||||||||
Balance at Beginning of Period | $ | 137,436 | $ | 152,902 | $ | 166,187 | |||||||||||||||||||||||||||||||
Sales of oil and gas, net of production costs | (95,973 | ) | (132,662 | ) | (168,563 | ) | |||||||||||||||||||||||||||||||
Net changes in prices and production costs | (28,098 | ) | (52,056 | ) | (11,223 | ) | |||||||||||||||||||||||||||||||
Revisions of previous quantity estimates | 74,497 | 43,815 | 155,111 | ||||||||||||||||||||||||||||||||||
Additions | 2,188 | 29,620 | 69,092 | ||||||||||||||||||||||||||||||||||
Changes in estimated future development costs | 31,686 | (5,345 | ) | (67,834 | ) | ||||||||||||||||||||||||||||||||
Development costs incurred during the period | - | 44,389 | 34,944 | ||||||||||||||||||||||||||||||||||
Accretion of discount | 24,163 | 15,290 | 16,619 | ||||||||||||||||||||||||||||||||||
Net change of income taxes | (15,609 | ) | 26,120 | 7,445 | |||||||||||||||||||||||||||||||||
Change in production rates (timing) and other | 19,097 | 15,363 | (48,876 | ) | |||||||||||||||||||||||||||||||||
Balance at End of Period | $ | 149,387 | $ | 137,436 | $ | 152,902 | |||||||||||||||||||||||||||||||
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the Company. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of oil and gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and gas sales prices may all differ from those assumed in these estimates. The standardized measure of discounted future net cash flow should not be construed as the current market value of the estimated oil and natural gas reserves attributable to the Company’s properties. The information set forth in the foregoing tables includes revisions for certain reserve estimates attributable to proved properties included in the preceding year’s estimates. Such revisions are the result of additional information from subsequent completions and production history from the properties involved or the result of a decrease (or increase) in the projected economic life of such properties resulting from changes in product prices. Moreover, crude oil amounts shown for Gabon are recoverable under a service contract and the reserves in place remain the property of the Gabon government. | |||||||||||||||||||||||||||||||||||||
In accordance with the guidelines of the Securities and Exchange Commission, the Company’s estimates of future net cash flow from the Company’s properties and the present value thereof are made using oil and gas contract prices using a twelve month average of beginning of month prices and are held constant throughout the life of the properties except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. In Gabon, the weighted average price was $98.88 per Bbl. In the United States, the weighted average price was $86.49 per Bbl of oil and $5.19 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 13% royalty so long as there are amounts remaining in the Cost Account. At December 31, 2014, there was $36.8 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. 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 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. In 2014, the Company cost recovered 907,400 barrels out of a theoretical 935,800 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/South Tchibala, and Ebouri fields. The Etame development area has a term of 20 years and will expire in 2021 which coincidentally matches the economic life of the Etame reserves under the current reserve report prepared by our independent reserves engineering firm. The Avouma/South Tchibala 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 expired 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, 2014 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. 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, 2014, 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 20 years. At December 31, 2014, 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 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 25 years. At December 31, 2014, the Company has no proved reserves related to Block P in Equatorial Guinea. |
SCHEDULE_I_PARENT_COMPANY_FINA
SCHEDULE I - PARENT COMPANY FINANCIAL STATEMENTS | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Condensed Financial Information Of Parent Company Only Disclosure [Abstract] | |||||||||||||
SCHEDULE I - PARENT COMPANY FINANCIAL STATEMENTS | SCHEDULE I — PARENT COMPANY FINANCIAL STATEMENTS | ||||||||||||
VAALCO ENERGY, INC. | |||||||||||||
CONSOLIDATED BALANCE SHEETS | |||||||||||||
(in thousands of dollars, except number of shares and par value amounts) | |||||||||||||
December 31, | December 31, | ||||||||||||
2014 | 2013 | ||||||||||||
ASSETS | |||||||||||||
Current assets: | |||||||||||||
Cash and cash equivalents | $ | 3,780 | $ | 8,605 | |||||||||
Restricted cash | - | 10,000 | |||||||||||
Receivables: | |||||||||||||
Other | 264 | 7 | |||||||||||
Prepayments and other | 505 | 89 | |||||||||||
Total current assets | 4,549 | 18,701 | |||||||||||
Property and equipment - successful efforts method: | |||||||||||||
Equipment and other | 1,316 | 500 | |||||||||||
1,316 | 500 | ||||||||||||
Accumulated depreciation, depletion and amortization | (442 | ) | (348 | ) | |||||||||
Net property and equipment | 874 | 152 | |||||||||||
Other assets: | |||||||||||||
Restricted cash | 10,000 | - | |||||||||||
Deferred tax asset | 1,349 | 1,349 | |||||||||||
Investment in Subsidiaries | 166,232 | 233,061 | |||||||||||
Total Assets | $ | 183,004 | $ | 253,263 | |||||||||
LIABILITIES AND EQUITY | |||||||||||||
Current liabilities: | |||||||||||||
Accounts payable and accrued liabilities | 2,541 | 2,389 | |||||||||||
Total current liabilities | $ | 2,541 | $ | 2,389 | |||||||||
Long term debt | - | - | |||||||||||
Total liabilities | 2,541 | 2,389 | |||||||||||
Minority Interest | |||||||||||||
VAALCO Energy Inc. shareholders’ equity: | |||||||||||||
Common stock, $0.10 par value, 100,000,000 authorized shares, 65,194,828 and | 6,519 | 6,408 | |||||||||||
64,012,914 shares issued with 7,393,714 and 7,162,573 shares in treasury at | |||||||||||||
Dec. 31, 2014 and 2013, respectively | |||||||||||||
Additional paid-in capital | 64,351 | 55,455 | |||||||||||
Retained earnings | 146,892 | 224,442 | |||||||||||
Less treasury stock, at cost | (37,299 | ) | (35,431 | ) | |||||||||
Total Equity | 180,463 | 250,874 | |||||||||||
Total Liabililities and Equity | $ | 183,004 | $ | 253,263 | |||||||||
VAALCO ENERGY, INC. | |||||||||||||
STATEMENTS OF CONSOLIDATED OPERATIONS | |||||||||||||
(in thousands of dollars, except per share amounts) | |||||||||||||
Year Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
Revenues: | |||||||||||||
Oil and gas sales | $ | - | $ | - | $ | - | |||||||
Operating costs and expenses: | |||||||||||||
Depreciation, depletion and amortization | 94 | 63 | 59 | ||||||||||
General and administrative expense | 6,740 | 5,750 | 8,065 | ||||||||||
Total operating costs and expenses | 6,834 | 5,813 | 8,124 | ||||||||||
Operating income (loss) | (6,834 | ) | (5,813 | ) | (8,124 | ) | |||||||
Other income (expense): | |||||||||||||
Interest income | 33 | 33 | 86 | ||||||||||
Other, net | 450 | - | - | ||||||||||
Equity in subsidiary earnings | (71,199 | ) | 48,852 | 13,377 | |||||||||
Total other income (expense) | (70,716 | ) | 48,885 | 13,463 | |||||||||
Income (loss) before income taxes | (77,550 | ) | 43,072 | 5,339 | |||||||||
Income tax expense | - | - | - | ||||||||||
Net income (loss) | (77,550 | ) | 43,072 | 5,339 | |||||||||
Less net income (loss) attributable to noncontrolling interest | - | - | (4,708 | ) | |||||||||
Net income (loss) attributable to VAALCO Energy, Inc. | $ | (77,550 | ) | $ | 43,072 | $ | 631 | ||||||
VAALCO ENERGY, INC. | |||||||||||||
STATEMENTS OF CONSOLIDATED CASH FLOWS | |||||||||||||
(in thousands of dollars) | |||||||||||||
Year Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
CASH FLOWS FROM OPERATING ACTIVITIES | |||||||||||||
Net income (loss) | $ | (77,550 | ) | $ | 43,072 | $ | 5,339 | ||||||
Adjustments to reconcile net income to net cash provided by operating activities | |||||||||||||
Depreciation, depletion and amortization | 94 | 63 | 59 | ||||||||||
Stock based compensation | 3,322 | 3,005 | 2,406 | ||||||||||
Equity in (earnings) loss from subsidiaries | 71,199 | (48,852 | ) | (13,377 | ) | ||||||||
Change in operating assets and liabilities: | |||||||||||||
Other receivables | (257 | ) | 180 | 27 | |||||||||
Prepayments and other | (416 | ) | (16 | ) | 14 | ||||||||
Accounts payable and other liabilities | 153 | 371 | (2,710 | ) | |||||||||
Net cash (used in) operating activities | (3,455 | ) | (2,177 | ) | (8,242 | ) | |||||||
CASH FLOWS FROM INVESTING ACTIVITIES | |||||||||||||
Investment in subsidiaries | (4,371 | ) | (8,245 | ) | - | ||||||||
Return of investment in subsidiaries | - | - | 19,307 | ||||||||||
Decrease/(increase) in restricted cash | - | - | (10,000 | ) | |||||||||
Property and equipment expenditures | (816 | ) | (47 | ) | (77 | ) | |||||||
Net cash (used in) investing activities | (5,187 | ) | (8,292 | ) | 9,230 | ||||||||
CASH FLOWS FROM FINANCING ACTIVITIES | |||||||||||||
Proceeds from the issuance of common stock | 5,685 | 3,729 | 3,335 | ||||||||||
Purchase of treasury stock | (1,868 | ) | (11,456 | ) | - | ||||||||
Distribution to noncontrolling interest | - | - | (5,595 | ) | |||||||||
Acquisition of noncontrolling interest | - | - | (26,200 | ) | |||||||||
Net cash provided by (used in) financing activities | 3,817 | (7,727 | ) | (28,460 | ) | ||||||||
NET CHANGE IN CASH AND CASH EQUIVALENTS | (4,825 | ) | (18,196 | ) | (27,472 | ) | |||||||
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD | 8,605 | 26,801 | 54,273 | ||||||||||
CASH AND CASH EQUIVALENTS AT END OF PERIOD | $ | 3,780 | $ | 8,605 | $ | 26,801 | |||||||
Note 1- The financial statements of VAALCO Energy, Inc (the “Registrant” or “Parent Company”) have been prepared pursuant to Rule 5-04 of Regulation S-X of the Securities Exchange Act of 1934, as amended, because certain of VAALCO’s subsidiaries are contractually prohibited from making payments, loans or transferring assets to the Parent Company or other affiliated entities. Specifically, under the terms of our IFC credit facility, VAALCO Etame (Gabon), Inc. could be restricted from transferring assets or making dividends, if the positive and negative covenants are not in compliance with the credit facility. The restricted net assets associated with each of these entities exceed 25% of the consolidated net assets of VAALCO Energy, Inc. as of December 31, 2014. | |||||||||||||
For purposes of these financial statements, the Parent Company’s investments in wholly owned subsidiaries are accounted for under the equity method. Under this method, the accounts of the subsidiaries are not consolidated. The investments in and advances to subsidiaries are recorded in the unconsolidated balance sheets. The income (loss) from operations of subsidiaries is reported on an equity basis as equity in subsidiary earnings, net of tax, in the unconsolidated statements of operations of registrant. These statements should be read in conjunction with the consolidated financial statements and notes thereto, included in Part II, Item 8 of in this Annual Report on Form 10-K. |
Summary_of_Significant_Account1
Summary of Significant Accounting Policies (Policies) | 12 Months Ended | ||
Dec. 31, 2014 | |||
Accounting Policies [Abstract] | |||
Principles of Consolidation | Principles of Consolidation - The accompanying consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. The portion of the income and net assets applicable to the non-controlling interest in the majority-owned operations of the Company’s Gabon subsidiary has been reflected as noncontrolling interest. All intercompany transactions within the consolidated group have been eliminated in consolidation. | ||
In December 2012, the Company acquired the noncontrolling interest in VAALCO International, Inc., for $26.2 million, with an effective date of October 1, 2012. Prior to the acquisition, the noncontrolling interest owned 9.99% of the issued and outstanding common stock of VAALCO International, Inc., a Delaware corporation of which VAALCO Gabon Etame, Inc. is the wholly owned subsidiary. | |||
Cash and Cash Equivalents | Cash and Cash Equivalents – Cash and cash equivalent includes deposits and funds invested in highly liquid instruments with original maturities of three months or less at the date of purchase. | ||
Restricted Cash | Restricted Cash – Restricted cash includes cash that is contractually restricted. Restricted cash is classified as a current or non-current asset based on its designated purpose and time duration. Current amounts at December 31, 2014 each include an escrow amount representing the Company’s bank guarantees for customs clearance in Gabon ($1.6 million).Long term amounts at December 31, 2014 and 2013 each include the Company’s charter payment escrow for the Floating Production Storage and Offloading tanker (“FPSO”) in Gabon ($0.8 million) and funds restricted to secure the Company’s drilling obligation in Block 5 in Angola under the original production sharing contract ($10.0 million) and an increase of $10.0 million related to the Subsequent Exploration Phase (“SEP”) entered into in October 2014 which included two additional well obligations. | ||
The Company invests restricted and excess cash in certificates of deposit and commercial paper issued by banks with maturities typically not exceeding 90 days. | |||
Inventory | Inventory - Materials and supplies are valued at the lower of cost, determined by the weighted-average method, or market. Crude oil inventories are carried at the lower of cost or market and represent the Company’s share of crude oil produced and stored on the FPSO, but unsold. | ||
Income Taxes | Income Taxes – VAALCO accounts for income taxes under an asset and liability approach that recognizes deferred income tax assets and liabilities for the estimated future tax consequences of differences between the financial statements and tax bases of assets and liabilities. Valuation allowances are provided against deferred tax assets that are not likely to be realized. | ||
Property and Equipment | Property and Equipment - The Company follows the successful efforts method of accounting for exploration and development costs. Under this method, exploration costs, other than the cost of exploratory wells, are charged to expense as incurred. Exploratory well costs are initially capitalized until a determination as to whether proved reserves have been discovered. If an exploratory well is deemed to not have found proved reserves, the associated costs are expensed at that time. Other exploration costs, including geological and geophysical expenses applicable to undeveloped leasehold, leasehold expiration costs and delay rentals are expensed as incurred. All development costs, including developmental dry hole costs, are capitalized. | ||
The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred by capitalizing the corresponding cost as part of the carrying amount of the long-lived assets. | |||
The Company reviews its oil and gas properties for impairment whenever events or changes in circumstances indicate that the carrying amount of such properties may not be recoverable. When it is determined that an oil and gas property’s estimated future net cash flows will not be sufficient to recover its carrying amount, an impairment charge must be recorded to reduce the carrying amount of the asset to its estimated fair value. Provisions for impairment of undeveloped oil and gas leases are based on periodic evaluations and other factors. | |||
Depletion of wells, platforms, and other production facilities are calculated on a field basis under the unit-of-production method based upon estimates of proved developed producing reserves. Depletion of developed leasehold acquisition costs are provided on a field basis under the unit-of-production method based upon estimates of proved reserves. Undeveloped leasehold acquisition costs are not subject to depletion, but are subject to impairment testing. Provision for depreciation of other property is made primarily on a straight-line basis over the estimated useful life of the property. The annual rates of depreciation are as follows: | |||
Office and miscellaneous equipment: | 3 - 5 years | ||
Leasehold improvements: | 8 - 12 years | ||
Foreign Exchange Transactions | Foreign Exchange Transactions - For financial reporting purposes, the subsidiaries use the United States Dollar as their functional currency. Gains and losses on foreign currency transactions are included in income currently. The Company recognized loss on foreign currency transactions of $0.7 million in 2014. The Company recognized loss on foreign currency transactions of $0.1 million in 2013 and gains of $0.4 million in 2012, respectively. | ||
Capitalized Interest | Capitalized Interest - Interest costs from external borrowings are capitalized on major projects with an expected construction period of one year or longer. Capitalized interest is added to the cost of the underlying asset and is depleted on the unit-of-production method in the same manner as the underlying assets. | ||
Accounts with Partners | Accounts With Partners - Accounts with partners represent cash calls due or excess cash calls paid by the partners for exploration, development and production expenditures made by VAALCO Gabon (Etame), Inc. and VAALCO Angola (Kwanza), Inc., and VAALCO (USA), Inc. | ||
Bad Debt | Bad Debt – On a quarterly basis, the Company evaluates its accounts receivable balances to confirm collectability. Where collectability is in doubt, the Company records an allowance against the accounts receivable balance with a corresponding charge to net income as bad debt expense. The majority of the Company’s accounts receivable balances are with its joint venture partners and purchasers of its oil, natural gas and natural gas liquids and with the government of Gabon for reimbursements of Value-Added Tax (“VAT”) paid by the Company. Collection efforts, including remedies provided for in the contracts, are pursued to collect overdue amounts owed to the Company. Collection efforts, including remedies provided for in the contracts, are pursued to collect overdue amounts owed to the Company. | ||
Revenue Recognition | Revenue Recognition – In May 2014, the Financial Accounting Standards Board ("FASB") issued revised guidance on revenue from contracts with customers, Accounting Standards Update (ASU) No. 2014-09, Revenue from Contracts with Customers that will supersede most current revenue recognition guidance, including industry-specific guidance. The core principle of the revenue model is that an entity will recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The new standard provides a five-step analysis for transactions to determine when and how revenue is recognized. The guidance will be effective for us beginning January 1, 2017 and early adoption is not permitted. The guidance permits the use of either a full retrospective or a modified retrospective approach. We are evaluating the transition methods and the impact of the amended guidance on our financial position, results of operations and related disclosures. | ||
The Company recognizes revenues from crude oil and natural gas sales upon delivery to the buyer. Oil and gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and collectability of the revenue is reasonably assured. Revenue from the production of oil, natural gas and NGLs on properties in which we have joint ownership is recorded under the sales method. Under this method, we recognize revenues on the volumes sold based on the provisional sales prices. The volumes sold may be more or less than the volumes to which we are entitled based on our ownership interest in the property. These differences result in a condition known in the industry as a production imbalance. A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves on such property. As of December 31, 2014 and 2013, we had no oil and gas imbalances recorded in our consolidated financial statements. | |||
Stock Based Compensation | Stock Based Compensation - The Company measures the cost of employee services received in exchange for an award of equity instruments based on the fair value of the award on the date of the grant. Grant date fair value for options is estimated using an option-pricing model which is consistent with the terms of the award. For restricted stock, grant date fair value is determined using the grant date price of the company’s shares. Such cost is recognized over the period during which an employee is required to provide service in exchange for the award (which is usually the vesting period). The Company estimates the number of instruments that will ultimately be issued, rather than accounting for forfeitures as they occur. | ||
Fair Value of Financial Instruments | Fair Value of Financial Instruments - The Company’s financial instruments consist primarily of cash, restricted cash, trade receivables and trade payables and debt. The book values of cash, restricted cash, trade receivables, and trade payables are representative of their respective fair values due to the short-term maturity of these instruments. The book value of the Company’s debt instruments are considered to approximate the fair value, as the interest rates are adjusted based on rates currently in effect. | ||
Fair Value | Fair Value – Fair value is defined as the price that would be received to sell an asset or the price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Inputs used in determining fair value are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. The three input levels of the fair-value hierarchy are as follows: | ||
Level 1 – Inputs represent quoted prices in active markets for identical assets or liabilities (for example, exchange-traded commodity derivatives). | |||
Level 2 – Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs). | |||
Level 3 – Inputs that are not observable from objective sources, such as the Company’s internally developed assumptions used in pricing an asset or liability (for example, an estimate of future cash flows used in the Company’s internally developed present value of future cash flows model that underlies the fair-value measurement). | |||
Risks and Uncertainties | Risks and Uncertainties - The Company’s interests are located overseas in onshore and offshore Gabon, offshore in Angola and Equatorial Guinea, and domestically in Texas, Montana, Alabama, and the Gulf of Mexico. | ||
Substantially all of the Company’s oil and gas is sold at the well head at posted or indexed prices under short-term contracts, as is customary in the industry. | |||
In Gabon, starting in the second quarter of 2014, the Company switched to an agency model to sell its crude oil. The Company contracted with a third party in order to sell, based on a fixed barrel fee, on the spot market. Prior to the second quarter in 2014, the Company sold oil under contracts with Mercuria Trading NV (“Mercuria”) beginning with the calendar year 2011. For the first quarter of 2015, the Company will also sell its oil under the agency model on the spot market. | |||
Domestic operated production in Texas is sold via two contracts, one for oil and one for gas and natural gas liquids. The Company has access to several alternative buyers for oil, gas, and natural gas liquids domestically. | |||
Use of Estimates in Financial Statement Preparation | Use of Estimates in Financial Statement Preparation - The preparation of financial statements in conformity with generally accepted accounting principles requires estimates and assumptions that affect the reported amounts of assets and liabilities as well as certain disclosures. The Company’s consolidated financial statements include amounts that are based on management’s best estimates and judgments. Actual results could differ from those estimates. | ||
Estimates of oil and gas reserves used in the consolidated financial statements to estimate depletion expense and impairment charges require extensive judgments and are generally less precise than other estimates made in connection with financial disclosures. The Company considers its estimates to be reasonable; however, due to inherent uncertainties and the limited nature of data, estimates are imprecise and subject to change over time as additional information become available. | |||
Asset Retirement Obligations ("ARO") | Asset Retirement Obligations (“ARO”) - The Company has significant obligations to remove tangible equipment and restore land or seabed at the end of oil and gas production operations. The Company’s removal and restoration obligations are primarily associated with plugging and abandoning wells, removing and disposing of all or a portion of offshore oil and gas platforms, and capping pipelines. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety, and public relations considerations. | ||
ARO associated with retiring tangible long-lived assets is recognized as a liability in the period in which the legal obligation is incurred and becomes determinable. The liability is offset by a corresponding increase in the underlying asset. The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with The Company’s oil and gas properties. The Company utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. |
Capitalization_of_Exploratory_1
Summary of Significant Accounting Policies (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Accounting Policies [Abstract] | |||||||||||||
Estimated Useful Life of Property Plant and Equipment | |||||||||||||
Office and miscellaneous equipment: | 3 - 5 years | ||||||||||||
Leasehold improvements: | 8 - 12 years | ||||||||||||
Rollforward Analysis of the Allowance Against the Partner Accounts Receivable Balance | |||||||||||||
Description | Balance | Charged | Balance | ||||||||||
at | to Costs | at End | |||||||||||
Beginning | and | of | |||||||||||
of Period | Expenses | Period | |||||||||||
Allowance for Bad Debt | |||||||||||||
Year Ended December 31, 2014 | (7,631 | ) | (2,400 | ) | (10,031 | ) | |||||||
Year Ended December 31, 2013 | (6,069 | ) | (1,562 | ) | (7,631 | ) | |||||||
Summary_of_Significant_Account2
Summary of Significant Accounting Policies (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Accounting Policies [Abstract] | |||||||||||||
Estimated Useful Life of Property Plant and Equipment | |||||||||||||
Office and miscellaneous equipment: | 3 - 5 years | ||||||||||||
Leasehold improvements: | 8 - 12 years | ||||||||||||
Rollforward Analysis of the Allowance Against the Partner Accounts Receivable Balance | |||||||||||||
Description | Balance | Charged | Balance | ||||||||||
at | to Costs | at End | |||||||||||
Beginning | and | of | |||||||||||
of Period | Expenses | Period | |||||||||||
Allowance for Bad Debt | |||||||||||||
Year Ended December 31, 2014 | (7,631 | ) | (2,400 | ) | (10,031 | ) | |||||||
Year Ended December 31, 2013 | (6,069 | ) | (1,562 | ) | (7,631 | ) | |||||||
Stock_Based_Compensation_Table
Stock Based Compensation (Tables) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||||||||||||||||
Stock Option Activity | A summary of the stock option activity for the year ended December 31, 2014 is provided below: | ||||||||||||||||
Number of | Weighted | Weighted | Aggregate | ||||||||||||||
Shares | Average | Average | Intrinsic | ||||||||||||||
Underlying | Exercise | Remaining | Value (in | ||||||||||||||
Options (in | Price Per | Contractual | millions) | ||||||||||||||
thousands) | Share | Term | |||||||||||||||
Outstanding at beginning of period | 4,927 | $ | 6.95 | 2.85 | 2.81 | ||||||||||||
Granted | 1,118 | $ | 7.05 | 4.18 | |||||||||||||
Exercised | (1,128 | ) | $ | 5.04 | 0.69 | ||||||||||||
Forfeited | (152 | ) | $ | 7.47 | 3.54 | ||||||||||||
Outstanding at end of period | 4,765 | $ | 7.41 | 2.62 | $ | 1.61 | |||||||||||
Vested - end of period | 3,318 | $ | 7.45 | 2.22 | $ | 1.18 | |||||||||||
Vested and expected to vest - end of period | 4,728 | $ | 7.41 | 2.62 | $ | 1.6 | |||||||||||
A Summary of the Values of Options Granted and Exercised | A summary of the values of options granted and exercised for each of the years ended December 31, 2014, 2013 and 2012 is provided below: | ||||||||||||||||
2014 | 2013 | 2012 | |||||||||||||||
Options granted - (thousands) | 1,118 | 1,836 | 1,024 | ||||||||||||||
Weighted average grant date fair value - ($/share) | $ | 2.43 | $ | 2.45 | $ | 3.49 | |||||||||||
Weighted average exercise price - ($/share) | $ | 5.04 | $ | 4.25 | $ | 4.62 | |||||||||||
Options exercised (thousands) | 1,128 | 877 | 759 | ||||||||||||||
Total intrinsic value of options exercised - ($thousands) | $ | 4,120 | $ | 1,201 | $ | 3,267 | |||||||||||
The Valuation of the Options Granted | The valuation of the options granted is based upon a Black Scholes model. The table below summarizes the assumptions used to value the options issued in 2014 and 2013. | ||||||||||||||||
Year | Options Issued | Average | Expected Term | Risk Free | Expected | ||||||||||||
(in thousands) | Volatility | Interest Rate | Dividend Yield | ||||||||||||||
2014 | 1,118 | 58% | 2.5 years | 0.50% | 0% | ||||||||||||
2013 | 1,836 | 51% | 2.5 years | 0.30% | 0% | ||||||||||||
2012 | 1,024 | 65% | 2.5 years | 0.50% | 0% | ||||||||||||
Restricted Stock | |||||||||||||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||||||||||||||||
Summary of Non Vested Awards | Shares of restricted stock are granted under the Company’s long-term incentive plan using the fair market value of the underlying shares on the date of grant. In general, restricted stock granted to employees will vest over a period determined by the Compensation Committee. Determined by the Compensation Committee, some restricted stocks granted are vested immediately while some are vested over a three year period with the initial one-third vesting at the first grant date anniversary. | ||||||||||||||||
Restricted Stock | Weighted Average Grant Price | ||||||||||||||||
Non-Vested Shares Outstanding December 31, 2013 | 100,000 | $ | 5.89 | ||||||||||||||
Awards granted | 99,468 | $ | 6.98 | ||||||||||||||
Awards vested | (51,600 | ) | $ | 6.56 | |||||||||||||
Awards forfeited | - | - | |||||||||||||||
Non-Vested Shares Outstanding December 31, 2014 | 147,868 | $ | 6.39 | ||||||||||||||
Stockholders_Equity_and_Earnin1
Stockholders' Equity and Earnings Per Share (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Earnings Per Share [Abstract] | |||||||||||||
Schedule of Diluted Shares | A reconciliation of diluted shares consists of the following: | ||||||||||||
Year Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
Item | |||||||||||||
Basic weighted average common stock issued and | 57,229,435 | 57,298,910 | 57,673,342 | ||||||||||
outstanding | |||||||||||||
Dilutive options and restricted stock | - | 626,091 | 1,158,717 | ||||||||||
Total diluted shares | 57,229,435 | 57,925,001 | 58,832,059 | ||||||||||
Income_Taxes_Tables
Income Taxes (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Income Tax Disclosure [Abstract] | |||||||||||||
Provision for Income Taxes | Provision for income taxes consists of the following: | ||||||||||||
(in thousands) | Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | |||||||||||
U.S. Federal: | |||||||||||||
Current | $ | - | $ | - | $ | - | |||||||
Deferred | - | - | - | ||||||||||
Foreign: | |||||||||||||
Current | 22,486 | 34,115 | 81,813 | ||||||||||
Deferred | - | - | - | ||||||||||
Total | $ | 22,486 | $ | 34,115 | $ | 81,813 | |||||||
Summary of Differences between the Financial Statement and Tax Bases of Assets and Liabilities | The primary differences between the financial statement and tax bases of assets and liabilities at December 31, 2014 and 2013 are as follows: (In thousands) | ||||||||||||
2014 | 2013 | ||||||||||||
Deferred Tax Assets: | |||||||||||||
Basis difference in fixed assets | $ | 63,931 | $ | 31,440 | |||||||||
Foreign tax credit carry forward | 48,928 | 55,908 | |||||||||||
Alternative minimum tax credit carryover | 1,349 | 1,349 | |||||||||||
Foreign net operating losses | 44,228 | 42,688 | |||||||||||
Asset retirement obligations | 5,196 | 4,012 | |||||||||||
Other | 3,828 | 3,300 | |||||||||||
$ | 167,460 | $ | 138,697 | ||||||||||
Valuation allowance | (166,111 | ) | (137,348 | ) | |||||||||
Total deferred tax asset | $ | 1,349 | $ | 1,349 | |||||||||
Pretax Income | Pretax income (loss) is comprised of the following: | ||||||||||||
(in thousands) | Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | |||||||||||
United States | $ | (6,349 | ) | $ | (17,649 | ) | $ | (56,979 | ) | ||||
Foreign | (48,715 | ) | 94,836 | 144,131 | |||||||||
$ | (55,064 | ) | $ | 77,187 | $ | 87,152 | |||||||
Statutory Rate Reconciliation | The statutory rate reconciliation is as follows: | ||||||||||||
(In Thousands) | Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | |||||||||||
Tax Provision Computed at Statutory Rate | $ | (19,273 | ) | $ | 27,015 | $ | 30,503 | ||||||
Foreign taxes not offset in U.S. by foreign tax credits | 4,433 | (2,072 | ) | 25,266 | |||||||||
Permanent Differences | 135 | 973 | 2,370 | ||||||||||
Foreign Tax Credit Adjustments | 8,417 | (28,027 | ) | ||||||||||
Increase/(Decrease) in Valuation Allowance | 28,762 | 37,752 | 23,675 | ||||||||||
Other | 12 | (1,526 | ) | - | |||||||||
Total Tax Expense | $ | 22,486 | $ | 34,115 | $ | 81,813 | |||||||
Income Tax Years Subject to Examination by Major Tax Jurisdictions | The following table summarizes the tax years that remain subject to examination by major tax jurisdictions: | ||||||||||||
United States | 2008-2014 | ||||||||||||
Gabon | 2007-2014 | ||||||||||||
Commitments_and_Contingencies_
Commitments and Contingencies (Tables) | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
Commitments And Contingencies Disclosure [Abstract] | |||||||||
Estimated Obligations and Companies Share for the Annual Charter Payment | The estimated obligations for the annual charter payment and the Company’s share of the charter payments through the end of the charter are as follows: (in thousands) | ||||||||
Year | Full | Company | |||||||
Charter | Share | ||||||||
Payment | |||||||||
2015 | $ | 25,843 | $ | 7,255 | |||||
2016 | 25,843 | 7,255 | |||||||
2017 | 25,843 | 7,255 | |||||||
2018 | 25,843 | 7,255 | |||||||
2019 | 25,843 | 7,255 | |||||||
Thereafter | 25,914 | 7,275 | |||||||
Total | $ | 155,129 | $ | 43,550 | |||||
Operating Lease Obligations for Rentals | In addition to the FPSO, the Company has operating lease obligations for rentals as follows: (in thousands) | ||||||||
Year | Gross | Company | |||||||
Obligation | Share | ||||||||
2015 | $ | 90,935 | $ | 36,812 | |||||
2016 | 36,607 | 10,594 | |||||||
2017 | 441 | 441 | |||||||
2018 | 408 | 408 | |||||||
2019 | 407 | 407 | |||||||
Thereafter | 340 | 340 | |||||||
Total | $ | 129,138 | $ | 49,002 | |||||
Capitalization_of_Exploratory_2
Capitalization of Exploratory Well Costs (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Inventory Disclosure [Abstract] | |||||||||||||
Schedule of Capitalized Exploratory Well Costs | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
Capitalized exploratory well costs that have been | - | 5.9 | |||||||||||
capitalized for a period less than one year | |||||||||||||
Capitalized exploratory well costs that have been | 8.9 | 16.7 | 8.1 | ||||||||||
capitalized for a period greater than one year | |||||||||||||
Total | 8.9 | 16.7 | 14 | ||||||||||
Number of exploratory wells that have been | 1 | 2 | 1 | ||||||||||
capitalized for a period greater than one year | |||||||||||||
Asset_Retirement_Obligations_T
Asset Retirement Obligations (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Asset Retirement Obligation Disclosure [Abstract] | |||||||||||||
Estimated Fair Value of Company's Asset Retirement Obligations | A summary of the recording of the estimated fair value of the Company’s asset retirement obligations is presented as follows: | ||||||||||||
(In Thousands) | Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | |||||||||||
Balances at January 1, | $ | 11,464 | $ | 10,368 | $ | 14,528 | |||||||
Accretion Expense | 720 | 643 | 814 | ||||||||||
Additions | 2,526 | 453 | 770 | ||||||||||
Revisions | 136 | - | (5,744 | ) | |||||||||
Balance December 31, | $ | 14,846 | $ | 11,464 | $ | 10,368 | |||||||
Segment_Information_Tables
Segment Information (Tables) | 12 Months Ended | ||||||||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||||||||
Segment Reporting [Abstract] | |||||||||||||||||||||||||
Segment Activity | |||||||||||||||||||||||||
2014 | Gabon | Angola | Equatorial | USA | Corporate | Total | |||||||||||||||||||
Guinea | and Other | ||||||||||||||||||||||||
Revenues | $ | 126,322 | $ | - | $ | - | $ | 1,369 | $ | - | $ | 127,691 | |||||||||||||
Depreciation, depletion and amortization | 19,079 | 12 | - | 901 | 94 | 20,086 | |||||||||||||||||||
Operating income (loss) | (42,105 | ) | (3,798 | ) | (1,525 | ) | (119 | ) | (6,859 | ) | (54,406 | ) | |||||||||||||
Interest income | 42 | - | - | - | 33 | 75 | |||||||||||||||||||
Income taxes | 22,486 | - | - | - | - | 22,486 | |||||||||||||||||||
Bad debt and other expenses | 2,400 | - | - | - | - | 2,400 | |||||||||||||||||||
Impairment of proved properties | 98,341 | - | - | - | - | 98,341 | |||||||||||||||||||
Additions to properties and equipment | 83,170 | 3,117 | - | 8 | 816 | 87,111 | |||||||||||||||||||
Long lived assets | 76,247 | 14,645 | 10,000 | 6,359 | 873 | 108,124 | |||||||||||||||||||
Total assets | 192,957 | 22,305 | 10,197 | 6,611 | 16,779 | 248,849 | |||||||||||||||||||
2013 | Gabon | Angola | Equatorial | USA | Corporate | Total | |||||||||||||||||||
Guinea | and Other | ||||||||||||||||||||||||
Revenues | $ | 167,386 | $ | - | $ | - | $ | 1,891 | $ | - | $ | 169,277 | |||||||||||||
Depreciation, depletion and amortization | 15,310 | 28 | - | 1,528 | 63 | 16,929 | |||||||||||||||||||
Operating income (loss) | 98,795 | (3,018 | ) | (768 | ) | (11,869 | ) | (5,915 | ) | 77,225 | |||||||||||||||
Interest income | 40 | - | - | - | 33 | 73 | |||||||||||||||||||
Income taxes | 34,115 | - | - | - | - | 34,115 | |||||||||||||||||||
Bad debt and other expenses | 1,764 | 1,562 | - | - | - | 3,326 | |||||||||||||||||||
Additions to properties and equipment | 53,015 | 629 | - | - | 47 | 53,691 | |||||||||||||||||||
Long lived assets | 109,597 | 11,540 | 10,000 | 7,235 | 152 | 138,524 | |||||||||||||||||||
Total assets | 256,033 | 12,204 | 10,059 | 9,660 | 20,211 | 308,167 | |||||||||||||||||||
2012 | Gabon | Angola | Equatorial | USA | Corporate | Total | |||||||||||||||||||
Guinea | and Other | ||||||||||||||||||||||||
Revenues | $ | 192,489 | $ | - | $ | - | $ | 2,798 | $ | - | $ | 195,287 | |||||||||||||
Depreciation, depletion and amortization | 15,954 | 28 | - | 3,872 | 59 | 19,913 | |||||||||||||||||||
Operating income (loss) | 147,985 | (3,293 | ) | (754 | ) | (48,940 | ) | (8,405 | ) | 86,593 | |||||||||||||||
Interest income | 60 | (1 | ) | - | - | 86 | 145 | ||||||||||||||||||
Income taxes | 81,813 | - | - | - | - | 81,813 | |||||||||||||||||||
Bad debt and expenses | - | 1,621 | - | - | - | 1,621 | |||||||||||||||||||
Impairment of proved properties | - | - | - | 7,620 | - | 7,620 | |||||||||||||||||||
Additions to properties and equipment | 22,731 | - | 10,000 | 13,558 | 77 | 46,366 | |||||||||||||||||||
Long lived assets | 71,225 | 10,938 | 10,000 | 14,279 | 166 | 106,608 | |||||||||||||||||||
Total assets | 190,652 | 11,405 | 10,000 | 17,314 | 38,585 | 267,956 | |||||||||||||||||||
Quarterly_Financial_Informatio1
Quarterly Financial Information (Unaudited) (Tables) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||
Quarterly Financial Information Disclosure [Abstract] | |||||||||||||||||
Summary of Quarterly Financial Information | |||||||||||||||||
(In thousands of dollars except per share information) | 1st Quarter | 2nd Quarter | 3rd Quarter | 4th Quarter | |||||||||||||
2014 | |||||||||||||||||
Total revenues (1) | $ | 28,071 | $ | 52,098 | $ | 24,486 | $ | 23,037 | |||||||||
Total operating costs and expenses | 28,721 | 18,270 | 17,799 | 117,308 | |||||||||||||
Operating income (loss) | (650 | ) | 33,828 | 6,687 | (94,270 | ) | |||||||||||
Net income (loss) | (7,038 | ) | 24,712 | 3,109 | (98,332 | ) | |||||||||||
Basic net income (loss) per share | $ | (0.12 | ) | $ | 0.43 | $ | 0.05 | $ | (1.70 | ) | |||||||
Diluted net income (loss) per share | $ | (0.12 | ) | $ | 0.43 | $ | 0.05 | $ | (1.70 | ) | |||||||
(In thousands of dollars except per share information) | 1st Quarter | 2nd Quarter | 3rd Quarter | 4th Quarter | |||||||||||||
2013 | |||||||||||||||||
Total revenues (1) | $ | 44,137 | $ | 29,118 | $ | 37,740 | $ | 58,282 | |||||||||
Total operating costs and expenses | 22,634 | 17,452 | 29,636 | 22,331 | |||||||||||||
Operating income | 21,503 | 11,666 | 8,104 | 35,951 | |||||||||||||
Net income | 7,188 | 7,121 | 2,386 | 26,377 | |||||||||||||
Basic net income per share | $ | 0.12 | $ | 0.12 | $ | 0.04 | $ | 0.46 | |||||||||
Diluted net income per share | $ | 0.12 | $ | 0.12 | $ | 0.04 | $ | 0.46 | |||||||||
-1 | Gabon crude oil sales are a function of the number and size of crude oil liftings in each quarter from the floating production, storage and offloading (“FPSO”) facility. |
Supplemental_Information_on_Oi1
Supplemental Information on Oil and Gas Producing Activities (Tables) | 12 Months Ended | ||||||||||||||||||||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||||||||||||||||||||
Extractive Industries [Abstract] | |||||||||||||||||||||||||||||||||||||
Costs Incurred in Oil and Gas Property - Acquisition, Exploration and Development Activities | |||||||||||||||||||||||||||||||||||||
(In thousands) | United States | ||||||||||||||||||||||||||||||||||||
2014 | 2013 | 2012 | |||||||||||||||||||||||||||||||||||
Costs incurred during the year: | |||||||||||||||||||||||||||||||||||||
Exploration - capitalized | $ | - | $ | - | $ | 2,602 | |||||||||||||||||||||||||||||||
Exploration - expensed | - | 11,497 | 38,159 | ||||||||||||||||||||||||||||||||||
Acquisition | - | - | 1,630 | ||||||||||||||||||||||||||||||||||
Development | 8 | 113 | 9,689 | ||||||||||||||||||||||||||||||||||
Total | $ | 8 | $ | 11,610 | $ | 52,080 | |||||||||||||||||||||||||||||||
(In thousands) | International | ||||||||||||||||||||||||||||||||||||
2014 | 2013 | 2012 | |||||||||||||||||||||||||||||||||||
Costs incurred during the year: | |||||||||||||||||||||||||||||||||||||
Exploration - capitalized | $ | - | $ | 2,942 | $ | 5,916 | |||||||||||||||||||||||||||||||
Exploration - expensed | 15,358 | 12,431 | 2,878 | ||||||||||||||||||||||||||||||||||
Acquisition | - | - | 10,000 | ||||||||||||||||||||||||||||||||||
Development | 79,722 | 54,420 | 4,022 | ||||||||||||||||||||||||||||||||||
Total | $ | 95,080 | $ | 69,793 | $ | 22,816 | |||||||||||||||||||||||||||||||
Capitalized Costs Relating to Oil and Gas Producing Activities | |||||||||||||||||||||||||||||||||||||
December 31, | |||||||||||||||||||||||||||||||||||||
2014 | 2013 | 2012 | |||||||||||||||||||||||||||||||||||
Capitalized costs - | |||||||||||||||||||||||||||||||||||||
Properties not being amortized | $ | 47,290 | $ | 88,194 | $ | 66,794 | |||||||||||||||||||||||||||||||
Properties being amortized (1) | 347,186 | 222,032 | 195,329 | ||||||||||||||||||||||||||||||||||
Total capitalized costs | $ | 394,476 | $ | 310,226 | $ | 262,123 | |||||||||||||||||||||||||||||||
Less accumulated depreciation, depletion, and | (289,272 | ) | (171,854 | ) | (155,681 | ) | |||||||||||||||||||||||||||||||
amortization | |||||||||||||||||||||||||||||||||||||
Net capitalized costs | $ | 105,204 | $ | 138,372 | $ | 106,442 | |||||||||||||||||||||||||||||||
-1 | Includes $5.2 million, $5.2 million, and $4.7 million asset retirement cost in 2014, 2013, and 2012, respectively. | ||||||||||||||||||||||||||||||||||||
Results of Operations for Oil and Gas Producing Activities | |||||||||||||||||||||||||||||||||||||
United States | International | ||||||||||||||||||||||||||||||||||||
2014 | 2013 | 2012 | 2014 | 2013 | 2012 | ||||||||||||||||||||||||||||||||
Gabon | Gabon | Gabon | |||||||||||||||||||||||||||||||||||
Crude oil and gas sales | $ | 1,369 | $ | 1,891 | $ | 2,798 | $ | 126,322 | $ | 167,386 | $ | 192,489 | |||||||||||||||||||||||||
Production, G&A and other expense | (467 | ) | (12,232 | ) | (47,866 | ) | (150,602 | ) | (52,776 | ) | (27,425 | ) | |||||||||||||||||||||||||
Depreciation, depletion and amortization | (901 | ) | (1,528 | ) | (3,872 | ) | (19,079 | ) | (15,302 | ) | (15,954 | ) | |||||||||||||||||||||||||
Income tax | - | - | - | (22,486 | ) | (34,115 | ) | (81,813 | ) | ||||||||||||||||||||||||||||
Results from oil and gas producing activities | $ | 1 | $ | (11,869 | ) | $ | (48,940 | ) | $ | (65,845 | ) | $ | 65,193 | $ | 67,297 | ||||||||||||||||||||||
Net Proved Reserves | |||||||||||||||||||||||||||||||||||||
Proved Reserves: | Oil (MBbls) | Gas (MMCF) | |||||||||||||||||||||||||||||||||||
Balance at January 1, 2012 | 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 | |||||||||||||||||||||||||||||||||||
Production | (1,351 | ) | (227 | ) | |||||||||||||||||||||||||||||||||
Revisions of previous estimates | 2,312 | 300 | |||||||||||||||||||||||||||||||||||
Extensions and discoveries | 67 | - | |||||||||||||||||||||||||||||||||||
Balance at December 31, 2014 | 8,260 | 1,406 | |||||||||||||||||||||||||||||||||||
Proved Developed Reserves | Oil (MBbls) | Gas (MMCF) | |||||||||||||||||||||||||||||||||||
Balance at January 1, 2012 | 3,854 | 856 | |||||||||||||||||||||||||||||||||||
Balance at December 31, 2012 | 3,750 | 1,544 | |||||||||||||||||||||||||||||||||||
Balance at December 31, 2013 | 3,305 | 1,333 | |||||||||||||||||||||||||||||||||||
Balance at December 31, 2014 | 3,224 | 1,406 | |||||||||||||||||||||||||||||||||||
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil Reserves | |||||||||||||||||||||||||||||||||||||
(In thousands) | United States | International | Total | ||||||||||||||||||||||||||||||||||
December 31, | December 31, | December 31, | |||||||||||||||||||||||||||||||||||
2014 | 2013 | 2012 | 2014 | 2013 | 2012 | 2014 | 2013 | 2012 | |||||||||||||||||||||||||||||
Future cash inflows | $ | 9,598 | $ | 8,276 | $ | 8,260 | $ | 814,059 | $ | 725,485 | $ | 776,646 | $ | 823,657 | $ | 733,761 | $ | 784,906 | |||||||||||||||||||
Future production costs | (1,475 | ) | (3,038 | ) | (3,194 | ) | (307,331 | ) | (223,643 | ) | (203,490 | ) | $ | (308,806 | ) | (226,681 | ) | (206,684 | ) | ||||||||||||||||||
Future development costs | - | - | - | (136,137 | ) | (164,142 | ) | (186,982 | ) | (136,137 | ) | (164,142 | ) | (186,982 | ) | ||||||||||||||||||||||
Future income tax expense | (359 | ) | (825 | ) | (807 | ) | (177,924 | ) | (154,519 | ) | (181,194 | ) | $ | (178,283 | ) | (155,344 | ) | (182,001 | ) | ||||||||||||||||||
Future net cash flows | $ | 7,764 | $ | 4,413 | $ | 4,259 | $ | 192,667 | $ | 183,181 | $ | 204,980 | $ | 200,431 | $ | 187,594 | $ | 209,239 | |||||||||||||||||||
Discount to present value at 10% annual rate | (3,516 | ) | (1,299 | ) | (1,028 | ) | (47,528 | ) | (48,859 | ) | (55,309 | ) | $ | (51,044 | ) | (50,158 | ) | (56,337 | ) | ||||||||||||||||||
Standardized measure of discounted future | $ | 4,248 | $ | 3,114 | $ | 3,231 | $ | 145,139 | $ | 134,322 | $ | 149,671 | $ | 149,387 | $ | 137,436 | $ | 152,902 | |||||||||||||||||||
net cash flows | |||||||||||||||||||||||||||||||||||||
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, | ||||||||||||||||||||||||||||||||||||
2014 | 2013 | 2012 | |||||||||||||||||||||||||||||||||||
Balance at Beginning of Period | $ | 137,436 | $ | 152,902 | $ | 166,187 | |||||||||||||||||||||||||||||||
Sales of oil and gas, net of production costs | (95,973 | ) | (132,662 | ) | (168,563 | ) | |||||||||||||||||||||||||||||||
Net changes in prices and production costs | (28,098 | ) | (52,056 | ) | (11,223 | ) | |||||||||||||||||||||||||||||||
Revisions of previous quantity estimates | 74,497 | 43,815 | 155,111 | ||||||||||||||||||||||||||||||||||
Additions | 2,188 | 29,620 | 69,092 | ||||||||||||||||||||||||||||||||||
Changes in estimated future development costs | 31,686 | (5,345 | ) | (67,834 | ) | ||||||||||||||||||||||||||||||||
Development costs incurred during the period | - | 44,389 | 34,944 | ||||||||||||||||||||||||||||||||||
Accretion of discount | 24,163 | 15,290 | 16,619 | ||||||||||||||||||||||||||||||||||
Net change of income taxes | (15,609 | ) | 26,120 | 7,445 | |||||||||||||||||||||||||||||||||
Change in production rates (timing) and other | 19,097 | 15,363 | (48,876 | ) | |||||||||||||||||||||||||||||||||
Balance at End of Period | $ | 149,387 | $ | 137,436 | $ | 152,902 | |||||||||||||||||||||||||||||||
Summary_of_Significant_Account3
Summary of Significant Accounting Policies - Additional Information (Detail) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Well | |||
Property Plant And Equipment [Line Items] | |||
Company's bank guarantees for customs clearance | $1,600,000 | ||
Company's charter payment escrow | 800,000 | 800,000 | |
Funds restricted to secure the Company's drilling obligation | 10,000,000 | 10,000,000 | |
Funds secure for well obligations | 10,000,000 | ||
Number of additional well obligations | 2 | ||
Date of maturity of certificates of deposit and commercial paper | not exceeding 90 days | ||
Gains or Loss on foreign currency transactions | -700,000 | -100,000 | 400,000 |
Bad debt expenses | 2,400,000 | 1,562,000 | 1,621,000 |
Vaalco International | |||
Property Plant And Equipment [Line Items] | |||
Company acquired the noncontrolling interest amount | $26,200,000 | ||
Noncontrolling interest owned issued and outstanding common stock | 9.99% |
Summary_of_Significant_Account4
Summary of Significant Accounting Policies - Estimated Useful Life of Property Plant and Equipment (Detail) | 12 Months Ended |
Dec. 31, 2014 | |
Office Equipment | Minimum | |
Property Plant And Equipment [Line Items] | |
Estimated useful life | 3 years |
Office Equipment | Maximum | |
Property Plant And Equipment [Line Items] | |
Estimated useful life | 5 years |
Leasehold Improvements | Minimum | |
Property Plant And Equipment [Line Items] | |
Estimated useful life | 8 years |
Leasehold Improvements | Maximum | |
Property Plant And Equipment [Line Items] | |
Estimated useful life | 12 years |
Summary_of_Significant_Account5
Summary of Significant Accounting Policies - Rollforward Analysis of the Allowance Against the Partner Accounts Receivable Balance (Detail) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Accounting Policies [Abstract] | |||
Allowance for Bad Debt, Beginning Balance | ($7,631) | ($6,069) | |
Allowance for Bad Debt, Charged to Costs and Expenses | -2,400 | -1,562 | -1,621 |
Allowance for Bad Debt, Ending Balance | ($10,031) | ($7,631) | ($6,069) |
Stock_Based_Compensation_Addit
Stock Based Compensation - Additional Information (Detail) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Stock options granted, exercisable life | 5 years | ||
Stock options remainder vesting period | 3 years | ||
Stock options, authorized | 4,657,552 | ||
Non-cash compensation expense | $3,322,000 | $3,005,000 | $2,406,000 |
Tax benefits related to stock based compensation | 0 | ||
Unrecognized compensation costs | 2,800,000 | ||
Compensation costs expected to be recognized | 2 years 6 months | ||
Cash proceeds from stock options exercised | $5,700,000 | $3,700,000 | $3,300,000 |
Minimum | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Stock options vested period | 3 years | ||
Maximum | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Stock options vested period | 5 years |
Stock_Based_Compensation_Stock
Stock Based Compensation - Stock Option Activity (Detail) (USD $) | 12 Months Ended | ||
In Millions, except Share data in Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Share Based Compensation Arrangement By Share Based Payment Award Options Outstanding Roll Forward | |||
Number of Shares Underlying Options, Outstanding at beginning of period | 4,927 | ||
Number of Shares Underlying Options, Granted | 1,118 | 1,836 | 1,024 |
Number of Shares Underlying Options, Exercised | -1,128 | -877 | -759 |
Number of Shares Underlying Options, Forfeited | -152 | ||
Number of Shares Underlying Options, Outstanding at end of period | 4,765 | 4,927 | |
Number of Shares Underlying Options, Vested - end of period | 3,318 | ||
Number of Shares Underlying Options, Vested and expected to vest - end of period | 4,728 | ||
Weighted Average Exercise Price Per Share, Outstanding at beginning of period | $6.95 | ||
Weighted Average Exercise Price Per Share, Granted | $7.05 | ||
Weighted Average Exercise Price Per Share, Exercised | $5.04 | $4.25 | $4.62 |
Weighted Average Exercise Price Per Share, Forfeited | $7.47 | ||
Weighted Average Exercise Price Per Share, Outstanding at end of period | $7.41 | $6.95 | |
Weighted Average Exercise Price Per Share, Vested - end of period | $7.45 | ||
Weighted Average Exercise Price Per Share, Vested and expected to vest - end of period | $7.41 | ||
Weighted Average Remaining Contractual Term, Outstanding balance | 2 years 7 months 13 days | 2 years 10 months 6 days | |
Weighted Average Remaining Contractual Term, Granted | 4 years 2 months 5 days | ||
Weighted Average Remaining Contractual Term, Exercised | 8 months 9 days | ||
Weighted Average Remaining Contractual Term, Forfeited | 3 years 6 months 15 days | ||
Weighted Average Remaining Contractual Term, Exercisable at end of period | 2 years 7 months 13 days | 2 years 10 months 6 days | |
Weighted Average Remaining Contractual Term, Vested - end of period | 2 years 2 months 19 days | ||
Weighted Average Remaining Contractual Term, Vested and expected to vest - end of period | 2 years 7 months 13 days | ||
Aggregate Intrinsic Value, Outstanding at beginning of period | $2.81 | ||
Aggregate Intrinsic Value, Outstanding at end of period | 1.61 | 2.81 | |
Aggregate Intrinsic Value, Vested - end of period | 1.18 | ||
Aggregate Intrinsic Value, Vested and expected to vest - end of the period | $1.60 |
Stockbased_Compensation_Summar
Stock-based Compensation - Summary of Non Vested Awards (Detail) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Number of Shares Underlying Options, Granted | 1,118,000 | 1,836,000 | 1,024,000 |
Restricted Stock | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Restricted Stock, Non-Vested Shares Outstanding at beginning period | 100,000 | ||
Number of Shares Underlying Options, Granted | 99,468 | ||
Restricted Stock, Awards vested | -51,600 | ||
Restricted Stock, Non-Vested Shares Outstanding at ending period | 147,868 | ||
Weighted Average Grant Price, Non-Vested Shares Outstanding at beginning period | 5.89 | ||
Weighted Average Grant Price, Awards granted | 6.98 | ||
Weighted Average Grant Price, Awards vested | 6.56 | ||
Weighted Average Grant Price, Non-Vested Shares Outstanding at ending period | 6.39 |
Stock_Based_Compensation_A_Sum
Stock Based Compensation - A Summary of the Values of Options Granted and Exercised (Detail) (USD $) | 12 Months Ended | ||
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Summary of the values of options granted and exercised | |||
Number of Shares Underlying Options, Granted | 1,118 | 1,836 | 1,024 |
Weighted average grant date fair value - ($/share) | $2.43 | $2.45 | $3.49 |
Weighted average exercise price - ($/share) | $5.04 | $4.25 | $4.62 |
Options exercised (thousands) | 1,128 | 877 | 759 |
Total intrinsic value of options exercised - ($thousands) | $4,120 | $1,201 | $3,267 |
Stock_Based_Compensation_The_V
Stock Based Compensation - The Valuation of the Options Granted (Detail) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Valuation of the options granted | |||
Options Issued | 1,118 | 1,836 | 1,024 |
Average Volatility | 58.00% | 51.00% | 65.00% |
Expected Term | 2 years 6 months | 2 years 6 months | 2 years 6 months |
Risk Free Interest Rate | 0.50% | 0.30% | 0.50% |
Expected Dividend Yield | 0.00% | 0.00% | 0.00% |
Stockholders_Equity_and_Earnin2
Stockholders' Equity and Earnings Per Share - Additional Information (Detail) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Earnings Per Share [Abstract] | |||
Common stock, shares authorized | 100,000,000 | 100,000,000 | |
Option to purchase shares, anti-dilutive | 2,329,392 | 3,508,865 | 1,018,900 |
Stockholders_Equity_and_Earnin3
Stockholders' Equity and Earnings Per Share - Schedule of Diluted Shares (Detail) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Schedule of Diluted shares | |||
Basic weighted average common stock issued and outstanding | 57,229,435 | 57,298,910 | 57,673,342 |
Dilutive options and restricted stock | 626,091 | 1,158,717 | |
Total diluted shares | 57,229,435 | 57,925,001 | 58,832,059 |
Income_Taxes_Provision_for_Inc
Income Taxes - Provision for Income Taxes (Detail) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Foreign: | |||
Current | $22,486 | $34,115 | $81,813 |
Total | $22,486 | $34,115 | $81,813 |
Income_Taxes_Summary_of_Differ
Income Taxes - Summary of Differences between the Financial Statement and Tax Bases of Assets and Liabilities (Detail) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Deferred Tax Assets: | ||
Basis difference in fixed assets | $63,931 | $31,440 |
Foreign tax credit carry forward | 48,928 | 55,908 |
Alternative minimum tax credit carryover | 1,349 | 1,349 |
Foreign net operating losses | 44,228 | 42,688 |
Asset retirement obligations | 5,196 | 4,012 |
Other | 3,828 | 3,300 |
Deferred Tax Assets, Gross | 167,460 | 138,697 |
Valuation allowance | -166,111 | -137,348 |
Total deferred tax asset | $1,349 | $1,349 |
Income_Taxes_Additional_Inform
Income Taxes - Additional Information (Detail) (USD $) | 12 Months Ended | |
Dec. 31, 2013 | Dec. 31, 2014 | |
Income Taxes (Textual) [Abstract] | ||
Valuation allowance | $137,348,000 | $166,111,000 |
Increase in deferred tax assets, tax credit carryforwards, foreign | $28,000,000 |
Income_Taxes_Pretax_Income_Det
Income Taxes - Pretax Income (Detail) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Pretax income | |||
United States | ($6,349) | ($17,649) | ($56,979) |
Foreign | -48,715 | 94,836 | 144,131 |
Income (loss) before income taxes | ($55,064) | $77,187 | $87,152 |
Income_Taxes_Statutory_Rate_Re
Income Taxes - Statutory Rate Reconciliation (Detail) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Statutory rate reconciliation | |||
Tax Provision Computed at Statutory Rate | ($19,273) | $27,015 | $30,503 |
Foreign taxes not offset in U.S. by foreign tax credits | 4,433 | -2,072 | 25,266 |
Permanent Differences | 135 | 973 | 2,370 |
Foreign Tax Credit Adjustments | 8,417 | -28,027 | |
Increase/(Decrease) in Valuation Allowance | 28,762 | 37,752 | 23,675 |
Other | 12 | -1,526 | |
Total | $22,486 | $34,115 | $81,813 |
Income_Taxes_Income_Tax_Years_
Income Taxes - Income Tax Years Subject to Examination by Major Tax Jurisdictions (Detail) | 12 Months Ended |
Dec. 31, 2014 | |
United States | Minimum | |
Income Tax years subject to examination by major tax jurisdictions | |
Income tax examination year under examination | 2008 |
United States | Maximum | |
Income Tax years subject to examination by major tax jurisdictions | |
Income tax examination year under examination | 2014 |
Gabon | Minimum | |
Income Tax years subject to examination by major tax jurisdictions | |
Income tax examination year under examination | 2007 |
Gabon | Maximum | |
Income Tax years subject to examination by major tax jurisdictions | |
Income tax examination year under examination | 2014 |
Commitments_and_Contingencies_1
Commitments and Contingencies - Additional Information (Detail) (USD $) | 0 Months Ended | 12 Months Ended | 3 Months Ended | 1 Months Ended | 3 Months Ended | 48 Months Ended | ||||||
Oct. 31, 2014 | Jul. 31, 2014 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Mar. 31, 2015 | Mar. 31, 2014 | Dec. 31, 2010 | Nov. 30, 2006 | Jan. 31, 2007 | Dec. 31, 2008 | Nov. 01, 2010 | |
Rigs | Well | sqkm | sqkm | sqkm | ||||||||
Commitments And Contingencies [Line Items] | ||||||||||||
Period of Charter | 2 years | |||||||||||
Company s share of the charter payment | 28.10% | |||||||||||
Liabilities, guarantees' fair value | $1,000,000 | $1,100,000 | ||||||||||
Charter fee for production up to 20,000 BOPD | 0.93 | 0.25 | ||||||||||
Charter fee for those bbls produced in excess of 20,000 BOPD | 2.5 | |||||||||||
Company's share of charter expense | 11,800,000 | 10,400,000 | 9,700,000 | |||||||||
Number of drilling rigs contracts | 2 | |||||||||||
Drilling rig commitment period | 2016-07 | |||||||||||
Drilling rig cost day rate | 168,000 | 338,000 | 25,800,000 | |||||||||
Second drilling rig contract expected well drilling period | The second drilling rig contract was signed in July 2014 for a semi-submersible rig to drill the exploration well on the Kindele prospect, a post-salt objective. The well began drilling in the first quarter of 2015. The drilling rig provides a forty-five day commitment at a day rate of approximately $338,000. The total commitment related to this rig is $15.2 million | |||||||||||
Second drilling rig contract commitment period | 45 days | |||||||||||
Rent expense, operating leases | 4,000,000 | 4,100,000 | 4,400,000 | |||||||||
Scenario, Forecast | ||||||||||||
Commitments And Contingencies [Line Items] | ||||||||||||
Drilling rig cost day rate | 15,200,000 | |||||||||||
Subsequent Exploration Phase | ||||||||||||
Commitments And Contingencies [Line Items] | ||||||||||||
Number of exploration wells | 4 | |||||||||||
Recorded restricted cash | 20,000,000 | |||||||||||
Subsequent Exploration Phase | Well One | ||||||||||||
Commitments And Contingencies [Line Items] | ||||||||||||
Total assessment of the exploration | 10,000,000 | |||||||||||
Assessment net to VAALCO | 5,000,000 | |||||||||||
Subsequent Exploration Phase | Well Two | ||||||||||||
Commitments And Contingencies [Line Items] | ||||||||||||
Total assessment of the exploration | 10,000,000 | |||||||||||
Assessment net to VAALCO | 5,000,000 | |||||||||||
Subsequent Exploration Phase | Well Three | ||||||||||||
Commitments And Contingencies [Line Items] | ||||||||||||
Total assessment of the exploration | 10,000,000 | |||||||||||
Assessment net to VAALCO | 5,000,000 | |||||||||||
Subsequent Exploration Phase | Well Four | ||||||||||||
Commitments And Contingencies [Line Items] | ||||||||||||
Total assessment of the exploration | 10,000,000 | |||||||||||
Assessment net to VAALCO | 5,000,000 | |||||||||||
Gabon | ||||||||||||
Commitments And Contingencies [Line Items] | ||||||||||||
Discount | 25.00% | |||||||||||
Contractual Obligation Company Share | 3,300,000 | 3,000,000 | 3,700,000 | |||||||||
Contractual Obligation accrued amount | 2,700,000 | |||||||||||
Offshore Gabon | ||||||||||||
Commitments And Contingencies [Line Items] | ||||||||||||
Annual funding related to production license, term | 7 years | |||||||||||
Percentage of annual funding over seven years | 12.14% | |||||||||||
Percentage of annual funding over last three years | 5.00% | |||||||||||
Cash funding arrangement for abandonment of the offshore wells, platforms and facilities | 8,400,000 | |||||||||||
Cash funding arrangement for abandonment of the offshore wells, platforms and facilities net | 2,300,000 | |||||||||||
Abandonment cost related to annual funding | 10,100,000 | |||||||||||
Offshore Gabon | Scenario, Forecast | ||||||||||||
Commitments And Contingencies [Line Items] | ||||||||||||
Cash funding arrangement for abandonment of the offshore wells, platforms and facilities | 4,200,000 | |||||||||||
Cash funding arrangement for abandonment of the offshore wells, platforms and facilities net | 1,200,000 | |||||||||||
Angola | ||||||||||||
Commitments And Contingencies [Line Items] | ||||||||||||
Number of exploration wells | 2 | |||||||||||
Cost related to drilling | 29,500,000 | |||||||||||
Area under acquire property exploration rights agreement term | 1,400,000 | |||||||||||
Joint operation agreement related to third party in working interest percentage | 40.00% | |||||||||||
Additional joint operation agreement related to third party in working interest percentage | 10.00% | |||||||||||
Production license agreement term | 4 years | |||||||||||
Production license agreement term extended by government | 3 years | |||||||||||
Drilling cost to company | 14,800,000 | |||||||||||
Extended drilling period | 1 year | |||||||||||
Percentage of working interest for amounts owned | 40.00% | |||||||||||
Exploration activities new expiry date | 30-Nov-17 | |||||||||||
Number of additional exploration wells due to exploration period extension | 2 | |||||||||||
Recorded restricted cash | 20,000,000 | |||||||||||
Number of well satisfying well obligation | 1 | |||||||||||
Decrease in restricted cash | 5,000,000 | |||||||||||
Angola | Seismic Obligation | ||||||||||||
Commitments And Contingencies [Line Items] | ||||||||||||
Length of acquired property | 1,175 | 524 | 1,000 | |||||||||
Seismic obligation cost to company | 3,750,000 | 3,000,000 | ||||||||||
Cost related to seismic obligation, gross | 7,500,000 | 6,000,000 | ||||||||||
Angola | Subsequent Exploration Phase | Two New Commitments | ||||||||||||
Commitments And Contingencies [Line Items] | ||||||||||||
Recorded restricted cash | $10,000,000 |
Commitments_and_Contingencies_2
Commitments and Contingencies - Estimated Obligations and Companies Share for the Annual Charter Payment (Detail) (USD $) | Dec. 31, 2014 |
In Thousands, unless otherwise specified | |
Estimated obligation and company share for annual charter payment | |
Annual charter payment, 2015 | $25,843 |
Annual charter payment, 2016 | 25,843 |
Annual charter payment, 2017 | 25,843 |
Annual charter payment, 2018 | 25,843 |
Annual charter payment, 2019 | 25,843 |
Annual charter payment, Thereafter | 25,914 |
Annual charter payment, Total | 155,129 |
Company Share | |
Estimated obligation and company share for annual charter payment | |
Annual charter payment, 2015 | 7,255 |
Annual charter payment, 2016 | 7,255 |
Annual charter payment, 2017 | 7,255 |
Annual charter payment, 2018 | 7,255 |
Annual charter payment, 2019 | 7,255 |
Annual charter payment, Thereafter | 7,275 |
Annual charter payment, Total | $43,550 |
Commitments_and_Contingencies_3
Commitments and Contingencies - Operating Lease Obligations for Rentals (Detail) (USD $) | Dec. 31, 2014 |
In Thousands, unless otherwise specified | |
Other Lease Obligations for rentals | |
Gross Obligation, 2015 | $90,935 |
Gross Obligation, 2016 | 36,607 |
Gross Obligation, 2017 | 441 |
Gross Obligation, 2018 | 408 |
Gross Obligation, 2019 | 407 |
Gross Obligation, Thereafter | 340 |
Gross Obligation, Total | 129,138 |
Company Share | |
Other Lease Obligations for rentals | |
Gross Obligation, 2015 | 36,812 |
Gross Obligation, 2016 | 10,594 |
Gross Obligation, 2017 | 441 |
Gross Obligation, 2018 | 408 |
Gross Obligation, 2019 | 407 |
Gross Obligation, Thereafter | 340 |
Gross Obligation, Total | $49,002 |
Long_Term_Debt_Additional_Info
Long Term Debt - Additional Information (Detail) (USD $) | 12 Months Ended | |
In Millions, unless otherwise specified | Dec. 31, 2014 | Jan. 31, 2014 |
Line Of Credit Facility [Line Items] | ||
Maximum borrowing capacity under loan agreement | $65 | |
Borrowings under credit facility | 15 | |
Debt maturity period | 2019-12 | |
Average interest rate on bank debt | 4.32% | |
Net assets pledged for secured debt facility | 58.7 | |
Debt instrument decrease period description | Every six months beginning June 30, 2016 through December 2019. | |
Credit facility borrowing base | 25 | |
Maximum | ||
Line Of Credit Facility [Line Items] | ||
Ratio Of Indebtedness To Net Capital | 1.5 | |
Fair Value Inputs Earnings Before Interest Taxes Depreciation And Amortization Multiple | 3 | |
Senior Tranche | ||
Line Of Credit Facility [Line Items] | ||
Maximum borrowing capacity under loan agreement | 50 | |
Decrease in debt instrument | 6.25 | |
Debt instrument, commitment fee | 1.50% | |
Senior Tranche | London Interbank Offered Rate (LIBOR) | ||
Line Of Credit Facility [Line Items] | ||
Debt instrument interest rate | 3.75% | |
Subordinated Tranche | ||
Line Of Credit Facility [Line Items] | ||
Maximum borrowing capacity under loan agreement | 15 | |
Decrease in debt instrument | $1.88 | |
Debt instrument, commitment fee | 2.30% | |
Subordinated Tranche | London Interbank Offered Rate (LIBOR) | ||
Line Of Credit Facility [Line Items] | ||
Debt instrument interest rate | 5.75% |
Capitalization_of_Interest_Add
Capitalization of Interest - Additional Information (Detail) (USD $) | 12 Months Ended |
In Millions, unless otherwise specified | Dec. 31, 2014 |
Debt Disclosure [Abstract] | |
Interest expense | $1.20 |
Capitalization_of_Exploratory_3
Capitalization of Exploratory Well Costs - Additional Information (Detail) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Capitalized Costs Relating To Oil And Gas Producing Activities By Geographic Area [Line Items] | |||
Accounting Standard Code for Extractive Industries followed for capitalization purposes - ASC Topic 932 | ASC Topic 932 - Extractive Industries provides that an exploratory well shall be capitalized as part of the entity’s uncompleted wells pending the determination of whether the well has found proved reserves. Further, an exploration well that discovers oil and gas reserves, but those reserves cannot be classified as proved when drilling is completed, shall be capitalized if the well has found a sufficient quantity of reserves to justify its completion as a producing well and the entity is making sufficient progress assessing the reserves and the economic and operating viability of the project. If either condition is not met, the exploration well would be assumed to be impaired and its costs would be charged to expense. | ||
Dry hole costs and impairment loss on unproved leasehold | $13,273,000 | $22,490,000 | $37,289,000 |
Etame Marin | |||
Capitalized Costs Relating To Oil And Gas Producing Activities By Geographic Area [Line Items] | |||
Number of side tracks | 2 | ||
Area of sand of oil | 5 | ||
Southeast Etame Field | |||
Capitalized Costs Relating To Oil And Gas Producing Activities By Geographic Area [Line Items] | |||
Dry hole costs and impairment loss on unproved leasehold | 7,800,000 | ||
Mutamba Iroru | |||
Capitalized Costs Relating To Oil And Gas Producing Activities By Geographic Area [Line Items] | |||
Number of side tracks | 3 | ||
Capitalization on development plan | $8,900,000 |
Capitalization_of_Exploratory_4
Capitalization of Exploratory Well Costs - Schedule of Capitalized Exploratory Well Costs (Detail) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
In Millions, unless otherwise specified | Well | Well | Well |
Extractive Industries [Abstract] | |||
Capitalized exploratory well costs that have been capitalized for a period less than one year | $5.90 | ||
Capitalized exploratory well costs that have been capitalized for a period greater than one year | 8.9 | 16.7 | 8.1 |
Total | $8.90 | $16.70 | $14 |
Number of exploratory wells that have been capitalized for a period greater than one year | 1 | 2 | 1 |
Employee_Benefit_Plans_Additio
Employee Benefit Plans - Additional Information (Detail) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Compensation And Retirement Disclosure [Abstract] | |||
Costs incurred for administering employee plan | $464,000 | $182,500 | $204,000 |
Asset_Retirement_Obligations_E
Asset Retirement Obligations - Estimated Fair Value of Company's Asset Retirement Obligations (Detail) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Estimated fair value of the Company's asset retirement obligations | |||
Balances at January 1, | $11,464 | $10,368 | $14,528 |
Accretion Expense | 720 | 643 | 814 |
Additions | 2,526 | 453 | 770 |
Revisions | 136 | -5,744 | |
Balance December 31, | $14,846 | $11,464 | $10,368 |
Asset_Retirement_Obligations_A
Asset Retirement Obligations - Additional Information (Detail) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2012 | Dec. 31, 2013 |
Platforms | Well | ||
Well | |||
Disclosure - Asset Retirement Obligations - Additional Information (Detail) [Line Items] | |||
Number of wells | 2 | ||
Revisions | $136 | ($5,744) | |
Number of new platforms | 2 | ||
Abandoned period of material assets | P5Y | ||
Offshore Gabon | |||
Disclosure - Asset Retirement Obligations - Additional Information (Detail) [Line Items] | |||
Number of wells | 2 |
Segment_Information_Segment_Ac
Segment Information - Segment Activity (Detail) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||||||||||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | ||||||||
Segment Reporting Information [Line Items] | |||||||||||||||||||
Revenues | $23,037 | [1] | $24,486 | [1] | $52,098 | [1] | $28,071 | [1] | $58,282 | [1] | $37,740 | [1] | $29,118 | [1] | $44,137 | [1] | $127,691 | $169,277 | $195,287 |
Depreciation, depletion and amortization | 20,086 | 16,929 | 19,913 | ||||||||||||||||
Operating income (loss) | -94,270 | 6,687 | 33,828 | -650 | 35,951 | 8,104 | 11,666 | 21,503 | -54,406 | 77,225 | 86,593 | ||||||||
Interest income | 75 | 73 | 145 | ||||||||||||||||
Income taxes | 22,486 | 34,115 | 81,813 | ||||||||||||||||
Bad debt and other expenses | 2,400 | 3,326 | 1,621 | ||||||||||||||||
Impairment of proved properties | 98,341 | 7,620 | |||||||||||||||||
Additions to properties and equipment | 87,111 | 53,691 | 46,366 | ||||||||||||||||
Long lived assets | 108,124 | 138,524 | 108,124 | 138,524 | 106,608 | ||||||||||||||
Total assets | 248,849 | 308,167 | 248,849 | 308,167 | 267,956 | ||||||||||||||
Gabon | |||||||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||||||
Revenues | 126,322 | 167,386 | 192,489 | ||||||||||||||||
United States | |||||||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||||||
Revenues | 1,369 | 1,891 | 2,798 | ||||||||||||||||
Operating Segments | Gabon | |||||||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||||||
Revenues | 126,322 | 167,386 | 192,489 | ||||||||||||||||
Depreciation, depletion and amortization | 19,079 | 15,310 | 15,954 | ||||||||||||||||
Operating income (loss) | -42,105 | 98,795 | 147,985 | ||||||||||||||||
Interest income | 42 | 40 | 60 | ||||||||||||||||
Income taxes | 22,486 | 34,115 | 81,813 | ||||||||||||||||
Bad debt and other expenses | 2,400 | 1,764 | |||||||||||||||||
Impairment of proved properties | 98,341 | ||||||||||||||||||
Additions to properties and equipment | 83,170 | 53,015 | 22,731 | ||||||||||||||||
Long lived assets | 76,247 | 109,597 | 76,247 | 109,597 | 71,225 | ||||||||||||||
Total assets | 192,957 | 256,033 | 192,957 | 256,033 | 190,652 | ||||||||||||||
Operating Segments | Angola | |||||||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||||||
Depreciation, depletion and amortization | 12 | 28 | 28 | ||||||||||||||||
Operating income (loss) | -3,798 | -3,018 | -3,293 | ||||||||||||||||
Interest income | -1 | ||||||||||||||||||
Bad debt and other expenses | 1,562 | 1,621 | |||||||||||||||||
Additions to properties and equipment | 3,117 | 629 | |||||||||||||||||
Long lived assets | 14,645 | 11,540 | 14,645 | 11,540 | 10,938 | ||||||||||||||
Total assets | 22,305 | 12,204 | 22,305 | 12,204 | 11,405 | ||||||||||||||
Operating Segments | Equatorial Guinea | |||||||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||||||
Operating income (loss) | -1,525 | -768 | -754 | ||||||||||||||||
Additions to properties and equipment | 10,000 | ||||||||||||||||||
Long lived assets | 10,000 | 10,000 | 10,000 | 10,000 | 10,000 | ||||||||||||||
Total assets | 10,197 | 10,059 | 10,197 | 10,059 | 10,000 | ||||||||||||||
Operating Segments | United States | |||||||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||||||
Revenues | 1,369 | 1,891 | 2,798 | ||||||||||||||||
Depreciation, depletion and amortization | 901 | 1,528 | 3,872 | ||||||||||||||||
Operating income (loss) | -119 | -11,869 | -48,940 | ||||||||||||||||
Impairment of proved properties | 7,620 | ||||||||||||||||||
Additions to properties and equipment | 8 | 13,558 | |||||||||||||||||
Long lived assets | 6,359 | 7,235 | 6,359 | 7,235 | 14,279 | ||||||||||||||
Total assets | 6,611 | 9,660 | 6,611 | 9,660 | 17,314 | ||||||||||||||
Corporate, Non-Segment | |||||||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||||||
Depreciation, depletion and amortization | 94 | 63 | 59 | ||||||||||||||||
Operating income (loss) | -6,859 | -5,915 | -8,405 | ||||||||||||||||
Interest income | 33 | 33 | 86 | ||||||||||||||||
Additions to properties and equipment | 816 | 47 | 77 | ||||||||||||||||
Long lived assets | 873 | 152 | 873 | 152 | 166 | ||||||||||||||
Total assets | $16,779 | $20,211 | $16,779 | $20,211 | $38,585 | ||||||||||||||
[1] | Gabon crude oil sales are a function of the number and size of crude oil liftings in each quarter from the floating production, storage and offloading (“FPSOâ€) facility. |
Impairment_of_Proved_Propertie1
Impairment of Proved Properties - Additional Information (Detail) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Impairment Of Proved Properties [Line Items] | |||
Company recognized an impairment loss | $98.30 | $7.60 | |
Impairment of Oil and Gas Properties | 0 | ||
Etame field | |||
Impairment Of Proved Properties [Line Items] | |||
Company recognized an impairment loss | 38.5 | ||
Ebouri field | |||
Impairment Of Proved Properties [Line Items] | |||
Company recognized an impairment loss | 5.9 | ||
Southeast Etame And North Tchibala field | |||
Impairment Of Proved Properties [Line Items] | |||
Company recognized an impairment loss | $53.90 |
Quarterly_Financial_Informatio2
Quarterly Financial Information (Unaudited) (Detail) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||||||||||
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | ||||||||
Selected Quarterly Financial Information [Abstract] | |||||||||||||||||||
Revenues | $23,037 | [1] | $24,486 | [1] | $52,098 | [1] | $28,071 | [1] | $58,282 | [1] | $37,740 | [1] | $29,118 | [1] | $44,137 | [1] | $127,691 | $169,277 | $195,287 |
Total operating costs and expenses | 117,308 | 17,799 | 18,270 | 28,721 | 22,331 | 29,636 | 17,452 | 22,634 | 182,097 | 92,052 | 108,694 | ||||||||
Operating income (loss) | -94,270 | 6,687 | 33,828 | -650 | 35,951 | 8,104 | 11,666 | 21,503 | -54,406 | 77,225 | 86,593 | ||||||||
Net income (loss) | ($98,332) | $3,109 | $24,712 | ($7,038) | $26,377 | $2,386 | $7,121 | $7,188 | ($77,550) | $43,072 | $5,339 | ||||||||
Basic net income (loss) per share | ($1.70) | $0.05 | $0.43 | ($0.12) | |||||||||||||||
Diluted net income (loss) per share | ($1.70) | $0.05 | $0.43 | ($0.12) | |||||||||||||||
Basic net income per share | $0.46 | $0.04 | $0.12 | $0.12 | ($1.36) | $0.75 | $0.01 | ||||||||||||
Diluted net income per share | $0.46 | $0.04 | $0.12 | $0.12 | ($1.36) | $0.74 | $0.01 | ||||||||||||
[1] | Gabon crude oil sales are a function of the number and size of crude oil liftings in each quarter from the floating production, storage and offloading (“FPSOâ€) facility. |
Supplemental_Information_on_Oi2
Supplemental Information on Oil and Gas Producing Activities - Costs Incurred in Oil and Gas Property - Acquisition, Exploration and Development Activities (Detail) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities | |||
Exploration - expensed | $15,358 | $23,928 | $41,037 |
Development | 52,800 | ||
United States | |||
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities | |||
Exploration - capitalized | 2,602 | ||
Exploration - expensed | 11,497 | 38,159 | |
Acquisition | 1,630 | ||
Development | 8 | 113 | 9,689 |
Total | 8 | 11,610 | 52,080 |
Foreign Tax Authority | |||
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities | |||
Exploration - capitalized | 2,942 | 5,916 | |
Exploration - expensed | 15,358 | 12,431 | 2,878 |
Acquisition | 10,000 | ||
Development | 79,722 | 54,420 | 4,022 |
Total | $95,080 | $69,793 | $22,816 |
Supplemental_Information_on_Oi3
Supplemental Information on Oil and Gas Producing Activities - Additional Information (Detail) (USD $) | 12 Months Ended | 3 Months Ended | 1 Months Ended | |||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Nov. 30, 2012 | Dec. 31, 2011 | |
MBbls | ||||||
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items] | ||||||
Exploration expense | $13,300,000 | $23,900,000 | $37,300,000 | |||
Future development costs | 52,800,000 | |||||
Development cost to company | 14,800,000 | |||||
Oil | ||||||
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items] | ||||||
Proved Developed Reserves | 3,224 | 3,305 | 3,750 | 3,305 | 3,854 | |
Gas | ||||||
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items] | ||||||
Proved Developed Reserves | 1,406,000 | 1,333,000 | 1,544,000 | 1,333,000 | 856,000 | |
Avouma and South Tchibala | ||||||
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items] | ||||||
Proved Developed Reserves | 1,500 | 1,200 | ||||
Etame | ||||||
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items] | ||||||
Proved Developed Reserves | 1,100 | 800 | 1,000 | 800 | ||
Period of development | 20 years | |||||
Expiration of development | expire in 2021 | |||||
Exploration area expiration year | expired in July 2014 | |||||
Ebouri | ||||||
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items] | ||||||
Proved Developed Reserves | 300 | |||||
Period of development | 20 years | |||||
Expiration of development | expire in 2026 | |||||
Consortium | ||||||
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items] | ||||||
Percentage of production | 70.00% | |||||
Net cost account | 36,800,000 | |||||
Cost Recovered | 907,400 | 929,400 | 367,000 | |||
Theoretical Cost | 935,800 | 1,079,300 | 1,197,000 | |||
Consortium | Minimum | ||||||
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items] | ||||||
Percentage of contract area | 50.00% | |||||
Consortium | Maximum | ||||||
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items] | ||||||
Percentage of contract area | 60.00% | |||||
Avouma | ||||||
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items] | ||||||
Period of development | 20 years | |||||
Expiration of development | expire in 2025 | |||||
Mutamba Iroru | ||||||
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items] | ||||||
Percentage of production | 70.00% | |||||
Net cost account | 36,400,000 | |||||
Proved reserves | 0 | |||||
Mutamba Iroru | Minimum | ||||||
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items] | ||||||
Percentage of contract area | 50.00% | |||||
Mutamba Iroru | Maximum | ||||||
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items] | ||||||
Percentage of contract area | 63.00% | |||||
Block 5 Production | ||||||
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items] | ||||||
Percentage of production | 50.00% | |||||
Period of development | 20 years | |||||
Proved reserves | 0 | |||||
Royalty Payments | 0 | |||||
Block 5 Production | Minimum | ||||||
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items] | ||||||
Percentage of contract area | 30.00% | |||||
Block 5 Production | Maximum | ||||||
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items] | ||||||
Percentage of contract area | 90.00% | |||||
Block P Production | ||||||
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items] | ||||||
Percentage of production | 70.00% | |||||
Period of development | 25 years | |||||
Proved reserves | 0 | |||||
Income tax on net profits | 25.00% | |||||
Block P Production | Minimum | ||||||
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items] | ||||||
Fixed royalty rate | 10.00% | |||||
Percentage of contract area | 10.00% | |||||
Block P Production | Maximum | ||||||
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items] | ||||||
Fixed royalty rate | 16.00% | |||||
Percentage of contract area | 60.00% | |||||
Gabon | ||||||
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items] | ||||||
Exploration expense | 11,700,000 | |||||
Unsuccessful exploration wells | 1 | |||||
Exploration license | 1,600,000 | |||||
Contractual price | 98.88 | |||||
Fixed royalty rate | 13.00% | |||||
Equatorial Guinea | ||||||
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items] | ||||||
Percentage of working interest acquired | 31.00% | |||||
Acquisition of Working Interest, cost | 10,000,000 | |||||
United States | ||||||
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items] | ||||||
Future development costs | $8,000 | $113,000 | $9,689,000 | |||
United States | Oil | ||||||
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items] | ||||||
Contractual price | 86.49 | |||||
United States | Gas | ||||||
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items] | ||||||
Contractual price | 5.19 |
Supplemental_Information_on_Oi4
Supplemental Information on Oil and Gas Producing Activities - Capitalized Costs Relating to Oil and Gas Producing Activities (Detail) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |||
In Thousands, unless otherwise specified | ||||||
Capitalized Costs Relating to Oil and Gas Producing Activities: | ||||||
Properties not being amortized | $47,290 | $88,194 | $66,794 | |||
Properties being amortized | 347,186 | [1] | 222,032 | [1] | 195,329 | [1] |
Total capitalized costs | 394,476 | 310,226 | 262,123 | |||
Less accumulated depreciation, depletion, and amortization | -289,272 | -171,854 | -155,681 | |||
Net capitalized costs | $105,204 | $138,372 | $106,442 | |||
[1] | Includes $5.2 million, $5.2 million, and $4.7 million asset retirement cost in 2014, 2013, and 2012, respectively. |
Supplemental_Information_on_Oi5
Supplemental Information on Oil and Gas Producing Activities - Capitalized Costs Relating to Oil and Gas Producing Activities (Parenthetical)(Detail) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Extractive Industries [Abstract] | |||
Asset retirement cost | $5.20 | $5.20 | $4.70 |
Supplemental_Information_on_Oi6
Supplemental Information on Oil and Gas Producing Activities - Results of Operations for Oil and Gas Producing Activities (Detail) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||||||||||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | ||||||||
Results of Operations for Oil and Gas Producing Activities: | |||||||||||||||||||
Crude oil and gas sales | $23,037 | [1] | $24,486 | [1] | $52,098 | [1] | $28,071 | [1] | $58,282 | [1] | $37,740 | [1] | $29,118 | [1] | $44,137 | [1] | $127,691 | $169,277 | $195,287 |
United States | |||||||||||||||||||
Results of Operations for Oil and Gas Producing Activities: | |||||||||||||||||||
Crude oil and gas sales | 1,369 | 1,891 | 2,798 | ||||||||||||||||
Production, G&A and other expense | -467 | -12,232 | -47,866 | ||||||||||||||||
Depreciation, depletion and amortization | -901 | -1,528 | -3,872 | ||||||||||||||||
Results from oil and gas producing activities | 1 | -11,869 | -48,940 | ||||||||||||||||
Gabon | |||||||||||||||||||
Results of Operations for Oil and Gas Producing Activities: | |||||||||||||||||||
Crude oil and gas sales | 126,322 | 167,386 | 192,489 | ||||||||||||||||
Production, G&A and other expense | -150,602 | -52,776 | -27,425 | ||||||||||||||||
Depreciation, depletion and amortization | -19,079 | -15,302 | -15,954 | ||||||||||||||||
Income tax | -22,486 | -34,115 | -81,813 | ||||||||||||||||
Results from oil and gas producing activities | ($65,845) | $65,193 | $67,297 | ||||||||||||||||
[1] | Gabon crude oil sales are a function of the number and size of crude oil liftings in each quarter from the floating production, storage and offloading (“FPSOâ€) facility. |
Supplemental_Information_on_Oi7
Supplemental Information on Oil and Gas Producing Activities - Net Proved Reserves (Detail) | 12 Months Ended | |||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
MBbls | MBbls | MBbls | MBbls | |
Oil | ||||
Proved Reserves: | ||||
Beginning Balance | 7,232 | 7,488 | 6,048 | |
Production | -1,351 | -1,549 | -1,741 | |
Revisions of previous estimates | 2,312 | 771 | 2,200 | |
Extensions and discoveries | 67 | 522 | 981 | |
Ending Balance | 8,260 | 7,232 | 7,488 | |
Proved Developed Reserves | 3,224 | 3,305 | 3,750 | 3,854 |
Gas | ||||
Proved Reserves: | ||||
Beginning Balance | 1,333,000 | 1,544,000 | 1,925,000 | |
Production | -227,000 | -325,000 | -532,000 | |
Revisions of previous estimates | 300,000 | 114,000 | 151,000 | |
Ending Balance | 1,406,000 | 1,333,000 | 1,544,000 | |
Proved Developed Reserves | 1,406,000 | 1,333,000 | 1,544,000 | 856,000 |
Supplemental_Information_on_Oi8
Supplemental Information on Oil and Gas Producing Activities - Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil Reserves (Detail) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
In Thousands, unless otherwise specified | ||||
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil Reserves | ||||
Future cash inflows | $823,657 | $733,761 | $784,906 | |
Future production costs | -308,806 | -226,681 | -206,684 | |
Future development costs | -136,137 | -164,142 | -186,982 | |
Future income tax expense | -178,283 | -155,344 | -182,001 | |
Future net cash flows | 200,431 | 187,594 | 209,239 | |
Discount to present value at 10% annual rate | -51,044 | -50,158 | -56,337 | |
Standardized measure of discounted future net cash flows | 149,387 | 137,436 | 152,902 | 166,187 |
United States | ||||
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil Reserves | ||||
Future cash inflows | 9,598 | 8,276 | 8,260 | |
Future production costs | -1,475 | -3,038 | -3,194 | |
Future income tax expense | -359 | -825 | -807 | |
Future net cash flows | 7,764 | 4,413 | 4,259 | |
Discount to present value at 10% annual rate | -3,516 | -1,299 | -1,028 | |
Standardized measure of discounted future net cash flows | 4,248 | 3,114 | 3,231 | |
International | ||||
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil Reserves | ||||
Future cash inflows | 814,059 | 725,485 | 776,646 | |
Future production costs | -307,331 | -223,643 | -203,490 | |
Future development costs | -136,137 | -164,142 | -186,982 | |
Future income tax expense | -177,924 | -154,519 | -181,194 | |
Future net cash flows | 192,667 | 183,181 | 204,980 | |
Discount to present value at 10% annual rate | -47,528 | -48,859 | -55,309 | |
Standardized measure of discounted future net cash flows | $145,139 | $134,322 | $149,671 |
Supplemental_Information_on_Oi9
Supplemental Information on Oil and Gas Producing Activities - Changes in Standardized Measure of Discounted Future Net Cash Flows (Detail) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Changes in Standardized Measure of Discounted Future Net Cash Flows: | |||
Balance at Beginning of Period | $137,436 | $152,902 | $166,187 |
Sales of oil and gas, net of production costs | -95,973 | -132,662 | -168,563 |
Net changes in prices and production costs | -28,098 | -52,056 | -11,223 |
Revisions of previous quantity estimates | 74,497 | 43,815 | 155,111 |
Additions | 2,188 | 29,620 | 69,092 |
Changes in estimated future development costs | 31,686 | -5,345 | -67,834 |
Development costs incurred during the period | 44,389 | 34,944 | |
Accretion of discount | 24,163 | 15,290 | 16,619 |
Net change of income taxes | -15,609 | 26,120 | 7,445 |
Change in production rates (timing) and other | 19,097 | 15,363 | -48,876 |
Balance at End of Period | $149,387 | $137,436 | $152,902 |
SCHEDULE_I_PARENT_COMPANY_FINA1
SCHEDULE I - PARENT COMPANY FINANCIAL STATEMENT- CONSOLIDATED BALANCE SHEETS (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
In Thousands, unless otherwise specified | ||||
Current assets: | ||||
Cash and cash equivalents | $69,051 | $130,529 | $130,800 | $137,139 |
Restricted cash | 1,584 | 12,366 | ||
Receivables: | ||||
Other, net of allowance of $2.4 million in 2014, and zero in 2013 | 3,285 | 4,435 | ||
Prepayments and other | 6,509 | 2,339 | ||
Total current assets | 113,050 | 167,464 | ||
Property and equipment - successful efforts method: | ||||
Equipment and other | 11,907 | 6,831 | ||
Property, plant and equipment, gross, Total | 397,838 | 310,726 | ||
Accumulated depreciation, depletion and amortization | -289,714 | -172,202 | ||
Net property and equipment | 108,124 | 138,524 | ||
Other assets: | ||||
Restricted cash | 20,830 | 830 | ||
Deferred tax asset | 1,349 | 1,349 | ||
Total Assets | 248,849 | 308,167 | 267,956 | |
Current liabilities: | ||||
Accounts payable and accrued liabilities | 38,540 | 42,561 | ||
Total current liabilities | 38,540 | 45,829 | ||
Long term debt | 15,000 | |||
Total liabilities | 68,386 | 57,293 | ||
VAALCO Energy Inc. shareholders’ equity: | ||||
Common stock, $0.10 par value, 100,000,000 authorized shares, 65,194,828 and 64,012,914 shares issued with 7,393,714 and 7,162,573 shares in treasury at Dec. 31, 2014 and 2013, respectively | 6,519 | 6,408 | ||
Additional paid-in capital | 64,351 | 55,455 | ||
Retained earnings | 146,892 | 224,442 | ||
Less treasury stock, at cost | -37,299 | -35,431 | ||
Total Equity | 180,463 | 250,874 | 212,525 | 233,067 |
Total Liabilities and Equity | 248,849 | 308,167 | ||
VAALCO ENERGY, INC. | ||||
Current assets: | ||||
Cash and cash equivalents | 3,780 | 8,605 | 26,801 | 54,273 |
Restricted cash | 10,000 | |||
Receivables: | ||||
Other, net of allowance of $2.4 million in 2014, and zero in 2013 | 264 | 7 | ||
Prepayments and other | 505 | 89 | ||
Total current assets | 4,549 | 18,701 | ||
Property and equipment - successful efforts method: | ||||
Equipment and other | 1,316 | 500 | ||
Property, plant and equipment, gross, Total | 1,316 | 500 | ||
Accumulated depreciation, depletion and amortization | -442 | -348 | ||
Net property and equipment | 874 | 152 | ||
Other assets: | ||||
Restricted cash | 10,000 | |||
Deferred tax asset | 1,349 | 1,349 | ||
Investment in Subsidiaries | 166,232 | 233,061 | ||
Total Assets | 183,004 | 253,263 | ||
Current liabilities: | ||||
Accounts payable and accrued liabilities | 2,541 | 2,389 | ||
Total current liabilities | 2,541 | 2,389 | ||
Total liabilities | 2,541 | 2,389 | ||
VAALCO Energy Inc. shareholders’ equity: | ||||
Common stock, $0.10 par value, 100,000,000 authorized shares, 65,194,828 and 64,012,914 shares issued with 7,393,714 and 7,162,573 shares in treasury at Dec. 31, 2014 and 2013, respectively | 6,519 | 6,408 | ||
Additional paid-in capital | 64,351 | 55,455 | ||
Retained earnings | 146,892 | 224,442 | ||
Less treasury stock, at cost | -37,299 | -35,431 | ||
Total Equity | 180,463 | 250,874 | ||
Total Liabilities and Equity | $183,004 | $253,263 |
SCHEDULE_I_PARENT_COMPANY_FINA2
SCHEDULE I - PARENT COMPANY FINANCIAL STATEMENT- CONSOLIDATED BALANCE SHEETS (Parenthetical) (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
Common stock, par value | $0.10 | $0.10 |
Common stock, shares authorized | 100,000,000 | 100,000,000 |
Common stock, shares issued | 65,194,828 | 64,012,914 |
Treasury stock, shares | 7,393,714 | 7,162,573 |
VAALCO ENERGY, INC. | ||
Common stock, par value | $0.10 | $0.10 |
Common stock, shares authorized | 100,000,000 | 100,000,000 |
Common stock, shares issued | 65,194,828 | 64,012,914 |
Treasury stock, shares | 7,393,714 | 7,162,573 |
SCHEDULE_I_PARENT_COMPANY_FINA3
SCHEDULE I - PARENT COMPANY FINANCIAL STATEMENT- STATEMENTS OF CONSOLIDATED OPERATIONS (Details) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||||||||||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | ||||||||
Revenues: | |||||||||||||||||||
Oil and gas sales | $23,037 | [1] | $24,486 | [1] | $52,098 | [1] | $28,071 | [1] | $58,282 | [1] | $37,740 | [1] | $29,118 | [1] | $44,137 | [1] | $127,691 | $169,277 | $195,287 |
Operating costs and expenses: | |||||||||||||||||||
Depreciation, depletion and amortization | 20,086 | 16,929 | 19,913 | ||||||||||||||||
General and administrative expense | 14,194 | 11,254 | 11,779 | ||||||||||||||||
Total operating costs and expenses | 117,308 | 17,799 | 18,270 | 28,721 | 22,331 | 29,636 | 17,452 | 22,634 | 182,097 | 92,052 | 108,694 | ||||||||
Operating income (loss) | -94,270 | 6,687 | 33,828 | -650 | 35,951 | 8,104 | 11,666 | 21,503 | -54,406 | 77,225 | 86,593 | ||||||||
Other income (expense): | |||||||||||||||||||
Interest income | 75 | 73 | 145 | ||||||||||||||||
Other, net | -733 | -111 | 414 | ||||||||||||||||
Total other income (expense) | -658 | -38 | 559 | ||||||||||||||||
Income (loss) before income taxes | -55,064 | 77,187 | 87,152 | ||||||||||||||||
Income tax expense | 22,486 | 34,115 | 81,813 | ||||||||||||||||
Net income (loss) | -98,332 | 3,109 | 24,712 | -7,038 | 26,377 | 2,386 | 7,121 | 7,188 | -77,550 | 43,072 | 5,339 | ||||||||
Less net income attributable to noncontrolling interest | -4,708 | ||||||||||||||||||
Net income (loss) attributable to VAALCO Energy, Inc. | -77,550 | 43,072 | 631 | ||||||||||||||||
VAALCO ENERGY, INC. | |||||||||||||||||||
Operating costs and expenses: | |||||||||||||||||||
Depreciation, depletion and amortization | 94 | 63 | 59 | ||||||||||||||||
General and administrative expense | 6,740 | 5,750 | 8,065 | ||||||||||||||||
Total operating costs and expenses | 6,834 | 5,813 | 8,124 | ||||||||||||||||
Operating income (loss) | -6,834 | -5,813 | -8,124 | ||||||||||||||||
Other income (expense): | |||||||||||||||||||
Interest income | 33 | 33 | 86 | ||||||||||||||||
Other, net | 450 | ||||||||||||||||||
Equity in subsidiary earnings | -71,199 | 48,852 | 13,377 | ||||||||||||||||
Total other income (expense) | -70,716 | 48,885 | 13,463 | ||||||||||||||||
Income (loss) before income taxes | -77,550 | 43,072 | 5,339 | ||||||||||||||||
Net income (loss) | -77,550 | 43,072 | 5,339 | ||||||||||||||||
Less net income attributable to noncontrolling interest | -4,708 | ||||||||||||||||||
Net income (loss) attributable to VAALCO Energy, Inc. | ($77,550) | $43,072 | $631 | ||||||||||||||||
[1] | Gabon crude oil sales are a function of the number and size of crude oil liftings in each quarter from the floating production, storage and offloading (“FPSOâ€) facility. |
SCHEDULE_I_PARENT_COMPANY_FINA4
SCHEDULE I - PARENT COMPANY FINANCIAL STATEMENT- STATEMENTS OF CONSOLIDATED CASH FLOWS (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
CASH FLOWS FROM OPERATING ACTIVITIES | |||
Net income (loss) | ($77,550) | $43,072 | $5,339 |
Adjustments to reconcile net income to net cash provided by operating activities | |||
Depreciation, depletion and amortization | 20,086 | 16,929 | 19,913 |
Stock based compensation | 3,322 | 3,005 | 2,406 |
Change in operating assets and liabilities: | |||
Other receivables | -1,250 | -53 | -199 |
Prepayments and other | -4,172 | 594 | -766 |
Accounts payable and other liabilities | -9,503 | 8,988 | 39 |
CASH FLOWS FROM INVESTING ACTIVITIES | |||
Decrease/(increase) in restricted cash | -9,219 | -1,065 | 78 |
CASH FLOWS FROM FINANCING ACTIVITIES | |||
Proceeds from the issuance of common stock | 5,685 | 3,729 | 3,335 |
Purchase of treasury stock | -1,868 | -11,456 | |
Distribution to noncontrolling interest | -5,595 | ||
Acquisition of noncontrolling interest | -26,200 | ||
NET CHANGE IN CASH AND CASH EQUIVALENTS | -61,478 | -270 | -6,339 |
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD | 130,529 | 130,800 | 137,139 |
CASH AND CASH EQUIVALENTS AT END OF PERIOD | 69,051 | 130,529 | 130,800 |
VAALCO ENERGY, INC. | |||
CASH FLOWS FROM OPERATING ACTIVITIES | |||
Net income (loss) | -77,550 | 43,072 | 5,339 |
Adjustments to reconcile net income to net cash provided by operating activities | |||
Depreciation, depletion and amortization | 94 | 63 | 59 |
Stock based compensation | 3,322 | 3,005 | 2,406 |
Equity in (earnings) loss from subsidiaries | 71,199 | -48,852 | -13,377 |
Change in operating assets and liabilities: | |||
Other receivables | -257 | 180 | 27 |
Prepayments and other | -416 | -16 | 14 |
Accounts payable and other liabilities | 153 | 371 | -2,710 |
Net cash (used in) operating activities | -3,455 | -2,177 | -8,242 |
CASH FLOWS FROM INVESTING ACTIVITIES | |||
Investment in subsidiaries | -4,371 | -8,245 | |
Return of investment in subsidiaries | 19,307 | ||
Decrease/(increase) in restricted cash | -10,000 | ||
Property and equipment expenditures | -816 | -47 | -77 |
Net cash (used in) investing activities | -5,187 | -8,292 | 9,230 |
CASH FLOWS FROM FINANCING ACTIVITIES | |||
Proceeds from the issuance of common stock | 5,685 | 3,729 | 3,335 |
Purchase of treasury stock | -1,868 | -11,456 | |
Distribution to noncontrolling interest | -5,595 | ||
Acquisition of noncontrolling interest | -26,200 | ||
Net cash provided by (used in) financing activities | 3,817 | -7,727 | -28,460 |
NET CHANGE IN CASH AND CASH EQUIVALENTS | -4,825 | -18,196 | -27,472 |
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD | 8,605 | 26,801 | 54,273 |
CASH AND CASH EQUIVALENTS AT END OF PERIOD | $3,780 | $8,605 | $26,801 |