Document and Entity Information
Document and Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2016 | Feb. 16, 2017 | Jun. 30, 2016 | |
Document and Entity Information | |||
Entity Registrant Name | Kosmos Energy Ltd. | ||
Entity Central Index Key | 1,509,991 | ||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2016 | ||
Amendment Flag | false | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Public Float | $ 849,378,870 | ||
Entity Common Stock, Shares Outstanding | 387,603,985 | ||
Document Fiscal Year Focus | 2,016 | ||
Document Fiscal Period Focus | FY |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Current assets: | ||
Cash and cash equivalents | $ 194,057 | $ 275,004 |
Restricted cash | 24,506 | 28,533 |
Receivables: | ||
Joint interest billings, net | 63,249 | 67,200 |
Oil sales | 54,195 | 35,950 |
Other | 25,893 | 34,882 |
Inventories | 74,380 | 85,173 |
Prepaid expenses and other | 7,209 | 24,766 |
Derivatives | 31,698 | 182,640 |
Total current assets | 475,187 | 734,148 |
Property and equipment: | ||
Oil and gas properties, net | 2,700,889 | 2,314,226 |
Other property, net | 8,003 | 8,613 |
Property and equipment, net | 2,708,892 | 2,322,839 |
Other assets: | ||
Restricted cash | 54,632 | 7,325 |
Long-term receivables - joint interest billings | 45,663 | 37,687 |
Deferred financing costs, net of accumulated amortization of $11,213 and $8,475 at December 31, 2016 and December 31, 2015, respectively | 5,248 | 7,986 |
Long-term deferred tax assets | 37,827 | 33,209 |
Derivatives | 3,808 | 59,856 |
Other | 10,208 | |
Total assets | 3,341,465 | 3,203,050 |
Current liabilities: | ||
Accounts payable | 220,627 | 295,689 |
Accrued liabilities | 129,706 | 159,897 |
Derivatives | 19,692 | 1,155 |
Total current liabilities | 370,025 | 456,741 |
Long-term liabilities: | ||
Long-term debt | 1,321,874 | 860,878 |
Derivatives | 14,123 | 4,196 |
Asset retirement obligations | 63,574 | 43,938 |
Deferred tax liabilities | 482,221 | 502,189 |
Other long-term liabilities | 8,449 | 9,595 |
Total long-term liabilities | 1,890,241 | 1,420,796 |
Shareholders' equity: | ||
Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at December 31, 2016 and December 31, 2015 | ||
Common shares, $0.01 par value; 2,000,000,000 authorized shares; 395,859,061 and 393,902,643 issued at December 31, 2016 and 2015, respectively | 3,959 | 3,939 |
Additional paid-in capital | 1,975,247 | 1,933,189 |
Accumulated deficit | (850,410) | (564,686) |
Treasury stock, at cost, 9,101,395 and 8,812,054 shares at December 31, 2016 and 2015, respectively | (47,597) | (46,929) |
Total shareholders' equity | 1,081,199 | 1,325,513 |
Total liabilities and shareholders' equity | $ 3,341,465 | $ 3,203,050 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
CONSOLIDATED BALANCE SHEETS | ||
Deferred financing costs, accumulated amortization (in dollars) | $ 11,213 | $ 8,475 |
Preference shares, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Preference shares, authorized shares | 200,000,000 | 200,000,000 |
Preference shares, issued shares | 0 | 0 |
Common shares, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Common shares, authorized shares | 2,000,000,000 | 2,000,000,000 |
Common shares, issued shares | 395,859,061 | 393,902,643 |
Treasury stock shares | 9,101,395 | 8,812,054 |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Revenues and other income: | |||
Oil and gas revenue | $ 310,377 | $ 446,696 | $ 855,877 |
Gain on sale of assets | 24,651 | 23,769 | |
Other income | 74,978 | 209 | 3,092 |
Total revenues and other income | 385,355 | 471,556 | 882,738 |
Costs and expenses: | |||
Oil and gas production | 119,367 | 105,336 | 100,122 |
Facilities insurance modifications | 14,961 | ||
Exploration expenses | 202,280 | 156,203 | 93,519 |
General and administrative | 87,623 | 136,809 | 135,231 |
Depletion and depreciation | 140,404 | 155,966 | 198,080 |
Interest and other financing costs, net | 44,147 | 37,209 | 45,548 |
Derivatives, net | 48,021 | (210,649) | (281,853) |
Restructuring charges | 11,742 | ||
Other expenses, net | 23,116 | 5,246 | 2,081 |
Total costs and expenses | 679,919 | 386,120 | 304,470 |
Income (Loss) before taxes | (294,564) | 85,436 | 578,268 |
Income tax expense (benefit) | (10,784) | 155,272 | 298,898 |
Net income (loss) | $ (283,780) | $ (69,836) | $ 279,370 |
Net income (loss) per share: | |||
Basic (in dollars per share) | $ (0.74) | $ (0.18) | $ 0.73 |
Diluted (in dollars per share) | $ (0.74) | $ (0.18) | $ 0.72 |
Weighted average number of shares used to compute net income (loss) per share: | |||
Basic (in shares) | 385,402 | 382,610 | 379,195 |
Diluted (in shares) | 385,402 | 382,610 | 386,119 |
CONSOLIDATED STATEMENTS OF COMP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) | |||
Net income (loss) | $ (283,780) | $ (69,836) | $ 279,370 |
Other comprehensive loss: | |||
Reclassification adjustments for derivative gains included in net income (loss) | (767) | (1,391) | |
Other comprehensive loss | (767) | (1,391) | |
Comprehensive income (loss) | $ (283,780) | $ (70,603) | $ 277,979 |
CONSOLIDATED STATEMENTS OF SHAR
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY - USD ($) shares in Thousands, $ in Thousands | Common Shares | Additional Paid-in Capital | Accumulated Deficit | Accumulated Other Comprehensive Income | Treasury Stock | Total |
Balance at Dec. 31, 2013 | $ 3,920 | $ 1,781,535 | $ (774,220) | $ 2,158 | $ (21,058) | $ 992,335 |
Balance (in shares) at Dec. 31, 2013 | 391,974 | |||||
Increase (Decrease) in Shareholders' Equity | ||||||
Equity-based compensation | 79,741 | 79,741 | ||||
Derivatives, net | (1,391) | (1,391) | ||||
Restricted stock awards and units | $ 4 | (4) | ||||
Restricted stock awards and units (in shares) | 469 | |||||
Restricted stock forfeitures | 2 | (2) | ||||
Purchase of treasury stock | (1,084) | (10,012) | (11,096) | |||
Net loss | 279,370 | 279,370 | ||||
Balance at Dec. 31, 2014 | $ 3,924 | 1,860,190 | (494,850) | 767 | (31,072) | 1,338,959 |
Balance (in shares) at Dec. 31, 2014 | 392,443 | |||||
Increase (Decrease) in Shareholders' Equity | ||||||
Equity-based compensation | 75,267 | 75,267 | ||||
Derivatives, net | $ (767) | (767) | ||||
Restricted stock awards and units | $ 15 | (15) | ||||
Restricted stock awards and units (in shares) | 1,460 | |||||
Restricted stock forfeitures | 16 | (16) | ||||
Purchase of treasury stock | (2,269) | (15,841) | (18,110) | |||
Net loss | (69,836) | (69,836) | ||||
Balance at Dec. 31, 2015 | $ 3,939 | 1,933,189 | (564,686) | (46,929) | 1,325,513 | |
Balance (in shares) at Dec. 31, 2015 | 393,903 | |||||
Increase (Decrease) in Shareholders' Equity | ||||||
Equity-based compensation | 43,391 | (1,944) | 41,447 | |||
Restricted stock awards and units | $ 20 | (20) | ||||
Restricted stock awards and units (in shares) | 1,956 | |||||
Restricted stock forfeitures | 2 | (2) | ||||
Purchase of treasury stock | (1,315) | (666) | (1,981) | |||
Net loss | (283,780) | (283,780) | ||||
Balance at Dec. 31, 2016 | $ 3,959 | $ 1,975,247 | $ (850,410) | $ (47,597) | $ 1,081,199 | |
Balance (in shares) at Dec. 31, 2016 | 395,859 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Operating activities | |||
Net income (loss) | $ (283,780) | $ (69,836) | $ 279,370 |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Depletion, depreciation and amortization | 150,608 | 166,290 | 208,628 |
Deferred income taxes | (23,561) | 110,786 | 216,409 |
Unsuccessful well costs | 6,079 | 94,910 | 1,105 |
Change in fair value of derivatives | 46,559 | (210,957) | (271,298) |
Cash settlements on derivatives, net (including $187.9 million, $225.5 million and $18.4 million on commodity hedges during 2016, 2015 and 2014) | 188,895 | 224,741 | 4,460 |
Equity-based compensation | 40,084 | 75,057 | 79,541 |
Gain on sale of assets | (24,651) | (23,769) | |
Loss on extinguishment of debt | 165 | 2,898 | |
Other | 13,355 | 7,875 | (3,875) |
Changes in assets and liabilities: | |||
(Increase) decrease in receivables | (20,558) | 2,209 | (156,192) |
Increase in inventories | (4,107) | (29,855) | (8,100) |
(Increase) decrease in prepaid expenses and other | 17,557 | 512 | 1,732 |
Increase (decrease) in accounts payable | (75,487) | 111,289 | 90,228 |
Increase (decrease) in accrued liabilities | (3,567) | (17,756) | 22,449 |
Net cash provided by (used in) operating activities | 52,077 | 440,779 | 443,586 |
Investing activities | |||
Oil and gas assets | (535,975) | (823,642) | (424,535) |
Other property | (1,998) | (1,483) | (2,383) |
Proceeds on sale of assets | 210 | 28,692 | 58,315 |
Net cash used in investing activities | (537,763) | (796,433) | (368,603) |
Financing activities | |||
Borrowings under long-term debt | 450,000 | 100,000 | |
Payments on long-term debt | (200,000) | (400,000) | |
Net proceeds from issuance of senior secured notes | 206,774 | 294,000 | |
Purchase of treasury stock | (1,981) | (18,110) | (11,096) |
Deferred financing costs | (9,030) | (22,088) | |
Net cash provided by (used in) financing activities | 448,019 | 79,634 | (139,184) |
Net decrease in cash, cash equivalents and restricted cash | (37,667) | (276,020) | (64,201) |
Cash, cash equivalents and restricted cash at beginning of period | 310,862 | 586,882 | 651,083 |
Cash, cash equivalents and restricted cash at end of period | 273,195 | 310,862 | 586,882 |
Cash paid for: | |||
Interest | 27,860 | 33,315 | 23,182 |
Income taxes | 13,997 | $ 35,857 | $ 108,068 |
Non-cash activity: | |||
Conversion of joint interest billings receivable to long-term note receivable | $ 9,814 |
CONSOLIDATED STATEMENTS OF CAS8
CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
CONSOLIDATED STATEMENTS OF CASH FLOWS | |||
Cash settlements on derivatives, net (including $187.9 million, $225.5 million and $18.4 million on commodity hedges during 2016, 2015 and 2014) | $ 187.9 | $ 225.5 | $ 18.4 |
Organization
Organization | 12 Months Ended |
Dec. 31, 2016 | |
Organization | |
Organization | 1. Organization Kosmos Energy Ltd. was incorporated pursuant to the laws of Bermuda in January 2011 to become a holding company for Kosmos Energy Holdings. Kosmos Energy Holdings is a privately held Cayman Islands company that was formed in March 2004. As a holding company, Kosmos Energy Ltd.’s management operations are conducted through a wholly owned subsidiary, Kosmos Energy, LLC. The terms “Kosmos,” the “Company,” “we,” “us,” “our,” “ours,” and similar terms refer to Kosmos Energy Ltd. and its wholly owned subsidiaries, unless the context indicates otherwise. Kosmos is a leading independent oil and gas exploration and production company focused on frontier and emerging areas along the Atlantic Margins. Our assets include existing production and development projects offshore Ghana, large discoveries and significant further hydrocarbon exploration potential offshore Mauritania and Senegal, as well as exploration licenses with significant hydrocarbon potential offshore Sao Tome and Principe, Suriname, Morocco and Western Sahara. Kosmos is listed on the New York Stock Exchange and is traded under the ticker symbol KOS. We have one reportable segment, which is the exploration and production of oil and natural gas. Substantially all of our long‑lived assets and all of our product sales are related to production located offshore Ghana. |
Accounting Policies
Accounting Policies | 12 Months Ended |
Dec. 31, 2016 | |
Accounting Policies | |
Accounting Policies | 2. Accounting Policies Principles of Consolidation The accompanying consolidated financial statements include the accounts of Kosmos Energy Ltd. and its wholly owned subsidiaries. All intercompany transactions have been eliminated. Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosures of contingent assets and liabilities. Actual results could differ from these estimates. Reclassifications Certain prior period amounts have been reclassified to conform with the current year presentation. Such reclassifications had no material impact on our reported net income (loss), current assets, total assets, current liabilities, total liabilities, shareholders’ equity or cash flows, except as disclosed related to the adoption of recent accounting pronouncements. Cash, Cash Equivalents and Restricted Cash December 31, 2016 2015 2014 (In thousands) Cash and cash equivalents $ $ $ Restricted cash - current Restricted cash - long-term Total cash, cash equivalents and restricted cash shown in the consolidated statements of cash flows $ $ $ Cash and cash equivalents includes demand deposits and funds invested in highly liquid instruments with original maturities of three months or less at the date of purchase. In accordance with our commercial debt facility (the “Facility”), we are required to maintain a restricted cash balance that is sufficient to meet the payment of interest and fees for the next six‑month period on the 7.875% Senior Secured Notes due 2021 (“Senior Notes”) plus the Corporate Revolver or the Facility, whichever is greater. As of December 31, 2016 and 2015, we had $24.5 million and $24.4 million, respectively, in current restricted cash to meet this requirement. In addition, in accordance with certain of our petroleum contracts, we have posted letters of credit related to performance guarantees for our minimum work obligations. These letters of credit are cash collateralized in accounts held by us and as such are classified as restricted cash. Upon completion of the minimum work obligations and/or entering into the next phase of the petroleum contract, the requirement to post the existing letters of credit will be satisfied and the cash collateral will be released. However, additional letters of credit may be required should we choose to move into the next phase of certain of our petroleum contracts. As of December 31, 2016 and 2015, we had zero and $4.1 million, respectively, of short-term restricted cash and $54.6 million and $7.3 million, respectively, of long‑term restricted cash used to cash collateralize performance guarantees related to our petroleum contracts. Receivables Our receivables consist of joint interest billings, oil sales and other receivables. For our oil sales receivable, we require a letter of credit to be posted to secure the outstanding receivable. Receivables from joint interest owners are stated at amounts due, net of any allowances for doubtful accounts. We determine our allowance by considering the length of time past due, future net revenues of the debtor’s ownership interest in oil and natural gas properties we operate, and the owner’s ability to pay its obligation, among other things. We had an allowance for doubtful accounts of $0.6 million and zero in current joint interest billings receivables as of December 31, 2016 and 2015, respectively. Inventories Inventories consisted of $68.1 million and $84.4 million of materials and supplies and $6.3 million and $0.8 million of hydrocarbons as of December 31, 2016 and 2015, respectively. The Company’s materials and supplies inventory primarily consists of casing and wellheads and is stated at the lower of cost, using the weighted average cost method, or net realizable value. We recorded a write down of $14.9 million during the year ended December 31, 2016 for materials and supplies inventories as other expenses, net in the consolidated statements of operations and other in the consolidated statements of cash flows. Hydrocarbon inventory is carried at the lower of cost, using the weighted average cost method, or net realizable value. Hydrocarbon inventory costs include expenditures and other charges incurred in bringing the inventory to its existing condition. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory costs. Exploration and Development Costs The Company follows the successful efforts method of accounting for its oil and gas properties. Acquisition costs for proved and unproved properties are capitalized when incurred. Costs of unproved properties are transferred to proved properties when a determination that proved reserves have been found. Exploration costs, including geological and geophysical costs and costs of carrying unproved properties, are expensed as incurred. Exploratory drilling costs are capitalized when incurred. If exploratory wells are determined to be commercially unsuccessful or dry holes, the applicable costs are expensed and recorded in exploration expense on the consolidated statement of operations. Costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized. Costs incurred to operate and maintain wells and equipment and to lift oil and natural gas to the surface are expensed as oil and gas production expense. The Company evaluates unproved property periodically for impairment. The impairment assessment considers results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of such projects. If the quantity of potential future reserves determined by such evaluations is not sufficient to fully recover the cost invested in each project, the Company will recognize an impairment loss at that time. Depletion, Depreciation and Amortization Proved properties and support equipment and facilities are depleted using the unit‑of‑production method based on estimated proved oil and natural gas reserves. Capitalized exploratory drilling costs that result in a discovery of proved reserves and development costs are amortized using the unit‑of‑production method based on estimated proved developed oil and natural gas reserves for the related field. Depreciation and amortization of other property is computed using the straight-line method over the assets’ estimated useful lives (not to exceed the lease term for leasehold improvements), ranging from one to eight years. Years Depreciated Leasehold improvements to 8 Office furniture, fixtures and computer equipment to 7 Vehicles 5 Amortization of deferred financing costs is computed using the straight‑line method over the life of the related debt. 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. Asset Retirement Obligations The Company accounts for asset retirement obligations as required by ASC 410—Asset Retirement and Environmental Obligations. Under these standards, the fair value of a liability for an asset retirement obligation is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. If a reasonable estimate of fair value cannot be made in the period the asset retirement obligation is incurred, the liability is recognized when a reasonable estimate of fair value can be made. If a tangible long‑lived asset with an existing asset retirement obligation is acquired, a liability for that obligation is recognized at the asset’s acquisition date. In addition, a liability for the fair value of a conditional asset retirement obligation is recorded if the fair value of the liability can be reasonably estimated. We capitalize the asset retirement costs by increasing the carrying amount of the related long‑lived asset by the same amount as the liability. We record increases in the discounted abandonment liability resulting from the passage of time in depletion and depreciation in the consolidated statement of operations. Impairment of Long‑lived Assets The Company reviews its long‑lived assets for impairment when changes in circumstances indicate that the carrying amount of an asset may not be recoverable, or at least annually. ASC 360—Property, Plant and Equipment requires an impairment loss to be recognized if the carrying amount of a long‑lived asset is not recoverable and exceeds its fair value. The carrying amount of a long‑lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. That assessment shall be based on the carrying amount of the asset at the date it is tested for recoverability, whether in use or under development. An impairment loss shall be measured as the amount by which the carrying amount of a long‑lived asset exceeds its fair value. Assets to be disposed of and assets not expected to provide any future service potential to the Company are recorded at the lower of carrying amount or fair value less cost to sell. We believe the assumptions used in our undiscounted cash flow analysis to test for impairment are appropriate and result in a reasonable estimate of future cash flows. The undiscounted cash flows from the analysis exceeded the carrying amount of our long-lived assets. The most significant assumptions are the pricing and production estimates used in undiscounted cash flow analysis. Where unproved reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the evaluation. In order to evaluate the sensitivity of the assumptions, we assumed a hypothetical reduction in our production profile which still showed no impairment. If we experience declines in oil pricing, increases in our estimated future expenditures or a decrease in our estimated production profile our long-lived assets could be at risk for impairment. Derivative Instruments and Hedging Activities We utilize oil derivative contracts to mitigate our exposure to commodity price risk associated with our anticipated future oil production. These derivative contracts consist of three‑way collars, put options, call options and swaps. We also use interest rate derivative contracts to mitigate our exposure to interest rate fluctuations related to our long‑term debt. Our derivative financial instruments are recorded on the balance sheet as either assets or liabilities and are measured at fair value. We do not apply hedge accounting to our oil derivative contracts. Effective June 1, 2010, we discontinued hedge accounting on our interest rate swap contracts. Therefore, from that date forward, the changes in the fair value of the instruments were recognized in earnings during the period of change. The effective portions of the discontinued hedges as of May 31, 2010, were included in accumulated other comprehensive income or loss (“AOCI”) in the equity section of the accompanying consolidated balance sheets, and were transferred to earnings when the hedged transactions settled. As of December 31, 2015 all instruments previously designated as hedges have settled and there is no balance remaining in AOCI. See Note 8—Derivative Financial Instruments. Estimates of Proved Oil and Natural Gas Reserves Reserve quantities and the related estimates of future net cash flows affect our periodic calculations of depletion and assessment of impairment of our oil and natural gas properties. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. As additional proved reserves are discovered, reserve quantities and future cash flows will be estimated by independent petroleum consultants and prepared in accordance with guidelines established by the Securities and Exchange Commission (“SEC”) and the Financial Accounting Standards Board (“FASB”). The accuracy of these reserve estimates is a function of: · the engineering and geological interpretation of available data; · estimates of the amount and timing of future operating cost, production taxes, development cost and workover cost; · the accuracy of various mandated economic assumptions; and · the judgments of the persons preparing the estimates. Revenue Recognition We use the sales method of accounting for oil and gas revenues. 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, 2016 and 2015, we had no oil and gas imbalances recorded in our consolidated financial statements. Our oil and gas revenues are based on provisional price contracts which contain an embedded derivative that is required to be separated from the host contract for accounting purposes. The host contract is the receivable from oil sales at the spot price on the date of sale. The embedded derivative, which is not designated as a hedge, is marked to market through oil and gas revenue each period until the final settlement occurs, which generally is limited to the month after the sale. Equity‑based Compensation For equity‑based compensation awards, compensation expense is recognized in the Company’s financial statements over the awards’ vesting periods based on their grant date fair value. The Company utilizes (i) the closing stock price on the date of grant to determine the fair value of service vesting restricted stock awards and restricted stock units and (ii) a Monte Carlo simulation to determine the fair value of restricted stock awards and restricted stock units with a combination of market and service vesting criteria. Forfeitures are recognized in the period in which they occur. Restructuring Charges The Company accounts for restructuring charges in accordance with ASC 420-Exit or Disposal Cost Obligations. Under these standards, the costs associated with restructuring charges are recorded during the period in which the liability is incurred. During the year ended December 31, 2014, we recognized $11.7 million in restructuring charges for employee severance and related benefit costs incurred as part of a corporate reorganization, which includes $5.0 million of accelerated non-cash expense related to awards previously granted under our Long-Term Incentive Plan (the “LTIP”). Treasury Stock We record treasury stock purchases at cost. The majority of our treasury stock purchases are from our employees that surrendered shares to the Company to satisfy their minimum statutory tax withholding requirements and were not part of a formal stock repurchase plan. The remainder of our treasury stock is forfeited restricted stock awards granted under our long‑term incentive plan. Income Taxes The Company accounts for income taxes as required by ASC 740—Income Taxes. Under this method, deferred income taxes are determined based on the difference between the financial statement and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts expected to be realized. On a quarterly basis, management evaluates the need for and adequacy of valuation allowances based on the expected realizability of the deferred tax assets and adjusts the amount of such allowances, if necessary. We recognize tax benefits from uncertain tax positions only if it is more likely than not that the tax position will be sustained upon examination by the tax authorities, based on the technical merits of the position. Accordingly, we measure tax benefits from such positions based on the most likely outcome to be realized. Foreign Currency Translation The U.S. dollar is the functional currency for all of the Company’s material foreign operations. Foreign currency transaction gains and losses and adjustments resulting from translating monetary assets and liabilities denominated in foreign currencies are included in other expenses. Cash balances held in foreign currencies are not significant, and as such, the effect of exchange rate changes is not material to any reporting period. Concentration of Credit Risk Our revenue can be materially affected by current economic conditions and the price of oil. However, based on the current demand for crude oil and the fact that alternative purchasers are readily available, we believe that the loss of our marketing agent and/or any of the purchasers identified by our marketing agent would not have a long‑term material adverse effect on our financial position or results of operations. Recent Accounting Standards Recently Adopted In July 2015, the FASB issued ASU 2015-11, “Simplifying the Measurement of Inventory.” ASU 2015-11 changes the measurement principle for entities that do not measure inventory using the last-in, first-out (LIFO) or retail inventory method from the lower of cost or market to lower of cost and net realizable value. The ASU also eliminates the requirement for these entities to consider replacement cost or net realizable value less an approximately normal profit margin when measuring inventory. The standard requires prospective application upon adoption. The Company has elected to early adopt ASU 2015-11 during the first quarter of 2016. The adoption of this standard did not have a material impact on the Company’s consolidated financial statements. The Company adopted ASU 2016-09, “Improvements to Employee Share-based Payment Accounting” during the year using an effective date of January 1, 2016. The change in accounting for forfeitures associated with share-based payment transactions was adopted using the modified retrospective method and resulted in a $1.9 million increase to opening accumulated deficit, a $3.0 million increase to opening additional paid-in capital and a $1.1 million increase to opening long-term deferred tax assets in the consolidated balance sheets. The changes in accounting for the recognition of excess tax benefits and tax shortfalls were adopted prospectively. In August 2016, the FASB issued ASU 2016-15, “Classification of Certain Cash Receipts and Cash Payments.” ASU 2016-15 clarifies current GAAP or provides specific guidance on eight cash flow classification issues to reduce current and potential future diversity in practice. The Company has elected to early adopt this standard using the retrospective method as prescribed by the standard. The adoption of this standard did not have a material impact on the Company’s consolidated financial statements. In November 2016, the FASB issued ASU 2016-18, “Restricted Cash (a consensus of the FASB Emerging Issues Task Force).” ASU 2016-18 requires that a statement of cash flows explain the change during the period in total of cash, cash equivalents, and amounts generally described as restricted cash and restricted cash equivalents. The ASU is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years with early adoption permitted. The Company has elected to early adopt this standard using the retrospective method as prescribed by the standard. The consolidated statements of cash flows have been reclassified to conform with the presentation required by ASU 2016-18, and the changes in restricted cash are now presented as part of the change in total cash, cash equivalents and restricted cash rather than as changes in investing activities as previously presented. Not Yet Adopted In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers (Topic 606)," which supersedes the revenue recognition requirements in ASC Topic 605, "Revenue Recognition," and most industry-specific guidance. ASU 2014-09 is based on the principle that revenue is recognized to depict the transfer of 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. ASU 2014-09 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. ASU 2014-09 applies to all contracts with customers except those that are within the scope of other topics in the FASB ASC. The new guidance is effective for annual reporting periods beginning after December 15, 2017 for public companies. Early adoption is not permitted. Entities have the option of using either a full retrospective or modified retrospective approach to adopt ASU 2014-09. As of December 31, 2016, the Company does not expect the adoption of this standard to have a material impact to our revenue recognition based on our existing contracts with customers. In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842).” ASU 2016-02 was issued to increase transparency and comparability across organizations by recognizing substantially all leases on the balance sheet through the concept of right-of-use lease assets and liabilities. Under current accounting guidance, lessees do not recognize lease assets or liabilities for leases classified as operating leases. The ASU is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years with early adoption permitted. The new leasing standard requires the modified retrospective adoption method. The Company is in the process of evaluating the impact of this accounting standard on its consolidated financial statements. In October 2016, the FASB issued ASU 2016-16, “Intra-Entity Transfers of Assets Other Than Inventory.” ASU 2016-16 requires the company to recognize income tax consequences, if any, on intercompany asset transfers, other than inventory, when the transfer occurs. The ASU is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years with early adoption permitted. The Company is in the process of evaluating the impact of this accounting standard on its consolidated financial statements. |
Acquisitions and Divestitures
Acquisitions and Divestitures | 12 Months Ended |
Dec. 31, 2016 | |
Acquisitions and Divestitures | |
Acquisitions and Divestitures | 3. Acquisitions and Divestitures 2016 Transactions In January and February 2016, we closed farm-in agreements with Equator Exploration Limited (“Equator”), an affiliate of Oando Energy Resources, for Block 5 and Block 12 offshore Sao Tome and Principe. As a result of subsequent farm-outs we currently have a 45% participating interest and operatorship in each block. The national petroleum agency, ANP STP, has a 15% and 12.5% carried interest in Block 5 and Block 12, respectively. In April 2016, we closed a farm-out agreement with Hess Suriname Exploration Limited, a wholly-owned subsidiary of the Hess Corporation (“Hess”), covering the Block 42 contract area offshore Suriname. Under the terms of the agreement, Hess acquired a one-third non-operated interest in Block 42 from both Chevron and Kosmos. As part of the agreement, Hess is funding the cost of acquiring and processing a 6,500 square kilometer 3D seismic survey, subject to a maximum spend. Additionally, Hess will disproportionately fund a portion of the first exploration well in the Block 42 contract area, subject to a maximum spend, contingent upon the partnership entering the next phase of the exploration period. The new participating interests are one-third to each of Kosmos, Chevron and Hess, respectively. Kosmos remains the operator. Staatsolie Maatschappij Suriname N.V. (“Staatsolie”), Suriname’s national oil company, has the option to back into the contract with an interest of not more than 10% upon approval of a development plan. In May 2016, Kosmos and Capricorn Exploration and Development Company Limited, a wholly owned subsidiary of Cairn Energy PLC (“Cairn”) executed a petroleum agreement with the Office National des Hydrocarbures et des Mines ("ONHYM"), the national oil company of the Kingdom of Morocco, for the Boujdour Maritime block. The Boujdour Maritime petroleum agreement largely replaces the acreage covered by the Cap Boujdour petroleum agreement which expired in March 2016. Under the terms of the petroleum agreement, Kosmos is the operator of the Boujdour Maritime block and has a 55% participating interest, Cairn has a 20% participating interest, and ONHYM holds a 25% carried interest in the block through the exploration period. In September 2016, we entered into an agreement by which BP agreed to pay Kosmos $30 million in lieu of drilling an exploration well and assigned its 45% participating interest in the Essaouira Offshore Block back to us, and the Moroccan government issued joint ministerial orders approving the assignment in October 2016, making it effective. After giving effect to the assignment, our participating interest is 75% in the Essaouria Offshore block and we remain the operator. The $30 million payment was received from BP in January 2017. In October 2016, we entered into a petroleum contract covering Block C6 with the Islamic Republic of Mauritania. As a result of a subsequent farm-out we have a 28% participating interest and provide technical exploration services to BP, the operator. The Mauritanian national oil company, Societe Mauritanienne des Hydrocarbures et de Patrimoine Minier (“SMHPM”), currently has a 10% carried participating interest during the exploration period. Block C6 currently comprises approximately 1.1 million acres (4,300 square kilometers), with a first exploration period of four years from the effective date (October 28, 2016). The first exploration phase includes a 2,000 square kilometer 3D seismic requirement. In December 2016, Kosmos closed a farm-out agreement with a subsidiary of Galp Energia SGPS S.A. (“Galp”) to farm-out a 20% non-operated stake of the Company’s interest in Blocks 5, 11, and 12 offshore Sao Tome and Principe. Based on the terms of the agreement, Galp will pay a proportionate share of Kosmos’ past costs in the form of a partial carry on the 3D seismic survey which began in the first quarter of 2017. In December 2016, we announced a partnership with affiliates of BP p.l.c. (‘‘BP’’) in Mauritania and Senegal following a competitive farm-out process for our interests in our blocks offshore Mauritania and Senegal. In Mauritania, BP acquired a 62% participating interest in our four Mauritania licenses (C6, C8, C12 and C13). In Senegal, BP acquired a 49.99% interest in Kosmos BP Senegal Limited, our controlled affiliate company which holds a 65% participating interest in the Cayar Offshore Profond and the Saint Louis Offshore Profond blocks offshore Senegal. The participating interest gives effect to the completion of our exercise in December 2016 of an option to increase our equity in each contract area from 60% to 65% in exchange for carrying Timis Corporation’s paying interest share of a third well in either contract area, subject to a maximum gross cost of $120.0 million. In consideration for these transactions, Kosmos will receive $162 million in cash up front, $221 million exploration and appraisal carry, up to $533 million in a development carry and variable consideration up to $2 per barrel for up to 1 billion barrels of liquids, structured as a production royalty, subject to future liquids discovery and prevailing oil prices. The effective date of these transactions is July 1, 2016, with BP paying interim costs from the effective date to the closing date. 2015 Transactions In March 2015, we closed a farm-in agreement with Repsol Exploracion, S.A. (“Repsol”), acquiring a non-operated interest in the Camarao, Ameijoa, Mexilhao and Ostra blocks in the Peniche Basin offshore Portugal. As part of the agreement, we reimbursed a portion of Repsol’s previously incurred exploration costs, as well as partially carried Repsol’s share of the costs of a planned 3D seismic program. After giving effect to the farm-in agreement, our participating interest is 31% in each of the blocks. In March 2015, we closed a farm‑out agreement with Chevron Corporation (“Chevron”) covering the C8, C12 and C13 petroleum contracts offshore Mauritania. As partial consideration for the farm-out, Chevron paid a disproportionate share of the costs of one exploration well, the Marsouin-1 exploration well, as well as its proportionate share of certain previously incurred exploration costs. The final allocation resulted in sales proceeds of $28.7 million, which exceeded our book basis in the assets, resulting in a $24.7 million gain on the transaction. As a further component of the consideration for the farm-out, Chevron was required to make an election by February 1, 2016, to either farm-in to the Tortue-1 exploration well by paying a disproportionate share of the costs incurred in drilling of the well or, alternatively elect to not farm-in to the Tortue-1 exploration well and pay a disproportionate share of the costs of a second contingent exploration or appraisal well in the contract areas, subject to maximum expenditure caps. Chevron failed to make this mandatory election by the required date. Consequently, pursuant to the terms of the farm-out agreement, Chevron has withdrawn from our Mauritania blocks. Chevron’s 30% non-operated participating interest was reassigned to us. In September 2015, we notified the government of Ireland and our partners that we are withdrawing from all of our blocks offshore Ireland. These blocks were acquired during 2013. In October 2015, we closed a sale and purchase agreement with ERHC Energy EEZ, LDA, whereby we acquired an 85% participating interest and operatorship in Block 11 offshore Sao Tome and Principe. The National Petroleum Agency, Agencia Nacional Do Petroleo De Sao Tome E Príncipe (“ANP STP”), has a 15% carried interest. In November 2015, we closed a farm-in agreement with Galp Energia Sao Tome E Principe, Unipessoal, LDA (“Galp”), a wholly owned subsidiary of Petrogal, S.A. to acquire a 45% non-operated participating interest in Block 6 offshore Sao Tome and Principe. 2014 Transactions In the first quarter of 2014, we closed three farm-out agreements with BP Exploration (Morocco) Limited, a wholly owned subsidiary of BP plc (“BP”), covering our three blocks in the Agadir Basin, offshore Morocco. The sales proceeds of the farm-outs were $56.9 million. The proceeds on the sale of the interests exceeded our book basis in the assets, resulting in a $23.8 million gain on the transaction. The petroleum agreements for Tarhazoute Offshore and Foum Assaka Offshore expired in June 2016 and July 2016, respectively. In the first quarter of 2014, we closed a farm-out agreement with Capricorn Exploration and Development Company Limited, a wholly owned subsidiary of Cairn Energy PLC (“Cairn”), covering the Cap Boujdour Offshore block, offshore Western Sahara. Cairn paid $1.5 million for their share of costs incurred from the effective date of the farm-out agreement through the closing date, which was recorded as a reduction in our basis. The Cap Boujdour petroleum agreement expired in March 2016. In August 2014, we entered into a farm-in agreement with Timis Corporation Limited (“Timis”), whereby we acquired a 60% participating interest and operatorship, covering the Cayar Offshore Profond and Saint Louis Offshore Profond blocks offshore Senegal. As part of the agreement, we carried the full costs of a 3D seismic program. Additionally, we carried the full costs of the Guembeul-1 exploration well and will fund Timis’ share of the costs of a second contingent exploration well in either contract area, subject to a maximum gross cost per well of $120.0 million, should Kosmos elect to drill such well. In December 2016, we exercised our option to increase our equity to 65% in exchange for carrying the full cost of a third contingent exploration or appraisal well, subject to a maximum gross cost of $120.0 million. |
Joint Interest Billings
Joint Interest Billings | 12 Months Ended |
Dec. 31, 2016 | |
Joint Interest Billings | |
Joint Interest Billings | 4. Joint Interest Billings The Company’s joint interest billings consist of receivables from partners with interests in common oil and gas properties operated by the Company. Joint interest billings are classified on the face of the consolidated balance sheets as current and long-term receivables based on when collection is expected to occur. In 2014, the Ghana National Petroleum Corporation (“GNPC”) notified us and our block partners of its request for the contractor group to pay GNPC’s 5% share of the Tweneboa, Enyenra and Ntomme (“TEN”) development costs. The block partners will be reimbursed for such costs plus interest out of a portion of GNPC’s TEN production revenues under the terms of the Deepwater Tano (“DT”) petroleum contract. As of December 31, 2016 and 2015, the joint interest billing receivables due from GNPC for the TEN fields development costs were $44.0 million and $35.3 million, respectively, which were classified as long-term on the consolidated balance sheets. |
Property and Equipment
Property and Equipment | 12 Months Ended |
Dec. 31, 2016 | |
Property and Equipment | |
Property and Equipment | 5. Property and Equipment Property and equipment is stated at cost and consisted of the following: December 31, 2016 2015 (In thousands) Oil and gas properties: Proved properties $ $ Unproved properties Support equipment and facilities Total oil and gas properties Accumulated depletion Oil and gas properties, net Other property Accumulated depreciation Other property, net Property and equipment, net $ $ We recorded depletion expense of $131.5 million, $146.6 million and $188.3 million for the years ended December 31, 2016, 2015 and 2014, respectively. |
Suspended Well Costs
Suspended Well Costs | 12 Months Ended |
Dec. 31, 2016 | |
Suspended Well Costs | |
Suspended Well Costs | 6. Suspended Well Costs The Company capitalizes exploratory well costs as unproved properties within oil and gas properties until a determination is made that the well has either found proved reserves or is impaired. If proved reserves are found, the capitalized exploratory well costs are reclassified to proved properties. Well costs are charged to exploration expense if the exploratory well is determined to be impaired. The following table reflects the Company’s capitalized exploratory well costs on completed wells as of and during the years ended December 31, 2016, 2015 and 2014. The table excludes $2.4 million, $70.3 million and $1.1 million in costs that were capitalized and subsequently expensed during the same year for the years ended December 31, 2016, 2015 and 2014, respectively. During 2014, the exploratory well costs associated with the TEN fields were reclassified to proved property. Years Ended December 31, 2016 2015 2014 (In thousands) Beginning balance $ $ $ Additions to capitalized exploratory well costs pending the determination of proved reserves Reclassification due to determination of proved reserves — — Capitalized exploratory well costs charged to expense — — Ending balance $ $ $ The following table provides aging of capitalized exploratory well costs based on the date drilling was completed and the number of projects for which exploratory well costs have been capitalized for more than one year since the completion of drilling: Years Ended December 31, 2016 2015 2014 (In thousands, except well counts) Exploratory well costs capitalized for a period of one year or less $ $ $ Exploratory well costs capitalized for a period of one to two years Exploratory well costs capitalized for a period of three to seven years Ending balance $ $ $ Number of projects that have exploratory well costs that have been capitalized for a period greater than one year As of December 31, 2016, the projects with exploratory well costs capitalized for more than one year since the completion of drilling are related to Mahogany, Teak (formerly Teak‑1 and Teak‑2) and Akasa discoveries in the West Cape Three Points (“WCTP”) Block and the Wawa discovery in the DT Block, which are all located offshore Ghana, the Greater Tortue discovery which crosses the Mauritania and Senegal maritime border and the Marsouin discovery in Block C8 offshore Mauritania. Mahogany and Teak Discoveries — In November 2015, we signed the Jubilee Field Unit Expansion Agreement with our partners to allow for the development of the Mahogany and Teak discoveries through the Jubilee FPSO and infrastructure. The expansion of the Jubilee Unit becomes effective upon approval by Ghana’s Ministry of Energy of the Greater Jubilee Full Field Development Plan (“GJFFDP”), which was submitted to the government of Ghana in December 2015. The GJFFDP encompasses future development of the Jubilee Field, in addition to future development of the Mahogany and Teak discoveries, which were declared commercial during 2015. We are currently in discussions with the government of Ghana concerning the GJFFDP. Upon approval of the GJFFDP by the Ministry of Energy, the Jubilee Unit will be expanded to include the Mahogany and Teak discoveries and revenues and expenses associated with these discoveries will be at the Jubilee Unit interests. The WCTP Block partners have agreed they will take the steps necessary to transfer operatorship of the remaining portions of the WCTP Block to Tullow after approval of the GJFFDP by Ghana’s Ministry of Energy. Akasa Discovery — We are currently in discussions with the government of Ghana regarding additional technical studies and evaluation that we want to conduct before we are able to make a determination regarding commerciality of the discovery. If we determine the discovery to be commercial, a declaration of commerciality would be provided and a PoD would be prepared and submitted to Ghana’s Ministry of Energy, as required under the WCTP petroleum contract. The WCTP Block partners have agreed they will take the steps necessary to transfer operatorship of the remaining portions of the WCTP Block, including the Akasa Discovery, to Tullow after approval of the GJFFDP by Ghana’s Ministry of Energy. Wawa Discovery — In February 2016, we requested the Ghana Ministry of Energy to approve the enlargement of the areal extent of the TEN fields and production area to capture the resource accumulation located in the Wawa Discovery Area for a potential future integrated development with the TEN fields. In April 2016, the Ghana Ministry of Energy approved our request to enlarge the TEN development and production area subject to continued subsurface and development concept evaluation, along with the requirement to integrate the Wawa Discovery into the TEN PoD. Greater Tortue Discovery — In May 2015, we completed the Tortue-1 exploration well in Block C8 offshore Mauritania which encountered hydrocarbon pay. Two additional wells have been drilled. Following additional evaluation, a decision regarding commerciality will be made. Marsouin Discovery — In November 2015, we completed the Marsouin-1 exploration well in the northern part of Block C8 offshore Mauritania which encountered hydrocarbon pay. Following additional evaluation, a decision regarding commerciality will be made. |
Debt
Debt | 12 Months Ended |
Dec. 31, 2016 | |
Debt | |
Debt | 7. Debt December 31, 2016 2015 (In thousands) Outstanding debt principal balances: Facility $ $ Senior Notes Total Unamortized deferred financing costs and discounts(1) Long-term debt $ $ (1) Includes $30.3 million and $37.5 million of unamortized deferred financing costs related to the Facility and $22.8 million and $26.6 million of unamortized deferred financing costs and discounts related to the Senior Notes as of December 31, 2016 and December 31, 2015, respectively. Facility In March 2014, the Company amended and restated the Facility with a total commitment of $1.5 billion from a number of financial institutions. The Facility supports our oil and gas exploration, appraisal and development programs and corporate activities. As part of the debt refinancing in March 2014, the repayment of borrowings under the existing facility attributable to financial institutions that did not participate in the amended Facility was accounted for as an extinguishment of debt, and existing unamortized debt issuance costs attributable to those participants were expensed. As a result, we recorded a $2.9 million loss on the extinguishment of debt. As of December 31, 2016, we have $30.3 million of unamortized issuance costs related to the Facility, which will be amortized over the remaining term of the Facility, including certain costs related to the amendment. In September 2016, following the lender’s semi-annual redetermination, the borrowing base under our Facility was $1.467 billion (effective October 1, 2016). The borrowing base calculation includes value related to the Jubilee and TEN fields. As of December 31, 2016, borrowings under the Facility totaled $850.0 million and the undrawn availability under the Facility was $616.9 million. Interest is the aggregate of the applicable margin (3.25% to 4.50%, depending on the length of time that has passed from the date the Facility was entered into); LIBOR; and mandatory cost (if any, as defined in the Facility). Interest is payable on the last day of each interest period (and, if the interest period is longer than six months, on the dates falling at six-month intervals after the first day of the interest period). We pay commitment fees on the undrawn and unavailable portion of the total commitments, if any. Commitment fees are equal to 40% per annum of the then-applicable respective margin when a commitment is available for utilization and, equal to 20% per annum of the then-applicable respective margin when a commitment is not available for utilization. We recognize interest expense in accordance with ASC 835—Interest, which requires interest expense to be recognized using the effective interest method. We determined the effective interest rate based on the estimated level of borrowings under the Facility. As part of the March 2014 amendment, the Facility’s estimated effective interest rate was changed and, accordingly, we adjusted our estimate of deferred interest previously recorded during prior years by $4.5 million, which was recorded as a reduction to interest expense for the year ended December 31, 2014. The Facility provides a revolving credit and letter of credit facility. The availability period for the revolving- credit facility, as amended in March 2014 expires on March 31, 2018, however the Facility has a revolving-credit sublimit, which will be the lesser of $500.0 million and the total available facility at that time, that will be available for drawing until the date falling one month prior to the final maturity date. The letter of credit facility expires on the final maturity date. The available facility amount is subject to borrowing base constraints and, beginning on March 31, 2018, outstanding borrowings will be constrained by an amortization schedule. The Facility has a final maturity date of March 31, 2021. As of December 31, 2016, we had no letters of credit issued under the Facility. Kosmos has the right to cancel all the undrawn commitments under the Facility. The amount of funds available to be borrowed under the Facility, also known as the borrowing base amount, is determined each year on March 31 and September 30. The borrowing base amount is based on the sum of the net present values of net cash flows and relevant capital expenditures reduced by certain percentages as well as value attributable to certain assets’ reserves and/or resources in Ghana. If an event of default exists under the Facility, the lenders can accelerate the maturity and exercise other rights and remedies, including the enforcement of security granted pursuant to the Facility over certain assets held by our subsidiaries. The Facility contains customary cross default provisions. We were in compliance with the financial covenants contained in the Facility as of the September 30, 2016 (the most recent assessment date). Corporate Revolver In November 2012, we secured a Corporate Revolver from a number of financial institutions which, as amended in June 2015, has an availability of $400.0 million. The Corporate Revolver is available for all subsidiaries for general corporate purposes and for oil and gas exploration; appraisal and development programs. As of December 31, 2016, we have $5.2 million of net deferred financing costs related to the Corporate Revolver, which will be amortized over the remaining term, which as amended expires in November 2018. These deferred financing costs are included in the Other assets section of the consolidated balance sheet. As of December 31, 2016, there were no borrowings outstanding under the Corporate Revolver and the undrawn availability under the Corporate Revolver was $400.0 million. Interest is the aggregate of the applicable margin (6.0%); LIBOR; and mandatory cost (if any, as defined in the Corporate Revolver). Interest is payable on the last day of each interest period (and, if the interest period is longer than six months, on the dates falling at six‑month intervals after the first day of the interest period). We pay commitment fees on the undrawn portion of the total commitments. Commitment fees, as amended in June 2015, for the lenders are equal to 30% per annum of the respective margin when a commitment is available for utilization. The Corporate Revolver, as amended in June 2015, expires on November 23, 2018. The available amount is not subject to borrowing base constraints. Kosmos has the right to cancel all the undrawn commitments under the Corporate Revolver. The Company is required to repay certain amounts due under the Corporate Revolver with sales of certain subsidiaries or sales of certain assets. If an event of default exists under the Corporate Revolver, the lenders can accelerate the maturity and exercise other rights and remedies, including the enforcement of security granted pursuant to the Corporate Revolver over certain assets held by us. We were in compliance with the financial covenants contained in the Corporate Revolver as of September 30, 2016 (the most recent assessment date). The Corporate Revolver contains customary cross default provisions. Revolving Letter of Credit Facility In July 2013, we entered into a revolving letter of credit facility agreement (“LC Facility”). The size of the LC Facility is $75.0 million, as amended in July 2015, with additional commitments up to $50.0 million being available if the existing lender increases its commitment or if commitments from new financial institutions are added. The LC Facility provides that we maintain cash collateral in an amount equal to at least 75% of all outstanding letters of credit under the LC Facility, provided that during the period of any breach of certain financial covenants, the required cash collateral amount shall increase to 100%. In July 2016, we amended and restated the LC Facility, extending the maturity date to July 2019. The LC Facility size remains at $75.0 million, as amended in July 2015, with additional commitments up to $50.0 million being available if the existing lender increases its commitment or if commitments from new financial institutions are added. Other amendments include increasing the margin from 0.5% to 0.8% per annum on amounts outstanding, adding a commitment fee payable quarterly in arrears at an annual rate equal to 0.65% on the available commitment amount and providing for issuance fees to be payable to the lender per new issuance of a letter of credit. We may voluntarily cancel any commitments available under the LC Facility at any time. As of December 31, 2016, there were nine outstanding letters of credit totaling $72.8 million under the LC Facility. The LC Facility contains customary cross default provisions. In February 2017, we exercised an option to increase the size of the LC Facility to $125.0 million to facilitate the issuance of additional letters of credit. 7.875% Senior Secured Notes due 2021 During August 2014, the Company issued $300.0 million of Senior Notes and received net proceeds of approximately $292.5 million after deducting discounts, commissions and deferred financing costs. The Company used the net proceeds to repay a portion of the outstanding indebtedness under the Facility and for general corporate purposes. During April 2015, we issued an additional $225.0 million of Senior Notes and received net proceeds of $206.8 million after deducting discounts, commissions and other expenses. We used the net proceeds to repay a portion of the outstanding indebtedness under the Facility and for general corporate purposes. The additional $225.0 million of Senior Notes have identical terms to the initial $300.0 million Senior Notes, other than the date of issue, the initial price, the first interest payment date and the first date from which interest accrued. The Senior Notes mature on August 1, 2021. Interest is payable semi-annually in arrears each February 1 and August 1 commencing on February 1, 2015 for the initial $300.0 million Senior Notes and August 1, 2015 for the additional $225.0 million Senior Notes. The Senior Notes are secured (subject to certain exceptions and permitted liens) by a first ranking fixed equitable charge on all shares held by us in our direct subsidiary, Kosmos Energy Holdings. The Senior Notes are currently guaranteed on a subordinated, unsecured basis by our existing restricted subsidiaries that guarantee the Facility and the Corporate Revolver, and, in certain circumstances, the Senior Notes will become guaranteed by certain of our other existing or future restricted subsidiaries (the “Guarantees”). Redemption and Repurchase . At any time prior to August 1, 2017 and subject to certain conditions, the Company may, on any one or more occasions, redeem up to 35% of the aggregate principal amount of Senior Notes issued under the indenture dated August 1, 2014 related to the Senior Notes (the “Indenture”) at a redemption price of 107.875%, plus accrued and unpaid interest, with the cash proceeds of certain eligible equity offerings. Additionally, at any time prior to August 1, 2017, the Company may, on any one or more occasions, redeem all or a part of the Senior Notes at a redemption price equal to 100%, plus any accrued and unpaid interest, and a make-whole premium. On or after August 1, 2017, the Company may redeem all or a part of the Senior Notes at the redemption prices (expressed as percentages of principal amount) set forth below plus accrued and unpaid interest: Year Percentage On or after August 1, 2017, but before August 1, 2018 % On or after August 1, 2018, but before August 1, 2019 % On or after August 1, 2019 and thereafter % We may also redeem the Senior Notes in whole, but not in part, at any time if changes in tax laws impose certain withholding taxes on amounts payable on the Senior Notes at a price equal to the principal amount of the Senior Notes plus accrued interest and additional amounts, if any, as may be necessary so that the net amount received by each holder after any withholding or deduction on payments of the Senior Notes will not be less than the amount such holder would have received if such taxes had not been withheld or deducted. Upon the occurrence of a change of control triggering event as defined under the Indenture, the Company will be required to make an offer to repurchase the Senior Notes at a repurchase price equal to 101% of the principal amount, plus accrued and unpaid interest to, but excluding, the date of repurchase. If we sell assets, under certain circumstances outlined in the Indenture, we will be required to use the net proceeds to make an offer to purchase the Senior Notes at an offer price in cash in an amount equal to 100% of the principal amount of the Senior Notes, plus accrued and unpaid interest to, but excluding, the repurchase date. Covenants. The Indenture restricts our ability and the ability of our restricted subsidiaries to, among other things: incur or guarantee additional indebtedness, create liens, pay dividends or make distributions in respect of capital stock, purchase or redeem capital stock, make investments or certain other restricted payments, sell assets, enter into agreements that restrict the ability of our subsidiaries to make dividends or other payments to us, enter into transactions with affiliates, or effect certain consolidations, mergers or amalgamations. These covenants are subject to a number of important qualifications and exceptions. Certain of these covenants will be terminated if the Senior Notes are assigned an investment grade rating by both Standard & Poor’s Rating Services and Fitch Ratings Inc. and no default or event of default has occurred and is continuing. Collateral. The Senior Notes are secured (subject to certain exceptions and permitted liens) by a first ranking fixed equitable charge on all currently outstanding shares, additional shares, dividends or other distributions paid in respect of such shares or any other property derived from such shares, in each case held by us in relation to the Company’s direct subsidiary, Kosmos Energy Holdings, pursuant to the terms of the Charge over Shares of Kosmos Energy Holdings dated November 23, 2012, as amended and restated on March 14, 2014, between the Company and BNP Paribas as Security and Intercreditor Agent. The Senior Notes share pari passu in the benefit of such equitable charge based on the respective amounts of the obligations under the Indenture and the amount of obligations under the Corporate Revolver. The Guarantees are not secured. At December 31, 2016, the estimated repayments of debt during the five years and thereafter are as follows: Payments Due by Year Total 2017 2018 2019 2020 2021 Thereafter (In thousands) Principal debt repayments(1) $ $ — $ — $ $ $ $ — (1) Includes the scheduled principal maturities for the $525.0 million aggregate principal amount of Senior Notes issued in August 2014 and April 2015 and the Facility. The scheduled maturities of debt related to the Facility are based on the level of borrowings and the estimated future available borrowing base as of December 31, 2016. Any increases or decreases in the level of borrowings or increases or decreases in the available borrowing base would impact the scheduled maturities of debt during the next five years and thereafter. As of December 31, 2016, there were no borrowings under the Corporate Revolver. Interest and other financing costs, net Interest and other financing costs, net incurred during the period comprised of the following: Years Ended December 31, 2016 2015 2014 (In thousands) Interest expense $ $ $ Amortization—deferred financing costs Loss on extinguishment of debt — Capitalized interest Deferred interest Interest income Other, net Interest and other financing costs, net $ $ $ |
Derivative Financial Instrument
Derivative Financial Instruments | 12 Months Ended |
Dec. 31, 2016 | |
Derivative Instruments and Hedging Activities | |
Derivative Financial Instruments | 8. Derivative Financial Instruments We use financial derivative contracts to manage exposures to commodity price and interest rate fluctuations. We do not hold or issue derivative financial instruments for trading purposes. We manage market and counterparty credit risk in accordance with our policies and guidelines. In accordance with these policies and guidelines, our management determines the appropriate timing and extent of derivative transactions. We have included an estimate of nonperformance risk in the fair value measurement of our derivative contracts as required by ASC 820—Fair Value Measurements and Disclosures. Oil Derivative Contracts The following table sets forth the volumes in barrels underlying the Company’s outstanding oil derivative contracts and the weighted average Dated Brent prices per Bbl for those contracts as of December 31, 2016. Volumes are net of any offsetting derivative contracts entered into. Weighted Average Dated Brent Price per Bbl Net Deferred Premium Term Type of Contract MBbl Payable Swap Sold Put Floor Ceiling Call 2017: January — December Swap with puts/calls $ $ $ $ — $ — $ January — December Swap with puts — — — — January — December Three-way collars — — January — December Sold calls(1) — — — — — 2018: January — December Three-way collars $ $ — $ $ $ $ — January — December Sold calls(1) — — — — — 2019: January — December Sold calls(1) $ — $ — $ — $ — $ $ — (1) Represents call option contracts sold to counterparties to enhance other derivative positions. In February 2017, we entered into three-way collar contracts for 1.0 MMBbl from January 2018 through December 2018 with a floor price of $50.00 per barrel, a ceiling price of $62.00 per barrel and a purchased call price of $70.00 per barrel. The contracts are indexed to Dated Brent prices and have a weighted average deferred premium payable of $2.32 per barrel. Interest Rate Derivative Contracts The following table summarizes our capped interest rate swaps whereby we pay a fixed rate of interest if LIBOR is below the cap, and pay the market rate less the spread between the cap (sold call) and the fixed rate of interest if LIBOR is above the cap as of December 31, 2016: Weighted Average Term Type of Contract Floating Rate Notional Swap Sold Call (In thousands) January 2017 — December 2018 Capped swap 1-month LIBOR $ % % Effective June 1, 2010, we discontinued hedge accounting on all interest rate derivative instruments. Therefore, from that date forward, changes in the fair value of the instruments have been recognized in earnings during the period of change. The effective portions of the discontinued hedges as of May 31, 2010, were included in AOCI in the equity section of the accompanying consolidated balance sheets, and were transferred to earnings when the hedged transaction settled. As of December 31, 2015 all instruments previously designated as hedges have settled and there is no balance remaining in AOCI. See Note 9—Fair Value Measurements for additional information regarding the Company’s derivative instruments. The following tables disclose the Company’s derivative instruments as of December 31, 2016 and 2015 and gain/(loss) from derivatives during the years ended December 31, 2016, 2015 and 2014 Estimated Fair Value Asset (Liability) December 31, Type of Contract Balance Sheet Location 2016 2015 (In thousands) Derivatives not designated as hedging instruments: Derivative assets: Commodity(1) Derivatives assets—current $ $ Commodity(2) Derivatives assets—long-term Interest rate Derivatives assets—long-term Derivative liabilities: Commodity(3) Derivatives liabilities—current — Interest rate Derivatives liabilities—current Commodity(4) Derivatives liabilities—long-term Total derivatives not designated as hedging instruments $ $ (1) Includes net deferred premiums payable of $3.9 million and $6.2 million related to commodity derivative contracts as of December 31, 2016 and 2015, respectively. (2) Includes net deferred premiums payable of $2.5 million and $6.9 million related to commodity derivative contracts as of December 31, 2016 and 2015, respectively. (3) Includes $30.9 thousand and zero as of December 31, 2016 and December 31, 2015, respectively which represents our provisional oil sales contract. Also, includes net deferred premiums payable of $6.2 million and zero related to commodity derivative contracts as of December 31, 2016 and 2015, respectively. (4) Includes net deferred premiums payable of $0.6 million and zero related to commodity derivative contracts as of December 31, 2016 and 2015, respectively. Amount of Gain/(Loss) Years Ended December 31, Type of Contract Location of Gain/(Loss) 2016 2015 2014 (In thousands) Derivatives in cash flow hedging relationships: Interest rate(1) Interest expense $ — $ $ Total derivatives in cash flow hedging relationships $ — $ $ Derivatives not designated as hedging instruments: Commodity(2) Oil and gas revenue $ $ $ Commodity Derivatives, net Interest rate Interest expense Total derivatives not designated as hedging instruments $ $ $ (2) (1) Amounts were reclassified from AOCI into earnings upon settlement. (2) Amounts represent the change in fair value of our provisional oil sales contracts. Offsetting of Derivative Assets and Derivative Liabilities Our derivative instruments which are subject to master netting arrangements with our counterparties only have the right of offset when there is an event of default. As of December 31, 2016 and 2015, there was not an event of default and, therefore, the associated gross asset or gross liability amounts related to these arrangements are presented on the consolidated balance sheets. |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2016 | |
Fair Value Measurements | |
Fair Value Measurements | 9. Fair Value Measurements In accordance with ASC 820—Fair Value Measurements and Disclosures, fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. We prioritize the inputs used in measuring fair value into the following fair value hierarchy: · Level 1—quoted prices for identical assets or liabilities in active markets. · Level 2—quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs derived principally from or corroborated by observable market data by correlation or other means. · Level 3—unobservable inputs for the asset or liability. The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in its entirety. The following tables present the Company’s assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2016 and 2015, for each fair value hierarchy level: Fair Value Measurements Using: Quoted Prices in Active Markets for Significant Other Significant Identical Assets Observable Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Total (In thousands) December 31, 2016 Assets: Commodity derivatives $ — $ $ — $ Interest rate derivatives — — Liabilities: Commodity derivatives — — Interest rate derivatives — — Total $ — $ $ — $ December 31, 2015 Assets: Commodity derivatives $ — $ $ — $ Interest rate derivatives — — Liabilities: Commodity derivatives — — Interest rate derivatives — — Total $ — $ $ — $ The book values of cash and cash equivalents and restricted cash approximate fair value based on Level 1 inputs. Joint interest billings, oil sales and other receivables, and accounts payable and accrued liabilities approximate fair value due to the short‑term nature of these instruments. Our long‑term receivables, after any allowances for doubtful accounts, and other long-term assets approximate fair value. The estimates of fair value of these items are based on Level 2 inputs. Commodity Derivatives Our commodity derivatives represent crude oil three‑way collars, put options, call options and swaps for notional barrels of oil at fixed Dated Brent oil prices. The values attributable to our oil derivatives are based on (i) the contracted notional volumes, (ii) independent active futures price quotes for Dated Brent, (iii) a credit‑adjusted yield curve applicable to each counterparty by reference to the credit default swap (“CDS”) market and (iv) an independently sourced estimate of volatility for Dated Brent. The volatility estimate was provided by certain independent brokers who are active in buying and selling oil options and was corroborated by market‑quoted volatility factors. The deferred premium is included in the fair market value of the commodity derivatives. See Note 8—Derivative Financial Instruments for additional information regarding the Company’s derivative instruments. Provisional Oil Sales The value attributable to the provisional oil sales derivative is based on (i) the sales volumes and (ii) the difference in the independent active futures price quotes for Dated Brent over the term of the pricing period designated in the sales contract and the spot price on the lifting date. Interest Rate Derivatives We enter into interest rate swaps, whereby the Company pays a fixed rate of interest and the counterparty pays a variable LIBOR‑based rate. We also enter into capped interest rate swaps, whereby the Company pays a fixed rate of interest if LIBOR is below the cap, and pays the market rate less the spread between the cap and the fixed rate of interest if LIBOR is above the cap. The values attributable to the Company’s interest rate derivative contracts are based on (i) the contracted notional amounts, (ii) LIBOR yield curves provided by independent third parties and corroborated with forward active market‑quoted LIBOR yield curves and (iii) a credit‑adjusted yield curve as applicable to each counterparty by reference to the CDS market. Debt The following table presents the carrying values and fair values at December 31, 2016 and 2015: December 31, 2016 December 31, 2015 Carrying Value Fair Value Carrying Value Fair Value (In thousands) Senior Notes $ $ $ $ Facility Total $ $ $ $ The carrying value of our Senior Notes represents the principal amounts outstanding less unamortized discounts. The fair value of our Senior Notes is based on quoted market prices, which results in a Level 1 fair value measurement. The carrying value of the Facility approximates fair value since it is subject to short-term floating interest rates that approximate the rates available to us for those periods. |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2016 | |
Asset Retirement Obligations | |
Asset Retirement Obligations | 10. Asset Retirement Obligations The following table summarizes the changes in the Company’s asset retirement obligations: December 31, 2016 2015 (In thousands) Asset retirement obligations: Beginning asset retirement obligations $ $ Liabilities incurred during period Revisions in estimated retirement obligations — Accretion expense Ending asset retirement obligations $ $ The Ghanaian legal and regulatory regime regarding oil field abandonment and other environmental matters is evolving. Currently, no Ghanaian environmental regulations expressly require that companies abandon or remove offshore assets. Under the Environmental Permit for the Jubilee Field, a decommissioning plan will be prepared and submitted to the Ghana Environmental Protection Agency. ASC 410—Asset Retirement and Environmental Obligations requires the Company to recognize this liability in the period in which the liability was incurred. The TEN fields commenced production during the third quarter and an asset retirement obligation was recorded for the facilities and wells that came online during 2016. Additional asset retirement obligations will be recorded in the period in which additional wells within our producing fields are commissioned. |
Equity-based Compensation
Equity-based Compensation | 12 Months Ended |
Dec. 31, 2016 | |
Equity-based Compensation | |
Equity-based Compensation | 11. Equity‑based Compensation Restricted Stock Awards and Restricted Stock Units Prior to our corporate reorganization, Kosmos Energy Holdings issued common units designated as profit units with a threshold value ranging from $0.85 to $90 to employees, management and directors. Profit units were equity awards that were measured on the grant date and expensed over a vesting period of four years. Founding management and directors vested 20% as of the date of issuance and an additional 20% on the anniversary date for each of the next four years. Profit units issued to employees vested 50% on the second and fourth anniversaries of the issuance date. As part of the corporate reorganization in May 2011, vested profit units were exchanged for 31.7 million common shares of Kosmos Energy Ltd., unvested profit units were exchanged for 10.0 million restricted stock awards and the $90 profit units were cancelled. These restricted stock awards ultimately vested during 2015. Based on the terms and conditions of the corporate reorganization, the exchange of profit units for common shares of Kosmos Energy Ltd. resulted in no incremental compensation costs. In April 2011, the Board of Directors approved the LTIP, which provides for the granting of incentive awards in the form of stock options, stock appreciation rights, restricted stock awards, restricted stock units, among other award types. In January 2015, the board of directors approved an amendment to the plan to add 15.0 million shares to the plan which was approved at the Annual General Meeting in June 2015. The LTIP provides for the issuance of 39.5 million shares pursuant to awards under the plan, in addition to the 10.0 million restricted stock awards exchanged for unvested profit units. As of December 31, 2016, the Company had approximately 8.3 million shares that remain available for issuance under the LTIP. The Company adopted ASU 2016-09, “Improvements to Employee Share-based Payment Accounting” during the second quarter of 2016 using an effective date of January 1, 2016. Prior period compensation expense disclosed below includes estimated forfeitures and has not been adjusted. We record equity-based compensation expense equal to the fair value of share‑based payments over the vesting periods of the LTIP awards. We recorded compensation expense from awards granted under our LTIP of $40.1 million, $75.1 million and $74.5 million during the years ended December 31, 2016, 2015 and 2014, respectively. During the year ended December 31, 2014, an additional $5.0 million of equity-based compensation was recorded as restructuring charges. The total tax benefit for the years ended December 31, 2016, 2015 and 2014 was $13.0 million, $25.7 million and $25.7 million, respectively. Additionally, we expensed a tax shortfall related to equity‑based compensation of $5.5 million, $18.6 million and $6.5 million for the years ended December 31, 2016, 2015 and 2014, respectively. The fair value of awards vested during 2016, 2015 and 2014 was approximately $14.4 million, $52.2 million, and $37.0 million, respectively. The Company granted both restricted stock awards and restricted stock units with service vesting criteria and granted both restricted stock awards and restricted stock units with a combination of market and service vesting criteria under the LTIP. Substantially, all of these awards vest over three or four year periods. Restricted stock awards are issued and included in the number of outstanding shares upon the date of grant and, if such awards are forfeited, they become treasury stock. Upon vesting, restricted stock units become issued and outstanding stock. The following table reflects the outstanding restricted stock awards as of December 31, 2016: Weighted- Market / Service Weighted- Service Vesting Average Vesting Average Restricted Stock Grant-Date Restricted Stock Grant-Date Awards Fair Value Awards Fair Value (In thousands) (In thousands) Outstanding at December 31, 2013 $ $ Granted — — — — Forfeited Vested — — Outstanding at December 31, 2014 Granted — — Forfeited Vested Outstanding at December 31, 2015 Granted — — — — Forfeited — — Vested Outstanding at December 31, 2016 — — The following table reflects the outstanding restricted stock units as of December 31, 2016: Weighted- Market / Service Weighted- Service Vesting Average Vesting Average Restricted Stock Grant-Date Restricted Stock Grant-Date Units Fair Value Units Fair Value (In thousands) (In thousands) Outstanding at December 31, 2013 $ $ Granted Forfeited Vested — — Outstanding at December 31, 2014 Granted Forfeited Vested — — Outstanding at December 31, 2015 $ $ Granted Forfeited Vested Outstanding at December 31, 2016 As of December 31, 2016, total equity‑based compensation to be recognized on unvested restricted stock awards and restricted stock units is $31.6 million over a weighted average period of 1.3 years. For restricted stock awards and restricted stock units with a combination of market and service vesting criteria, the number of common shares to be issued is determined by comparing the Company’s total shareholder return with the total shareholder return of a predetermined group of peer companies over the performance period and can vest in up to 100% of the awards granted for restricted stock awards and up to 200% of the awards granted for restricted stock units. The grant date fair value of these awards ranged from $6.70 to $13.57 per award for restricted stock awards and $4.83 to $15.81 per award for restricted stock units. The Monte Carlo simulation model utilizes multiple input variables that determine the probability of satisfying the market condition stipulated in the award grant and calculates the fair value of the award. The expected volatility utilized in the model was estimated using our historical volatility and the historical volatilities of our peer companies and ranged from 41.3% to 56.7% for restricted stock awards and 44.0% to 54.0% for restricted stock units. The risk‑free interest rate was based on the U.S. treasury rate for a term commensurate with the expected life of the grant and ranged from 0.5% to 1.1% for restricted stock awards and 0.5% to 1.2% for restricted stock units. For profit units that were exchanged for restricted stock awards, the significant assumptions used to calculate the fair values of the profit units granted as calculated using a binomial tree, were as follows: no dividend yield, expected volatility ranging from approximately 25% to 66%; risk‑free interest rate ranging from 1.3% to 5.1%; expected life ranging from 1.2 to 8.1 years; and projected turnover rates ranging from 7.0% to 27.0% for employees and none for management. For profit units granted immediately prior to our initial public offering, we utilized the midpoint of the range of the estimated offering price, or $17.00 per share. In January 2017, we granted 1.8 million service vesting restricted stock units and 2.1 million market and service vesting restricted stock units to our employees under our long-term incentive plan. We expect to recognize approximately $34.1 million of non-cash compensation expense related to these grants over the next three years. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2016 | |
Income Taxes | |
Income Taxes | 12. Income Taxes Kosmos Energy Ltd. is a Bermuda company that is not subject to taxation at the corporate level. We provide for income taxes based on the laws and rates in effect in the countries in which our operations are conducted. The relationship between our pre‑tax income or loss from continuing operations and our income tax expense or benefit varies from period to period as a result of various factors which include changes in total pre‑tax income or loss, the jurisdictions in which our income (loss) is earned and the tax laws in those jurisdictions. The components of income (loss) before income taxes were as follows: Years Ended December 31, 2016 2015 2014 (In thousands) Bermuda $ $ $ United States Foreign—other Income (loss) before income taxes $ $ $ The components of the provision for income taxes attributable to our income (loss) before income taxes consist of the following: Years Ended December 31, 2016 2015 2014 (In thousands) Current: Bermuda $ — $ — $ — United States Foreign—other Total current Deferred: Bermuda — — — United States Foreign—other Total deferred Income tax expense (benefit) $ $ $ Our reconciliation of income tax expense (benefit) computed by applying our Bermuda statutory rate and the reported effective tax rate on income (loss) from continuing operations is as follows: Years Ended December 31, 2016 2015 2014 (In thousands) Tax at Bermuda statutory rate $ — $ — $ — Foreign income (loss) taxed at different rates Change in valuation allowance and the expiration of fully valued deferred tax assets Non-deductible and other items Tax shortfall on equity-based compensation Total tax expense (benefit) $ $ $ Effective tax rate(1) % % % (1) The effective tax rate during the years ended December 31, 2016, 2015 and 2014 were impacted by losses of $121.4 million, $153.5 million and $159.9 million, respectively, incurred in jurisdictions in which we are not subject to taxes and therefore do not generate any income tax benefits. The effective tax rate for the United States is approximately 179%, 220% and 81% for the years ended December 31, 2016, 2015 and 2014, respectively. The effective tax rate in the United States is impacted by the effect of equity-based compensation tax shortfalls equal to the excess income tax benefit recognized for financial statement purposes over the income tax benefit realized for tax return purposes. The effective tax rate for Ghana is approximately 23%, 35% and 36% for the years ended December 31, 2016, 2015 and 2014, respectively. The effective tax rate in Ghana is impacted by non-deductible expenditures associated with the damage to the turret bearing, which we expect to recover from insurance proceeds. Any such insurance recoveries would not be subject to income tax. Our operations in other foreign jurisdictions have a 0% effective tax rate because they reside in countries with a 0% statutory rate or we have incurred losses in those countries and have full valuation allowances against the corresponding net deferred tax assets. Deferred tax assets and liabilities, which are computed on the estimated income tax effect of temporary differences between financial and tax bases in assets and liabilities, are determined using the tax rates expected to be in effect when taxes are actually paid or recovered. In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. The tax effects of significant temporary differences giving rise to deferred tax assets and liabilities are as follows: December 31, 2016 2015 (In thousands) Deferred tax assets: Foreign capitalized operating expenses $ $ Foreign net operating losses Equity compensation Other Total deferred tax assets Valuation allowance Total deferred tax assets, net Deferred tax liabilities: Depletion, depreciation and amortization related to property and equipment Unrealized derivative gains Total deferred tax liabilities Net deferred tax liability $ $ The Company has recorded a full valuation allowance against the net deferred tax assets in countries where we only have exploration operations. The net decrease in the valuation allowance of $29.0 million is due to the write-off of previously capitalized foreign operating expenses and tax losses in Morocco related to the relinquishment of three licenses and the utilization of deferred tax assets to offset the tax impact of a payment from a joint license holder related to their withdrawal from three licenses, together totaling $58.2 million. The decrease in valuation allowance was partially offset by the tax effect of 2016 losses and foreign capitalized operating expenses of $29.2 million. The Company has entered into various petroleum contracts in Morocco. These petroleum contracts provide for a tax holiday, at a 0% tax rate, for a period of 10 years beginning on the date of first production, if any. The Company has foreign net operating loss carryforwards of $116.7 million. Of these losses, we expect $0.9 million, $13.4 million, $0.5 million, $0.5 million and $0.6 million to expire in 2019, 2020, 2021, 2022 and 2023, respectively, and $100.8 million do not expire. The Ghana tax loss of $53.3 million is expected to be fully utilized in 2017. The remaining $63.4 million in tax losses currently have offsetting valuation allowances. A subsidiary of the Company files a U.S. federal income tax return and a Texas margin tax return. In addition to the United States, the Company files income tax returns in the countries in which we operate. The Company is open to U.S. federal income tax examinations for tax years 2013 through 2016 and to Texas margin tax examinations for the tax years 2011 through 2016. In addition, the Company is open to income tax examinations for years 2011 through 2016 in its significant other foreign jurisdictions, primarily Ghana. As of December 31, 2016, the Company had no material uncertain tax positions. The Company’s policy is to recognize potential interest and penalties related to income tax matters in income tax expense. |
Net Income (Loss) Per Share
Net Income (Loss) Per Share | 12 Months Ended |
Dec. 31, 2016 | |
Net income (loss) per share | |
Net Income (Loss) Per Share | 13. Net Income (Loss) Per Share In the calculation of basic net income per share, participating securities are allocated earnings based on actual dividend distributions received plus a proportionate share of undistributed net income, if any. We calculate basic net income per share under the two‑class method. Diluted net income (loss) per share is calculated under both the two-class method and the treasury stock method and the more dilutive of the two calculations is presented. The computation of diluted net income (loss) per share reflects the potential dilution that could occur if all outstanding awards under our LTIP were converted into common shares or resulted in the issuance of common shares that would then share in the earnings of the Company. During periods in which the Company realizes a loss from continuing operations securities would not be dilutive to net loss per share and conversion into common shares is assumed not to occur. Basic net income (loss) per share is computed as (i) net income (loss), (ii) less income allocable to participating securities (iii) divided by weighted average basic shares outstanding. The Company’s diluted net income (loss) per share is computed as (i) basic net income (loss), (ii) plus diluted adjustments to income allocable to participating securities (iii) divided by weighted average diluted shares outstanding. Years Ended December 31, 2016 2015 2014 (In thousands, except per share data) Numerator: Net income (loss) $ $ $ Basic income allocable to participating securities(1) — — Basic net income (loss) allocable to common shareholders Diluted adjustments to income allocable to participating securities(1) — — Diluted net income (loss) allocable to common shareholders $ $ $ Denominator: Weighted average number of shares outstanding: Basic Restricted stock awards and units(1)(2) — — Diluted Net income (loss) per share: Basic $ $ $ Diluted $ $ $ (1) Our service vesting restricted stock awards represent participating securities because they participate in non-forfeitable dividends with common equity owners. Income allocable to participating securities represents the distributed and undistributed earnings attributable to the participating securities. Our restricted stock awards with market and service vesting criteria and all restricted stock units are not considered to be participating securities and, therefore, are excluded from the basic net income (loss) per common share calculation. Our service vesting restricted stock awards do not participate in undistributed net losses because they are not contractually obligated to do so and, therefore, are excluded from the basic net income (loss) per common share calculation in periods we are in a net loss position. (2) For the years ended December 31, 2016, 2015 and 2014, we excluded 11.8 million, 11.2 million and 4.4 million outstanding restricted stock awards and restricted stock units, respectively, from the computations of diluted net income per share because the effect would have been anti‑dilutive. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2016 | |
Commitments and Contingencies | |
Commitments and Contingencies | 14. Commitments and Contingencies From time to time, we are involved in litigation, regulatory examinations and administrative proceedings primarily arising in the ordinary course of our business in jurisdictions in which we do business. Although the outcome of these matters cannot be predicted with certainty, management believes none of these matters, either individually or in the aggregate, would have a material effect upon the Company’s financial position; however, an unfavorable outcome could have a material adverse effect on our results from operations for a specific interim period or year. The Jubilee Field in Ghana covers an area within both the WCTP and DT petroleum contract areas. It was agreed the Jubilee Field would be unitized for optimal resource recovery. Kosmos and its partners executed a comprehensive unitization and unit operating agreement, the Jubilee UUOA, to unitize the Jubilee Field and govern each party’s respective rights and duties in the Jubilee Unit, which was effective July 16, 2009. Pursuant to the terms of the Jubilee UUOA, the tract participations are subject to a process of redetermination. The initial redetermination process was completed on October 14, 2011. As a result of the initial redetermination process, our Unit Interest is 24.1%. These consolidated financial statements are based on these re determined tract participations. Our unit interest may change in the future should another redetermination occur. The Company leases facilities under various operating leases that expire through 2019, including our office space. Rent expense under these agreements, was $3.3 million, $4.7 million and $4.6 million for the years ended December 31, 2016, 2015 and 2014, respectively. We currently have a commitment to drill two exploration wells in Mauritania. In Mauritania, our partner is obligated to fund our share of the cost of the exploration wells, subject to their maximum $221 million cumulative exploration and appraisal carry covering both our Mauritania and Senegal blocks. Additionally, in Sao Tome and Principe we have 2D and 3D seismic requirements of 1,200 square kilometers and 4,000 square kilometers, respectively, and we have 3D seismic requirements in Mauritania and Western Sahara of 3,000 square kilometers and 5,000 square kilometers, respectively. In January 2017, Kosmos Energy Ventures ( “KEV”), a subsidiary of Kosmos Energy Ltd., elected to cancel the fourth year option of the Atwood Achiever drilling rig contract and revert to the original day rate of approximately $0.6 million per day and original agreement end date of November 2017. KEV is required to make a rate recovery payment of approximately $48.1 million representing the difference between the original day rate and the amended day rate multiplied by the number of days from the amendment effective date to the date the election is exercised plus certain administrative costs. This amount will be charged to exploration expense in the first quarter of 2017. In November 2015, we entered into a line of credit agreement with one of our block partners, whereby, our partner may draw up to $30 million on the line of credit to pay their portion of costs under the petroleum agreement. Interest accrues on drawn balances at 7.875%. The agreement matures on December 31, 2017, or earlier if certain conditions are met. As of December 31, 2016, there was $10.2 outstanding under the agreement, which is included in other long-term assets. Future minimum rental commitments under these leases at December 31, 2016, are as follows: Payments Due By Year(1) Total 2017 2018 2019 2020 2021 Thereafter (In thousands) Operating leases(2) $ $ $ $ $ — $ — $ — Atwood Achiever drilling rig contract(3) — — — — — (1) Does not include purchase commitments for jointly owned fields and facilities where we are not the operator and excludes commitments for exploration activities, including well commitments, in our petroleum contracts. (2) Primarily relates to corporate office and foreign office leases. (3) In January 207, KEV exercised its option to cancel the fourth year and revert to the original day rate of approximately $0.6 million per day and original agreement end date of November 2017. Commitments calculated using the original day rate of $0.6 million effective February 1, 2017, excluding applicable taxes. The commitments also include a $48.1 million rate recovery payment equal to the difference between the original day rate and the amended day rate. |
Additional Financial Informatio
Additional Financial Information | 12 Months Ended |
Dec. 31, 2016 | |
Additional Financial Information | |
Additional Financial Information | 15. Additional Financial Information Accrued Liabilities Accrued liabilities consisted of the following: December 31, 2016 2015 (In thousands) Accrued liabilities: Exploration, development and production $ $ General and administrative expenses Interest Income taxes Taxes other than income Other — $ $ Other Income Other income consisted of $74.8 million of Loss of Production Income (“LOPI”) proceeds related to the turret bearing issue on the Jubilee FPSO for the year ended December 31, 2016. Facilities Insurance Modifications Facilities insurance modifications consist of costs associated with the long-term solution to convert the FPSO to a permanently spread moored facility which we expect to recover from our insurance policy. Insurance reimbursement of these costs, if any, will also be recorded to this line. Other Expenses, Net Other expenses, net incurred during the period is comprised of the following: Years Ended December 31, 2016 2015 2014 (In thousands) Inventory write-off $ $ $ (Gain) loss on insurance settlements - riser — Disputed charges and related costs — — Other, net Other expenses, net $ $ $ The disputed charges and related costs are expenditures arising from Tullow Ghana Limited’s contract with Seadrill for use of the West Leo drilling rig once partner-approved 2016 work program objectives were concluded. Tullow has charged such expenditures to the Deepwater Tano (“DT”) joint account. Kosmos disputes that these expenditures are chargeable to the DT joint account on the basis that the Seadrill West Leo drilling rig contract was not approved by the DT operating committee pursuant to the DT Joint Operating Agreement. |
Supplemental Quarterly Financia
Supplemental Quarterly Financial Information (Unaudited) | 12 Months Ended |
Dec. 31, 2016 | |
Supplemental Quarterly Financial Information (Unaudited) | |
Supplemental Quarterly Financial Information (Unaudited) | Supplemental Quarterly Quarter Ended March 31, June 30, September 30, December 31, (In thousands, except per share data) 2016 Revenues and other income $ $ $ $ Costs and expenses Net loss Net loss per share: Basic(1) Diluted(1) 2015 Revenues and other income $ $ $ $ Costs and expenses Net income (loss) Net income (loss) per share: Basic(1) Diluted(1) (1) The sum of the quarterly earnings per share information may not add to the annual earnings per share information as a result of rounding. |
Schedule I Condensed Parent Com
Schedule I Condensed Parent Company Financial Statements | 12 Months Ended |
Dec. 31, 2016 | |
Schedule I Condensed Parent Company Financial Statements | |
Schedule I-Condensed Parent Company Financial Statements | Schedule I—Condensed Parent Company Financial Statements Under the terms of agreements governing the indebtedness of subsidiaries of Kosmos Energy Ltd. for 2016, 2015 and 2014 (collectively “KEL,” the “Parent Company”), such subsidiaries are restricted from making dividend payments, loans or advances to KEL. Schedule I of Article 5‑04 of Regulation S‑X requires the condensed financial information of the Parent Company to be filed when the restricted net assets of consolidated subsidiaries exceed 25 percent of consolidated net assets as of the end of the most recently completed fiscal year. The following condensed parent‑only financial statements of KEL have been prepared in accordance with Rule 12‑04, Schedule I of Regulation S‑X and included herein. The Parent Company’s 100% investment in its subsidiaries has been recorded using the equity basis of accounting in the accompanying condensed parent‑only financial statements. The condensed financial statements should be read in conjunction with the consolidated financial statements of Kosmos Energy Ltd. and subsidiaries and notes thereto. The terms “Kosmos,” the “Company,” and similar terms refer to Kosmos Energy Ltd. and its wholly owned subsidiaries, unless the context indicates otherwise. Certain prior period amounts have been reclassified to conform with the current year presentation. Such reclassifications had no impact on our reported net income, current assets, total assets, current liabilities, total liabilities or shareholders equity. KOSMOS ENERGY LTD. CONDENSED PARENT COMPANY BALANCE SHEETS (In thousands, except share data) December 31, 2016 2015 Assets Current assets: Cash and cash equivalents $ $ Receivables from subsidiaries — Prepaid expenses and other Total current assets Investment in subsidiaries at equity Deferred financing costs, net of accumulated amortization of $11,213 and $8,475, respectively Total assets $ $ Liabilities and shareholders’ equity Current liabilities: Accounts payable $ $ Accounts payable to subsidiaries — Accrued liabilities Total current liabilities Long-term debt Shareholders’ equity: Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at December 31, 2016 and December 31, 2015 — — Common shares, $0.01 par value; 2,000,000,000 authorized shares; 395,859,061 and 393,902,643 issued at December 31, 2016 and 2015, respectively Additional paid-in capital Accumulated deficit Treasury stock, at cost, 9,101,395 and 8,812,054 shares at December 31, 2016 and 2015, respectively Total shareholders’ equity Total liabilities and shareholders’ equity $ $ KOSMOS ENERGY LTD. CONDENSED PARENT COMPANY STATEMENTS OF OPERATIONS (In thousands) Years Ended December 31, 2016 2015 2014 Revenues and other income: Oil and gas revenue $ — $ — $ — Total revenues and other income — — — Costs and expenses: General and administrative General and administrative recoveries—related party Interest and other financing costs, net Other expenses, net Equity in (earnings) losses of subsidiaries Total costs and expenses Income (loss) before income taxes Income tax expense — — — Net income (loss) $ $ $ KOSMOS ENERGY LTD. CONDENSED PARENT COMPANY STATEMENTS OF CASH FLOWS (In thousands) Years Ended December 31, 2016 2015 2014 Operating activities Net income (loss) $ $ $ Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: Equity in (earnings) losses of subsidiaries Equity-based compensation Amortization Other Changes in assets and liabilities: (Increase) decrease in prepaid expenses and other (Increase) decrease due to/from related party Increase in accounts payable and accrued liabilities Net cash provided by (used in) operating activities Investing activities Investment in subsidiaries Net cash used in investing activities Financing activities Net proceeds from issuance of senior secured notes — Purchase of treasury stock Deferred financing costs — Net cash provided by (used in) financing activities Net increase (decrease) in cash and cash equivalents Cash and cash equivalents at beginning of period Cash and cash equivalents at end of period $ $ $ |
Schedule II Valuation and Quali
Schedule II Valuation and Qualifying Accounts | 12 Months Ended |
Dec. 31, 2016 | |
Valuation and Qualifying Accounts | |
Schedule II Valuation and Qualifying Accounts | Kosmos Energy Ltd. Valuation and Qualifying Accounts For the Years Ended December 31, 2016, 2015 and 2014 Additions Charged to Charged Deductions Balance Costs and To Other From Balance Description January 1, Expenses Accounts Reserves December 31, 2016 Allowance for doubtful receivables $ — $ $ — $ — $ Allowance for deferred tax assets $ $ $ — $ — $ 2015 Allowance for doubtful receivables $ — $ — $ — $ — $ — Allowance for deferred tax assets $ $ $ — $ — $ 2014 Allowance for doubtful receivables $ — $ — $ — $ — $ — Allowance for deferred tax assets $ $ $ — $ — $ Schedules other than Schedule I and Schedule II have been omitted because they are not applicable or the required information is presented in the consolidated financial statements or the notes to consolidated financial statements. |
Accounting Policies (Policies)
Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2016 | |
Accounting Policies | |
Principles of Consolidation | Principles of Consolidation The accompanying consolidated financial statements include the accounts of Kosmos Energy Ltd. and its wholly owned subsidiaries. All intercompany transactions have been eliminated. |
Use of Estimates | Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosures of contingent assets and liabilities. Actual results could differ from these estimates. |
Reclassifications | Reclassifications Certain prior period amounts have been reclassified to conform with the current year presentation. Such reclassifications had no material impact on our reported net income (loss), current assets, total assets, current liabilities, total liabilities, shareholders’ equity or cash flows, except as disclosed related to the adoption of recent accounting pronouncements. |
Cash, Cash Equivalents and Restricted Cash | Cash, Cash Equivalents and Restricted Cash December 31, 2016 2015 2014 (In thousands) Cash and cash equivalents $ $ $ Restricted cash - current Restricted cash - long-term Total cash, cash equivalents and restricted cash shown in the consolidated statements of cash flows $ $ $ Cash and cash equivalents includes demand deposits and funds invested in highly liquid instruments with original maturities of three months or less at the date of purchase. In accordance with our commercial debt facility (the “Facility”), we are required to maintain a restricted cash balance that is sufficient to meet the payment of interest and fees for the next six‑month period on the 7.875% Senior Secured Notes due 2021 (“Senior Notes”) plus the Corporate Revolver or the Facility, whichever is greater. As of December 31, 2016 and 2015, we had $24.5 million and $24.4 million, respectively, in current restricted cash to meet this requirement. In addition, in accordance with certain of our petroleum contracts, we have posted letters of credit related to performance guarantees for our minimum work obligations. These letters of credit are cash collateralized in accounts held by us and as such are classified as restricted cash. Upon completion of the minimum work obligations and/or entering into the next phase of the petroleum contract, the requirement to post the existing letters of credit will be satisfied and the cash collateral will be released. However, additional letters of credit may be required should we choose to move into the next phase of certain of our petroleum contracts. As of December 31, 2016 and 2015, we had zero and $4.1 million, respectively, of short-term restricted cash and $54.6 million and $7.3 million, respectively, of long‑term restricted cash used to cash collateralize performance guarantees related to our petroleum contracts. |
Receivables | Receivables Our receivables consist of joint interest billings, oil sales and other receivables. For our oil sales receivable, we require a letter of credit to be posted to secure the outstanding receivable. Receivables from joint interest owners are stated at amounts due, net of any allowances for doubtful accounts. We determine our allowance by considering the length of time past due, future net revenues of the debtor’s ownership interest in oil and natural gas properties we operate, and the owner’s ability to pay its obligation, among other things. We had an allowance for doubtful accounts of $0.6 million and zero in current joint interest billings receivables as of December 31, 2016 and 2015, respectively. |
Inventories | Inventories Inventories consisted of $68.1 million and $84.4 million of materials and supplies and $6.3 million and $0.8 million of hydrocarbons as of December 31, 2016 and 2015, respectively. The Company’s materials and supplies inventory primarily consists of casing and wellheads and is stated at the lower of cost, using the weighted average cost method, or net realizable value. We recorded a write down of $14.9 million during the year ended December 31, 2016 for materials and supplies inventories as other expenses, net in the consolidated statements of operations and other in the consolidated statements of cash flows. Hydrocarbon inventory is carried at the lower of cost, using the weighted average cost method, or net realizable value. Hydrocarbon inventory costs include expenditures and other charges incurred in bringing the inventory to its existing condition. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory costs. |
Exploration and Development Costs | Exploration and Development Costs The Company follows the successful efforts method of accounting for its oil and gas properties. Acquisition costs for proved and unproved properties are capitalized when incurred. Costs of unproved properties are transferred to proved properties when a determination that proved reserves have been found. Exploration costs, including geological and geophysical costs and costs of carrying unproved properties, are expensed as incurred. Exploratory drilling costs are capitalized when incurred. If exploratory wells are determined to be commercially unsuccessful or dry holes, the applicable costs are expensed and recorded in exploration expense on the consolidated statement of operations. Costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized. Costs incurred to operate and maintain wells and equipment and to lift oil and natural gas to the surface are expensed as oil and gas production expense. The Company evaluates unproved property periodically for impairment. The impairment assessment considers results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of such projects. If the quantity of potential future reserves determined by such evaluations is not sufficient to fully recover the cost invested in each project, the Company will recognize an impairment loss at that time. |
Depletion, Depreciation and Amortization | Depletion, Depreciation and Amortization Proved properties and support equipment and facilities are depleted using the unit‑of‑production method based on estimated proved oil and natural gas reserves. Capitalized exploratory drilling costs that result in a discovery of proved reserves and development costs are amortized using the unit‑of‑production method based on estimated proved developed oil and natural gas reserves for the related field. Depreciation and amortization of other property is computed using the straight-line method over the assets’ estimated useful lives (not to exceed the lease term for leasehold improvements), ranging from one to eight years. Years Depreciated Leasehold improvements to 8 Office furniture, fixtures and computer equipment to 7 Vehicles 5 Amortization of deferred financing costs is computed using the straight‑line method over the life of the related debt. |
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. |
Asset Retirement Obligations | Asset Retirement Obligations The Company accounts for asset retirement obligations as required by ASC 410—Asset Retirement and Environmental Obligations. Under these standards, the fair value of a liability for an asset retirement obligation is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. If a reasonable estimate of fair value cannot be made in the period the asset retirement obligation is incurred, the liability is recognized when a reasonable estimate of fair value can be made. If a tangible long‑lived asset with an existing asset retirement obligation is acquired, a liability for that obligation is recognized at the asset’s acquisition date. In addition, a liability for the fair value of a conditional asset retirement obligation is recorded if the fair value of the liability can be reasonably estimated. We capitalize the asset retirement costs by increasing the carrying amount of the related long‑lived asset by the same amount as the liability. We record increases in the discounted abandonment liability resulting from the passage of time in depletion and depreciation in the consolidated statement of operations. |
Impairment of Long-lived Assets | Impairment of Long‑lived Assets The Company reviews its long‑lived assets for impairment when changes in circumstances indicate that the carrying amount of an asset may not be recoverable, or at least annually. ASC 360—Property, Plant and Equipment requires an impairment loss to be recognized if the carrying amount of a long‑lived asset is not recoverable and exceeds its fair value. The carrying amount of a long‑lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. That assessment shall be based on the carrying amount of the asset at the date it is tested for recoverability, whether in use or under development. An impairment loss shall be measured as the amount by which the carrying amount of a long‑lived asset exceeds its fair value. Assets to be disposed of and assets not expected to provide any future service potential to the Company are recorded at the lower of carrying amount or fair value less cost to sell. We believe the assumptions used in our undiscounted cash flow analysis to test for impairment are appropriate and result in a reasonable estimate of future cash flows. The undiscounted cash flows from the analysis exceeded the carrying amount of our long-lived assets. The most significant assumptions are the pricing and production estimates used in undiscounted cash flow analysis. Where unproved reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the evaluation. In order to evaluate the sensitivity of the assumptions, we assumed a hypothetical reduction in our production profile which still showed no impairment. If we experience declines in oil pricing, increases in our estimated future expenditures or a decrease in our estimated production profile our long-lived assets could be at risk for impairment. |
Derivative Instruments and Hedging Activities | Derivative Instruments and Hedging Activities We utilize oil derivative contracts to mitigate our exposure to commodity price risk associated with our anticipated future oil production. These derivative contracts consist of three‑way collars, put options, call options and swaps. We also use interest rate derivative contracts to mitigate our exposure to interest rate fluctuations related to our long‑term debt. Our derivative financial instruments are recorded on the balance sheet as either assets or liabilities and are measured at fair value. We do not apply hedge accounting to our oil derivative contracts. Effective June 1, 2010, we discontinued hedge accounting on our interest rate swap contracts. Therefore, from that date forward, the changes in the fair value of the instruments were recognized in earnings during the period of change. The effective portions of the discontinued hedges as of May 31, 2010, were included in accumulated other comprehensive income or loss (“AOCI”) in the equity section of the accompanying consolidated balance sheets, and were transferred to earnings when the hedged transactions settled. As of December 31, 2015 all instruments previously designated as hedges have settled and there is no balance remaining in AOCI. See Note 8—Derivative Financial Instruments. |
Estimates of Proved Oil and Natural Gas Reserves | Estimates of Proved Oil and Natural Gas Reserves Reserve quantities and the related estimates of future net cash flows affect our periodic calculations of depletion and assessment of impairment of our oil and natural gas properties. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. As additional proved reserves are discovered, reserve quantities and future cash flows will be estimated by independent petroleum consultants and prepared in accordance with guidelines established by the Securities and Exchange Commission (“SEC”) and the Financial Accounting Standards Board (“FASB”). The accuracy of these reserve estimates is a function of: · the engineering and geological interpretation of available data; · estimates of the amount and timing of future operating cost, production taxes, development cost and workover cost; · the accuracy of various mandated economic assumptions; and · the judgments of the persons preparing the estimates. |
Revenue Recognition | Revenue Recognition We use the sales method of accounting for oil and gas revenues. 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, 2016 and 2015, we had no oil and gas imbalances recorded in our consolidated financial statements. Our oil and gas revenues are based on provisional price contracts which contain an embedded derivative that is required to be separated from the host contract for accounting purposes. The host contract is the receivable from oil sales at the spot price on the date of sale. The embedded derivative, which is not designated as a hedge, is marked to market through oil and gas revenue each period until the final settlement occurs, which generally is limited to the month after the sale. |
Equity-based Compensation | Equity‑based Compensation For equity‑based compensation awards, compensation expense is recognized in the Company’s financial statements over the awards’ vesting periods based on their grant date fair value. The Company utilizes (i) the closing stock price on the date of grant to determine the fair value of service vesting restricted stock awards and restricted stock units and (ii) a Monte Carlo simulation to determine the fair value of restricted stock awards and restricted stock units with a combination of market and service vesting criteria. Forfeitures are recognized in the period in which they occur. |
Restructuring charges | Restructuring Charges The Company accounts for restructuring charges in accordance with ASC 420-Exit or Disposal Cost Obligations. Under these standards, the costs associated with restructuring charges are recorded during the period in which the liability is incurred. During the year ended December 31, 2014, we recognized $11.7 million in restructuring charges for employee severance and related benefit costs incurred as part of a corporate reorganization, which includes $5.0 million of accelerated non-cash expense related to awards previously granted under our Long-Term Incentive Plan (the “LTIP”). |
Treasury Stock | Treasury Stock We record treasury stock purchases at cost. The majority of our treasury stock purchases are from our employees that surrendered shares to the Company to satisfy their minimum statutory tax withholding requirements and were not part of a formal stock repurchase plan. The remainder of our treasury stock is forfeited restricted stock awards granted under our long‑term incentive plan. |
Income Taxes | Income Taxes The Company accounts for income taxes as required by ASC 740—Income Taxes. Under this method, deferred income taxes are determined based on the difference between the financial statement and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts expected to be realized. On a quarterly basis, management evaluates the need for and adequacy of valuation allowances based on the expected realizability of the deferred tax assets and adjusts the amount of such allowances, if necessary. We recognize tax benefits from uncertain tax positions only if it is more likely than not that the tax position will be sustained upon examination by the tax authorities, based on the technical merits of the position. Accordingly, we measure tax benefits from such positions based on the most likely outcome to be realized. |
Foreign Currency Translation | Foreign Currency Translation The U.S. dollar is the functional currency for all of the Company’s material foreign operations. Foreign currency transaction gains and losses and adjustments resulting from translating monetary assets and liabilities denominated in foreign currencies are included in other expenses. Cash balances held in foreign currencies are not significant, and as such, the effect of exchange rate changes is not material to any reporting period. |
Concentration of Credit Risk | Concentration of Credit Risk Our revenue can be materially affected by current economic conditions and the price of oil. However, based on the current demand for crude oil and the fact that alternative purchasers are readily available, we believe that the loss of our marketing agent and/or any of the purchasers identified by our marketing agent would not have a long‑term material adverse effect on our financial position or results of operations. |
Recent Accounting Standards | Recent Accounting Standards Recently Adopted In July 2015, the FASB issued ASU 2015-11, “Simplifying the Measurement of Inventory.” ASU 2015-11 changes the measurement principle for entities that do not measure inventory using the last-in, first-out (LIFO) or retail inventory method from the lower of cost or market to lower of cost and net realizable value. The ASU also eliminates the requirement for these entities to consider replacement cost or net realizable value less an approximately normal profit margin when measuring inventory. The standard requires prospective application upon adoption. The Company has elected to early adopt ASU 2015-11 during the first quarter of 2016. The adoption of this standard did not have a material impact on the Company’s consolidated financial statements. The Company adopted ASU 2016-09, “Improvements to Employee Share-based Payment Accounting” during the year using an effective date of January 1, 2016. The change in accounting for forfeitures associated with share-based payment transactions was adopted using the modified retrospective method and resulted in a $1.9 million increase to opening accumulated deficit, a $3.0 million increase to opening additional paid-in capital and a $1.1 million increase to opening long-term deferred tax assets in the consolidated balance sheets. The changes in accounting for the recognition of excess tax benefits and tax shortfalls were adopted prospectively. In August 2016, the FASB issued ASU 2016-15, “Classification of Certain Cash Receipts and Cash Payments.” ASU 2016-15 clarifies current GAAP or provides specific guidance on eight cash flow classification issues to reduce current and potential future diversity in practice. The Company has elected to early adopt this standard using the retrospective method as prescribed by the standard. The adoption of this standard did not have a material impact on the Company’s consolidated financial statements. In November 2016, the FASB issued ASU 2016-18, “Restricted Cash (a consensus of the FASB Emerging Issues Task Force).” ASU 2016-18 requires that a statement of cash flows explain the change during the period in total of cash, cash equivalents, and amounts generally described as restricted cash and restricted cash equivalents. The ASU is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years with early adoption permitted. The Company has elected to early adopt this standard using the retrospective method as prescribed by the standard. The consolidated statements of cash flows have been reclassified to conform with the presentation required by ASU 2016-18, and the changes in restricted cash are now presented as part of the change in total cash, cash equivalents and restricted cash rather than as changes in investing activities as previously presented. Not Yet Adopted In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers (Topic 606)," which supersedes the revenue recognition requirements in ASC Topic 605, "Revenue Recognition," and most industry-specific guidance. ASU 2014-09 is based on the principle that revenue is recognized to depict the transfer of 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. ASU 2014-09 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. ASU 2014-09 applies to all contracts with customers except those that are within the scope of other topics in the FASB ASC. The new guidance is effective for annual reporting periods beginning after December 15, 2017 for public companies. Early adoption is not permitted. Entities have the option of using either a full retrospective or modified retrospective approach to adopt ASU 2014-09. As of December 31, 2016, the Company does not expect the adoption of this standard to have a material impact to our revenue recognition based on our existing contracts with customers. In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842).” ASU 2016-02 was issued to increase transparency and comparability across organizations by recognizing substantially all leases on the balance sheet through the concept of right-of-use lease assets and liabilities. Under current accounting guidance, lessees do not recognize lease assets or liabilities for leases classified as operating leases. The ASU is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years with early adoption permitted. The new leasing standard requires the modified retrospective adoption method. The Company is in the process of evaluating the impact of this accounting standard on its consolidated financial statements. In October 2016, the FASB issued ASU 2016-16, “Intra-Entity Transfers of Assets Other Than Inventory.” ASU 2016-16 requires the company to recognize income tax consequences, if any, on intercompany asset transfers, other than inventory, when the transfer occurs. The ASU is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years with early adoption permitted. The Company is in the process of evaluating the impact of this accounting standard on its consolidated financial statements. |
Accounting Policies (Tables)
Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Accounting Policies | |
Schedule of cash and cash equivalents | December 31, 2016 2015 2014 (In thousands) Cash and cash equivalents $ $ $ Restricted cash - current Restricted cash - long-term Total cash, cash equivalents and restricted cash shown in the consolidated statements of cash flows $ $ $ |
Schedule of estimated useful lives of other property | Years Depreciated Leasehold improvements to 8 Office furniture, fixtures and computer equipment to 7 Vehicles 5 |
Property and Equipment (Tables)
Property and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Property and Equipment | |
Schedule of property and equipment | December 31, 2016 2015 (In thousands) Oil and gas properties: Proved properties $ $ Unproved properties Support equipment and facilities Total oil and gas properties Accumulated depletion Oil and gas properties, net Other property Accumulated depreciation Other property, net Property and equipment, net $ $ |
Suspended Well Costs (Tables)
Suspended Well Costs (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Suspended Well Costs | |
Schedule of capitalized exploratory well costs | Years Ended December 31, 2016 2015 2014 (In thousands) Beginning balance $ $ $ Additions to capitalized exploratory well costs pending the determination of proved reserves Reclassification due to determination of proved reserves — — Capitalized exploratory well costs charged to expense — — Ending balance $ $ $ |
Schedule of aging of capitalized exploratory well costs and number of projects for which exploratory well costs were capitalized for more than one year | Years Ended December 31, 2016 2015 2014 (In thousands, except well counts) Exploratory well costs capitalized for a period of one year or less $ $ $ Exploratory well costs capitalized for a period of one to two years Exploratory well costs capitalized for a period of three to seven years Ending balance $ $ $ Number of projects that have exploratory well costs that have been capitalized for a period greater than one year |
Debt (Tables)
Debt (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Debt | |
Schedule of debt | December 31, 2016 2015 (In thousands) Outstanding debt principal balances: Facility $ $ Senior Notes Total Unamortized deferred financing costs and discounts(1) Long-term debt $ $ (1) Includes $30.3 million and $37.5 million of unamortized deferred financing costs related to the Facility and $22.8 million and $26.6 million of unamortized deferred financing costs and discounts related to the Senior Notes as of December 31, 2016 and December 31, 2015, respectively. |
Schedule of redemption prices (expressed as percentages of principal amount) of all or a part of the Senior Notes | Year Percentage On or after August 1, 2017, but before August 1, 2018 % On or after August 1, 2018, but before August 1, 2019 % On or after August 1, 2019 and thereafter % |
Schedule of estimated repayments of debt | Payments Due by Year Total 2017 2018 2019 2020 2021 Thereafter (In thousands) Principal debt repayments(1) $ $ — $ — $ $ $ $ — (1) Includes the scheduled principal maturities for the $525.0 million aggregate principal amount of Senior Notes issued in August 2014 and April 2015 and the Facility. The scheduled maturities of debt related to the Facility are based on the level of borrowings and the estimated future available borrowing base as of December 31, 2016. Any increases or decreases in the level of borrowings or increases or decreases in the available borrowing base would impact the scheduled maturities of debt during the next five years and thereafter. As of December 31, 2016, there were no borrowings under the Corporate Revolver. |
Schedule of interest and other financing costs, net | Years Ended December 31, 2016 2015 2014 (In thousands) Interest expense $ $ $ Amortization—deferred financing costs Loss on extinguishment of debt — Capitalized interest Deferred interest Interest income Other, net Interest and other financing costs, net $ $ $ |
Derivative Financial Instrume32
Derivative Financial Instruments (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Derivative Instruments and Hedging Activities | |
Schedule of oil derivative contracts | The following table sets forth the volumes in barrels underlying the Company’s outstanding oil derivative contracts and the weighted average Dated Brent prices per Bbl for those contracts as of December 31, 2016. Volumes are net of any offsetting derivative contracts entered into. Weighted Average Dated Brent Price per Bbl Net Deferred Premium Term Type of Contract MBbl Payable Swap Sold Put Floor Ceiling Call 2017: January — December Swap with puts/calls $ $ $ $ — $ — $ January — December Swap with puts — — — — January — December Three-way collars — — January — December Sold calls(1) — — — — — 2018: January — December Three-way collars $ $ — $ $ $ $ — January — December Sold calls(1) — — — — — 2019: January — December Sold calls(1) $ — $ — $ — $ — $ $ — (1) Represents call option contracts sold to counterparties to enhance other derivative positions. |
Schedule of interest rate derivative contracts | The following table summarizes our capped interest rate swaps whereby we pay a fixed rate of interest if LIBOR is below the cap, and pay the market rate less the spread between the cap (sold call) and the fixed rate of interest if LIBOR is above the cap as of December 31, 2016: Weighted Average Term Type of Contract Floating Rate Notional Swap Sold Call (In thousands) January 2017 — December 2018 Capped swap 1-month LIBOR $ % % |
Schedule of derivative instruments by balance sheet location | Estimated Fair Value Asset (Liability) December 31, Type of Contract Balance Sheet Location 2016 2015 (In thousands) Derivatives not designated as hedging instruments: Derivative assets: Commodity(1) Derivatives assets—current $ $ Commodity(2) Derivatives assets—long-term Interest rate Derivatives assets—long-term Derivative liabilities: Commodity(3) Derivatives liabilities—current — Interest rate Derivatives liabilities—current Commodity(4) Derivatives liabilities—long-term Total derivatives not designated as hedging instruments $ $ (1) Includes net deferred premiums payable of $3.9 million and $6.2 million related to commodity derivative contracts as of December 31, 2016 and 2015, respectively. (2) Includes net deferred premiums payable of $2.5 million and $6.9 million related to commodity derivative contracts as of December 31, 2016 and 2015, respectively. (3) Includes $30.9 thousand and zero as of December 31, 2016 and December 31, 2015, respectively which represents our provisional oil sales contract. Also, includes net deferred premiums payable of $6.2 million and zero related to commodity derivative contracts as of December 31, 2016 and 2015, respectively. (4) Includes net deferred premiums payable of $0.6 million and zero related to commodity derivative contracts as of December 31, 2016 and 2015, respectively. |
Schedule of derivative instruments by location of gain/(loss) | Amount of Gain/(Loss) Years Ended December 31, Type of Contract Location of Gain/(Loss) 2016 2015 2014 (In thousands) Derivatives in cash flow hedging relationships: Interest rate(1) Interest expense $ — $ $ Total derivatives in cash flow hedging relationships $ — $ $ Derivatives not designated as hedging instruments: Commodity(2) Oil and gas revenue $ $ $ Commodity Derivatives, net Interest rate Interest expense Total derivatives not designated as hedging instruments $ $ $ (1) (1) Amounts were reclassified from AOCI into earnings upon settlement. (2) Amounts represent the change in fair value of our provisional oil sales contracts. |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Fair Value Measurements | |
Schedule of Company's assets and liabilities that are measured at fair value on a recurring basis | Fair Value Measurements Using: Quoted Prices in Active Markets for Significant Other Significant Identical Assets Observable Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Total (In thousands) December 31, 2016 Assets: Commodity derivatives $ — $ $ — $ Interest rate derivatives — — Liabilities: Commodity derivatives — — Interest rate derivatives — — Total $ — $ $ — $ December 31, 2015 Assets: Commodity derivatives $ — $ $ — $ Interest rate derivatives — — Liabilities: Commodity derivatives — — Interest rate derivatives — — Total $ — $ $ — $ |
Schedule of carrying values and fair values of financial instruments that are not carried at fair value | : December 31, 2016 December 31, 2015 Carrying Value Fair Value Carrying Value Fair Value (In thousands) Senior Notes $ $ $ $ Facility Total $ $ $ $ |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Asset Retirement Obligations | |
Schedule of changes in asset retirement obligations | December 31, 2016 2015 (In thousands) Asset retirement obligations: Beginning asset retirement obligations $ $ Liabilities incurred during period Revisions in estimated retirement obligations — Accretion expense Ending asset retirement obligations $ $ |
Equity-based Compensation (Tabl
Equity-based Compensation (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Restricted stock awards | |
Equity-based Compensation | |
Schedule of plan activity | Weighted- Market / Service Weighted- Service Vesting Average Vesting Average Restricted Stock Grant-Date Restricted Stock Grant-Date Awards Fair Value Awards Fair Value (In thousands) (In thousands) Outstanding at December 31, 2013 $ $ Granted — — — — Forfeited Vested — — Outstanding at December 31, 2014 Granted — — Forfeited Vested Outstanding at December 31, 2015 Granted — — — — Forfeited — — Vested Outstanding at December 31, 2016 — — |
Restricted stock units | |
Equity-based Compensation | |
Schedule of plan activity | Weighted- Market / Service Weighted- Service Vesting Average Vesting Average Restricted Stock Grant-Date Restricted Stock Grant-Date Units Fair Value Units Fair Value (In thousands) (In thousands) Outstanding at December 31, 2013 $ $ Granted Forfeited Vested — — Outstanding at December 31, 2014 Granted Forfeited Vested — — Outstanding at December 31, 2015 $ $ Granted Forfeited Vested Outstanding at December 31, 2016 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Income Taxes | |
Schedule of components of income (loss) before income taxes | Years Ended December 31, 2016 2015 2014 (In thousands) Bermuda $ $ $ United States Foreign—other Income (loss) before income taxes $ $ $ |
Schedule of components of the provision for income taxes attributable to the entity's income (loss) before income taxes | Years Ended December 31, 2016 2015 2014 (In thousands) Current: Bermuda $ — $ — $ — United States Foreign—other Total current Deferred: Bermuda — — — United States Foreign—other Total deferred Income tax expense (benefit) $ $ $ |
Schedule of reconciliation of income tax expense and the reported effective tax rate | Years Ended December 31, 2016 2015 2014 (In thousands) Tax at Bermuda statutory rate $ — $ — $ — Foreign income (loss) taxed at different rates Change in valuation allowance and the expiration of fully valued deferred tax assets Non-deductible and other items Tax shortfall on equity-based compensation Total tax expense (benefit) $ $ $ Effective tax rate(1) % % % (1) The effective tax rate during the years ended December 31, 2016, 2015 and 2014 were impacted by losses of $121.4 million, $153.5 million and $159.9 million, respectively, incurred in jurisdictions in which we are not subject to taxes and therefore do not generate any income tax benefits. |
Schedule of tax effects of significant temporary differences to deferred tax assets and liabilities | December 31, 2016 2015 (In thousands) Deferred tax assets: Foreign capitalized operating expenses $ $ Foreign net operating losses Equity compensation Other Total deferred tax assets Valuation allowance Total deferred tax assets, net Deferred tax liabilities: Depletion, depreciation and amortization related to property and equipment Unrealized derivative gains Total deferred tax liabilities Net deferred tax liability $ $ |
Net Income (Loss) Per Share (Ta
Net Income (Loss) Per Share (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Net income (loss) per share | |
Schedule of reconciliation between net income and the amounts used to compute basic and diluted net income per share and the weighted average shares outstanding used to compute basic and diluted net income per share | Years Ended December 31, 2016 2015 2014 (In thousands, except per share data) Numerator: Net income (loss) $ $ $ Basic income allocable to participating securities(1) — — Basic net income (loss) allocable to common shareholders Diluted adjustments to income allocable to participating securities(1) — — Diluted net income (loss) allocable to common shareholders $ $ $ Denominator: Weighted average number of shares outstanding: Basic Restricted stock awards and units(1)(2) — — Diluted Net income (loss) per share: Basic $ $ $ Diluted $ $ $ (1) Our service vesting restricted stock awards represent participating securities because they participate in non-forfeitable dividends with common equity owners. Income allocable to participating securities represents the distributed and undistributed earnings attributable to the participating securities. Our restricted stock awards with market and service vesting criteria and all restricted stock units are not considered to be participating securities and, therefore, are excluded from the basic net income (loss) per common share calculation. Our service vesting restricted stock awards do not participate in undistributed net losses because they are not contractually obligated to do so and, therefore, are excluded from the basic net income (loss) per common share calculation in periods we are in a net loss position. For the years ended December 31, 2016, 2015 and 2014, we excluded 11.8 million, 11.2 million and 4.4 million outstanding restricted stock awards and restricted stock units, respectively, from the computations of diluted net income per share because the effect would have been anti‑dilutive. |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Commitments and Contingencies | |
Schedule of estimated future minimum commitments | Payments Due By Year(1) Total 2017 2018 2019 2020 2021 Thereafter (In thousands) Operating leases(2) $ $ $ $ $ — $ — $ — Atwood Achiever drilling rig contract(3) — — — — — (1) Does not include purchase commitments for jointly owned fields and facilities where we are not the operator and excludes commitments for exploration activities, including well commitments, in our petroleum contracts. (2) Primarily relates to corporate office and foreign office leases. (3) In January 207, KEV exercised its option to cancel the fourth year and revert to the original day rate of approximately $0.6 million per day and original agreement end date of November 2017. Commitments calculated using the original day rate of $0.6 million effective February 1, 2017, excluding applicable taxes. The commitments also include a $48.1 million rate recovery payment equal to the difference between the original day rate and the amended day rate. |
Additional Financial Informat39
Additional Financial Information (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Additional Financial Information | |
Schedule of accrued liabilities | December 31, 2016 2015 (In thousands) Accrued liabilities: Exploration, development and production $ $ General and administrative expenses Interest Income taxes Taxes other than income Other — $ $ |
Schedule of Other expenses, net incurred | Years Ended December 31, 2016 2015 2014 (In thousands) Inventory write-off $ $ $ (Gain) loss on insurance settlements - riser — Disputed charges and related costs — — Other, net Other expenses, net $ $ $ |
Supplemental Quarterly Financ40
Supplemental Quarterly Financial Information (Unaudited) (Table) | 12 Months Ended |
Dec. 31, 2016 | |
Supplemental Quarterly Financial Information (Unaudited) | |
Schedule of Supplemental Quarterly Financial Information | Quarter Ended March 31, June 30, September 30, December 31, (In thousands, except per share data) 2016 Revenues and other income $ $ $ $ Costs and expenses Net loss Net loss per share: Basic(1) Diluted(1) 2015 Revenues and other income $ $ $ $ Costs and expenses Net income (loss) Net income (loss) per share: Basic(1) Diluted(1) (1) The sum of the quarterly earnings per share information may not add to the annual earnings per share information as a result of rounding. |
Organization (Details)
Organization (Details) | 12 Months Ended |
Dec. 31, 2016segment | |
Organization | |
Number of reportable segments | 1 |
Accounting Policies (Details)
Accounting Policies (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Restricted Cash | ||||
Cash and cash equivalents | $ 194,057 | $ 275,004 | $ 554,831 | |
Restricted cash - current | 24,506 | 28,533 | 15,926 | |
Restricted cash - long-term | 54,632 | 7,325 | 16,125 | |
Total cash, cash equivalents and restricted cash shown in the consolidated statements of cash flows | 273,195 | 310,862 | 586,882 | $ 651,083 |
Receivables | ||||
Allowance for doubtful accounts | 600 | 0 | ||
Inventories | ||||
Materials and supplies inventory | 68,100 | 84,400 | ||
Hydrocarbons inventory | 6,300 | 800 | ||
Write down of materials and supplies | 14,900 | 36 | 170 | |
Restructuring Charges | ||||
Restructuring charges | 11,742 | |||
Recent Accounting Standards | ||||
Long-term deferred tax assets | 37,827 | 33,209 | ||
Long-term deferred tax liabilities | 482,221 | 502,189 | ||
Revenue Recognition | ||||
Oil and gas imbalances | 0 | 0 | ||
Stockholders' Equity Attributable to Parent [Abstract] | ||||
Accumulated deficit | (850,410) | (564,686) | ||
Additional paid-in capital | 1,975,247 | 1,933,189 | ||
Long-term deferred tax assets | 37,827 | 33,209 | ||
LTIP | ||||
Restructuring Charges | ||||
Non-cash expense included in restructuring charges | $ 5,000 | |||
Accounting Standards Update 2016-09 | Adjustment member | ||||
Recent Accounting Standards | ||||
Long-term deferred tax assets | 1,100 | |||
Stockholders' Equity Attributable to Parent [Abstract] | ||||
Accumulated deficit | (1,900) | |||
Additional paid-in capital | 3,000 | |||
Long-term deferred tax assets | 1,100 | |||
Restricted Cash | Petroleum agreements - performance guarantees | ||||
Restricted Cash | ||||
Restricted cash - current | 0 | 4,100 | ||
Restricted cash - long-term | 54,600 | 7,300 | ||
Restricted Cash | Facility interest or the Senior Notes plus the Corporate Revolver interest | ||||
Restricted Cash | ||||
Restricted cash - current | $ 24,500 | $ 24,400 | ||
Restricted cash period required as per commercial debt facility to meet interest and commitment fee payments | 6 months | |||
Senior Notes | 7.875% senior notes due 2021 | ||||
Restricted Cash | ||||
Interest rate | 7.875% |
Accounting Policies - Various (
Accounting Policies - Various (Details) $ in Thousands | 12 Months Ended |
Dec. 31, 2016USD ($) | |
Impairment of Long-lived Assets | |
Impairment of Oil and Gas | $ 0 |
Derivative Instruments and Hedging Activities | |
Accumulated other comprehensive income | $ 0 |
Minimum | |
Depreciation and amortization | |
Estimated useful lives (in years) | 1 year |
Maximum | |
Depreciation and amortization | |
Estimated useful lives (in years) | 8 years |
Leasehold improvements | Minimum | |
Depreciation and amortization | |
Estimated useful lives (in years) | 1 year |
Leasehold improvements | Maximum | |
Depreciation and amortization | |
Estimated useful lives (in years) | 8 years |
Office furniture, fixtures and computer equipment | Minimum | |
Depreciation and amortization | |
Estimated useful lives (in years) | 3 years |
Office furniture, fixtures and computer equipment | Maximum | |
Depreciation and amortization | |
Estimated useful lives (in years) | 7 years |
Vehicles | |
Depreciation and amortization | |
Estimated useful lives (in years) | 5 years |
Capitalized interest | Minimum | |
Capitalized Interest | |
Expected construction period for capitalization of interest costs on major projects | 1 year |
Acquisitions and Divestitures (
Acquisitions and Divestitures (Details) a in Millions, MMBbls in Millions | Feb. 01, 2016 | Jan. 31, 2017USD ($) | Dec. 31, 2016USD ($)itemMMBbls | Oct. 31, 2016km² | Sep. 30, 2016USD ($) | May 31, 2016 | Apr. 30, 2016km² | Nov. 30, 2015 | Oct. 31, 2015 | Mar. 31, 2015USD ($)item | Aug. 31, 2014USD ($) | Oct. 31, 2016km² | Mar. 31, 2014USD ($)agreementitem | Nov. 30, 2016 | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Oct. 31, 2016a |
Acquisitions and Divestitures | ||||||||||||||||||
Proceeds on sale of assets | $ 210,000 | $ 28,692,000 | $ 58,315,000 | |||||||||||||||
Gain on sale of assets | $ 24,651,000 | $ 23,769,000 | ||||||||||||||||
Farm-in agreement | Camarao, Ameijoa, Mexilhao and Ostra blocks | ||||||||||||||||||
Acquisitions and Divestitures | ||||||||||||||||||
Participating interests (as a percent) | 31.00% | |||||||||||||||||
Farm-in agreement | Block 11 | ||||||||||||||||||
Acquisitions and Divestitures | ||||||||||||||||||
Participation interest acquired (as a percent) | 85.00% | |||||||||||||||||
Farm-in agreement | Block 6 | ||||||||||||||||||
Acquisitions and Divestitures | ||||||||||||||||||
Participation interest acquired (as a percent) | 45.00% | |||||||||||||||||
Petroleum agreement | Block C6 Related To Mauritania | ||||||||||||||||||
Acquisitions and Divestitures | ||||||||||||||||||
3 D seismic requirements (in square kilometers) | km² | 2,000 | |||||||||||||||||
Initial exploration period | 4 years | |||||||||||||||||
Area of petroleum exploration | 4,300 | 4,300 | 1.1 | |||||||||||||||
Sales and purchase agreement | Kosmos BP Senegal Limited | Cayar Offshore Profond And Saint Louis Offshore Profond Blocks | ||||||||||||||||||
Acquisitions and Divestitures | ||||||||||||||||||
Participating interests (as a percent) | 65.00% | |||||||||||||||||
Timis Corporation Limited | Farm-in agreement | Cayar Offshore Profond And Saint Louis Offshore Profond Blocks | ||||||||||||||||||
Acquisitions and Divestitures | ||||||||||||||||||
Participation interest acquired (as a percent) | 60.00% | |||||||||||||||||
Participating interests (as a percent) | 60.00% | |||||||||||||||||
Maximum cost per contingent exploration well | $ 120,000,000 | $ 120,000,000 | ||||||||||||||||
Participating interest for carrying the full cost of third contingent exploration or appraisal well (as a percent) | 65.00% | 65.00% | ||||||||||||||||
Chevron | Farm-out agreements | Block C8 Block C12 And Block C13 | ||||||||||||||||||
Acquisitions and Divestitures | ||||||||||||||||||
Participating interest reassigned (as a percent) | 30.00% | |||||||||||||||||
Proceeds on sale of assets | $ 28,700,000 | |||||||||||||||||
Gain on sale of assets | $ 24,700,000 | |||||||||||||||||
Number of exploration wells for which a third party will pay a disproportionate amount | item | 1 | |||||||||||||||||
Chevron | Farm-out agreements | Block 42 | ||||||||||||||||||
Acquisitions and Divestitures | ||||||||||||||||||
Participating interests (as a percent) | 33.33% | |||||||||||||||||
Hess Corporation | Farm-out agreements | Block 42 | ||||||||||||||||||
Acquisitions and Divestitures | ||||||||||||||||||
3 D seismic requirements (in square kilometers) | km² | 6,500 | |||||||||||||||||
ANP STP | Farm-in agreement | Block 5 | ||||||||||||||||||
Acquisitions and Divestitures | ||||||||||||||||||
Carried interest held by third party as a percent | 15.00% | |||||||||||||||||
ANP STP | Farm-in agreement | Block 12 | ||||||||||||||||||
Acquisitions and Divestitures | ||||||||||||||||||
Carried interest held by third party as a percent | 12.50% | |||||||||||||||||
ANP STP | Farm-in agreement | Block 11 | ||||||||||||||||||
Acquisitions and Divestitures | ||||||||||||||||||
Carried interest held by third party as a percent | 15.00% | |||||||||||||||||
Staatsolie | Farm-out agreements | Block 42 | ||||||||||||||||||
Acquisitions and Divestitures | ||||||||||||||||||
Maximum percentage interest available upon approval (as a percent) | 10.00% | |||||||||||||||||
Parent company | Essaouira Offshore Block | ||||||||||||||||||
Acquisitions and Divestitures | ||||||||||||||||||
Participating interests (as a percent) | 75.00% | |||||||||||||||||
Parent company | Farm-in agreement | Block 5 | ||||||||||||||||||
Acquisitions and Divestitures | ||||||||||||||||||
Participating interests (as a percent) | 45.00% | |||||||||||||||||
Parent company | Farm-in agreement | Block 12 | ||||||||||||||||||
Acquisitions and Divestitures | ||||||||||||||||||
Participating interests (as a percent) | 45.00% | |||||||||||||||||
Parent company | Farm-out agreements | Block 42 | ||||||||||||||||||
Acquisitions and Divestitures | ||||||||||||||||||
Participating interests (as a percent) | 33.33% | |||||||||||||||||
Parent company | Petroleum agreement | Block C6 Related To Mauritania | ||||||||||||||||||
Acquisitions and Divestitures | ||||||||||||||||||
Participating interests (as a percent) | 28.00% | |||||||||||||||||
Parent company | Petroleum agreement | Boujdour Maritime block | ||||||||||||||||||
Acquisitions and Divestitures | ||||||||||||||||||
Participating interests (as a percent) | 55.00% | |||||||||||||||||
BP | Essaouira Offshore Block | ||||||||||||||||||
Acquisitions and Divestitures | ||||||||||||||||||
Participating interest reassigned (as a percent) | 45.00% | |||||||||||||||||
Amount due in lieu of drilling exploration well | $ 30,000,000 | |||||||||||||||||
Amount received in lieu of drilling exploration well | $ 30,000,000 | |||||||||||||||||
BP | Farm-out agreements | Block C6 Block C8 Block C12 and Block C13 Mauritania | ||||||||||||||||||
Acquisitions and Divestitures | ||||||||||||||||||
Number of blocks covered by farm-out agreements | item | 4 | |||||||||||||||||
Participation interest acquired (as a percent) | 62.00% | |||||||||||||||||
BP | Farm-out agreements | Essaouira Offshore, Foum Assaka Offshore and Tarhazoute Offshore blocks | ||||||||||||||||||
Acquisitions and Divestitures | ||||||||||||||||||
Number of farm-out agreements | agreement | 3 | |||||||||||||||||
Number of blocks covered by farm-out agreements | item | 3 | |||||||||||||||||
Proceeds on sale of assets | $ 56,900,000 | |||||||||||||||||
Gain on sale of assets | 23,800,000 | |||||||||||||||||
BP | Farm-out agreements | Mauritania And Senegal Offshore Block | ||||||||||||||||||
Acquisitions and Divestitures | ||||||||||||||||||
Amount of potential and variable consideration per barrel | $ 2 | |||||||||||||||||
BP | Farm-out agreements | Mauritania And Senegal Offshore Block | Maximum | ||||||||||||||||||
Acquisitions and Divestitures | ||||||||||||||||||
Number of barrels | MMBbls | 1,000 | |||||||||||||||||
BP | Sales and purchase agreement | Kosmos BP Senegal Limited | ||||||||||||||||||
Acquisitions and Divestitures | ||||||||||||||||||
Participation interest acquired (as a percent) | 49.99% | |||||||||||||||||
BP | Sales and purchase agreement and farm-out agreements | Mauritania And Senegal Offshore Block | ||||||||||||||||||
Acquisitions and Divestitures | ||||||||||||||||||
Upfront amount to be received in cash | $ 162,000,000 | |||||||||||||||||
Spending by third party for exploration and appraisal costs | 221,000,000 | |||||||||||||||||
Spending by third party for Kosmos' development costs | $ 533,000,000 | |||||||||||||||||
Cairn | Farm-out agreements | Cap Boujdour Offshore block | ||||||||||||||||||
Acquisitions and Divestitures | ||||||||||||||||||
Reimbursement of shared costs previously incurred | $ 1,500,000 | |||||||||||||||||
Cairn | Petroleum agreement | Boujdour Maritime block | ||||||||||||||||||
Acquisitions and Divestitures | ||||||||||||||||||
Participating interests (as a percent) | 20.00% | |||||||||||||||||
ONHYM | Petroleum agreement | Boujdour Maritime block | ||||||||||||||||||
Acquisitions and Divestitures | ||||||||||||||||||
Carried interest held by third party as a percent | 25.00% | |||||||||||||||||
SMHPM | Petroleum agreement | Block C6 Related To Mauritania | ||||||||||||||||||
Acquisitions and Divestitures | ||||||||||||||||||
Carried interest held by third party as a percent | 10.00% | |||||||||||||||||
GALP | Farm-out agreements | Block 5, Block 11, and Block 12 | ||||||||||||||||||
Acquisitions and Divestitures | ||||||||||||||||||
Non operated interest | 20.00% |
Joint Interest Billings (Detail
Joint Interest Billings (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Joint interest billings | ||
Long-term receivables - joint interest billings | $ 45,663 | $ 37,687 |
TEN Discoveries | GNPC | ||
Joint interest billings | ||
Long-term receivables - joint interest billings | $ 44,000 | $ 35,300 |
TEN Discoveries | GNPC | ||
Joint interest billings | ||
GNPC's paying interest (as a percent) | 5.00% |
Property and Equipment (Details
Property and Equipment (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Oil and gas properties: | |||
Proved properties | $ 1,385,331 | $ 1,337,215 | |
Unproved properties | 919,056 | 593,510 | |
Support equipment and facilities | 1,386,448 | 1,241,943 | |
Total oil and gas properties | 3,690,835 | 3,172,668 | |
Less: accumulated depletion | (989,946) | (858,442) | |
Oil and gas properties, net | 2,700,889 | 2,314,226 | |
Other property | 37,186 | 34,807 | |
Less: accumulated depreciation | (29,183) | (26,194) | |
Other property, net | 8,003 | 8,613 | |
Property and equipment, net | 2,708,892 | 2,322,839 | |
Depletion expense | $ 131,500 | $ 146,600 | $ 188,300 |
Suspended Well Costs (Details)
Suspended Well Costs (Details) $ in Thousands | 1 Months Ended | 12 Months Ended | |||||
May 31, 2015project | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Dec. 31, 2016USD ($)project | Dec. 31, 2015USD ($)project | Dec. 31, 2014USD ($)project | |
Reconciliation of capitalized exploratory well costs on completed wells | |||||||
Beginning balance | $ 426,881 | $ 226,714 | $ 376,166 | ||||
Additions to capitalized exploratory well costs pending the determination of proved reserves | 307,582 | 223,542 | 71,039 | ||||
Reclassification due to determination of proved reserves | (220,491) | ||||||
Capitalized exploratory well costs charged to expense | (23,375) | ||||||
Ending balance | 734,463 | 426,881 | 226,714 | ||||
Aging of capitalized exploratory well costs and number of projects for which exploratory well costs were capitalized for more than one year | |||||||
Exploratory well costs capitalized for a period of one year or less | $ 279,809 | $ 199,486 | $ 16,814 | ||||
Exploratory well costs capitalized for a period one to two years | 244,804 | 17,702 | 40,865 | ||||
Exploratory well costs capitalized for a period three to six years | 209,850 | 209,693 | 169,035 | ||||
Ending balance | 426,881 | 226,714 | 376,166 | $ 734,463 | $ 426,881 | $ 226,714 | |
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year | project | 5 | 3 | 5 | ||||
Capitalized exploratory well costs subsequently expensed in the same period | $ 2,400 | $ 70,300 | $ 1,100 | ||||
Greater Tortue Discovery | |||||||
Aging of capitalized exploratory well costs and number of projects for which exploratory well costs were capitalized for more than one year | |||||||
Number of additional wells drilled | project | 2 |
Debt (Details)
Debt (Details) $ in Thousands | 1 Months Ended | 12 Months Ended | |||||||||||
Jul. 31, 2016USD ($) | Jun. 30, 2016 | Jul. 31, 2015USD ($) | Apr. 30, 2015USD ($) | Aug. 31, 2014USD ($) | Mar. 31, 2014USD ($) | Dec. 31, 2016USD ($)item | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Feb. 28, 2017USD ($) | Oct. 01, 2016USD ($) | Aug. 01, 2015USD ($) | Feb. 01, 2015USD ($) | |
Debt | |||||||||||||
Outstanding debt principal | $ 1,375,000 | $ 925,000 | |||||||||||
Unamortized issuance costs and discount | (53,126) | (64,122) | |||||||||||
Long-term debt | 1,321,874 | 860,878 | |||||||||||
Loss on extinguishment of debt | 165 | $ 2,898 | |||||||||||
Net deferred financing costs | 5,248 | 7,986 | |||||||||||
Scheduled maturities of debt during the five year period and thereafter | |||||||||||||
2,019 | 268,823 | ||||||||||||
2,020 | 395,166 | ||||||||||||
2,021 | 711,011 | ||||||||||||
Parent company | |||||||||||||
Debt | |||||||||||||
Net deferred financing costs | 5,248 | 7,986 | |||||||||||
Facility | |||||||||||||
Debt | |||||||||||||
Outstanding debt principal | 850,000 | 400,000 | |||||||||||
Unamortized issuance costs and discount | 30,300 | 37,500 | |||||||||||
Total commitment | $ 1,500,000 | ||||||||||||
Current borrowing capacity | $ 1,467,000 | ||||||||||||
Loss on extinguishment of debt | 2,900 | ||||||||||||
Net deferred financing costs | 30,300 | ||||||||||||
Amount outstanding | 850,000 | ||||||||||||
Undrawn availability | $ 616,900 | ||||||||||||
Variable rate basis | LIBOR | ||||||||||||
Commitment fee percentage of the then-applicable margin when commitment is available for utilization | 40.00% | ||||||||||||
Commitment fee percentage of the then-applicable margin when commitment is not available for utilization | 20.00% | ||||||||||||
Adjustment in estimate of deferred interest | 4,500 | ||||||||||||
Revolving-credit sublimit amount after March 31, 2018 | $ 500,000 | ||||||||||||
Availability period of revolving-credit sublimit | 1 month | ||||||||||||
Amount outstanding under letters of credit | $ 0 | ||||||||||||
Interval period for payment of interest | 6 months | ||||||||||||
Size of LC Facility | $ 1,500,000 | ||||||||||||
Facility | Minimum | LIBOR | |||||||||||||
Debt | |||||||||||||
Applicable margin (as a percent) | 3.25% | ||||||||||||
Facility | Maximum | LIBOR | |||||||||||||
Debt | |||||||||||||
Applicable margin (as a percent) | 4.50% | ||||||||||||
Corporate Revolver | |||||||||||||
Debt | |||||||||||||
Total commitment | $ 400,000 | ||||||||||||
Percentage of the margin used to calculate commitment fees | 30.00% | ||||||||||||
Net deferred financing costs | $ 5,200 | ||||||||||||
Amount outstanding | 0 | ||||||||||||
Undrawn availability | $ 400,000 | ||||||||||||
Applicable margin (as a percent) | 6.00% | ||||||||||||
Variable rate basis | LIBOR | ||||||||||||
Interval period for payment of interest | 6 months | ||||||||||||
Size of LC Facility | $ 400,000 | ||||||||||||
Revolving Letter of Credit Facility | |||||||||||||
Debt | |||||||||||||
Total commitment | $ 75,000 | $ 75,000 | |||||||||||
Amount outstanding | $ 72,800 | ||||||||||||
Number of letters of credit | item | 9 | ||||||||||||
Applicable margin (as a percent) | 0.80% | 0.50% | |||||||||||
Commitment fee payable | 0.65% | ||||||||||||
Size of LC Facility | $ 75,000 | $ 75,000 | |||||||||||
Other disclosures | |||||||||||||
Cash collateral required as a percentage of outstanding letters of credit under breach of certain financial covenants | 100.00% | ||||||||||||
Revolving Letter of Credit Facility | Forecast | |||||||||||||
Debt | |||||||||||||
Total commitment | $ 125,000 | ||||||||||||
Size of LC Facility | $ 125,000 | ||||||||||||
Revolving Letter of Credit Facility | Minimum | |||||||||||||
Other disclosures | |||||||||||||
Cash collateral maintained as a percentage of outstanding letters of credit | 75.00% | ||||||||||||
Revolving Letter of Credit Facility | Maximum | |||||||||||||
Debt | |||||||||||||
Additional commitments | $ 50,000 | $ 50,000 | |||||||||||
Senior Notes | |||||||||||||
Debt | |||||||||||||
Outstanding debt principal | $ 525,000 | 525,000 | |||||||||||
Unamortized issuance costs and discount | 22,800 | $ 26,600 | |||||||||||
Senior Notes | 7.875% senior notes due 2021 | |||||||||||||
Debt | |||||||||||||
Senior notes offering face amount | $ 225,000 | $ 300,000 | $ 525,000 | $ 225,000 | $ 300,000 | ||||||||
Proceeds, net of offering discounts and deferred financing costs | $ 206,800 | $ 292,500 | |||||||||||
Other disclosures | |||||||||||||
Redemption price percentage following change of control | 101.00% | ||||||||||||
Redemption price percentage following sell of certain assets | 100.00% | ||||||||||||
Senior Notes | 7.875% senior notes due 2021 | Prior to August 1, 2017 | |||||||||||||
Other disclosures | |||||||||||||
Senior notes redemption, start date | Aug. 1, 2014 | ||||||||||||
Senior notes redemption, end date | Aug. 1, 2017 | ||||||||||||
Maximum percentage of principal amount available to be redeemed with proceeds from equity offerings | 35.00% | ||||||||||||
Redemption price percentage using proceeds from equity offerings | 107.875% | ||||||||||||
Redemption price percentage, excluding proceeds from equity offerings | 100.00% | ||||||||||||
Senior Notes | 7.875% senior notes due 2021 | On or after August 1, 2017, but before August 1, 2018 | |||||||||||||
Other disclosures | |||||||||||||
Redemption price, as a percent of the of principal amount | 103.90% | ||||||||||||
Senior Notes | 7.875% senior notes due 2021 | On or after August 1, 2018, but before August 1, 2019 | |||||||||||||
Other disclosures | |||||||||||||
Redemption price, as a percent of the of principal amount | 102.00% | ||||||||||||
Senior Notes | 7.875% senior notes due 2021 | On or after August 1, 2019 and thereafter | |||||||||||||
Other disclosures | |||||||||||||
Redemption price, as a percent of the of principal amount | 100.00% |
Debt Interest (Details)
Debt Interest (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Interest expense | $ 89,029 | $ 74,897 | $ 57,876 |
Amortization-deferred financing costs | 10,204 | 10,324 | 10,548 |
Loss on extinguishment of debt | 165 | 2,898 | |
Capitalized interest | (59,803) | (52,392) | (20,577) |
Deferred interest | (581) | 1,770 | (3,562) |
Interest income | (1,954) | (844) | (529) |
Other, net | 7,252 | 3,289 | (1,106) |
Interest and other financing costs, net | 44,147 | 37,209 | 45,548 |
Parent company | |||
Interest and other financing costs, net | $ 55,253 | $ 49,572 | $ 20,559 |
Derivative Financial Instrume50
Derivative Financial Instruments (Details) | 1 Months Ended | 12 Months Ended |
Feb. 28, 2017$ / bblMMBbls | Dec. 31, 2016$ / bblMBbls | |
Term January 2017 to December 2017 | Three-way Collars | ||
Derivative Financial Instruments | ||
Volumes (in MBbl) | MBbls | 3,002 | |
Weighted average deferred premium payable per Bbl | 2.29 | |
Weighted average sold put price per Bbl | 30 | |
Weighted average floor price per Bbl | 45 | |
Weighted average ceiling price per Bbl | 57.50 | |
Term January 2017 to December 2017 | Swaps with puts | ||
Derivative Financial Instruments | ||
Volumes (in MBbl) | MBbls | 2,000 | |
Weighted average swap price per Bbl | 64.95 | |
Weighted average sold put price per Bbl | 50 | |
Term January 2017 to December 2017 | Sold calls | ||
Derivative Financial Instruments | ||
Volumes (in MBbl) | MBbls | 2,000 | |
Weighted average ceiling price per Bbl | 85 | |
Term January 2017 to December 2017 | Swap with puts/calls | ||
Derivative Financial Instruments | ||
Volumes (in MBbl) | MBbls | 2,000 | |
Weighted average deferred premium payable per Bbl | 2.13 | |
Weighted average swap price per Bbl | 72.50 | |
Weighted average sold put price per Bbl | 55 | |
Weighted average purchased call price per Bbl | 90 | |
Term January 2018 to December 2018 | Three-way Collars | ||
Derivative Financial Instruments | ||
Volumes (in MBbl) | 1,000 | 2,913 |
Weighted average deferred premium payable per Bbl | 2.32 | 0.74 |
Weighted average sold put price per Bbl | 41.57 | |
Weighted average floor price per Bbl | 50 | 56.57 |
Weighted average ceiling price per Bbl | 62 | 65.90 |
Weighted average purchased call price per Bbl | 70 | |
Term January 2018 to December 2018 | Sold calls | ||
Derivative Financial Instruments | ||
Volumes (in MBbl) | MBbls | 2,000 | |
Weighted average ceiling price per Bbl | 65 | |
Term January 2019 to December 2019 | Sold calls | ||
Derivative Financial Instruments | ||
Volumes (in MBbl) | MBbls | 913 | |
Weighted average ceiling price per Bbl | 80 |
Derivative Financial Instrume51
Derivative Financial Instruments - Swaps (Details) $ in Thousands | Dec. 31, 2016USD ($) |
Derivative Financial Instruments | |
Accumulated other comprehensive income | $ 0 |
1-month LIBOR | Interest Rate Cap Swap | Term January 2017 to December 2018 | |
Derivative Financial Instruments | |
Weighted Average Notional Amount | $ 200,000 |
Weighted Average Fixed Rate (as a percent) | 1.23% |
Interest rate cap | 3.00% |
Derivative Financial Instrume52
Derivative Financial Instruments - Derivatives (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Derivative instruments, Balance Sheet Location | ||
Derivatives assets - current | $ 31,698,000 | $ 182,640,000 |
Derivatives assets-long-term | 3,808,000 | 59,856,000 |
Derivatives liabilities - current | (19,692,000) | (1,155,000) |
Derivatives liabilities - long-term | (14,123,000) | (4,196,000) |
Not designated as hedging instruments | ||
Derivative instruments, Balance Sheet Location | ||
Total | 1,691,000 | 237,145,000 |
Commodity derivatives | Not designated as hedging instruments | ||
Derivative instruments, Balance Sheet Location | ||
Derivatives assets - current | 31,698,000 | 182,640,000 |
Derivatives assets-long-term | 3,226,000 | 59,197,000 |
Derivatives liabilities - current | (19,163,000) | |
Derivatives liabilities - long-term | (14,123,000) | (4,196,000) |
Net deferred premiums payable related to commodity derivative contracts - current assets | 3,900,000 | 6,200,000 |
Net deferred premiums payable related to commodity derivative contracts - non current assets | 2,500,000 | 6,900,000 |
Net deferred premiums payable related to commodity derivative contracts - current liabilities | 6,200,000 | 0 |
Net deferred premiums payable related to commodity derivative contracts - non current liabilities | 600,000 | 0 |
Commodity derivatives | Not designated as hedging instruments | Oil and gas revenue | ||
Derivative instruments, Balance Sheet Location | ||
Derivatives liabilities - current | (30,900) | 0 |
Interest rate contracts | Not designated as hedging instruments | ||
Derivative instruments, Balance Sheet Location | ||
Derivatives assets-long-term | 582,000 | 659,000 |
Derivatives liabilities - current | $ (529,000) | $ (1,155,000) |
Derivative Financial Instrume53
Derivative Financial Instruments- Location of Gain (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Derivative instruments, Location of Gain/(Loss) | |||
Amount of Gain/(Loss), derivatives not designated as hedging instruments | $ (46,559) | $ 210,190 | $ 269,907 |
Commodity derivatives | Oil and gas revenue | |||
Derivative instruments, Location of Gain/(Loss) | |||
Amount of Gain/(Loss), derivatives not designated as hedging instruments | 2,538 | 3 | (11,661) |
Commodity derivatives | Derivatives, net | |||
Derivative instruments, Location of Gain/(Loss) | |||
Amount of Gain/(Loss), derivatives not designated as hedging instruments | (48,021) | 210,649 | 281,853 |
Interest rate contracts | Interest expense | |||
Derivative instruments, Location of Gain/(Loss) | |||
Amount of Gain/(Loss), derivatives not designated as hedging instruments | $ (1,076) | (462) | (285) |
Derivatives in cash flow hedging relationships | |||
Derivative instruments, Location of Gain/(Loss) | |||
Interest rate derivatives, net | 767 | 1,391 | |
Derivatives in cash flow hedging relationships | Interest rate contracts | Interest expense | |||
Derivative instruments, Location of Gain/(Loss) | |||
Amount of Gain/(Loss) reclassified from AOCI into earnings | $ 767 | $ 1,391 |
Fair Value Measurements (Detail
Fair Value Measurements (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Carrying Value | ||
Liabilities: | ||
Long-term debt | $ 1,353,716 | $ 900,186 |
Total Fair Value | ||
Liabilities: | ||
Long-term debt | 1,378,938 | 823,612 |
Recurring basis | ||
Liabilities: | ||
Total fair value, net | 1,691 | 237,145 |
Recurring basis | Commodity derivatives | ||
Assets: | ||
Derivative asset, fair value | 34,924 | 241,837 |
Liabilities: | ||
Derivative liability, fair value | (33,286) | (4,196) |
Recurring basis | Interest rate contracts | ||
Assets: | ||
Derivative asset, fair value | 582 | 659 |
Liabilities: | ||
Derivative liability, fair value | (529) | (1,155) |
Recurring basis | Level 2 | ||
Liabilities: | ||
Total fair value, net | 1,691 | 237,145 |
Recurring basis | Level 2 | Commodity derivatives | ||
Assets: | ||
Derivative asset, fair value | 34,924 | 241,837 |
Liabilities: | ||
Derivative liability, fair value | (33,286) | (4,196) |
Recurring basis | Level 2 | Interest rate contracts | ||
Assets: | ||
Derivative asset, fair value | 582 | 659 |
Liabilities: | ||
Derivative liability, fair value | (529) | (1,155) |
Facility | Carrying Value | ||
Liabilities: | ||
Long-term debt | 850,000 | 400,000 |
Facility | Total Fair Value | ||
Liabilities: | ||
Long-term debt | 850,000 | 400,000 |
Senior Notes | Carrying Value | ||
Liabilities: | ||
Long-term debt | 503,716 | 500,186 |
Senior Notes | Total Fair Value | ||
Liabilities: | ||
Long-term debt | $ 528,938 | $ 423,612 |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Asset retirement obligations: | ||
Beginning asset retirement obligations | $ 43,938 | $ 44,023 |
Liabilities incurred during period | 14,235 | 3,818 |
Revisions in estimated retirement obligations | (9,023) | |
Accretion expense | 5,401 | 5,120 |
Ending asset retirement obligations | $ 63,574 | $ 43,938 |
Equity-based Compensation (Deta
Equity-based Compensation (Details) - USD ($) $ / shares in Units, shares in Thousands | May 17, 2011 | May 16, 2011 | May 11, 2011 | Jan. 31, 2017 | Jun. 30, 2015 | May 31, 2011 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2016 |
Compensation agreement | ||||||||||
Tax shortfall related to equity-based compensation | $ 5,504,000 | $ 18,603,000 | $ 6,547,000 | |||||||
LTIP | ||||||||||
Compensation agreement | ||||||||||
Compensation expense recognized | 40,100,000 | 75,100,000 | 74,500,000 | |||||||
Tax benefit | 13,000,000 | 25,700,000 | 25,700,000 | |||||||
Tax shortfall related to equity-based compensation | $ 5,500,000 | $ 18,600,000 | $ 6,500,000 | |||||||
Other disclosures | ||||||||||
Additional shares authorized | 15,000 | |||||||||
Approved and authorized awards (in shares) | 39,500 | |||||||||
Number of shares remaining available for grant | 8,300 | 8,300 | ||||||||
Minimum | LTIP | ||||||||||
Equity-based Compensation | ||||||||||
Vesting period | 3 years | |||||||||
Maximum | LTIP | ||||||||||
Equity-based Compensation | ||||||||||
Vesting period | 4 years | |||||||||
Service Vesting Restricted Stock Awards | LTIP | ||||||||||
Weighted-Average Grant-Date Fair Value for awards | ||||||||||
Granted (in dollars per share) | $ 8.64 | |||||||||
Outstanding unvested awards activity | ||||||||||
Outstanding at the beginning of the period (in shares) | 488 | 810 | 3,240 | 6,384 | ||||||
Granted (in shares) | 660 | |||||||||
Forfeited (in shares) | (2) | (122) | ||||||||
Vested (in shares) | (322) | (3,088) | (3,022) | |||||||
Outstanding at the end of the period (in shares) | 488 | 810 | 3,240 | 488 | ||||||
Weighted-Average Grant-Date Fair Value | ||||||||||
Outstanding at beginning of the period (in dollars per share) | $ 8.83 | $ 9.20 | $ 16.95 | $ 16.48 | ||||||
Granted (in dollars per share) | 8.64 | |||||||||
Forfeited (in dollars per share) | 12.84 | 15.20 | ||||||||
Vested (in dollars per share) | 9.77 | 17.21 | 16.02 | |||||||
Outstanding at the end of the period (in dollars per share) | $ 8.83 | $ 9.20 | $ 16.95 | $ 8.83 | ||||||
Market/Service Vesting Restricted Stock Awards | LTIP | ||||||||||
Outstanding unvested awards activity | ||||||||||
Outstanding at the beginning of the period (in shares) | 261 | 3,361 | 3,438 | |||||||
Forfeited (in shares) | (162) | (1,554) | (77) | |||||||
Vested (in shares) | (99) | (1,546) | ||||||||
Outstanding at the end of the period (in shares) | 261 | 3,361 | ||||||||
Weighted-Average Grant-Date Fair Value | ||||||||||
Outstanding at beginning of the period (in dollars per share) | $ 9.44 | $ 13 | $ 12.95 | |||||||
Forfeited (in dollars per share) | 9.44 | 13.29 | 10.74 | |||||||
Vested (in dollars per share) | 9.44 | 13.30 | ||||||||
Outstanding at the end of the period (in dollars per share) | 9.44 | 13 | ||||||||
Market/Service Vesting Restricted Stock Awards | Minimum | LTIP | ||||||||||
Weighted-Average Grant-Date Fair Value for awards | ||||||||||
Granted (in dollars per share) | 6.70 | |||||||||
Weighted-Average Grant-Date Fair Value | ||||||||||
Granted (in dollars per share) | 6.70 | |||||||||
Significant assumptions used to calculate fair values | ||||||||||
Expected volatility (as a percent) | 41.30% | |||||||||
Risk-free interest rate (as a percent) | 0.50% | |||||||||
Market/Service Vesting Restricted Stock Awards | Maximum | LTIP | ||||||||||
Weighted-Average Grant-Date Fair Value for awards | ||||||||||
Granted (in dollars per share) | 13.57 | |||||||||
Weighted-Average Grant-Date Fair Value | ||||||||||
Granted (in dollars per share) | $ 13.57 | |||||||||
Significant assumptions used to calculate fair values | ||||||||||
Expected volatility (as a percent) | 56.70% | |||||||||
Risk-free interest rate (as a percent) | 1.10% | |||||||||
Other disclosures | ||||||||||
Vesting percentage of the awards granted | 100.00% | |||||||||
Service Vesting Restricted Stock Units | LTIP | ||||||||||
Outstanding awards activity | ||||||||||
Granted (in shares) | 1,800 | |||||||||
Weighted-Average Grant-Date Fair Value for awards | ||||||||||
Granted (in dollars per share) | $ 4.05 | $ 8.37 | $ 10.80 | |||||||
Outstanding unvested awards activity | ||||||||||
Outstanding at the beginning of the period (in shares) | 4,160 | 3,592 | 3,367 | 2,238 | ||||||
Granted (in shares) | 2,158 | 1,539 | 2,113 | |||||||
Forfeited (in shares) | (134) | (254) | (412) | |||||||
Vested (in shares) | (1,456) | (1,060) | (572) | |||||||
Outstanding at the end of the period (in shares) | 4,160 | 3,592 | 3,367 | 4,160 | ||||||
Weighted-Average Grant-Date Fair Value | ||||||||||
Outstanding at beginning of the period (in dollars per share) | $ 6.91 | $ 9.79 | $ 10.76 | $ 10.74 | ||||||
Granted (in dollars per share) | 4.05 | 8.37 | 10.80 | |||||||
Forfeited (in dollars per share) | 8.87 | 10.14 | 10.90 | |||||||
Vested (in dollars per share) | 9.61 | 10.71 | 10.74 | |||||||
Outstanding at the end of the period (in dollars per share) | 6.91 | 9.79 | 10.76 | $ 6.91 | ||||||
Market/Service Vesting Restricted Stock Units | LTIP | ||||||||||
Outstanding awards activity | ||||||||||
Granted (in shares) | 2,100 | |||||||||
Weighted-Average Grant-Date Fair Value for awards | ||||||||||
Granted (in dollars per share) | $ 4.88 | $ 12.96 | $ 15.71 | |||||||
Outstanding unvested awards activity | ||||||||||
Outstanding at the beginning of the period (in shares) | 7,194 | 6,578 | 3,246 | 1,858 | ||||||
Granted (in shares) | 1,379 | 3,544 | 1,572 | |||||||
Forfeited (in shares) | (70) | (212) | (184) | |||||||
Vested (in shares) | (693) | |||||||||
Outstanding at the end of the period (in shares) | 7,194 | 6,578 | 3,246 | 7,194 | ||||||
Weighted-Average Grant-Date Fair Value | ||||||||||
Outstanding at beginning of the period (in dollars per share) | $ 12.29 | $ 14.24 | $ 15.66 | $ 15.59 | ||||||
Granted (in dollars per share) | 4.88 | 12.96 | 15.71 | |||||||
Forfeited (in dollars per share) | 14.49 | 14.48 | 15.48 | |||||||
Vested (in dollars per share) | 15.81 | |||||||||
Outstanding at the end of the period (in dollars per share) | 12.29 | $ 14.24 | $ 15.66 | $ 12.29 | ||||||
Market/Service Vesting Restricted Stock Units | Minimum | LTIP | ||||||||||
Weighted-Average Grant-Date Fair Value for awards | ||||||||||
Granted (in dollars per share) | 4.83 | |||||||||
Weighted-Average Grant-Date Fair Value | ||||||||||
Granted (in dollars per share) | $ 4.83 | |||||||||
Significant assumptions used to calculate fair values | ||||||||||
Expected volatility (as a percent) | 44.00% | |||||||||
Risk-free interest rate (as a percent) | 0.50% | |||||||||
Market/Service Vesting Restricted Stock Units | Maximum | LTIP | ||||||||||
Weighted-Average Grant-Date Fair Value for awards | ||||||||||
Granted (in dollars per share) | $ 15.81 | |||||||||
Weighted-Average Grant-Date Fair Value | ||||||||||
Granted (in dollars per share) | $ 15.81 | |||||||||
Significant assumptions used to calculate fair values | ||||||||||
Expected volatility (as a percent) | 54.00% | |||||||||
Risk-free interest rate (as a percent) | 1.20% | |||||||||
Other disclosures | ||||||||||
Vesting percentage of the awards granted | 200.00% | |||||||||
Restricted Stock Awards and Restricted Stock Units | ||||||||||
Weighted-Average Grant-Date Fair Value | ||||||||||
Compensation expense not yet recognized | $ 31,600,000 | $ 31,600,000 | ||||||||
Weighted average period over which compensation expense is to be recognized | 1 year 3 months 18 days | |||||||||
Restricted Stock Awards and Restricted Stock Units | LTIP | ||||||||||
Compensation agreement | ||||||||||
Fair value of awards vested | $ 14,400,000 | $ 52,200,000 | $ 37,000,000 | |||||||
Profit units | Kosmos Energy Holdings | ||||||||||
Equity-based Compensation | ||||||||||
Vesting period | 4 years | |||||||||
Weighted-Average Grant-Date Fair Value for awards | ||||||||||
Granted (in dollars per share) | $ 17 | |||||||||
Weighted-Average Grant-Date Fair Value | ||||||||||
Granted (in dollars per share) | $ 17 | |||||||||
Other disclosures | ||||||||||
Number of common shares into which the units were exchanged | 31,700 | |||||||||
Incremental compensation costs | $ 0 | |||||||||
Threshold value of awards cancelled (in dollars per unit) | $ 90 | |||||||||
Profit units | Kosmos Energy Holdings | Employees | ||||||||||
Equity-based Compensation | ||||||||||
Vesting rights on the second and fourth anniversary of issuance date (as a percent) | 50.00% | |||||||||
Profit units | Kosmos Energy Holdings | Founding Management and Directors | ||||||||||
Equity-based Compensation | ||||||||||
Vesting rights as of the date of issuance (as a percent) | 20.00% | |||||||||
Additional vesting rights on the anniversary date for each of the next four years (as a percent) | 20.00% | |||||||||
Profit units | Kosmos Energy Holdings | Minimum | ||||||||||
Equity-based Compensation | ||||||||||
Threshold value to employees, management and directors (in dollars per units) | $ 0.85 | |||||||||
Significant assumptions used to calculate fair values | ||||||||||
Expected volatility (as a percent) | 25.00% | |||||||||
Risk-free interest rate (as a percent) | 1.30% | |||||||||
Expected life | 1 year 2 months 12 days | |||||||||
Profit units | Kosmos Energy Holdings | Minimum | Employees | ||||||||||
Significant assumptions used to calculate fair values | ||||||||||
Projected turnover rate (as a percent) | 7.00% | |||||||||
Profit units | Kosmos Energy Holdings | Maximum | ||||||||||
Equity-based Compensation | ||||||||||
Threshold value to employees, management and directors (in dollars per units) | $ 90 | |||||||||
Significant assumptions used to calculate fair values | ||||||||||
Expected volatility (as a percent) | 66.00% | |||||||||
Risk-free interest rate (as a percent) | 5.10% | |||||||||
Expected life | 8 years 1 month 6 days | |||||||||
Profit units | Kosmos Energy Holdings | Maximum | Employees | ||||||||||
Significant assumptions used to calculate fair values | ||||||||||
Projected turnover rate (as a percent) | 27.00% | |||||||||
Restricted stock awards | ||||||||||
Equity-based Compensation | ||||||||||
Exchanged (in shares) | 10,000 | |||||||||
Restricted stock awards | LTIP | ||||||||||
Equity-based Compensation | ||||||||||
Exchanged (in shares) | 10,000 | |||||||||
Restricted stock units | LTIP | ||||||||||
Weighted-Average Grant-Date Fair Value | ||||||||||
Compensation expense not yet recognized | $ 34,100,000 | |||||||||
Weighted average period over which compensation expense is to be recognized | 3 years | |||||||||
Restructuring Charges.. | LTIP | ||||||||||
Compensation agreement | ||||||||||
Compensation expense recognized | $ 5,000,000 |
Income Taxes - Deferred (Detail
Income Taxes - Deferred (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Deferred Tax Assets, Net of Valuation Allowance [Abstract] | ||
Foreign capitalized operating expenses | $ 69,804 | $ 101,823 |
Foreign net operating losses | 36,352 | 14,719 |
Equity compensation | 30,752 | 26,095 |
Other | 33,744 | 22,656 |
Total deferred tax assets | 170,652 | 165,293 |
Valuation allowance | (87,517) | (116,541) |
Total deferred tax assets, net | 83,135 | 48,752 |
Deferred tax liabilities: | ||
Depletion, depreciation and amortization related to property and equipment | (526,945) | (425,183) |
Unrealized derivative gains | (584) | (92,549) |
Total deferred tax liabilities | (527,529) | (517,732) |
Net deferred tax liability | $ 444,394 | $ 468,980 |
Income Taxes (Details)
Income Taxes (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Income Taxes | |||
Income tax expense (benefit) | $ (10,784) | $ 155,272 | $ 298,898 |
Income (loss) before income taxes | $ (294,564) | $ 85,436 | $ 578,268 |
Effective tax rate (as a percent) | 4.00% | 182.00% | 52.00% |
Components of the provision for income taxes attributable to income (loss) before income taxes | |||
Current | $ 12,777 | $ 44,486 | $ 82,489 |
Deferred | (23,561) | 110,786 | 216,409 |
Reconciliation of income tax expense and the reported effective tax rate | |||
Foreign income (loss) taxed at different rates | (57,898) | 94,184 | 266,993 |
Change in valuation allowance and the expiration of fully valued deferred tax assets | 29,263 | 40,600 | 16,401 |
Non-deductible and other items | 12,347 | 1,885 | 8,957 |
Tax shortfall related to equity-based compensation | 5,504 | 18,603 | 6,547 |
Impact of losses incurred in jurisdictions in which company is not subject to taxes on effective tax rate | 121,400 | 153,500 | 159,900 |
Bermuda | |||
Income Taxes | |||
Income (loss) before income taxes | (63,749) | (62,372) | (31,787) |
United States | |||
Income Taxes | |||
Income (loss) before income taxes | $ 5,083 | $ 10,652 | $ 15,684 |
Effective tax rate (as a percent) | 179.00% | 220.00% | 81.00% |
Components of the provision for income taxes attributable to income (loss) before income taxes | |||
Current | $ 12,675 | $ 15,199 | $ 27,167 |
Deferred | (3,594) | 8,241 | (14,403) |
Foreign-other | |||
Income Taxes | |||
Income (loss) before income taxes | $ (235,898) | 137,156 | 594,371 |
Effective tax rate (as a percent) | 0.00% | ||
Statutory tax rate (as a percent) | 0.00% | ||
Components of the provision for income taxes attributable to income (loss) before income taxes | |||
Current | $ 102 | 29,287 | 55,322 |
Deferred | $ (19,967) | $ 102,545 | $ 230,812 |
Ghana | |||
Income Taxes | |||
Effective tax rate (as a percent) | 23.00% | 35.00% | 36.00% |
Parent company | |||
Income Taxes | |||
Income (loss) before income taxes | $ (283,780) | $ (69,836) | $ 279,370 |
Income Taxes - Foreign and Othe
Income Taxes - Foreign and Other (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2016USD ($)item | |
Income Taxes | |
Foreign net operating loss carryforwards | $ 116.7 |
Foreign net operating loss carryforwards expiring in 2019 | 0.9 |
Foreign net operating loss carryforwards expiring in 2020 | 13.4 |
Foreign net operating loss carryforwards expiring in 2021 | 0.5 |
Foreign net operating loss carryforwards expiring in 2022 | 0.5 |
Foreign net operating loss carryforwards expiring in 2023 | 0.6 |
Foreign net operating loss carryforwards not expiring | $ 100.8 |
Morocco | |
Income Taxes | |
Number of licenses withdrawn | item | 3 |
Tax rate applicable relating to tax holiday (as a percent) | 0.00% |
Period of income tax holiday from date of first production | 10 years |
Ireland, Mauritania, Morocco, Senegal and Suriname | |
Income Taxes | |
Net change in valuation allowance on deferred tax assets | $ 29 |
Deferred tax assets offset | 58.2 |
Foreign capitalized operating expenses | 29.2 |
Ghana | |
Income Taxes | |
Foreign net operating loss carryforwards | 53.3 |
Ireland Mauritania Morocco Portugal Senegal Suriname | |
Income Taxes | |
Foreign net operating loss carryforwards | $ 63.4 |
Net Income (Loss) Per Share (De
Net Income (Loss) Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Numerator: | |||||||||||
Net income (loss) | $ (56,700) | $ (59,763) | $ (108,324) | $ (58,993) | $ 24,000 | $ 60,265 | $ (75,192) | $ (78,909) | $ (283,780) | $ (69,836) | $ 279,370 |
Less: Basic income allocable to participating securities | (3,286) | ||||||||||
Basic net income (loss) allocable to common shareholders | (283,780) | (69,836) | 276,084 | ||||||||
Diluted adjustments to income allocable to participating securities | 58 | ||||||||||
Diluted net income (loss) allocable to common shareholders | $ (283,780) | $ (69,836) | $ 276,142 | ||||||||
Weighted average number of shares used to compute net income (loss) per share: | |||||||||||
Basic (in shares) | 385,402 | 382,610 | 379,195 | ||||||||
Restricted stock awards and units (in shares) | 6,924 | ||||||||||
Diluted (in shares) | 385,402 | 382,610 | 386,119 | ||||||||
Net income (loss) per share: | |||||||||||
Basic (in dollars per share) | $ (0.15) | $ (0.15) | $ (0.28) | $ (0.15) | $ 0.06 | $ 0.16 | $ (0.20) | $ (0.21) | $ (0.74) | $ (0.18) | $ 0.73 |
Diluted (in dollars per share) | $ (0.15) | $ (0.15) | $ (0.28) | $ (0.15) | $ 0.06 | $ 0.15 | $ (0.20) | $ (0.21) | $ (0.74) | $ (0.18) | $ 0.72 |
Outstanding restricted stock awards and units excluded from the computations of diluted net income per share (in shares) | 11,800 | 11,200 | 4,400 |
Commitments and Contingencies61
Commitments and Contingencies (Details) $ in Thousands | Oct. 14, 2011 | Jan. 31, 2017USD ($) | Nov. 30, 2015USD ($) | Dec. 31, 2016USD ($)km²item | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) |
Commitments and contingencies | ||||||
Rent expense | $ 3,300 | $ 4,700 | $ 4,600 | |||
Mauritania | ||||||
Commitments and contingencies | ||||||
3 D seismic requirements (in square kilometers) | km² | 3,000 | |||||
Offshore drilling rig contract commitments | ||||||
Number of exploration wells | item | 2 | |||||
Sao Tome and Principe | ||||||
Commitments and contingencies | ||||||
2 D seismic requirements (in square kilometers) | km² | 1,200 | |||||
3 D seismic requirements (in square kilometers) | km² | 4,000 | |||||
Western Sahara | ||||||
Commitments and contingencies | ||||||
3 D seismic requirements (in square kilometers) | km² | 5,000 | |||||
Other noncurrent assets | ||||||
Offshore drilling rig contract commitments | ||||||
Line of credit receivable | $ 30,000 | |||||
Interest accrual rate on line of credit receivable | 7.875% | |||||
Line of credit receivable amount outstanding | $ 10,200 | |||||
Jubilee Unitization And Unit Operating Agreement [Member] | ||||||
Commitments and contingencies | ||||||
Unit interest after redetermination process (as a percent) | 24.10% | |||||
Farm-out agreements | Mauritania And Senegal Offshore Block | BP | Maximum | ||||||
Commitments and contingencies | ||||||
Spending by third party for exploration and appraisal costs | 221,000 | |||||
Operating leases | ||||||
Future minimum rental commitments | ||||||
2,017 | 4,190 | |||||
2,018 | 3,820 | |||||
2,019 | 3,161 | |||||
Total | 11,171 | |||||
Atwood Achiever drilling rig contract | ||||||
Future minimum rental commitments | ||||||
2,017 | 229,482 | |||||
Total | $ 229,482 | |||||
Atwood Achiever drilling rig contract | Kosmos Energy Ventures | ||||||
Future minimum rental commitments | ||||||
Recovery payment for reverting the rig rate back to original day rate | $ 48,100 | |||||
Rig rate per day - subsidiary's revert option | $ 600 |
Additional Financial Informat62
Additional Financial Information - Accrued Liabilities (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Accrued liabilities: | |||
Exploration, development and production | $ 76,194 | $ 111,064 | |
General and administrative expenses | 31,243 | 24,839 | |
Interest | 17,247 | 17,512 | |
Income taxes | 2,579 | 3,418 | |
Taxes other than income | 1,914 | 3,064 | |
Other | 529 | ||
Accrued liabilities | 129,706 | 159,897 | |
Other Income | |||
Other Income | 74,800 | ||
Other Expenses, Net | |||
Inventory write-off | 14,900 | 36 | $ 170 |
(Gain) loss on insurance settlements - riser | (4,003) | 4,151 | |
Disputed charges and related costs | 11,299 | ||
Other, net | 920 | 1,059 | 1,911 |
Other expenses, net | $ 23,116 | $ 5,246 | $ 2,081 |
Supplementary Quarterly Financi
Supplementary Quarterly Financial Information (Unaudited) - (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Supplemental Quarterly Financial Information (Unaudited) | |||||||||||
Revenues and other income | $ 210,917 | $ 66,629 | $ 45,676 | $ 62,133 | $ 121,868 | $ 95,318 | $ 121,813 | $ 132,557 | $ 385,355 | $ 471,556 | $ 882,738 |
Costs and expenses | 268,337 | 118,890 | 169,544 | 123,148 | 55,903 | (27,165) | 171,615 | 185,767 | 679,919 | 386,120 | 304,470 |
Net income (loss) | $ (56,700) | $ (59,763) | $ (108,324) | $ (58,993) | $ 24,000 | $ 60,265 | $ (75,192) | $ (78,909) | $ (283,780) | $ (69,836) | $ 279,370 |
Net income (loss) per share | |||||||||||
Basic (in dollars per share) | $ (0.15) | $ (0.15) | $ (0.28) | $ (0.15) | $ 0.06 | $ 0.16 | $ (0.20) | $ (0.21) | $ (0.74) | $ (0.18) | $ 0.73 |
Diluted (in dollars per share) | $ (0.15) | $ (0.15) | $ (0.28) | $ (0.15) | $ 0.06 | $ 0.15 | $ (0.20) | $ (0.21) | $ (0.74) | $ (0.18) | $ 0.72 |
Schedule I Condensed Parent C64
Schedule I Condensed Parent Company Financial Statements - Balance Sheet (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Current assets: | ||||
Cash and cash equivalents | $ 194,057 | $ 275,004 | $ 554,831 | |
Prepaid expenses and other | 7,209 | 24,766 | ||
Total current assets | 475,187 | 734,148 | ||
Deferred financing costs, net of accumulated amortization of accumulated amortization of $11,213 and 8,475 at December 31, 2016 and December 31, 2015, respectively | 5,248 | 7,986 | ||
Total assets | 3,341,465 | 3,203,050 | ||
Current liabilities: | ||||
Accounts payable | 220,627 | 295,689 | ||
Accrued liabilities | 129,706 | 159,897 | ||
Total current liabilities | 370,025 | 456,741 | ||
Long-term debt | 1,321,874 | 860,878 | ||
Shareholders' equity: | ||||
Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at December 31, 2016 and December 31, 2015 | ||||
Common shares, $0.01 par value; 2,000,000,000 authorized shares; 395,859,061 and 393,902,643 issued at December 31, 2016 and 2015, respectively | 3,959 | 3,939 | ||
Additional paid-in capital | 1,975,247 | 1,933,189 | ||
Accumulated deficit | (850,410) | (564,686) | ||
Accumulated other comprehensive income | 0 | |||
Treasury stock, at cost, 9,101,395 and 8,812,054 shares at December 31, 2016 and 2015, respectively | (47,597) | (46,929) | ||
Total shareholders' equity | 1,081,199 | 1,325,513 | 1,338,959 | $ 992,335 |
Total liabilities and shareholders' equity | $ 3,341,465 | 3,203,050 | ||
Parent company | ||||
Investment in subsidiaries (as a percent) | 100.00% | |||
Current assets: | ||||
Cash and cash equivalents | $ 1,092 | 74,683 | $ 165,894 | $ 35,092 |
Receivables from subsidiaries | 14,131 | |||
Prepaid expenses and other | 417 | 469 | ||
Total current assets | 15,640 | 75,152 | ||
Investment in subsidiaries at equity | 1,580,459 | 1,759,419 | ||
Deferred financing costs, net of accumulated amortization of accumulated amortization of $11,213 and 8,475 at December 31, 2016 and December 31, 2015, respectively | 5,248 | 7,986 | ||
Total assets | 1,601,347 | 1,842,557 | ||
Current liabilities: | ||||
Accounts payable | 13 | 11 | ||
Accounts payable to subsidiaries | 1,070 | |||
Accrued liabilities | 17,939 | 17,629 | ||
Total current liabilities | 17,952 | 18,710 | ||
Long-term debt | 502,196 | 498,334 | ||
Shareholders' equity: | ||||
Common shares, $0.01 par value; 2,000,000,000 authorized shares; 395,859,061 and 393,902,643 issued at December 31, 2016 and 2015, respectively | 3,959 | 3,939 | ||
Additional paid-in capital | 1,975,247 | 1,933,189 | ||
Accumulated deficit | (850,410) | (564,686) | ||
Treasury stock, at cost, 9,101,395 and 8,812,054 shares at December 31, 2016 and 2015, respectively | (47,597) | (46,929) | ||
Total shareholders' equity | 1,081,199 | 1,325,513 | ||
Total liabilities and shareholders' equity | $ 1,601,347 | $ 1,842,557 |
Schedule I Condensed Parent C65
Schedule I Condensed Parent Company Financial Statements - Balance Sheet Parenthetical (Details) - USD ($) $ / shares in Units, $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Deferred financing costs, accumulated amortization (in dollars) | $ 11,213 | $ 8,475 |
Preference shares, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Preference shares, authorized shares | 200,000,000 | 200,000,000 |
Preference shares, issued shares | 0 | 0 |
Common shares, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Common shares, authorized shares | 2,000,000,000 | 2,000,000,000 |
Common shares, issued shares | 395,859,061 | 393,902,643 |
Treasury stock shares | 9,101,395 | 8,812,054 |
Parent company | ||
Deferred financing costs, accumulated amortization (in dollars) | $ 11,213 | $ 8,475 |
Preference shares, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Preference shares, authorized shares | 200,000,000 | 200,000,000 |
Preference shares, issued shares | 0 | 0 |
Common shares, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Common shares, authorized shares | 2,000,000,000 | 2,000,000,000 |
Treasury stock shares | 9,101,395 | 8,812,054 |
Schedule I Condensed Parent C66
Schedule I Condensed Parent Company Financial Statements - Statement of Operations (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Revenues and other income: | |||||||||||
Oil and Gas Sales Revenue | $ 310,377 | $ 446,696 | $ 855,877 | ||||||||
Total revenues and other income | $ 210,917 | $ 66,629 | $ 45,676 | $ 62,133 | $ 121,868 | $ 95,318 | $ 121,813 | $ 132,557 | 385,355 | 471,556 | 882,738 |
Costs and expenses: | |||||||||||
General and administrative | 87,623 | 136,809 | 135,231 | ||||||||
Interest and other financing costs, net | 44,147 | 37,209 | 45,548 | ||||||||
Total costs and expenses | 268,337 | 118,890 | 169,544 | 123,148 | 55,903 | (27,165) | 171,615 | 185,767 | 679,919 | 386,120 | 304,470 |
Income (Loss) before taxes | (294,564) | 85,436 | 578,268 | ||||||||
Income tax expense (benefit) | (10,784) | 155,272 | 298,898 | ||||||||
Net income (loss) | $ (56,700) | $ (59,763) | $ (108,324) | $ (58,993) | $ 24,000 | $ 60,265 | $ (75,192) | $ (78,909) | (283,780) | (69,836) | 279,370 |
Parent company | |||||||||||
Costs and expenses: | |||||||||||
General and administrative | 48,542 | 85,103 | 88,789 | ||||||||
General and administrative recoveries-related party | (40,047) | (72,543) | (78,880) | ||||||||
Interest and other financing costs, net | 55,253 | 49,572 | 20,559 | ||||||||
Other expenses, net | 1 | 240 | 1,319 | ||||||||
Equity in (earnings) losses of subsidiaries | 220,031 | 7,464 | (311,157) | ||||||||
Total costs and expenses | 283,780 | 69,836 | (279,370) | ||||||||
Income (Loss) before taxes | (283,780) | (69,836) | 279,370 | ||||||||
Net income (loss) | $ (283,780) | $ (69,836) | $ 279,370 |
Schedule I Condensed Parent C67
Schedule I Condensed Parent Company Financial Statements - Statements of Cash Flows (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Operating activities | |||||||||||
Net income (loss) | $ (56,700) | $ (59,763) | $ (108,324) | $ (58,993) | $ 24,000 | $ 60,265 | $ (75,192) | $ (78,909) | $ (283,780) | $ (69,836) | $ 279,370 |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||||||||||
Equity-based compensation | 40,084 | 75,057 | 79,541 | ||||||||
Other | 13,355 | 7,875 | (3,875) | ||||||||
Changes in assets and liabilities: | |||||||||||
(Increase) decrease in prepaid expenses and other | 17,557 | 512 | 1,732 | ||||||||
Net cash provided by (used in) operating activities | 52,077 | 440,779 | 443,586 | ||||||||
Investing activities | |||||||||||
Net cash used in investing activities | (537,763) | (796,433) | (368,603) | ||||||||
Financing activities | |||||||||||
Net proceeds from issuance of senior secured notes | 206,774 | 294,000 | |||||||||
Purchase of treasury stock | (1,981) | (18,110) | (11,096) | ||||||||
Deferred financing costs | (9,030) | (22,088) | |||||||||
Net cash provided by (used in) financing activities | 448,019 | 79,634 | (139,184) | ||||||||
Cash and cash equivalents at beginning of period | 275,004 | 554,831 | 275,004 | 554,831 | |||||||
Cash and cash equivalents at end of period | 194,057 | 275,004 | 194,057 | 275,004 | 554,831 | ||||||
Parent company | |||||||||||
Operating activities | |||||||||||
Net income (loss) | (283,780) | (69,836) | 279,370 | ||||||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||||||||||
Equity in (earnings) losses of subsidiaries | 220,031 | 7,464 | (311,157) | ||||||||
Equity-based compensation | 40,423 | 75,267 | 79,741 | ||||||||
Amortization | 3,070 | 3,190 | 3,188 | ||||||||
Other | 3,530 | 2,704 | 269 | ||||||||
Changes in assets and liabilities: | |||||||||||
(Increase) decrease in prepaid expenses and other | 52 | (34) | 89 | ||||||||
(Increase) decrease due to/from related party | (15,201) | 1,224 | (3,915) | ||||||||
Increase in accounts payable and accrued liabilities | 312 | 2,721 | 10,593 | ||||||||
Net cash provided by (used in) operating activities | (31,563) | 22,700 | 58,178 | ||||||||
Investing activities | |||||||||||
Investment in subsidiaries | (40,047) | (293,545) | (208,879) | ||||||||
Net cash used in investing activities | (40,047) | (293,545) | (208,879) | ||||||||
Financing activities | |||||||||||
Net proceeds from issuance of senior secured notes | 206,774 | 294,000 | |||||||||
Purchase of treasury stock | (1,981) | (18,110) | (11,096) | ||||||||
Deferred financing costs | (9,030) | (1,401) | |||||||||
Net cash provided by (used in) financing activities | (1,981) | 179,634 | 281,503 | ||||||||
Net increase (decrease) in cash and cash equivalents | (73,591) | (91,211) | 130,802 | ||||||||
Cash and cash equivalents at beginning of period | $ 74,683 | $ 165,894 | 74,683 | 165,894 | 35,092 | ||||||
Cash and cash equivalents at end of period | $ 1,092 | $ 74,683 | $ 1,092 | $ 74,683 | $ 165,894 |
Schedule II Valuation and Qua68
Schedule II Valuation and Qualifying Accounts (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Changes in valuation and qualifying Accounts | |||
Charged to Costs and Expenses | $ 574 | ||
Balance at the end of the period | 574 | ||
Allowance for deferred tax asset | |||
Changes in valuation and qualifying Accounts | |||
Balance at the beginning of the period | 116,541 | $ 75,941 | $ 59,540 |
Charged to Costs and Expenses | (29,024) | 40,600 | 16,401 |
Balance at the end of the period | $ 87,517 | $ 116,541 | $ 75,941 |