Cobalt International Energy 10-K 14 Mar 17 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Jan. 31, 2017	Jun. 30, 2016
Document And Entity Information [Abstract]
Entity Registrant Name	Cobalt International Energy, Inc.
Entity Central Index Key	1,471,261
Document Type	10-K
Document Period End Date	Dec. 31, 2016
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Trading Symbol	CIE
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Accelerated Filer
Entity Public Float			$ 486.6
Entity Common Stock, Shares Outstanding		447,296,474
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	$ 613,534	$ 80,171
Restricted cash	2,517	58,715
Joint interest and other receivables	167,573	211,308
Other current assets	23,149	134,434
Short-term investments	340,418	1,185,335
Total current assets	1,147,191	1,669,963
Oil and natural gas properties, net of accumulated depletion of $20,204 and $0 as of December 31, 2016 and 2015, respectively	1,078,885	2,359,033
Other property, net of accumulated depreciation and amortization of $8,426 and $12,859, as of December 31, 2016 and 2015, respectively	3,902	12,309
Other assets	500	19,914
Total assets	2,230,478	4,061,219
Current liabilities:
Trade and other accounts payable	36,954	6,945
Accrued liabilities	227,418	369,692
Accrued contract amendment costs	19,582
Angolan preliminary consideration	250,000	250,000
Total current liabilities	533,954	626,637
Long-term debt	2,479,349	1,981,895
Long-term derivative liabilities	50,123
Asset retirement obligations	6,523	3,167
Other long-term liabilities	1,863	3,383
Commitments and contingencies
Stockholders' Equity:
Common stock, $0.01 par value per share; 2,000,000,000 shares authorized, 441,210,817 and 408,740,182 issued and outstanding as of December 31, 2016 and 2015, respectively	4,412	4,088
Additional paid-in capital	4,219,611	4,164,097
Accumulated deficit	(5,065,357)	(2,722,048)
Total stockholders' equity	(841,334)	1,446,137
Total liabilities and stockholders' equity	$ 2,230,478	$ 4,061,219

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Statement Of Financial Position [Abstract]
Oil and natural gas properties, accumulated depletion (in dollars)	$ 20,204	$ 0
Other property, accumulated depreciation and amortization (in dollars)	$ 8,426	$ 12,859
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized	2,000,000,000	2,000,000,000
Common stock, shares issued	441,210,817	408,740,182
Common stock, shares outstanding	441,210,817	408,740,182

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
Income Statement [Abstract]
Oil, natural gas and natural gas liquids revenues	$ 16,805
Operating costs and expenses:
Seismic and exploration costs	58,170	$ 61,844	$ 85,567
Dry hole costs and impairments	1,967,180	462,234	236,930
Loss on amendment of contract	95,908
Lease operating expenses	7,574
General and administrative expenses	127,860	110,634	114,860
Accretion expense	550	99
Depreciation, depletion and amortization	21,983	3,881	4,584
Total operating costs and expenses	2,279,225	638,692	441,941
Operating loss	(2,262,420)	(638,692)	(441,941)
Other (expense) income, net:
Other (expense) income	(2,505)	1,555	(12)
Interest income	4,661	6,087	5,958
Interest expense	(83,045)	(63,376)	(74,768)
Total other expense, net	(80,889)	(55,734)	(68,822)
Net loss	$ (2,343,309)	$ (694,426)	$ (510,763)
Basic and diluted loss per share:	$ (5.69)	$ (1.70)	$ (1.25)
Weighted average common shares outstanding (basic and diluted)	412,080	408,535	407,116

Consolidated Statements of Chan

Consolidated Statements of Changes in Stockholders' Equity - USD ($) $ in Thousands	Total	Common Stock	Additional Paid-in Capital	Accumulated Deficit
Balance at Dec. 31, 2013	$ 2,129,146	$ 4,069	$ 3,641,936	$ (1,516,859)
Common stock issued for restricted stock and stock options		16	(16)
Equity-based compensation	31,742		31,742
Exercise of stock options	33		33
Common stock withheld for taxes on equity-based compensation	(630)		(630)
Conversion option relating to 3.125% convertible senior notes due 2024, net of allocated costs	464,738		464,738
Net loss	(510,763)			(510,763)
Balance at Dec. 31, 2014	2,114,266	4,085	4,137,803	(2,027,622)
Common stock issued for restricted stock		3	(3)
Equity-based compensation	26,297		26,297
Net loss	(694,426)			(694,426)
Balance at Dec. 31, 2015	1,446,137	4,088	4,164,097	(2,722,048)
Common stock issued for restricted stock		24	(24)
Common stock issued in debt exchange	39,595	300	39,295
Equity-based compensation	16,243		16,243
Net loss	(2,343,309)			(2,343,309)
Balance at Dec. 31, 2016	$ (841,334)	$ 4,412	$ 4,219,611	$ (5,065,357)

Consolidated Statements of Cha6

Consolidated Statements of Changes in Stockholders' Equity (Parenthetical)	Dec. 31, 2016	Dec. 06, 2016	Dec. 31, 2014
3.125% convertible senior notes due 2024
Interest rate (as a percent)	3.125%	3.125%	3.125%

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash flows from operating activities:
Net loss	$ (2,343,309)	$ (694,426)	$ (510,763)
Adjustments to reconcile net loss to net cash used in operating activities:
Dry hole costs and impairments	1,967,180	462,234	236,930
Equity-based compensation	14,889	26,297	31,742
Accretion expense	550	99
Depreciation and amortization	21,983	3,881	4,584
Loss on derivatives	2,505
(Accretion of discount) amortization of premium on investments	(242)	14,483	20,925
Amortization of debt discount	77,041	89,662	71,330
Other	(213)	(1,555)	12
Changes in operating assets and liabilities:
Joint interest and other receivables	44,679	(151,334)	64,679
Other current assets	71,323	(27,528)	20,453
Trade and other accounts payable	20,138	2,681	(64,369)
Accrued liabilities	(62,058)	272,065	46,749
Accrued contract amendment costs	19,582
Other	287	1,795	15,968
Net cash flows used in operating activities	(165,665)	(1,646)	(61,760)
Cash flows from investing activities
Additions to oil and natural gas properties	(687,892)	(915,861)	(748,656)
Capital expenditures for other property	(3,479)	(4,808)	(4,074)
Proceeds from maturity of investment securities	3,390,112	1,999,421	2,350,705
Purchase of investment securities	(2,545,911)	(1,192,873)	(2,739,134)
Net cash flows provided by (used in) investing activities	152,830	(114,121)	(1,141,159)
Cash flows from financing activities
Proceeds from issuance of long-term debt	490,000
Proceeds from debt offering, net of costs			1,269,778
Payment of debt issuance costs		(4,068)
Proceeds from exercise of stock options			33
Payments for common stock withheld for taxes on equity-based compensation			(631)
Net cash flows provided by (used in) financing activities	490,000	(4,068)	1,269,180
Increase (decrease) in cash, cash equivalents and restricted cash	477,165	(119,835)	66,261
Cash, cash equivalents and restricted cash, beginning of year	138,886	258,721	192,460
Cash, cash equivalents and restricted cash, end of year	$ 616,051	$ 138,886	$ 258,721

Organization and Nature of Busi

Organization and Nature of Business	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Organization and Nature of Business	NOTE 1. ORGANIZATION AND NATURE OF BUSINESS Cobalt International Energy, Inc., together with its wholly–owned subsidiaries (the “Company”) is an independent exploration and production company with operations in the deepwater U.S. Gulf of Mexico and offshore Angola and Gabon in West Africa. The Company operates in one reportable segment as its chief operating decision maker, the Chief Executive Officer, assesses performance and allocates resources based on the consolidated results of its business. The Company no longer accounts for its Angolan operations as discontinued operations and has reclassified its consolidated financial statements for all periods presented to no longer reflect these operations as discontinued. Liquidity and Going Concern The accompanying consolidated financial statements have been prepared on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. The consolidated financial statements do not include any adjustments that might be necessary should the Company be unable to continue as a going concern. In 2016, the Company impaired its Angolan assets (see Note 3), which led to the Company reporting a net loss of $2,343.3 million, causing the Company to have a stockholders’ deficit of $841.3 million. Although the Company commenced initial production from its Heidelberg project in January 2016, the Company’s ongoing capital and operating expenditures will vastly exceed the revenue it expects to receive from its oil and natural gas operations for the foreseeable future. In order to grow production, the Company needs to develop its discoveries into producing oil and natural gas properties, which will require that the Company raise substantial additional funding. If the Company is unable to raise substantial additional funding on a timely basis or on acceptable terms, the Company may be required to significantly curtail its exploration, appraisal and development activities. The Company adopted Accounting Standards Update (“ASU”) No. 2014–15, Presentation of Financial Statements – Going Concern In December 2016, the Company consummated a debt exchange and financing transaction (the “Transaction”) as a part of obtaining new capital. The indentures governing the new debt obligations contain certain covenants including the maintenance of a minimum consolidated cash balance of at least $200.0 million. As the Company’s detailed cash forecast shows that its projected cash balances would be out of compliance with the minimum consolidated cash balance covenant within one year after the date the consolidated financial statements are issued, the Company has concluded that there is substantial doubt about its ability to continue as a going concern. The Company’s ability to continue as a going concern is subject to, among other factors, its ability to monetize assets, its ability to obtain financing or refinance existing indebtedness, its ability to continue its cost cutting efforts for long–term rig and support services, the production rates achieved from the Heidelberg project, oil and natural gas prices, the number of commercially viable hydrocarbon discoveries made and the quantities of hydrocarbons discovered, the speed and cost with which the Company can bring such discoveries to production, whether and to what extent the Company invests in additional oil leases and concessional licenses, and the actual cost of exploration, appraisal and development of its prospects. There can be no assurance that the Company will be able to obtain additional funding on satisfactory terms or at all. In addition, no assurance can be given that any such financing, if obtained, will be adequate to meet the Company’s capital needs and support its growth. If additional funding cannot be obtained on a timely basis and on satisfactory terms, then the Company’s operations would be materially negatively impacted. If the Company becomes unable to continue as a going concern, the Company may find it necessary to file a voluntary petition for reorganization under the Bankruptcy Code in order to provide it additional time to identify an appropriate solution to its financial situation and implement a plan of reorganization aimed at improving our capital structure.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Basis of Presentation The consolidated financial statements include the accounts of the Company and its majority–owned subsidiaries (“we,” “our” or “us”). All significant intercompany accounts and transactions have been eliminated in consolidation. In the Notes to Consolidated Financial Statements, all dollar and share amounts in tabulations are in thousands of dollars and shares, respectively, unless otherwise indicated. Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and judgments that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. We base our estimates and judgments on historical experience and on various other assumptions and information that are believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. While we believe that the estimates and assumptions used in the preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates. Cash and Cash Equivalents We consider all highly liquid investments with an original maturity of three months or less at the time of purchase to be cash equivalents. All of our cash and cash equivalents are maintained with several major financial institutions in the United States. Deposits with these financial institutions may exceed the amount of insurance provided on such deposits; however, we regularly monitor the financial stability of these financial institutions and believe that we are not exposed to any significant default risk. Restricted Cash Restricted cash serves as collateral for certain of our obligations. These restricted funds are invested in interest–bearing accounts. Joint Interest and Other Receivables Joint interest receivables result from billing shared costs under the respective operating agreements to our partners. Accounts receivable from oil, natural gas and natural gas liquids sales are recorded at the invoiced amount and do not bear interest. We routinely assess the financial strength of our customers and partners and bad debts are recorded based on an account–by–account review after all means of collection have been exhausted, and the potential recovery is considered remote. As of December 31, 2016, we have a $159.1 million receivable from Sonangol Pesquisa e Produção, S.A. (“Sonangol P&P”) related to its share of costs incurred under the Block 21 Risk Services Agreement. Although this amount has been outstanding for over one year, Sonangol P&P has acknowledged that this amount is owed to us. We continue to work with them on resolution of this issue and have determined that we did not need to set up a reserve for doubtful accounts as of December 31, 2016. As of December 31, 2016 and 2015, we did not have any reserves for doubtful accounts. We also did not have any off–balance sheet credit exposure related to our customers. Investments We have investments in marketable debt securities that are classified as held–to–maturity as we have the positive intent and ability to hold the investments until they mature. We classify investments with original maturities of greater than three months and remaining maturities of less than one year as short–term investments, and investments with maturities beyond one year as long–term investments. Our debt securities are carried at amortized cost and the carrying value of these securities is adjusted for amortization of premiums and accretion of discounts to maturity over the life of the securities. As the estimated fair value of each investment approximates its amortized cost, there were no significant unrecognized holding gains or losses as of December 31, 2016 and 2015. Income related to these securities is reported as a component of interest income in our consolidated statements of operations. Investments are considered to be impaired when a decline in fair value is determined to be other–than–temporary. We conduct a regular assessment of our debt securities with unrealized losses to determine whether these securities have other–than-temporary impairment (“OTTI”). This assessment considers, among other factors, the nature of the securities, credit rating or financial condition of the issuer, the extent and duration of the unrealized loss, market conditions and whether we intend to sell or whether it is more likely than not that we will be required to sell the debt securities. As of December 31, 2016 and 2015, we have no OTTI in our debt securities. Property and Depreciation, Depletion and Amortization Our oil, natural gas and natural gas liquids producing activities are accounted for under the successful efforts method of accounting. Under this method, costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs and costs of carrying and retaining unproved properties are charged to expense as incurred. For 2016, 2015 and 2014, we recorded dry hole costs of $213.5 million, $188.0 million and $165.5 million, respectively, to expense costs associated with the drilling of exploratory wells that did not find proved reserves. Costs for unproved leasehold properties and exploratory wells that find reserves that cannot yet be classified as proved are capitalized if the well has found a sufficient quantity of reserves to justify its completion as a producing well and we are making sufficient progress assessing the reserves and the economic and operating viability of the project. Often, the ability to move into the development phase and record proved reserves is dependent on obtaining permits and government or partner approvals, the timing of which is ultimately beyond our control. Exploratory well costs remain suspended as long as we are actively pursuing such approvals and permits, and believe they will be obtained. For complex exploratory projects, it is not unusual to have exploratory wells remain suspended on the balance sheet for several years while additional appraisal drilling and seismic work is performed on the field or while we seek government or partner approval of development plans. Our assessment of suspended exploratory well costs is continuous until a determination is made to either sanction the project or to expense the well costs as dry hole costs as sufficient progress has not been made in assessing the reserves and the economic and operating viability of the project. In 2016, we recorded dry hole costs of $1,276.4 million to expense costs associated with our Angolan exploratory wells (see Note 3). The capitalized costs of our producing oil and natural gas properties are depreciated and depleted by the units–of–production method based on the ratio of current production to estimated total net proved reserves as estimated by independent petroleum engineers. Proved developed reserves are used in computing unit rates for drilling and development costs and total proved reserves are used for depletion rates of leasehold costs. Other property is stated at cost less accumulated depreciation, which is computed using the straight–line method based on estimated economic lives ranging from three to ten years. We expense costs for maintenance and repairs in the period incurred. Significant improvements and betterments are capitalized if they extend the useful life of the asset. Impairment of Oil and Natural Gas Properties We evaluate our proved oil and natural gas properties and related equipment and facilities for impairment whenever events or changes in circumstances indicate that the carrying amounts of such properties may not be recoverable. The determination of recoverability is made based upon estimated undiscounted future net cash flows. The amount of impairment loss, if any, is determined by comparing the fair value, as determined by a discounted cash flow analysis, with the carrying value of the related asset. For 2015, we recorded impairment charges of $256.8 million related to our proved oil and natural gas properties as the carrying amounts of such properties were determined not to be recoverable (see Note 5). Oil and natural gas leases for unproved properties with a carrying value greater than $1.0 million are assessed individually for impairment based on our current exploration plans and an allowance for impairment is provided if impairment is indicated. Leases that are individually less than $1.0 million in carrying value or are near expiration are amortized over the terms of the leases at rates that provide for full amortization of leases upon lease expiration. These leases have expiration dates ranging from 2017 through 2026. For 2016, 2015 and 2014, we recorded impairment charges of $66.6 million, $26.9 million and $70.5 million, respectively, related to our leases for unproved oil and natural gas properties. In 2016, we also recorded an impairment charge of $353.4 million related to our Angolan leases in conjunction with the write-off of our Angolan exploratory well costs (see Note 3). Asset Retirement Obligations An asset retirement obligation (“ARO”) represents the future abandonment costs of tangible assets, such as wells, service assets, and other facilities. We record an ARO and capitalize the asset retirement cost in oil and natural gas properties in the period in which the retirement obligation is incurred based upon the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells. After recording these amounts, the ARO is accreted to its future estimated value using an assumed cost of funds and the additional capitalized costs are depreciated on a unit–of–production basis. If the ARO is settled for an amount other than the recorded amount, a gain or loss is recognized. Embedded Derivatives Our first lien senior secured notes due (the “First Lien Notes”) and our second lien senior secured notes due 2023 (the “Second Lien Notes”) include features which were determined to be embedded derivatives requiring bifurcation and accounting as separate financial instruments. The embedded derivatives were initially recorded at fair value and are subject to remeasurement as of each balance sheet date. We have elected not to designate our embedded derivatives as hedging instruments. Changes in the fair value of these embedded derivatives are recorded immediately to earnings in “Other (expense) income” in our consolidated statements of operations. Revenue Recognition Oil, natural gas and natural gas liquids revenues are recognized when production is sold to a purchaser at fixed or determinable prices, when delivery has occurred and title has transferred and collectability of the revenue is reasonably assured. We follow the sales method of accounting for natural gas revenues. Under this method of accounting, revenues are recognized based on volumes sold, which may differ from the volume to which we are entitled based on our working interest. An imbalance is recognized as a liability only when the estimated remaining reserves will not be sufficient to enable the under–produced owner(s) to recoup its entitled share through future production. Under the sales method, no receivables are recorded where we have taken less than our share of production. There were no significant natural gas imbalances at December 31, 2016. Income Taxes We use the liability method to determine our income tax provisions, under which current and deferred tax liabilities and assets are recorded in accordance with enacted tax laws and rates. Under this method, the amounts of deferred tax liabilities and assets at the end of each period are determined using the tax rate expected to be in effect when taxes are actually paid or recovered. Valuation allowances are established to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. Concentration of Credit Risk Our oil, natural gas and natural gas liquids revenues are derived principally from uncollateralized sales to customers in the oil and natural gas industry; therefore, our customers may be similarly affected by changes in economic and other conditions within the industry. We have experienced no credit losses on such sales in the past. In 2016, one customer accounted for 96.5% of our consolidated oil, natural gas and natural gas liquids revenues. We believe that the loss of this customer would have a temporary effect on our revenues but, that over time, we would be able to replace this customer. Recently Issued Accounting Standards In May 2014, the Financial Accounting Standards Board (“FASB”) issued ASU No. 2014–09, Revenue from Contracts with Customers. In August 2014, the FASB issued ASU No. 2014–15, Presentation of Financial Statements – Going Concern In April 2015, the FASB issued ASU No. 2015–03, Interest—Imputation of Interest In July 2015, the FASB issued ASU No. 2015–11, Accounting for Inventory In February 2016, the FASB issued ASU No. 2016-02, Leases In March 2016, the FASB issued ASU No. 2016-09, Compensation – Stock Compensation (Subtopic 718) In June 2016, the FASB issued ASU 2016–13, Financial Instruments – Credit Losses In November 2016, the FASB issued ASU 2016–18, Statement of Cash Flows on December 31, 2016, which required that we apply the guidance on a retrospective basis, wherein our consolidated statements of cash flows for all periods presented were adjusted to reflect the effects of applying the guidance. The following table shows the effects of applying the guidance: Prior to Adoption (1) As Adjusted Year ended December 31, 2015: (Accretion of discount) amortization of premium on investments $ 14,207 $ 14,483 Accrued liabilities 22,453 272,065 Net cash flows used in operating activities (251,942 ) (1,646 ) Change in restricted funds (3,856 ) — Proceeds from maturity of investment securities 1,894,562 1,999,421 Purchase of investment securities (892,577 ) (1,192,873 ) Net cash flows provided by (used in) investing activities 77,460 (114,121 ) Increase (decrease) in cash, cash equivalents and restricted cash (178,550 ) (119,835 ) Cash, cash equivalents and restricted cash, end of year 80,171 138,886 Year ended December 31, 2014: (Accretion of discount) amortization of premium on investments 18,159 20,925 Net cash flows used in operating activities (64,526 ) (61,760 ) Change in restricted funds 43,667 — Proceeds from maturity of investment securities 1,700,123 2,350,705 Purchase of investment securities (2,129,453 ) (2,739,134 ) Net cash flows provided by (used in) investing activities (1,138,393 ) (1,141,159 ) (1) Amounts are after reclassification of Angolan operations to no longer reflect these operations as discontinued. No other new accounting pronouncements issued or effective during 2016 have had or are expected to have a material impact on our consolidated financial statements.

Angolan Impairments

Angolan Impairments	12 Months Ended
	Dec. 31, 2016
Asset Impairment Charges [Abstract]
Angolan Impairments	NOTE 3. ANGOLAN IMPAIRMENTS In August 2015, we executed the Agreement with Sonangol for the sale by us to Sonangol of the entire issued and outstanding share capital of Cobalt Angola’s indirect wholly–owned subsidiaries, CIE Angola Block 20 Ltd. and CIE Angola Block 21 Ltd., which respectively hold our 40% working interest in each of Block 20 and Block 21 offshore Angola. The requisite Angolan government approvals were not received within one year from the execution date and the Agreement terminated by its terms in August 2016. Since then, we have been working with Sonangol to understand and agree on the financial and operational implications of the termination of the Agreement. As part of these discussions, we have requested that Sonangol extend certain deadlines for exploration and development milestones under the agreements governing Blocks 20 and 21. Under the Agreement, we are entitled to be put back in our original position as if no agreement had been concluded, which we believe requires Sonangol to extend all such deadlines by, at a minimum, the one year period the Agreement was pending plus the period of time from the termination of the Agreement until this matter is resolved. No extensions have been granted to date. Over six months have passed since the termination of the Agreement, and there can be no assurance that such extensions will be forthcoming, on favorable terms or at all. We reserve the right to and will vigorously enforce the provisions of the Agreement and our rights under international law if Sonangol does not grant the extensions we believe we are entitled to under the Agreement. The dispute resolution procedures of the Agreement require that any dispute be finally resolved under the Rules of Arbitration of the International Chamber of Commerce, with proceedings seated in London, England. In addition, prior to commencing arbitration proceedings, a party must provide the other party with a Notice of Dispute describing the nature of the dispute and the relief requested. Given Sonangol’s delays and failure to date to grant the extensions, we submitted such a Notice of Dispute on March 8, 2017 to Sonangol under the Agreement. If Sonangol does not timely resolve this matter to our satisfaction, we intend to move forward with arbitration and at that time we will seek all available remedies at law or in equity. Further, our Angolan assets are indirectly held by a German subsidiary, and we therefore believe we are entitled to certain protections provided under international law under the bilateral investment treaty between Germany and Angola, dated October 30, 2003, including its substantive and procedural protections to investments of German investors. In 2016, we recorded $1,629.8 million of dry hole costs and impairments to write off capitalized well costs and the underlying leases associated with our Angolan operations in accordance with Accounting Standards Codification (“ASC”) 932, Extractive Activities – Oil and Gas Although we plan to continue to fulfill our obligations as operator, we do not plan to make any material additional investments in Angola until the financial and operational implications of the termination of the Agreement are resolved to our satisfaction. In addition, we are currently holding the $250.0 million initial payment that Sonangol made to us under the Agreement and do not plan to return any part of it until this matter, and the related matter concerning the payment of the joint interest receivable owed to us by Sonangol under the Block 21 Risk Services Agreement, is resolved.

Investments

Investments	12 Months Ended
	Dec. 31, 2016
Investments Debt And Equity Securities [Abstract]
Investments	NOTE 4. INVESTMENTS Our investments in held–to–maturity securities consist of the following as of December 31: 2016 2015 Corporate securities $ 227,854 $ 492,955 Commercial paper 292,466 604,986 U.S. Treasury securities 161,778 105,064 Certificates of deposit — 20,750 Total $ 682,098 $ 1,223,755 These investments are recorded in our consolidated balance sheets as follows as of December 31: 2016 2015 Cash and cash equivalents $ 341,680 $ 38,420 Short-term investments (1) 340,418 1,185,335 $ 682,098 $ 1,223,755 (1) As of December 31, 2016 and 2015, $9.1 million and $299.3 million, respectively, of these investments serve as collateral for certain of our obligations. At December 31, 2016 and 2015, the contractual maturities of our investments were within one year. Actual maturities may differ from contractual maturities as some borrowers have the right to call or prepay obligations with or without call or prepayment penalties.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Fair Value Measurements	NOTE 5. FAIR VALUE MEASUREMENTS The fair value hierarchy has three levels based on the reliability of the inputs used to determine fair value. Level 1 refers to fair values determined based on quoted prices in active markets for identical assets or liabilities. Level 2 refers to fair values determined based on quoted prices for similar assets and liabilities in active markets or inputs that are observable for the asset or liability, either directly or indirectly through market corroboration. Level 3 refers to fair values determined based on our own assumptions used to measure assets and liabilities at fair value. Recurring Basis The following table represents the fair value hierarchy for our liabilities required to be measured at fair value on a recurring basis: Fair Value Measurements at the End of the Reporting Period: Fair Value Level 1 Level 2 Level 3 As of December 31, 2016: Embedded derivative liabilities: First Lien Notes $ 27,012 $ — $ — $ 27,012 Second Lien Notes 23,111 — — 23,111 Total $ 50,123 $ — $ — $ 50,123 The fair values of these embedded derivatives were estimated using the “with” and “without” method. Using this methodology, the First Lien Notes and Second Lien Notes were first valued with the embedded derivatives (the “with” scenario) and subsequently valued without the embedded derivative (the “without” scenario). The fair values of the embedded derivatives were estimated as the difference between the fair values of the First Lien Notes and Second Lien Notes in the “with” and “without” scenarios. The fair values of the First Lien Notes and Second Lien Notes in the “with” and “without” scenarios were estimated using a risk–neutral probability of default model. Significant Level 3 assumptions used in the valuation of the embedded derivatives were the fair values of our long–term debt, the expected recovery rates, the risk–neutral probability of default and the risk–free rates. The initial measurement of fair value for these embedded derivatives was at December 6, 2016, the date we entered into the First Lien Notes and Second Lien Notes (see Note 7). The reconciliation of changes in the fair value of our embedded derivatives is as follows for the year ended December 31: 2016 Beginning of period $ — Issuance of First Lien Notes and Second Lien Notes 47,618 Change in fair value 2,505 End of period $ 50,123 Nonrecurring Basis In 2015, as a result of a reduction in future net cash flows, we recognized a $256.8 million impairment charge to write down proved oil and natural gas properties to their fair value of $68.4 million. The fair value was determined using the income approach and was based on the expected present value of the future net cash flows from estimated reserves. Significant Level 3 assumptions associated with the calculation of discounted cash flows used in the impairment analysis included estimates of future prices, production costs, development expenditures, anticipated production of our estimated reserves, appropriate risk–adjusted discount rates and other relevant data. Financial Instruments The estimated fair values of our financial instruments have been determined at discrete points in time based on relevant market information. Our financial instruments consist of cash and cash equivalents, joint interest and other receivables, held–to–maturity investments, accounts payable and accrued liabilities. The carrying amounts of our financial instruments, other than held–to–maturity–investments and long–term debt, approximate fair value because of the short–term nature of the items. There were no significant unrecognized holding gains or losses related to our held–to–maturity investments as of December 31, 2016 and 2015. Accordingly, the carrying value of our held–to–maturity investments approximates their fair value. Our held–to–maturity investments are not traded on a public exchange and the fair value of these investments is based on inputs using valuations obtained from independent brokers. As these valuations use readily observable market parameters that are actively quoted and can be validated through external sources, we have categorized these investments as Level 2. The estimated fair value of our long–term debt is as follows as of December 31: 2016 2015 10.75% first lien notes due 2021 $ 482,250 $ — 7.75% second lien notes due 2023 327,449 — 2.625% convertible senior notes due 2019 305,378 791,209 3.125% convertible senior notes due 2024 332,344 577,291 $ 1,447,421 $ 1,368,500 The fair values of our long–term debt were estimated using quoted market prices. As these valuations use quoted prices in active markets for identical assets or liabilities, we have categorized the long–term debt as Level 1.

Oil and Natural Gas Properties

Oil and Natural Gas Properties	12 Months Ended
	Dec. 31, 2016
Property Plant And Equipment [Abstract]
Oil and Natural Gas Properties	NOTE 6. OIL AND NATURAL GAS PROPERTIES Oil and natural gas properties consisted of the following as of December 31: 2016 2015 Proved oil and natural gas properties: Well and development costs $ 118,245 $ 71,463 Accumulated depletion (20,204 ) — Total proved properties 98,041 71,463 Unproved oil and natural gas properties: Oil and natural gas leaseholds 651,295 738,852 Accumulated valuation allowance (507,198 ) (178,463 ) 144,097 560,389 Exploratory wells in process 836,747 1,727,181 Total unproved properties 980,844 2,287,570 Total oil and natural gas properties, net $ 1,078,885 $ 2,359,033 Capitalized Exploratory Well Costs The following tables reflect the net changes in and the cumulative costs of capitalized exploratory well costs (excluding any related leasehold costs): 2016 2015 2014 Beginning of period $ 1,727,181 $ 1,186,464 $ 777,823 Additions to capitalized exploration Exploratory well costs 499,985 630,395 522,892 Capitalized interest 99,541 87,683 51,208 Amounts charged to expense (1) (1,489,960 ) (177,361 ) (165,459 ) End of period $ 836,747 $ 1,727,181 $ 1,186,464 (1) Amounts represent dry hole costs related to exploratory wells which did not encounter commercial hydrocarbons or where it was determined that sufficient progress was not being made. 2016 2015 Cumulative costs: Exploratory well costs $ 582,115 $ 1,572,090 Capitalized interest 254,632 155,091 $ 836,747 $ 1,727,181 Wells costs capitalized for a period greater than one year after completion after drilling (included in table above) $ 609,893 $ 1,225,747 As of December 31, 2016, capitalized exploratory well costs that have been suspended longer than one year are associated with our Shenandoah, North Platte, Anchor, and Gabon discoveries. As of December 31, 2015, capitalized exploratory well costs that have been suspended longer that one year as associated with our Shenandoah, North Platte, Anchor, Gabon and Angolan discoveries. These well costs are suspended pending ongoing evaluation including, but not limited to, results of additional appraisal drilling, well–test analysis, additional geological and geophysical data and approval of a development plan. We believe these discoveries exhibit sufficient indications of hydrocarbons to justify potential development and are actively pursuing efforts to fully assess them. If additional information becomes available that raises substantial doubt as to the economic or operational viability of these discoveries, the associated costs will be expensed at that time.

Long-term Debt, Net

Long-term Debt, Net	12 Months Ended
	Dec. 31, 2016
Long Term Debt [Abstract]
Long-term Debt, Net	NOTE 7. LONG–TERM DEBT, NET Long–term debt, net consisted of the following as of December 31: 2016 2015 10.75% first lien notes due 2021 Principal outstanding $ 500,000 $ — Unamortized discount (1) (34,416 ) — Carrying amount 465,584 — 7.75% second lien notes due 2023 Principal outstanding 584,732 — Unamortized discount (2) (54,856 ) — Carrying amount 529,876 — 2.625% convertible senior notes due 2019: Principal outstanding 763,446 1,380,000 Unamortized discount (3) (109,689 ) (258,565 ) Carrying amount 653,757 1,121,435 3.125% convertible senior notes due 2024: Principal outstanding 1,204,145 1,300,000 Unamortized discount (4) (374,013 ) (439,540 ) Carrying amount 830,132 860,460 Total $ 2,479,349 $ 1,981,895 (1) (2) (3) (4) On December 6, 2016, we consummated the Transaction with certain holders (the “Holders”) of our outstanding 2.625% Convertible Senior Notes due 2019 (the “2019 Notes”) and 3.125% Convertible Senior Notes due 2024 (the “2024 Notes”). The Transaction consisted of: (i) the issuance of $500.0 million aggregate principal amount of the First Lien Notes to Holders for cash at a price of 98% and (ii) the issuance of $584.7 million aggregate principal amount of the Second Lien Notes and 30.0 million shares of our common stock to Holders in exchange for $616.6 million aggregate principal amount of 2019 Notes and $95.9 million aggregate principal amount of 2024 Notes held by the Holders. Both our First Lien Notes and Second Lien Notes have a requirement to pay an applicable premium upon a change in control or an event of default. In addition, our Second Lien Notes also have a put option in an asset sale. These requirements were determined to be embedded derivatives that require us to bifurcate and fair value the derivatives as of December 6, 2016 and to fair value the derivatives as of each subsequent reporting date (see Note 5). At December 6, 2016, we recognized derivative liabilities of $24.8 million and $22.8 million for our First Lien Notes and Second Lien Notes, respectively, which decreased the carrying value of these notes. We accounted for the Transaction as a debt modification as we determined that the terms of the new debt instruments were not substantially different from the terms of the original instruments. We did not recognize any gain or loss on the Transaction and have prospectively adjusted the effective interest rates on the 2019 Notes and 2024 Notes. Costs related to the Transaction totaled $19.6 million and are included in “General and administrative expenses” in our consolidated statements of operations. 10.75% First Lien Notes The 10.75% First Lien Notes were issued under an indenture dated December 6, 2016 (the “First Lien Indenture”) and mature on December 1, 2021. Interest is payable semi–annually in arrears on each June 1 and December 1 of each year. The First Lien Notes are initially guaranteed by all of our wholly–owned domestic subsidiaries (the “Guarantors”) and are secured, subject to certain exceptions, by a first priority lien on (i) substantially all of ours and the Guarantors’ assets and (ii) 65% of the shares of capital stock of Cobalt International Energy Overseas Ltd., which indirectly owns our working interests in our blocks offshore Angola and offshore Gabon (collectively, the “Collateral”). The First Lien Indenture includes covenants including, without limitation, restrictions on our ability to incur additional indebtedness, create liens on our properties, pay dividends and make restricted payments or certain investments, in each case subject to certain exceptions. The First Lien Indenture also requires us to apply a portion of the proceeds from certain asset sales to offer to repay the obligations under the First Lien Indenture, limits the incurrence of indebtedness secured on a second lien basis (including additional Second Lien Notes), prohibits the issuance of additional First Lien Notes and requires us to maintain a cash balance of at least $200.0 million. Prior to December 1, 2018, we may redeem the First Lien Notes, at our option, at a redemption price equal to 100% of the outstanding principal amount of such notes plus the applicable premium (as defined in the First Lien Indenture). On and after December 1, 2018, the First Lien Notes may be redeemed in multiples of $1,000 principal amount at a redemption price equal to 100% of the First Lien Notes to be redeemed, plus accrued and unpaid interest to, but excluding, the redemption date. 7.75% Second Lien Notes The 7.75% Second Lien Notes were issued pursuant to an indenture dated December 6, 2016 (as amended or supplemented from time to time, the “Second Lien Indenture”) and mature on December 1, 2023. Interest is payable semi–annually in arrears on each June 1 and December 1 of each year. The Second Lien Notes are guaranteed by the Guarantors and are secured, subject to certain exceptions, by a second priority lien on the Collateral. The Second Lien Indenture includes covenants and redemption provisions substantially similar to those in the First Lien Indenture. 2.625% Convertible Senior Notes due 2019 The 2019 Notes were issued under an indenture dated December 17, 2012 (the “2019 Indenture”) and mature December 1, 2019. Interest is payable semi–annually in arrears on June 1 and December 1 of each year. The 2019 Notes are senior unsecured obligations. The 2019 Notes may be converted at the option of the holder on the second scheduled trading day immediately preceding the maturity date, in multiples of $1,000 principal amount. The 2019 Notes are convertible at an initial conversion rate of 28.023 shares of common stock per $1,000 principal amount, representing an initial conversion price of approximately $35.68 per share. The conversion rate is subject to adjustment upon the occurrence of certain events, as defined in 2019 Indenture, but will not be adjusted for any accrued and unpaid interest except in limited circumstances. We can satisfy the conversion obligation, at our option, in either cash, shares of common stock or a combination thereof. When the 2019 Notes were issued, we accounted for the debt and equity components of the 2019 Notes separately, as we have the option to settle the conversion obligation in cash. At the date of issuance, we calculated the fair value of the 2019 Notes, excluding the conversion feature, based on the fair value of similar non–convertible debt instruments. The difference between the cash proceeds and the estimated fair value represented the value which was assigned to the equity component and recorded as a debt discount. The debt discount is being amortized using the effective interest rate method over the period from issuance to the maturity date of December 1, 2019. The carrying amount of the equity component of the 2019 Notes reported in additional paid in capital was initially valued at $381.4 million, which is net of $9.1 million of debt issuance costs allocated to the equity component. As the closing price of our common stock on December 31, 2016 was less than the initial conversion price for the 2019 Notes, the if–converted value of the 2019 Notes would be less than principal amount. Holders of the 2019 Notes who convert their notes in connection with a “make–whole fundamental change”, as defined in the 2019 Indenture, may be entitled to a make–whole premium in the form of an increase in the conversion rate. Additionally, in the event of a fundamental change, as defined in the 2019 Indenture, holders of the 2019 Notes may require us to repurchase for cash all or a portion of their notes equal to $1,000, or a multiple of $1,000, at a fundamental change repurchase price equal to 100% of the principal amount of 2019 Notes, plus accrued and unpaid interest, if any, to, but not including, the fundamental change repurchase date. Upon the occurrence of an event of default, as defined within the 2019 Indenture, the trustee or the holders of at least 25% in aggregate principal amount of the 2019 Notes then outstanding may declare 100% of the principal of, and accrued and unpaid interest on, all the 2019 Notes to be due and payable immediately. 3.125% Convertible Senior Notes due 2024 The 2024 Notes were issued under an indenture dated May 13, 2014 (the “2024 Indenture”) and mature on May 15, 2024. Interest is payable semi–annually in arrears on May 15 and November 15 of each year. The 2024 Notes are senior unsecured obligations and ran equal in right of payment to the 2019 Notes. Prior to November 15, 2023, the 3.125% Notes are convertible only under the following circumstances: (i) during any fiscal quarter commencing after March 31, 2015 (and only during such fiscal quarter), if the last reported sale price of our common stock for at least 20 trading days (whether or not consecutive) during a 30 consecutive trading day period ending on, and including, the last trading day of the immediately preceding fiscal quarter exceeds $30.00 on each applicable trading day; (ii) during the five business day period after any five consecutive trading day period (the “2024 Notes Measurement Period”) in which the trading price per $1,000 principal amount of notes for each trading day of the 2024 Notes Measurement Period was less than 98% of the product of the last reported sale price of our common stock and the conversion rate on each such trading day; (iii) if we call all or any portion of the 2024 Notes for redemption on the second scheduled trading day immediately preceding the related redemption date; or (iv) upon the occurrence of specified distributions or the occurrence of specified corporate events. As of December 31, 2016, none of the conditions allowing holders of the 2024 Notes to convert had been met. On or after November 15, 2023, the 2024 Notes may be converted at the option of the holder at any time on the second scheduled trading day immediately preceding the stated maturity date, in multiples of $1,000 principal amount. The 2024 Notes are convertible at an initial conversion rate of 43.3604 shares of common stock per $1,000 principal amount, representing an initial conversion price of approximately $23.06 per share. The conversion rate is subject to adjustment upon the occurrence of certain events, as defined in the 2024 Indenture, but will not be adjusted for any accrued and unpaid interest except in limited circumstances. We can satisfy the conversion obligation, at our option, in either cash, shares of common stock or a combination thereof. When the 2024 Notes were issued, we accounted for the debt and equity components of the 2024 Notes separately, as we have the option to settle the conversion obligation in cash. At the date of issuance, we calculated the fair value of the 2024 Notes, excluding the conversion feature, based on the fair value of similar non–convertible debt instruments. The difference between the cash proceeds and the estimated fair value represented the value which was assigned to the equity component and recorded as a debt discount. The debt discount is being amortized using the effective interest rate method over the period from issuance to the maturity date of May 15, 2024. The carrying amount of the equity component of the 2024 Notes reported in additional paid in capital was initially valued at $464.7 million, which is net of $11.1 million of debt issuance costs allocated to the equity component. As the closing price of our common stock on December 31, 2016 was less than the initial conversion price for the 2024 Notes, the if–converted value of the 2024 Notes would be less than principal amount. Holders of the 2024 Notes who convert their notes in connection with a “make– whole fundamental change”, as defined in the 2024 Indenture, may be entitled to a make–whole premium in the form of an increase in the conversion rate. Additionally, in the event of a fundamental change, as defined in the 2024 Indenture, holders of the 2024 Notes may require us to repurchase for cash all or a portion of their notes equal to $1,000 or a multiple of $1,000 at a fundamental change repurchase price equal to 100% of the principal amount of 2024 Notes, plus accrued and unpaid interest, if any, to, but not including, the fundamental change repurchase date. Upon the occurrence of an event of default, as defined within the 2024 Indenture, the trustee or the holders of at least 25% in aggregate principal amount of the Notes then outstanding may declare 100% of the principal of, and accrued and unpaid interest on, all the 2024 Notes to be due and payable immediately. Borrowing Base Facility Agreement In 2015, Cobalt GOM #1 LLC, an indirect, wholly-owned subsidiary, entered into a Borrowing Base Facility Agreement (the “Facility Agreement”) which provided for a limited recourse $150.0 million senior secured reserve–based term loan facility, with an amount available for borrowing at any time limited to a periodically adjusted borrowing base amount. In 2016, we terminated the Facility Agreement because the borrowing base amount under the Facility Agreement was expected to be materially reduced to a level that would not justify the ongoing expense of maintaining the facility. In conjunction with the termination, we wrote off $3.3 million of debt issuance costs associated with the facility agreement. We had no amounts outstanding under the Facility Agreement at any time it was in place. Maturities of Long–Term Debt The maturities of our long–term debt are as follows for the years ended December 31: Payments Due By Year 2017 2018 2019 2020 2021 Thereafter Principal outstanding $ — $ — $ 763,446 $ — $ 500,000 $ 1,788,877

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2016
Asset Retirement Obligation [Abstract]
Asset Retirement Obligations	NOTE 8. ASSET RETIREMENT OBLIGATIONS The changes in ARO are as follows for the years ended December 31: 2016 2015 Beginning of period $ 3,167 $ — Liabilities incurred — 3,068 Revisions 2,806 — Accretion 550 99 End of period $ 6,523 $ 3,167

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2016
Commitments And Contingencies Disclosure [Abstract]
Commitments and Contingencies	NOTE 9. COMMITMENTS AND CONTINGENCIES We are currently, and from time to time we may become, involved in various legal and regulatory proceedings arising in the normal course of business. In November 2014, two purported stockholders, St. Lucie County Fire District Firefighters’ Pension Trust Fund and Fire and Police Retiree Health Care Fund, San Antonio, filed a class action lawsuit in the U.S. District Court for the Southern District of Texas on behalf of a putative class of all purchasers of our securities from February 21, 2012 through November 4, 2014 (the “St. Lucie lawsuit”). The St. Lucie lawsuit, filed against us and certain officers, former and current members of the Board of Directors, underwriters, and investment firms and funds, asserted violations of federal securities laws based on alleged misrepresentations and omissions in SEC filings and other public disclosures, primarily regarding compliance with the U.S. Foreign Corrupt Practices Act (“FCPA”) in our Angolan operations and the performance of certain wells offshore Angola. In December 2014, Steven Neuman, a purported stockholder, filed a substantially similar lawsuit against us and certain of our officers in the U.S. District Court for the Southern District of Texas on behalf of a putative class of all purchasers of our securities from February 21, 2012 through August 4, 2014 (the “Neuman lawsuit”). Like the St. Lucie lawsuit, the Neuman lawsuit asserted violations of federal securities laws based on alleged misrepresentations and omissions in SEC filings and other public disclosures regarding our compliance with the FCPA in our Angolan operations. In March 2015, the Court entered an order consolidating the Neuman lawsuit with the St. Lucie lawsuit (the “Consolidated Action”) and also entered an order in the Consolidated Action appointing Lead Plaintiffs and Lead Counsel. Lead Plaintiffs filed their consolidated amended complaint in May 2015. Among other remedies, the Consolidated Action seeks damages in an unspecified amount, along with an award of attorney fees and other costs and expenses to the plaintiffs. We filed a motion to dismiss the consolidated amended complaint in June 2015, and the other defendants also filed motions to dismiss. The Court denied our motion to dismiss in January 2016, and, in March 2016, the Court also denied our motion requesting that the Court certify its order on the motions to dismiss so that we may seek interlocutory appellate review of the order. Lead Plaintiffs also have filed a motion for class certification, seeking to certify a class of all persons and entities who purchased or otherwise acquired our securities between March 1, 2011 and November 3, 2014. The matter remains ongoing. In May 2016, Gaines, a purported stockholder, filed a derivative action in the 295th District Court in Harris County, Texas against us, as a nominal defendant, certain of our current and former officers and directors, and certain investment firms and funds. The lawsuit alleges that current and former officers and directors breached their fiduciary duties by making, and permitting us to make, alleged misrepresentations about two of our exploration wells offshore Angola; that certain officers received performance-based compensation in excess of what they were entitled; and that the investment firms and funds owed a fiduciary duty to us as controlling stockholders and breached that duty by engaging in insider trading. The lawsuit further alleges that demand was wrongfully refused. The plaintiff asserts claims for breach of fiduciary duty and unjust enrichment and seeks damages in an unspecified amount, disgorgement of profits, appropriate equitable relief, and an award of attorney fees and other costs and expenses. In July 2016, we filed our answer and special exceptions challenging the plaintiff’s standing to bring such claims against us. The Court heard arguments on our special exceptions in December 2016. The In November 2016, McDonaugh, a purported stockholder, filed a derivative action in the 80th District Court in Harris County, Texas against us, as a nominal defendant, and certain of our current and former officers and directors. The lawsuit alleges that defendants breached their fiduciary duties by failing to maintain adequate internal controls and by permitting or failing to prevent alleged misrepresentations and omissions in our SEC filings and other public disclosures, including in relation to compliance with the FCPA in our Angolan operations and regarding the performance of certain wells offshore Angola. The lawsuit also alleges that defendants received compensation or other benefits in excess of what they were entitled and that certain officers and directors engaged in unlawful trading and misappropriation of information. The lawsuit further alleges that demand was wrongfully refused. The plaintiff asserts claims for breach of fiduciary duty and unjust enrichment and seeks damages in an unspecified amount, reform of our governance and internal controls, restitution and disgorgement of profits, and an award of attorney fees and other costs and expenses. We filed our answer and special exceptions challenging the plaintiff’s standing to bring such claims against us in January 2017. The matter remains ongoing. In May 2016, we filed suit against XL Specialty Insurance Company (“XL”) in Harris County District Court in Houston, Texas. We assert XL improperly denied coverage for insurance claims made in July 2012 and other claims subsequently submitted to them in connection with our defending against the St. Lucie lawsuit, the Ogden derivative action, and other investigations and actions. In December 2016, we amended our petition to add Axis Insurance Company (“Axis”). Axis provides coverage in excess of the XL policy’s limit of liability. We allege breach of contract, violation of the Texas Prompt Payment of Claims Act, and seek a declaratory judgment that XL and Axis are obligated to pay any additional loss suffered by us due to the circumstances, investigation, and claims described in the suit. In December 2016, we also amended our petition to add claims against Illinois National Insurance Company, an AIG subsidiary (“AIG”), which served as our insurer after XL Against AIG, we allege breach of contract, violation of the Texas Prompt Payment of Claims Act, violation of the Texas Deceptive Trade Practices-Consumer Protection Act, and seek a declaratory judgment that AIG is obligated to pay any additional loss suffered by us due to the circumstances, investigations, and actions related to the Lontra and/or Loengo wells. Discovery is ongoing in the case and trial is set for June 2017. We are vigorously defending against the current lawsuits. It is not presently possible to determine whether any such matters will have a material adverse effect on our consolidated financial position, results of operations or liquidity. At December 31, 2016, we had the following estimated contractual commitments for the years ending December 31: Payments Due By Year 2017 2018 2019 2020 2021 Thereafter Drilling rig commitments $ 85,269 $ — $ — $ — $ — $ — Social payment obligations (1) 86,473 74 — — — — Delay rental payments (2) 5,243 3,388 3,575 3,595 3,595 7,492 Operating leases 2,309 2,369 2,405 2,454 2,501 671 Total $ 179,294 $ 5,831 $ 5,980 $ 6,049 $ 6,096 $ 8,163 (1) Includes our contractual payment obligations for social projects such as the Sonangol Research and Technology Center and academic scholarships for Angolan students that we agreed to pay in consideration for the Angolan government granting us the licenses to explore for and develop hydrocarbons offshore Angola. (2) We recorded $9.2 million, $12.4 million, and $12.8 million of office and delay rental expense in 2016, 2015 and 2014, respectively.

Equity-Based Compensation

Equity-Based Compensation	12 Months Ended
	Dec. 31, 2016
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Equity-Based Compensation	NOTE 10. EQUITY–BASED COMPENSATION We have various long–term incentive plans for employees. These plans allow for the issuance of restricted stock awards (“RSAs”), non–qualified stock options (“NQSOs”), performance stock units (“PSUs”), stock appreciation rights (SARs”) and restricted stock units (“RSUs”). As of December 31, 2016, we have 25.7 million shares authorized for issuance under these plans, and 7.7 million shares remain available for grant. We also have various long–term incentive plans for our non–employee directors. These plans allow for the issuance of NQSOs, RSUs or other equity–based awards as retainers. As of December 31, 2016, we have 1.5 million shares authorized for issuance under these plans, and 0.6 shares remain available for grant. Our policy is to issue new shares when RSAs are granted, when NQSOs are exercised and, should we elect to settle our PSUs, SARs and RSUs in shares of our common stock, when PSUs, SARs and RSUs are vested. Restricted Stock Awards An RSA is an award of common stock with no exercise price. In 2016 and 2015, we granted 0.6 million and 0.4 million RSAs, respectively, with both a performance and a service condition, and the fair value was measured using the Monte Carlo simulation model. The remainder of the RSAs granted in 2016 and 2015 and all of the RSAs granted in 2014 had a service condition only, and the fair value was measured using the market price of our common stock on the grant date. RSAs generally vest in three equal annual installments. The following weighted average assumptions were used to estimate the fair value of the RSAs for the year ended December 31: 2016 2015 Expected volatility 55.02 % 49.79 % Risk-free interest rate 2.03 % 1.77 % Dividend yield — % — % Expected life (years) 5.7 10.0 Volatility was estimated based on historical daily prices from January 1, 2010 to the grant date. The risk–free interest rate was based on the yield of a zero–coupon U.S. Treasury bill that is commensurate with the RSAs contractual term. The expected dividend yield was not taken into account as we have historically not paid any dividends. The expected life was based on the derived service period, which is the period between the grant date and the date the performance condition is met, as calculated by the Monte Carlo simulation model. Activity related to RSAs is as follows: Number of RSAs Weighted Average Grant Date Fair Value Per RSA Nonvested at January 1, 2016 5,780,239 $ 11.59 Granted 3,898,052 1.43 Vested (2,494,643 ) 11.33 Forfeited (1,061,890 ) 12.70 Nonvested at December 31, 2016 6,121,758 $ 5.00 Exercisable at December 31, 2016 755,657 $ 6.73 The fair value of RSAs granted in 2016, 2015 and 2014 was $6.3 million, $30.5 million and $33.1 million, respectively, and the fair value of RSAs vested in 2016, 2015 and 2014 was $4.6 million, $1.4 million and $11.5 million, respectively. The weighted average remaining contractual terms for RSAs outstanding and RSAs exercisable at December 31, 2016 were 5.4 years and 3.7 years, respectively. As of December 31, 2016, there was $15.6 million of total unrecognized compensation cost related to unvested RSAs which is expected to be recognized over a weighted-average period of 1.6 years. Non-Qualified Stock Options We grant NQSOs to employees at an exercise price equal to the market value of our common stock on the grant date. The NQSOs have contractual terms of 10 years. The NQSOs granted in 2016 and 2015 vest after one year of service, subject to our common stock maintaining a minimum stock price for a specified period of time. The NQSOs granted in 2014 vest 50% at the end of the third year from date of grant and 50% at the end of the fourth year from date of grant. As the NQSOs granted in 2016 and 2015 had both service and market conditions, we estimated the fair value of these NQSOs using the Monte Carlo simulation model. The fair values of the NQSOs granted in 2014 were determined using the Black–Scholes option pricing model. The following weighted average assumptions were used to estimate the fair value of the NQSOs for the years ended December 31: 2016 2015 2014 Expected volatility 55.02 % 54.97 % 57.27 % Risk-free interest rate 2.03 % 1.84 % 1.69 % Dividend yield — % — % — % Expected life (years) 5.7 5.5 5.5 Volatility was estimated based on historical daily prices from January 1, 2010 to the grant date. The risk–free interest rate was based on the yield of a zero–coupon U.S. Treasury bill that is commensurate with the NQSOs contractual term. The expected dividend yield was not taken into account as we have historically not paid any dividends. The expected life was based on the derived service period, which is the period between the grant date and the date the performance condition is met, as calculated by the Monte Carlo simulation model. Activity related to the NQSOs is as follows: Number of NQSOs Weighted Average Exercise Price per NQSO Outstanding at January 1, 2016 3,766,941 $ 17.23 Granted 1,129,944 3.50 Forfeited (588,744 ) 19.69 Outstanding at December 31, 2016 4,308,141 $ 13.29 Exercisable at December 31, 2016 3,110,337 $ 16.75 The fair value of NQSOs granted in 2016, 2015 and 2014 was $4.0 million, $5.9 million and $14.2 million, respectively, and the fair value of NQSOs vested in 2016, 2015 and 2014 was $14.5 million, $12.3 million and $16.1 million, respectively. The weighted average remaining contractual terms for NQSOs outstanding and NQSOs exercisable at December 31, 2016 were 6.7 years and 5.8 years, respectively. There was no intrinsic value for both NQSOs outstanding and NQSOs exercisable as the exercise prices exceeded the market price of our common stock as of December 31, 2016. As of December 31, 2016, there was $0.4 million of total unrecognized compensation cost related to unvested NQSOs which is expected to be recognized over a weighted-average period of 0.8 years. Performance Stock Units A PSU is an award where each unit represents the right to receive, subject to our common stock attaining a specified return, the value of one share of our common stock at the date of vesting. The PSUs may be settled by, at our discretion, either the issuance of our common stock, cash or a combination thereof based on the fair market value of the common stock on the date of exercise. The PSUs vest in three equal installments subject to our common stock attaining a specified return each vesting date. The PSUs granted in 2016 had both service and performance conditions, and we estimated the fair value of these PSUs using the Monte Carlo simulation model. The following weighted average assumptions were used to estimate the fair value of the PSUs for the year ended December 31: 2016 Expected volatility 64.31 % Risk-free interest rate 0.80 % Dividend yield — % Expected volatility was calculated for the peer company based on historical volatility over the most recent three years using daily stock prices. The risk–free interest rate was based on the yield of a zero–coupon U.S. Treasury bill that is commensurate with the end date of the longest remaining period of three years. The expected dividend yield was not taken into account as we have historically not paid any dividends. Activity related to the PSUs is as follows: Number of PSUs Weighted Average Grant Date Fair Value Per PSU Nonvested at January 1, 2016 — $ — Granted 283,750 0.75 Nonvested at December 31, 2016 283,750 $ 0.75 Exercisable at December 31, 2016 — $ — The weighted average remaining contractual term for PSUs outstanding at December 31, 2016 was 9.6 years. As of December 31, 2016, there was $0.2 million of total unrecognized compensation cost related to unvested PSUs which is expected to be recognized over a weighted-average period of 2.6 years. Restricted Stock Units An RSU is an award where each unit represents the right to receive the value of one share of our common stock at the date of vesting. RSUs may be settled by, at our discretion, either the issuance of our common stock, cash or a combination thereof based on the fair market value of the common stock on the date of exercise. The RSUs granted in 2016 vest in three equal annual installments. Activity related to the RSUs is as follows: Number of RSUs Weighted Average Grant Date Fair Value Per RSU Nonvested at January 1, 2016 — $ — Granted 3,491,352 2.44 Vested (596,823 ) 2.44 Forfeited (457,097 ) 2.44 Nonvested at December 31, 2016 2,437,432 $ 2.44 Exercisable at December 31, 2016 358,606 $ 2.44 The fair value of RSUs vested in 2016 and 2014 was $0.8 million and $0.7 million, respectively. No RSUs vested in 2015. The weighted average remaining contractual terms for both RSUs outstanding and RSUs exercisable at December 31, 2016 was 9.1 years. As of December 31, 2016, there was $4.1 million of total unrecognized compensation cost related to unvested RSUs which is expected to be recognized over a weighted–average period of 2.2 years. Stock Appreciation Rights An SAR represents a contractual right to receive an amount equal to the appreciation in the price of one share of our common stock from the grant date over the exercise price of the SAR. SARs may be settled by, at our discretion, either the issuance of our common stock, cash or a combination thereof based on the fair market value of the common stock on the date of exercise. We grant SARs to employees at an exercise price equal to the market value of our common stock on the grant date. The SARs have contractual terms of 10 years and vest in three equal annual installments. We account for the SARs as liability awards, and the fair value of the SARs is remeasured at the end of each reporting period based on the current fair value of the SARs. We estimate the fair value of the SARs using the Black–Scholes option price model. The following weighted average assumptions were used to estimate the fair value of the SARs for the year ended December 31: 2015 Expected volatility 54.97 % Risk-free interest rate 1.84 % Dividend yield — % Expected life (years) 5.5 Activity related to the SARs is as follows: Number of SARs Weighted Average Exercise Price Per SAR Outstanding at January 1, 2016 1,452,332 $ 8.87 Forfeited (595,566 ) 8.87 Outstanding at December 31, 2016 856,766 $ 8.87 Exercisable at December 31, 2016 698,424 $ 8.87 The weighted average grant date fair value of SARs granted in 2015 was $4.2 million. No SARs were granted in 2016 or 2014. As of December 31, 2016, the weighted average remaining contractual term for both SARs outstanding and SARs exercisable was 8.1 years and there was no intrinsic value for both the SARS outstanding and the SARS exercisable as the exercise price exceeds the market price of our common stock as of December 31, 2016. As of December 31, 2016, there was $10 thousand of total unrecognized compensation cost related to unvested SARs which is expected to be recognized over a weighted–average period of 1.1 years. Non–Employee Director Grants We granted a total of 0.3 million, 0.05 million and 0.03 million shares of our common stock to our non–employee directors as retainer awards in 2016, 2015 and 2014, respectively. The directors have elected to defer the issuance of this stock. Accordingly, we have recorded a liability for the future issuance of these shares. The weighted average fair value of the common stock granted in 2016, 2015 and 2014 was $1.89, $9.49 and $17.52 , respectively. In addition, we granted 0.4 million RSUs to our non–employee directors. These RSUs will be settled by, at our discretion, either the issuance of our common stock, cash or a combination thereof. The fair value of these RSUs on the date of grant was $0.8 million. Compensation Cost Equity–based compensation cost is measured at the date of grant based on the calculated fair value of the award and is generally recognized on a straight–line basis over the requisite service period, including those with graded vesting. The compensation cost is determined based on awards ultimately expected to vest, and we have reduced the cost for estimated forfeitures based on historical forfeiture rtes. Forfeitures are estimated at the time of grant and revised, if necessary, in subsequent periods to reflect actual forfeitures. The following table presents the compensation costs recognized for the years ended December 31: 2016 2015 2014 Equity awards $ 16,243 $ 26,297 $ 31,742 Liability awards (1,354 ) 1,451 — Total $ 14,889 $ 27,748 $ 31,742

Employee Benefit Plan

Employee Benefit Plan	12 Months Ended
	Dec. 31, 2016
Compensation And Retirement Disclosure [Abstract]
Employee Benefit Plan	NOTE 11. EMPLOYEE BENEFIT PLAN We have a defined contribution 401(k) plan (the “Plan”). All of our employees are eligible to participate in the Plan after three months of continuous employment. The plan is discretionary and provides a 6% employee contribution match as determined by our Board of Directors. For 2016, 2015 and 2014, we recorded $1.5 million, $1.7 million, and $1.0 million, respectively, in benefits contributions to the Plan, which are included in general and administrative expenses in our consolidated statements of operations.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Income Taxes	NOTE 12. INCOME TAXES The provision for income taxes is comprised of the following for the years ended December 31: 2016 2015 2014 Current taxes: U.S. $ — $ — $ — Foreign — — — Deferred taxes: U.S — — — Foreign — — — Total $ — $ — $ — As we establish full valuation allowances against net deferred tax assets where we have determined that it is more likely than not that all of the deferred tax assets will not be realized, we have recognized no income taxes in our consolidated statements of operations for the years ended December 31, 2016, 2015 and 2014. The geographic sources of our loss are as follows for the years ended December 31: 2016 2015 2014 U.S. $ (2,313,482 ) $ (490,190 ) $ (307,025 ) Foreign (29,827 ) (204,236 ) (203,738 ) Net loss $ (2,343,309 ) $ (694,426 ) $ (510,763 ) The effective tax rate on our loss differs from the U.S. statutory rate as follows for the years ended December 31: 2016 2015 2014 Income tax expense (benefit) at the federal statutory rate 35.0 % 35.0 % 35.0 % State income taxes, net of federal income tax benefit 0.1 % 0.1 % 0.2 % Foreign income tax 41.5 % 13.5 % 21.8 % Other (4.0 )% (0.5 )% (1.8 )% Valuation allowance (72.6 )% (48.1 )% (55.2 )% — % — % — % Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The tax effects of our temporary differences and net operating losses (“NOL”) are as follows at December 31: 2016 2015 Long-term deferred tax asset: Seismic and exploration costs $ 2,227,489 $ 733,183 Stock based compensation 27,342 26,995 Domestic NOL carry forwards 695,434 568,050 Foreign NOL carry forwards 43,969 42,625 Other 11,522 (88,837 ) Valuation allowance (2,597,708 ) (896,355 ) Total long-term deferred tax asset 408,048 385,661 Long-term deferred tax liability: 2019 Notes (61,944 ) (85,339 ) 2024 Notes (107,629 ) (148,279 ) Oil and natural gas properties (238,475 ) (152,043 ) Total long-term deferred tax liability (408,048 ) (385,661 ) Net long-term deferred tax asset $ — $ — As of December 31, 2016, we had NOL carryforwards for federal and state income tax purposes of approximately $2.0 billion and $82.8 million, respectively, which begin to expire in 2026 and 2025, respectively. As of December 31, 2016, we had an NOL carryforward for foreign income tax purposes of approximately $85.6 million which began to expire in 2016. The utilization of the NOL carryforwards is dependent upon generating sufficient future taxable income in the appropriate jurisdictions within the carryforward period. Our tax filings are subject to examination by federal and state tax authorities where we conduct our business. These examinations may result in assessments of additional tax that are resolved with the authorities or through the courts. We have evaluated whether any material tax position we have taken will more likely than not be sustained upon examination by the appropriate taxing authority. As we believe that all such material tax positions we have taken are supportable by existing laws and related interpretations, we believe there are no material uncertain tax positions to consider. There were no unrecognized tax benefits or accrued interest or penalties associated with unrecognized tax benefits as of December 31, 2016 and 2015.

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2016
Earnings Per Share [Abstract]
Earnings Per Share	NOTE 13. EARNINGS PER SHARE A reconciliation of the number of shares used for the basic and diluted loss per share computations is as follows for the years ended December 31: 2016 2015 2014 Weighted average common shares outstanding (basic and diluted) 412,080 408,535 407,116 Anti-dilutive shares excluded from diluted loss per share (1) 101,740 104,693 80,498 (1) Excludes RSAs, RSUs, NQSOs, PSUs, SARs and the shares underlying the 2.625% convertible senior notes due 2019 and the 3.125% convertible senior notes due 2024 as their effect, if included, would have been anti–dilutive.

Other Supplement Information

Other Supplement Information	12 Months Ended
	Dec. 31, 2016
Supplemental Financial Information [Abstract]
Other Supplemental Information	NOTE 14. OTHER SUPPLEMENTAL INFORMATION Cash, cash equivalents and restricted cash are recorded in our consolidated balance sheets as follows as of December 31: 2016 2015 Cash and cash equivalents $ 613,534 $ 80,171 Restricted cash 2,517 58,715 $ 616,051 $ 138,886 Supplemental cash flows and noncash transactions were as follows as of and for the years ended December 31: 2016 2015 2014 Supplemental cash flows information: Cash paid for interest $ 78,320 $ 78,410 $ 56,764 Cash paid for income taxes — — — Noncash transactions - changes in accrued capital expenditures (69,667 ) (47,580 ) (56,129 ) Accrued liabilities consisted of the following as of December 31: 2016 2015 Accrued AFE costs $ 73,808 $ 202,439 Social obligation payments 86,473 115,110 Funds from release of letter of credit on Block 9 18,375 — Interest 13,793 7,843 Angolan consumption tax and withholding on services 9,796 13,421 Bonuses 8,900 12,300 General expenses 5,849 5,467 Seismic and other operating costs 5,625 9,782 Other 4,799 3,330 Total accrued liabilities $ 227,418 $ 369,692

Other Matters

Other Matters	12 Months Ended
	Dec. 31, 2016
Other Matters Disclosure [Abstract]
Other Matters	NOTE 15. OTHER MATTERS In February 2016, we initiated a workforce reduction program in response to the pending sale of our Angola properties and prolonged commodity price weakness, which resulted in a reduction of our capital programs and other operations. In 2016, we recorded a charge for severance expense of $9.9 million. As of December 31, 2016, we had accrued severance of $0.9 million, which we expect will be paid in 2017. In September 2016, we announced that we entered into an amendment to our drilling contract with Rowan (UK) Reliance Limited and recorded a charge of $95.9 million, of which $76.3 million was paid in 2016. This amendment provided for the early termination of our long–term drilling contract for one of their drillships. The drilling contract was originally scheduled to terminate in February 2018, but the amendment provides for a contract termination date in March 2017. This charge is recorded in “Loss on amendment of contract” in our consolidated statements of operations. As of December 31, 2016, we had accrued costs of $19.6 million, which will be paid in March 2017.

Quarterly Data (Unaudited)

Quarterly Data (Unaudited)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Quarterly Data (Unaudited)	NOTE 16. QUARTERLY DATA (UNAUDITED) First Quarter Second Quarter Third Quarter Fourth Quarter 2016 Revenues $ 1,636 $ 3,173 $ 4,228 $ 7,768 Gross profit (1) 680 1,470 1,856 5,225 Net loss (2) (46,615 ) (205,549 ) (2) (218,205 ) (3) (1,872,940 ) (4) Basic and diluted loss per share $ (0.11 ) $ (0.50 ) $ (0.53 ) $ (4.47 ) 2015 Revenues $ — $ — $ — $ — Gross profit — — — — Net loss (81,617 ) (66,810 ) (59,164 ) (486,835 ) (5) Basic and diluted loss per share $ (0.20 ) $ (0.16 ) $ (0.14 ) $ (1.19 ) (1) Represents oil, natural gas and natural gas liquids revenues less lease operating expenses. (2) Includes dry hole costs and impairments of $155.8 million, of which $149.9 million relates to the Goodfellow exploratory well and underlying leases. (3) Includes a $95.9 million charge related to the amendment of a drilling contract in the U.S. Gulf of Mexico. (4) Includes dry hole costs and impairment of $1,761.4 million, of which $1,691.8 million relates to our Angolan assets. (5) Includes dry hole costs and impairments of $422.4 million, of which $256.8 million relates to our proved oil and natural gas properties and $151.4 million relates to the Lontra exploratory well.

Supplementary Information on Oi

Supplementary Information on Oil and Natural Gas Activities (Unaudited)	12 Months Ended
	Dec. 31, 2016
Extractive Industries [Abstract]
Supplementary Information on Oil and Natural Gas Activities (Unaudited)	NOTE 17. SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS ACTIVITIES (UNAUDITED) Oil and Natural Gas Properties Capitalized costs relating to oil and natural gas producing activities are as follows at December 31: 2016 2015 Proved oil and natural gas properties $ 118,245 $ 71,463 Unproved oil and natural gas properties, net 980,844 2,287,570 1,099,089 2,359,033 Accumulated depreciation, depletion and amortization (20,204 ) — Net capitalized costs $ 1,078,885 $ 2,359,033 Costs incurred in oil and natural gas property development activities are as follows for the years ended December 31: 2016 2015 2014 Acquisition of unproved oil and natural gas properties $ 3,715 $ 35,993 $ 27,784 Exploration costs: Capitalized 599,526 718,078 574,100 Expensed 58,170 61,844 85,567 Development costs 39,111 145,021 90,642 Total $ 700,522 $ 960,936 $ 778,093 Estimated Proved Oil, Natural Gas and Natural Gas Liquids Reserves Our estimated proved reserves are all located within the U.S. Gulf of Mexico. We caution that there are many uncertainties inherent in estimating proved reserve quantities and in projecting future production rates and the timing of development expenditures. Accordingly, these estimates are expected to change as further information becomes available. Material revisions of reserve estimates may occur in the future, development and production of the oil, natural gas and natural gas liquids reserves may not occur in the periods assumed, and actual prices realized and actual costs incurred may vary significantly from those used in these estimates. The estimates of our proved reserves as of December 31, 2016, 2015 and 2014 have been prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), independent petroleum consultants. The following table sets forth changes in estimated proved and estimated proved developed reserves for the periods indicated. Oil (MMBbls) Natural Gas (Bcf) Natural Gas Liquids (MMBbls) MMBOE Proved developed and undeveloped reserves: As of December 31, 2013 7.9 3.4 — 8.5 Extensions and discoveries 0.5 0.3 — 0.5 As of December 31, 2014 8.4 3.7 — 9.0 Revisions of previous estimates (2.8 ) (1.9 ) 0.3 (2.8 ) As of December 31, 2015 5.6 1.8 0.3 6.2 Revisions of previous estimates (2.2 ) (0.5 ) (0.2 ) (2.5 ) Production (0.4 ) (0.1 ) — (0.4 ) As of December 31, 2016 3.0 1.2 0.1 3.3 Proved developed reserves: December 31, 2013 — — — — December 31, 2014 — — — — December 31, 2015 — — — — December 31, 2016 1.9 0.8 0.1 2.1 Proved undeveloped reserves: December 31, 2013 7.9 3.4 — 8.5 December 31, 2014 8.4 3.7 — 9.0 December 31, 2015 5.6 1.8 0.3 6.2 December 31, 2016 1.1 0.4 — 1.2 Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves The following tables present a standardized measure of discounted future net cash flows and changes therein relating to estimated proved oil, natural gas and natural gas liquids reserves. In computing this data, assumptions other than those required by the Securities and Exchange Commission (“SEC”) could produce different results. Accordingly, the data should not be construed as representative of the fair market value of our estimated proved oil, natural gas and natural gas liquids reserves. The following assumptions have been made: • Future cash inflows were based on prices used in estimating our proved oil, natural gas and natural gas liquids reserves. Future price changes were included only to the extent provided by existing contractual agreements. • Future development and production costs were computed using year end costs assuming no change in present economic conditions. • No provisions for future federal income taxes were computed as the tax basis of our oil and natural gas properties in the United States and net operating losses attributable to oil and natural gas operations exceed the future net revenues. • Future net cash flows were discounted at an annual rate of 10%. The standardized measure of discounted future net cash flows relating to estimated proved oil, natural gas and natural gas liquids reserves is as follows at December 31: 2016 2015 2014 Future cash inflows $ 123,889 $ 288,705 $ 814,394 Future production and development costs (86,103 ) (186,053 ) (257,016 ) Future net cash flows 37,786 102,652 557,378 10% annual premium (discount) for estimated timing of cash flows 1,164 (45,077 ) (192,094 ) Standardized measure of discounted future net cash flows $ 38,950 $ 57,575 $ 365,284 As specified by the SEC, the prices for oil, natural gas and natural gas liquids used in this calculation were the average prices during the year determined using the price of the first day of each month, except for volumes subject to fixed price contracts. The prices utilized in calculating our total estimated proved reserves at December 31, 2016, 2015 and 2014 were $40.32, $50.78 and $95.24 per barrel of oil, $19.23, $15.23 and $0.00 per barrel of natural gas liquids, and $2.056, $(0.182) and $4.770 per Mcf of natural gas, respectively. The principal sources of changes in the standardized measure of future net cash flows are as follows for the years ended December 31: 2016 2015 2014 Standardized measure at beginning of year $ 57,575 $ 365,284 $ 276,633 Sales and transfers of oil, natural gas and natural gas liquids produced, net of production costs (9,231 ) — — Net changes in prices and production costs (31,738 ) (314,367 ) (36,869 ) Development costs incurred during the period 45,611 — — Revisions and other (23,579 ) (122,584 ) 17,351 Accretion of discount 5,757 36,528 27,663 Changes in estimated future development costs (822 ) 99,964 49,700 Changes in timing and other (4,623 ) (7,250 ) 30,806 Standardized measure, ending $ 38,950 $ 57,575 $ 365,284

Subsequent Events (Unaudited)

Subsequent Events (Unaudited)	12 Months Ended
	Dec. 31, 2016
Subsequent Events [Abstract]
Subsequent Events (Unaudited)	NOTE 18. SUBSEQUENT EVENTS (UNAUDITED) In January 2017, we consummated a follow–on debt exchange transaction with certain of the Holders whereby we issued an aggregate principal amount of $139.2 million in additional second lien notes due 2023 in exchange for $137.8 million aggregate principal amount of the 2019 Notes and $60.0 million aggregate principal amount of the 2024 Notes held by the Holders. In February 2017, we received a letter from the Department of Justice (“DOJ”) advising us that the DOJ has closed its investigation into our operations in Angola. This formally concluded the DOJ investigation, which was the last investigation by any U.S. regulatory agency into our Angolan operations. No regulatory action has been taken against us as a result of these investigations. In March 2017, the SEC informed us by telephone that it had initiated an informal inquiry regarding the Company related to the Sonangol Research and Technology Center (the “Technology Center”). As background, in December 2011, we executed the Block 20 Production Sharing Contract under which we and BP Exploration Angola (Kwanza Benguela) Limited are required to make certain social contributions to Sonangol, including for the Technology Center. In March 2017, we also received a voluntary request for information regarding such inquiry. We believe our activities in Angola have complied with all applicable laws, including the Foreign Corrupt Practices Act, and we will cooperate with the SEC’s inquiry. We evaluated subsequent events for appropriate accounting and disclosure through the date these consolidated financial statements were issued and determined that there were no other material items that required recognition or disclosure in our consolidated financial statements.

Summary of Significant Accoun26

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation The consolidated financial statements include the accounts of the Company and its majority–owned subsidiaries (“we,” “our” or “us”). All significant intercompany accounts and transactions have been eliminated in consolidation. In the Notes to Consolidated Financial Statements, all dollar and share amounts in tabulations are in thousands of dollars and shares, respectively, unless otherwise indicated.
Use of Estimates	Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and judgments that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. We base our estimates and judgments on historical experience and on various other assumptions and information that are believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. While we believe that the estimates and assumptions used in the preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates.
Cash and Cash Equivalents	Cash and Cash Equivalents We consider all highly liquid investments with an original maturity of three months or less at the time of purchase to be cash equivalents. All of our cash and cash equivalents are maintained with several major financial institutions in the United States. Deposits with these financial institutions may exceed the amount of insurance provided on such deposits; however, we regularly monitor the financial stability of these financial institutions and believe that we are not exposed to any significant default risk.
Restricted Cash	Restricted Cash Restricted cash serves as collateral for certain of our obligations. These restricted funds are invested in interest–bearing accounts.
Joint Interest and Other Receivables	Joint Interest and Other Receivables Joint interest receivables result from billing shared costs under the respective operating agreements to our partners. Accounts receivable from oil, natural gas and natural gas liquids sales are recorded at the invoiced amount and do not bear interest. We routinely assess the financial strength of our customers and partners and bad debts are recorded based on an account–by–account review after all means of collection have been exhausted, and the potential recovery is considered remote. As of December 31, 2016, we have a $159.1 million receivable from Sonangol Pesquisa e Produção, S.A. (“Sonangol P&P”) related to its share of costs incurred under the Block 21 Risk Services Agreement. Although this amount has been outstanding for over one year, Sonangol P&P has acknowledged that this amount is owed to us. We continue to work with them on resolution of this issue and have determined that we did not need to set up a reserve for doubtful accounts as of December 31, 2016. As of December 31, 2016 and 2015, we did not have any reserves for doubtful accounts. We also did not have any off–balance sheet credit exposure related to our customers.
Investments	Investments We have investments in marketable debt securities that are classified as held–to–maturity as we have the positive intent and ability to hold the investments until they mature. We classify investments with original maturities of greater than three months and remaining maturities of less than one year as short–term investments, and investments with maturities beyond one year as long–term investments. Our debt securities are carried at amortized cost and the carrying value of these securities is adjusted for amortization of premiums and accretion of discounts to maturity over the life of the securities. As the estimated fair value of each investment approximates its amortized cost, there were no significant unrecognized holding gains or losses as of December 31, 2016 and 2015. Income related to these securities is reported as a component of interest income in our consolidated statements of operations. Investments are considered to be impaired when a decline in fair value is determined to be other–than–temporary. We conduct a regular assessment of our debt securities with unrealized losses to determine whether these securities have other–than-temporary impairment (“OTTI”). This assessment considers, among other factors, the nature of the securities, credit rating or financial condition of the issuer, the extent and duration of the unrealized loss, market conditions and whether we intend to sell or whether it is more likely than not that we will be required to sell the debt securities. As of December 31, 2016 and 2015, we have no OTTI in our debt securities.
Property and Depreciation, Depletion and Amortization	Property and Depreciation, Depletion and Amortization Our oil, natural gas and natural gas liquids producing activities are accounted for under the successful efforts method of accounting. Under this method, costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs and costs of carrying and retaining unproved properties are charged to expense as incurred. For 2016, 2015 and 2014, we recorded dry hole costs of $213.5 million, $188.0 million and $165.5 million, respectively, to expense costs associated with the drilling of exploratory wells that did not find proved reserves. Costs for unproved leasehold properties and exploratory wells that find reserves that cannot yet be classified as proved are capitalized if the well has found a sufficient quantity of reserves to justify its completion as a producing well and we are making sufficient progress assessing the reserves and the economic and operating viability of the project. Often, the ability to move into the development phase and record proved reserves is dependent on obtaining permits and government or partner approvals, the timing of which is ultimately beyond our control. Exploratory well costs remain suspended as long as we are actively pursuing such approvals and permits, and believe they will be obtained. For complex exploratory projects, it is not unusual to have exploratory wells remain suspended on the balance sheet for several years while additional appraisal drilling and seismic work is performed on the field or while we seek government or partner approval of development plans. Our assessment of suspended exploratory well costs is continuous until a determination is made to either sanction the project or to expense the well costs as dry hole costs as sufficient progress has not been made in assessing the reserves and the economic and operating viability of the project. In 2016, we recorded dry hole costs of $1,276.4 million to expense costs associated with our Angolan exploratory wells (see Note 3). The capitalized costs of our producing oil and natural gas properties are depreciated and depleted by the units–of–production method based on the ratio of current production to estimated total net proved reserves as estimated by independent petroleum engineers. Proved developed reserves are used in computing unit rates for drilling and development costs and total proved reserves are used for depletion rates of leasehold costs. Other property is stated at cost less accumulated depreciation, which is computed using the straight–line method based on estimated economic lives ranging from three to ten years. We expense costs for maintenance and repairs in the period incurred. Significant improvements and betterments are capitalized if they extend the useful life of the asset.
Impairment of Oil and Natural Gas Properties	Impairment of Oil and Natural Gas Properties We evaluate our proved oil and natural gas properties and related equipment and facilities for impairment whenever events or changes in circumstances indicate that the carrying amounts of such properties may not be recoverable. The determination of recoverability is made based upon estimated undiscounted future net cash flows. The amount of impairment loss, if any, is determined by comparing the fair value, as determined by a discounted cash flow analysis, with the carrying value of the related asset. For 2015, we recorded impairment charges of $256.8 million related to our proved oil and natural gas properties as the carrying amounts of such properties were determined not to be recoverable (see Note 5). Oil and natural gas leases for unproved properties with a carrying value greater than $1.0 million are assessed individually for impairment based on our current exploration plans and an allowance for impairment is provided if impairment is indicated. Leases that are individually less than $1.0 million in carrying value or are near expiration are amortized over the terms of the leases at rates that provide for full amortization of leases upon lease expiration. These leases have expiration dates ranging from 2017 through 2026. For 2016, 2015 and 2014, we recorded impairment charges of $66.6 million, $26.9 million and $70.5 million, respectively, related to our leases for unproved oil and natural gas properties. In 2016, we also recorded an impairment charge of $353.4 million related to our Angolan leases in conjunction with the write-off of our Angolan exploratory well costs (see Note 3).
Asset Retirement Obligations	Asset Retirement Obligations An asset retirement obligation (“ARO”) represents the future abandonment costs of tangible assets, such as wells, service assets, and other facilities. We record an ARO and capitalize the asset retirement cost in oil and natural gas properties in the period in which the retirement obligation is incurred based upon the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells. After recording these amounts, the ARO is accreted to its future estimated value using an assumed cost of funds and the additional capitalized costs are depreciated on a unit–of–production basis. If the ARO is settled for an amount other than the recorded amount, a gain or loss is recognized.
Embedded Derivatives	Embedded Derivatives Our first lien senior secured notes due (the “First Lien Notes”) and our second lien senior secured notes due 2023 (the “Second Lien Notes”) include features which were determined to be embedded derivatives requiring bifurcation and accounting as separate financial instruments. The embedded derivatives were initially recorded at fair value and are subject to remeasurement as of each balance sheet date. We have elected not to designate our embedded derivatives as hedging instruments. Changes in the fair value of these embedded derivatives are recorded immediately to earnings in “Other (expense) income” in our consolidated statements of operations.
Revenue Recognition	Revenue Recognition Oil, natural gas and natural gas liquids revenues are recognized when production is sold to a purchaser at fixed or determinable prices, when delivery has occurred and title has transferred and collectability of the revenue is reasonably assured. We follow the sales method of accounting for natural gas revenues. Under this method of accounting, revenues are recognized based on volumes sold, which may differ from the volume to which we are entitled based on our working interest. An imbalance is recognized as a liability only when the estimated remaining reserves will not be sufficient to enable the under–produced owner(s) to recoup its entitled share through future production. Under the sales method, no receivables are recorded where we have taken less than our share of production. There were no significant natural gas imbalances at December 31, 2016.
Income Taxes	Income Taxes We use the liability method to determine our income tax provisions, under which current and deferred tax liabilities and assets are recorded in accordance with enacted tax laws and rates. Under this method, the amounts of deferred tax liabilities and assets at the end of each period are determined using the tax rate expected to be in effect when taxes are actually paid or recovered. Valuation allowances are established to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized.
Concentration of Credit Risk	Concentration of Credit Risk Our oil, natural gas and natural gas liquids revenues are derived principally from uncollateralized sales to customers in the oil and natural gas industry; therefore, our customers may be similarly affected by changes in economic and other conditions within the industry. We have experienced no credit losses on such sales in the past. In 2016, one customer accounted for 96.5% of our consolidated oil, natural gas and natural gas liquids revenues. We believe that the loss of this customer would have a temporary effect on our revenues but, that over time, we would be able to replace this customer.
Recently Issued Accounting Standards	Recently Issued Accounting Standards In May 2014, the Financial Accounting Standards Board (“FASB”) issued ASU No. 2014–09, Revenue from Contracts with Customers. In August 2014, the FASB issued ASU No. 2014–15, Presentation of Financial Statements – Going Concern In April 2015, the FASB issued ASU No. 2015–03, Interest—Imputation of Interest In July 2015, the FASB issued ASU No. 2015–11, Accounting for Inventory In February 2016, the FASB issued ASU No. 2016-02, Leases In March 2016, the FASB issued ASU No. 2016-09, Compensation – Stock Compensation (Subtopic 718) In June 2016, the FASB issued ASU 2016–13, Financial Instruments – Credit Losses In November 2016, the FASB issued ASU 2016–18, Statement of Cash Flows on December 31, 2016, which required that we apply the guidance on a retrospective basis, wherein our consolidated statements of cash flows for all periods presented were adjusted to reflect the effects of applying the guidance. The following table shows the effects of applying the guidance: Prior to Adoption (1) As Adjusted Year ended December 31, 2015: (Accretion of discount) amortization of premium on investments $ 14,207 $ 14,483 Accrued liabilities 22,453 272,065 Net cash flows used in operating activities (251,942 ) (1,646 ) Change in restricted funds (3,856 ) — Proceeds from maturity of investment securities 1,894,562 1,999,421 Purchase of investment securities (892,577 ) (1,192,873 ) Net cash flows provided by (used in) investing activities 77,460 (114,121 ) Increase (decrease) in cash, cash equivalents and restricted cash (178,550 ) (119,835 ) Cash, cash equivalents and restricted cash, end of year 80,171 138,886 Year ended December 31, 2014: (Accretion of discount) amortization of premium on investments 18,159 20,925 Net cash flows used in operating activities (64,526 ) (61,760 ) Change in restricted funds 43,667 — Proceeds from maturity of investment securities 1,700,123 2,350,705 Purchase of investment securities (2,129,453 ) (2,739,134 ) Net cash flows provided by (used in) investing activities (1,138,393 ) (1,141,159 ) (1) Amounts are after reclassification of Angolan operations to no longer reflect these operations as discontinued. No other new accounting pronouncements issued or effective during 2016 have had or are expected to have a material impact on our consolidated financial statements.

Summary of Significant Accoun27

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Summary of Effect of Applying Guidance on Consolidated Statements of Cash Flows	The following table shows the effects of applying the guidance: Prior to Adoption (1) As Adjusted Year ended December 31, 2015: (Accretion of discount) amortization of premium on investments $ 14,207 $ 14,483 Accrued liabilities 22,453 272,065 Net cash flows used in operating activities (251,942 ) (1,646 ) Change in restricted funds (3,856 ) — Proceeds from maturity of investment securities 1,894,562 1,999,421 Purchase of investment securities (892,577 ) (1,192,873 ) Net cash flows provided by (used in) investing activities 77,460 (114,121 ) Increase (decrease) in cash, cash equivalents and restricted cash (178,550 ) (119,835 ) Cash, cash equivalents and restricted cash, end of year 80,171 138,886 Year ended December 31, 2014: (Accretion of discount) amortization of premium on investments 18,159 20,925 Net cash flows used in operating activities (64,526 ) (61,760 ) Change in restricted funds 43,667 — Proceeds from maturity of investment securities 1,700,123 2,350,705 Purchase of investment securities (2,129,453 ) (2,739,134 ) Net cash flows provided by (used in) investing activities (1,138,393 ) (1,141,159 ) (1) Amounts are after reclassification of Angolan operations to no longer reflect these operations as discontinued.

Investments (Tables)

Investments (Tables)	12 Months Ended
	Dec. 31, 2016
Investments Debt And Equity Securities [Abstract]
Schedule of Fair Value of Held-to-maturity Securities Recorded at Amortized Cost	Our investments in held–to–maturity securities consist of the following as of December 31: 2016 2015 Corporate securities $ 227,854 $ 492,955 Commercial paper 292,466 604,986 U.S. Treasury securities 161,778 105,064 Certificates of deposit — 20,750 Total $ 682,098 $ 1,223,755
Schedule of Investments Recorded in Consolidated Balance Sheets	These investments are recorded in our consolidated balance sheets as follows as of December 31: 2016 2015 Cash and cash equivalents $ 341,680 $ 38,420 Short-term investments (1) 340,418 1,185,335 $ 682,098 $ 1,223,755 (1) As of December 31, 2016 and 2015, $9.1 million and $299.3 million, respectively, of these investments serve as collateral for certain of our obligations.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2016
Fair Value Hierarchy for Liabilities Required to be Measured at Fair Value on a Recurring basis	The following table represents the fair value hierarchy for our liabilities required to be measured at fair value on a recurring basis: Fair Value Measurements at the End of the Reporting Period: Fair Value Level 1 Level 2 Level 3 As of December 31, 2016: Embedded derivative liabilities: First Lien Notes $ 27,012 $ — $ — $ 27,012 Second Lien Notes 23,111 — — 23,111 Total $ 50,123 $ — $ — $ 50,123
Reconciliation of Changes in the Fair Value of Embedded Derivatives	The reconciliation of changes in the fair value of our embedded derivatives is as follows for the year ended December 31: 2016 Beginning of period $ — Issuance of First Lien Notes and Second Lien Notes 47,618 Change in fair value 2,505 End of period $ 50,123
Summary of Estimated Fair Value of Long-term Debt	2016 2015 10.75% first lien notes due 2021 Principal outstanding $ 500,000 $ — Unamortized discount (1) (34,416 ) — Carrying amount 465,584 — 7.75% second lien notes due 2023 Principal outstanding 584,732 — Unamortized discount (2) (54,856 ) — Carrying amount 529,876 — 2.625% convertible senior notes due 2019: Principal outstanding 763,446 1,380,000 Unamortized discount (3) (109,689 ) (258,565 ) Carrying amount 653,757 1,121,435 3.125% convertible senior notes due 2024: Principal outstanding 1,204,145 1,300,000 Unamortized discount (4) (374,013 ) (439,540 ) Carrying amount 830,132 860,460 Total $ 2,479,349 $ 1,981,895 (1) (2) (3) (4)
Estimated fair value of long-term debt
Summary of Estimated Fair Value of Long-term Debt	The estimated fair value of our long–term debt is as follows as of December 31: 2016 2015 10.75% first lien notes due 2021 $ 482,250 $ — 7.75% second lien notes due 2023 327,449 — 2.625% convertible senior notes due 2019 305,378 791,209 3.125% convertible senior notes due 2024 332,344 577,291 $ 1,447,421 $ 1,368,500

Oil and Natural Gas Properties

Oil and Natural Gas Properties (Tables)	12 Months Ended
	Dec. 31, 2016
Property Plant And Equipment [Abstract]
Schedule of Oil and Natural Gas Properties	Oil and natural gas properties consisted of the following as of December 31: 2016 2015 Proved oil and natural gas properties: Well and development costs $ 118,245 $ 71,463 Accumulated depletion (20,204 ) — Total proved properties 98,041 71,463 Unproved oil and natural gas properties: Oil and natural gas leaseholds 651,295 738,852 Accumulated valuation allowance (507,198 ) (178,463 ) 144,097 560,389 Exploratory wells in process 836,747 1,727,181 Total unproved properties 980,844 2,287,570 Total oil and natural gas properties, net $ 1,078,885 $ 2,359,033
Schedule of Net Changes in Capitalized Exploratory Well Costs	The following tables reflect the net changes in and the cumulative costs of capitalized exploratory well costs (excluding any related leasehold costs): 2016 2015 2014 Beginning of period $ 1,727,181 $ 1,186,464 $ 777,823 Additions to capitalized exploration Exploratory well costs 499,985 630,395 522,892 Capitalized interest 99,541 87,683 51,208 Amounts charged to expense (1) (1,489,960 ) (177,361 ) (165,459 ) End of period $ 836,747 $ 1,727,181 $ 1,186,464 (1) Amounts represent dry hole costs related to exploratory wells which did not encounter commercial hydrocarbons or where it was determined that sufficient progress was not being made.
Schedule of Cumulative Costs of Capitalized Exploratory Well Costs	2016 2015 Cumulative costs: Exploratory well costs $ 582,115 $ 1,572,090 Capitalized interest 254,632 155,091 $ 836,747 $ 1,727,181 Wells costs capitalized for a period greater than one year after completion after drilling (included in table above) $ 609,893 $ 1,225,747

Long-term Debt, Net (Tables)

Long-term Debt, Net (Tables)	12 Months Ended
	Dec. 31, 2016
Long Term Debt [Abstract]
Summary of Estimated Fair Value of Long-term Debt	2016 2015 10.75% first lien notes due 2021 Principal outstanding $ 500,000 $ — Unamortized discount (1) (34,416 ) — Carrying amount 465,584 — 7.75% second lien notes due 2023 Principal outstanding 584,732 — Unamortized discount (2) (54,856 ) — Carrying amount 529,876 — 2.625% convertible senior notes due 2019: Principal outstanding 763,446 1,380,000 Unamortized discount (3) (109,689 ) (258,565 ) Carrying amount 653,757 1,121,435 3.125% convertible senior notes due 2024: Principal outstanding 1,204,145 1,300,000 Unamortized discount (4) (374,013 ) (439,540 ) Carrying amount 830,132 860,460 Total $ 2,479,349 $ 1,981,895 (1) (2) (3) (4)
Schedule of Maturities of Long-term Debt	The maturities of our long–term debt are as follows for the years ended December 31: Payments Due By Year 2017 2018 2019 2020 2021 Thereafter Principal outstanding $ — $ — $ 763,446 $ — $ 500,000 $ 1,788,877

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2016
Asset Retirement Obligation [Abstract]
Schedule of changes in asset retirement obligation	The changes in ARO are as follows for the years ended December 31: 2016 2015 Beginning of period $ 3,167 $ — Liabilities incurred — 3,068 Revisions 2,806 — Accretion 550 99 End of period $ 6,523 $ 3,167

Commitments and Contingencies

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2016
Commitments And Contingencies Disclosure [Abstract]
Schedule of Estimated Contractual Commitments	Payments Due By Year 2017 2018 2019 2020 2021 Thereafter Drilling rig commitments $ 85,269 $ — $ — $ — $ — $ — Social payment obligations (1) 86,473 74 — — — — Delay rental payments (2) 5,243 3,388 3,575 3,595 3,595 7,492 Operating leases 2,309 2,369 2,405 2,454 2,501 671 Total $ 179,294 $ 5,831 $ 5,980 $ 6,049 $ 6,096 $ 8,163 (1) Includes our contractual payment obligations for social projects such as the Sonangol Research and Technology Center and academic scholarships for Angolan students that we agreed to pay in consideration for the Angolan government granting us the licenses to explore for and develop hydrocarbons offshore Angola. (2)

Equity-Based Compensation (Tabl

Equity-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2016
Equity Based Compensation
Schedule of Activity Related to Stock Appreciation Rights	Activity related to the SARs is as follows: Number of SARs Weighted Average Exercise Price Per SAR Outstanding at January 1, 2016 1,452,332 $ 8.87 Forfeited (595,566 ) 8.87 Outstanding at December 31, 2016 856,766 $ 8.87 Exercisable at December 31, 2016 698,424 $ 8.87
Schedule of Recognized Equity-based Compensation Costs	The following table presents the compensation costs recognized for the years ended December 31: 2016 2015 2014 Equity awards $ 16,243 $ 26,297 $ 31,742 Liability awards (1,354 ) 1,451 — Total $ 14,889 $ 27,748 $ 31,742
Restricted stock awards
Equity Based Compensation
Schedule of Weighted Average Assumptions Used to Estimate the Fair Value of Stock Awards	The following weighted average assumptions were used to estimate the fair value of the RSAs for the year ended December 31: 2016 2015 Expected volatility 55.02 % 49.79 % Risk-free interest rate 2.03 % 1.77 % Dividend yield — % — % Expected life (years) 5.7 10.0
Schedule of Activity Related to Stock Awards/Units	Activity related to RSAs is as follows: Number of RSAs Weighted Average Grant Date Fair Value Per RSA Nonvested at January 1, 2016 5,780,239 $ 11.59 Granted 3,898,052 1.43 Vested (2,494,643 ) 11.33 Forfeited (1,061,890 ) 12.70 Nonvested at December 31, 2016 6,121,758 $ 5.00 Exercisable at December 31, 2016 755,657 $ 6.73
Non-qualified stock options
Equity Based Compensation
Schedule of Weighted Average Assumptions Used to Estimate the Fair Value of Stock Awards	The following weighted average assumptions were used to estimate the fair value of the NQSOs for the years ended December 31: 2016 2015 2014 Expected volatility 55.02 % 54.97 % 57.27 % Risk-free interest rate 2.03 % 1.84 % 1.69 % Dividend yield — % — % — % Expected life (years) 5.7 5.5 5.5
Non-qualified stock options
Equity Based Compensation
Schedule of Activity Related to Stock Awards/Units	Activity related to the NQSOs is as follows: Number of NQSOs Weighted Average Exercise Price per NQSO Outstanding at January 1, 2016 3,766,941 $ 17.23 Granted 1,129,944 3.50 Forfeited (588,744 ) 19.69 Outstanding at December 31, 2016 4,308,141 $ 13.29 Exercisable at December 31, 2016 3,110,337 $ 16.75
Performance stock units
Equity Based Compensation
Schedule of Weighted Average Assumptions Used to Estimate Fair Value of Performance Stock Units	The following weighted average assumptions were used to estimate the fair value of the PSUs for the year ended December 31: 2016 Expected volatility 64.31 % Risk-free interest rate 0.80 % Dividend yield — %
Schedule of Activity Related to Performance Stock Units	Activity related to the PSUs is as follows: Number of PSUs Weighted Average Grant Date Fair Value Per PSU Nonvested at January 1, 2016 — $ — Granted 283,750 0.75 Nonvested at December 31, 2016 283,750 $ 0.75 Exercisable at December 31, 2016 — $ —
Restricted stock units
Equity Based Compensation
Schedule of Activity Related to Stock Awards/Units	Activity related to the RSUs is as follows: Number of RSUs Weighted Average Grant Date Fair Value Per RSU Nonvested at January 1, 2016 — $ — Granted 3,491,352 2.44 Vested (596,823 ) 2.44 Forfeited (457,097 ) 2.44 Nonvested at December 31, 2016 2,437,432 $ 2.44 Exercisable at December 31, 2016 358,606 $ 2.44
Stock appreciation rights (SARs)
Equity Based Compensation
Schedule of Weighted Average Assumptions Used to Estimate Fair Value of Stock Appreciation Rights	The following weighted average assumptions were used to estimate the fair value of the SARs for the year ended December 31: 2015 Expected volatility 54.97 % Risk-free interest rate 1.84 % Dividend yield — % Expected life (years) 5.5

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Schedule of Provision for Income Taxes	The provision for income taxes is comprised of the following for the years ended December 31: 2016 2015 2014 Current taxes: U.S. $ — $ — $ — Foreign — — — Deferred taxes: U.S — — — Foreign — — — Total $ — $ — $ —
Schedule of Geographic Sources of Loss	The geographic sources of our loss are as follows for the years ended December 31: 2016 2015 2014 U.S. $ (2,313,482 ) $ (490,190 ) $ (307,025 ) Foreign (29,827 ) (204,236 ) (203,738 ) Net loss $ (2,343,309 ) $ (694,426 ) $ (510,763 )
Schedule of Effective Tax Rate on Loss	The effective tax rate on our loss differs from the U.S. statutory rate as follows for the years ended December 31: 2016 2015 2014 Income tax expense (benefit) at the federal statutory rate 35.0 % 35.0 % 35.0 % State income taxes, net of federal income tax benefit 0.1 % 0.1 % 0.2 % Foreign income tax 41.5 % 13.5 % 21.8 % Other (4.0 )% (0.5 )% (1.8 )% Valuation allowance (72.6 )% (48.1 )% (55.2 )% — % — % — %
Schedule of Tax Effects of Temporary Differences and Net Operating Losses	The tax effects of our temporary differences and net operating losses (“NOL”) are as follows at December 31: 2016 2015 Long-term deferred tax asset: Seismic and exploration costs $ 2,227,489 $ 733,183 Stock based compensation 27,342 26,995 Domestic NOL carry forwards 695,434 568,050 Foreign NOL carry forwards 43,969 42,625 Other 11,522 (88,837 ) Valuation allowance (2,597,708 ) (896,355 ) Total long-term deferred tax asset 408,048 385,661 Long-term deferred tax liability: 2019 Notes (61,944 ) (85,339 ) 2024 Notes (107,629 ) (148,279 ) Oil and natural gas properties (238,475 ) (152,043 ) Total long-term deferred tax liability (408,048 ) (385,661 ) Net long-term deferred tax asset $ — $ —

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2016
Earnings Per Share [Abstract]
Schedule of Earnings Per Share, Basic and Diluted Loss Per Share Computations	A reconciliation of the number of shares used for the basic and diluted loss per share computations is as follows for the years ended December 31: 2016 2015 2014 Weighted average common shares outstanding (basic and diluted) 412,080 408,535 407,116 Anti-dilutive shares excluded from diluted loss per share (1) 101,740 104,693 80,498 (1) Excludes RSAs, RSUs, NQSOs, PSUs, SARs and the shares underlying the 2.625% convertible senior notes due 2019 and the 3.125% convertible senior notes due 2024 as their effect, if included, would have been anti–dilutive.

Other Supplement Information (T

Other Supplement Information (Tables)	12 Months Ended
	Dec. 31, 2016
Supplemental Financial Information [Abstract]
Schedule of Cash, Cash Equivalents and Restricted Cash Recorded in Consolidated Balance Sheets	Cash, cash equivalents and restricted cash are recorded in our consolidated balance sheets as follows as of December 31: 2016 2015 Cash and cash equivalents $ 613,534 $ 80,171 Restricted cash 2,517 58,715 $ 616,051 $ 138,886
Schedule of Supplemental Cash Flows and Noncash Transactions	Supplemental cash flows and noncash transactions were as follows as of and for the years ended December 31: 2016 2015 2014 Supplemental cash flows information: Cash paid for interest $ 78,320 $ 78,410 $ 56,764 Cash paid for income taxes — — — Noncash transactions - changes in accrued capital expenditures (69,667 ) (47,580 ) (56,129 )
Schedule of Accrued Liabilities	Accrued liabilities consisted of the following as of December 31: 2016 2015 Accrued AFE costs $ 73,808 $ 202,439 Social obligation payments 86,473 115,110 Funds from release of letter of credit on Block 9 18,375 — Interest 13,793 7,843 Angolan consumption tax and withholding on services 9,796 13,421 Bonuses 8,900 12,300 General expenses 5,849 5,467 Seismic and other operating costs 5,625 9,782 Other 4,799 3,330 Total accrued liabilities $ 227,418 $ 369,692

Quarterly Data (Unaudited) (Tab

Quarterly Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Schedule of Quarterly Data Unaudited	First Quarter Second Quarter Third Quarter Fourth Quarter 2016 Revenues $ 1,636 $ 3,173 $ 4,228 $ 7,768 Gross profit (1) 680 1,470 1,856 5,225 Net loss (2) (46,615 ) (205,549 ) (2) (218,205 ) (3) (1,872,940 ) (4) Basic and diluted loss per share $ (0.11 ) $ (0.50 ) $ (0.53 ) $ (4.47 ) 2015 Revenues $ — $ — $ — $ — Gross profit — — — — Net loss (81,617 ) (66,810 ) (59,164 ) (486,835 ) (5) Basic and diluted loss per share $ (0.20 ) $ (0.16 ) $ (0.14 ) $ (1.19 ) (1) Represents oil, natural gas and natural gas liquids revenues less lease operating expenses. (2) Includes dry hole costs and impairments of $155.8 million, of which $149.9 million relates to the Goodfellow exploratory well and underlying leases. (3) Includes a $95.9 million charge related to the amendment of a drilling contract in the U.S. Gulf of Mexico. (4) Includes dry hole costs and impairment of $1,761.4 million, of which $1,691.8 million relates to our Angolan assets. (5) Includes dry hole costs and impairments of $422.4 million, of which $256.8 million relates to our proved oil and natural gas properties and $151.4 million relates to the Lontra exploratory well.

Supplementary Information on 39

Supplementary Information on Oil and Natural Gas Activities (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2016
Extractive Industries [Abstract]
Schedule of Capitalized Costs Relating to Oil and Natural Gas Producing Activities	Capitalized costs relating to oil and natural gas producing activities are as follows at December 31: 2016 2015 Proved oil and natural gas properties $ 118,245 $ 71,463 Unproved oil and natural gas properties, net 980,844 2,287,570 1,099,089 2,359,033 Accumulated depreciation, depletion and amortization (20,204 ) — Net capitalized costs $ 1,078,885 $ 2,359,033
Schedule of Costs Incurred in Oil and Natural Gas Property Development Activities	Costs incurred in oil and natural gas property development activities are as follows for the years ended December 31: 2016 2015 2014 Acquisition of unproved oil and natural gas properties $ 3,715 $ 35,993 $ 27,784 Exploration costs: Capitalized 599,526 718,078 574,100 Expensed 58,170 61,844 85,567 Development costs 39,111 145,021 90,642 Total $ 700,522 $ 960,936 $ 778,093
Schedule of Changes in Estimated Proved and Estimated Proved Developed Reserves	The following table sets forth changes in estimated proved and estimated proved developed reserves for the periods indicated. Oil (MMBbls) Natural Gas (Bcf) Natural Gas Liquids (MMBbls) MMBOE Proved developed and undeveloped reserves: As of December 31, 2013 7.9 3.4 — 8.5 Extensions and discoveries 0.5 0.3 — 0.5 As of December 31, 2014 8.4 3.7 — 9.0 Revisions of previous estimates (2.8 ) (1.9 ) 0.3 (2.8 ) As of December 31, 2015 5.6 1.8 0.3 6.2 Revisions of previous estimates (2.2 ) (0.5 ) (0.2 ) (2.5 ) Production (0.4 ) (0.1 ) — (0.4 ) As of December 31, 2016 3.0 1.2 0.1 3.3 Proved developed reserves: December 31, 2013 — — — — December 31, 2014 — — — — December 31, 2015 — — — — December 31, 2016 1.9 0.8 0.1 2.1 Proved undeveloped reserves: December 31, 2013 7.9 3.4 — 8.5 December 31, 2014 8.4 3.7 — 9.0 December 31, 2015 5.6 1.8 0.3 6.2 December 31, 2016 1.1 0.4 — 1.2
Schedule of Standardized Measure of Discounted Future Net Cash Flows Relating to Estimated Proved Oil, Natural Gas and Natural Gas Liquids Reserves	The standardized measure of discounted future net cash flows relating to estimated proved oil, natural gas and natural gas liquids reserves is as follows at December 31: 2016 2015 2014 Future cash inflows $ 123,889 $ 288,705 $ 814,394 Future production and development costs (86,103 ) (186,053 ) (257,016 ) Future net cash flows 37,786 102,652 557,378 10% annual premium (discount) for estimated timing of cash flows 1,164 (45,077 ) (192,094 ) Standardized measure of discounted future net cash flows $ 38,950 $ 57,575 $ 365,284
Schedule of Changes in Standardized Measure of Future Net Cash Flows	The principal sources of changes in the standardized measure of future net cash flows are as follows for the years ended December 31: 2016 2015 2014 Standardized measure at beginning of year $ 57,575 $ 365,284 $ 276,633 Sales and transfers of oil, natural gas and natural gas liquids produced, net of production costs (9,231 ) — — Net changes in prices and production costs (31,738 ) (314,367 ) (36,869 ) Development costs incurred during the period 45,611 — — Revisions and other (23,579 ) (122,584 ) 17,351 Accretion of discount 5,757 36,528 27,663 Changes in estimated future development costs (822 ) 99,964 49,700 Changes in timing and other (4,623 ) (7,250 ) 30,806 Standardized measure, ending $ 38,950 $ 57,575 $ 365,284

Organization and Nature of Bu40

Organization and Nature of Business - Additional Information (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)segment	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Number of reportable segments | segment	1
Net loss	$ (2,343,309)	$ (694,426)	$ (510,763)
Stockholders' deficit due to impairment of Angola assets	(841,334)	$ 1,446,137	$ 2,114,266	$ 2,129,146
Compensating cash balance	$ 200,000

Summary of Significant Accoun41

Summary of Significant Accounting Policies - Additional Information (Details)	12 Months Ended
	Dec. 31, 2016USD ($)Customer	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Summary Of Significant Accounting Policies [Line Items]
Joint interest and other receivables	$ 167,573,000	$ 211,308,000
Held-to-maturity securities unrecognized holding gains	0	0
Held-to-maturity securities unrecognized holding losses	0	0
OTTI in debt securities	0	0
Dry hole costs	213,500,000	188,000,000	$ 165,500,000
Upper limit of individual leasehold	1,000,000
Lower limit of individual leasehold	$ 1,000,000
New Accounting Pronouncement Early Adoption Effect
Summary Of Significant Accounting Policies [Line Items]
Reclassification of unamortized debt issuance costs		32,900,000
Sales revenue, net | Customer concentration risk
Summary Of Significant Accounting Policies [Line Items]
Number of customers | Customer	1
Concentration risk, percentage	96.50%
7.75% second lien notes due 2023
Summary Of Significant Accounting Policies [Line Items]
Debt instrument maturity year	2,023
Minimum
Summary Of Significant Accounting Policies [Line Items]
Estimated economic lives	3 years
Maximum
Summary Of Significant Accounting Policies [Line Items]
Estimated economic lives	10 years
Proved oil and natural gas properties
Summary Of Significant Accounting Policies [Line Items]
Impairment charges		256,800,000
Unproved oil and natural gas properties
Summary Of Significant Accounting Policies [Line Items]
Impairment charges	$ 66,600,000	$ 26,900,000	$ 70,500,000
Leases expiration dates, description	These leases have expiration dates ranging from 2017 through 2026.
Angolan | Exploration well costs
Summary Of Significant Accounting Policies [Line Items]
Dry hole costs	$ 1,276,400,000
Impairment charges	353,400,000
Block 21 risk services agreement | Sonangol P&P
Summary Of Significant Accounting Policies [Line Items]
Joint interest and other receivables	$ 159,100,000

Summary of Significant Accoun42

Summary of Significant Accounting Policies - Summary of Effect of Applying Guidance on Consolidated Statements of Cash Flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Summary Of Significant Accounting Policies [Line Items]
(Accretion of discount) amortization of premium on investments	$ (242)	$ 14,483	$ 20,925
Accrued liabilities	(62,058)	272,065	46,749
Net cash flows used in operating activities	(165,665)	(1,646)	(61,760)
Proceeds from maturity of investment securities	3,390,112	1,999,421	2,350,705
Purchase of investment securities	(2,545,911)	(1,192,873)	(2,739,134)
Net cash flows provided by (used in) investing activities	152,830	(114,121)	(1,141,159)
Increase (decrease) in cash, cash equivalents and restricted cash	477,165	(119,835)	66,261
Cash, cash equivalents and restricted cash, end of year	$ 616,051	138,886	258,721	$ 192,460
New Accounting Pronouncement Early Adoption Effect
Summary Of Significant Accounting Policies [Line Items]
(Accretion of discount) amortization of premium on investments		14,483	20,925
Accrued liabilities		272,065
Net cash flows used in operating activities		(1,646)	(61,760)
Proceeds from maturity of investment securities		1,999,421	2,350,705
Purchase of investment securities		(1,192,873)	(2,739,134)
Net cash flows provided by (used in) investing activities		(114,121)	(1,141,159)
Increase (decrease) in cash, cash equivalents and restricted cash		(119,835)
Cash, cash equivalents and restricted cash, end of year		138,886
New Accounting Pronouncement Early Adoption Effect | Prior to Adoption
Summary Of Significant Accounting Policies [Line Items]
(Accretion of discount) amortization of premium on investments		14,207	18,159
Accrued liabilities		22,453
Net cash flows used in operating activities		(251,942)	(64,526)
Change in restricted funds		(3,856)	43,667
Proceeds from maturity of investment securities		1,894,562	1,700,123
Purchase of investment securities		(892,577)	(2,129,453)
Net cash flows provided by (used in) investing activities		77,460	$ (1,138,393)
Increase (decrease) in cash, cash equivalents and restricted cash		(178,550)
Cash, cash equivalents and restricted cash, end of year		$ 80,171

Angolan Impairments - Additiona

Angolan Impairments - Additional Information (Details) - USD ($) $ in Thousands	3 Months Ended			12 Months Ended
	Dec. 31, 2016	Jun. 30, 2016	Dec. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Aug. 31, 2015
Impaired Long Lived Assets Held And Used [Line Items]
Dry hole costs and impairments	$ 1,761,400	$ 155,800	$ 422,400	$ 1,967,180	$ 462,234	$ 236,930
Initial payment made by Sonangol	250,000		$ 250,000	250,000	$ 250,000
Block 20, offshore Angola | CIE Angola Block 20 Ltd
Impaired Long Lived Assets Held And Used [Line Items]
Percentage of working interest acquired							40.00%
Block 21, offshore Angola | CIE Angola Block 21 Ltd
Impaired Long Lived Assets Held And Used [Line Items]
Percentage of working interest acquired							40.00%
Block 20 and Block 21 | CIE Angola block 20 and block 21
Impaired Long Lived Assets Held And Used [Line Items]
Dry hole costs and impairments				1,629,800
Impairment charges				62,000
Initial payment made by Sonangol	$ 250,000			$ 250,000

Investments - Schedule of Fair

Investments - Schedule of Fair Value of Held-to-maturity Securities Recorded at Amortized Cost (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Schedule Of Held To Maturity Securities [Line Items]
Fair market value	$ 682,098	$ 1,223,755
Corporate securities
Schedule Of Held To Maturity Securities [Line Items]
Fair market value	227,854	492,955
U.S. Treasury securities
Schedule Of Held To Maturity Securities [Line Items]
Fair market value	161,778	105,064
Commercial paper
Schedule Of Held To Maturity Securities [Line Items]
Fair market value	$ 292,466	604,986
Certificates of deposit
Schedule Of Held To Maturity Securities [Line Items]
Fair market value		$ 20,750

Investments - Schedule of Inves

Investments - Schedule of Investments Recorded in Consolidated Balance Sheets (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Schedule Of Held To Maturity Securities [Line Items]
Fair market value	$ 682,098	$ 1,223,755
Cash and cash equivalents
Schedule Of Held To Maturity Securities [Line Items]
Fair market value	341,680	38,420
Short-term investments
Schedule Of Held To Maturity Securities [Line Items]
Fair market value	$ 340,418	$ 1,185,335

Investments - Schedule of Inv46

Investments - Schedule of Investments Recorded in Consolidated Balance Sheets (Parenthetical) (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Short-term investments
Schedule Of Held To Maturity Securities [Line Items]
Investments serve as collateral for certain obligations	$ 9.1	$ 299.3

Fair Value Measurements - Fair

Fair Value Measurements - Fair Value Hierarchy for Liabilities Required to be Measured at Fair Value on a Recurring basis (Details) $ in Thousands	Dec. 31, 2016USD ($)
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Embedded derivative liabilities, Fair Value	$ 50,123
Recurring basis
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Embedded derivative liabilities, Fair Value	50,123
Recurring basis | First Lien Notes
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Embedded derivative liabilities, Fair Value	27,012
Recurring basis | Second Lien Notes
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Embedded derivative liabilities, Fair Value	23,111
Level 3 | Recurring basis
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Embedded derivative liabilities, Fair Value	50,123
Level 3 | Recurring basis | First Lien Notes
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Embedded derivative liabilities, Fair Value	27,012
Level 3 | Recurring basis | Second Lien Notes
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Embedded derivative liabilities, Fair Value	$ 23,111

Fair Value Measurements - Recon

Fair Value Measurements - Reconciliation of Changes in the Fair Value of Embedded Derivatives (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)
Embedded Derivative [Abstract]
Issuance of First Lien Notes and Second Lien Notes	$ 47,618
Change in fair value	2,505
End of period	$ 50,123

Fair Value Measurements - Addit

Fair Value Measurements - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Pre tax impairment of oil and gas properties		$ 256,800,000
Fair value of proved oil and gas properties		68,400,000
Held-to-maturity securities unrecognized holding gains	$ 0	0
Held-to-maturity securities unrecognized holding losses	$ 0	$ 0

Fair Value Measurements - Summa

Fair Value Measurements - Summary of Estimated Fair Value of Long-term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Long-term debt, fair value	$ 1,447,421	$ 1,368,500
10.75% first lien notes due 2021
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Long-term debt, fair value	482,250
7.75% second lien notes due 2023
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Long-term debt, fair value	327,449
2.625% convertible senior notes due 2019
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Long-term debt, fair value	305,378	791,209
3.125% convertible senior notes due 2024
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Long-term debt, fair value	$ 332,344	$ 577,291

Fair Value Measurements - Sum51

Fair Value Measurements - Summary of Estimated Fair Value of Long-term Debt (Parenthetical) (Details)	Dec. 31, 2016	Dec. 06, 2016	Dec. 31, 2014
10.75% first lien notes due 2021
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Interest rate (as a percent)	10.75%	10.75%
7.75% second lien notes due 2023
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Interest rate (as a percent)	7.75%	7.75%
2.625% convertible senior notes due 2019
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Interest rate (as a percent)	2.625%	2.625%
3.125% convertible senior notes due 2024
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Interest rate (as a percent)	3.125%	3.125%	3.125%

Oil and Natural Gas Propertie52

Oil and Natural Gas Properties - Schedule of Oil and Natural Gas Properties (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Property Plant And Equipment [Abstract]
Well and development costs	$ 118,245	$ 71,463
Accumulated depletion	(20,204)	0
Total proved properties	98,041	71,463
Oil and natural gas leaseholds	651,295	738,852
Accumulated valuation allowance	(507,198)	(178,463)
Total oil and gas leasehold	144,097	560,389
Exploratory wells in process	836,747	1,727,181	$ 1,186,464	$ 777,823
Total unproved properties	980,844	2,287,570
Total oil and natural gas properties, net	$ 1,078,885	$ 2,359,033

Oil and Natural Gas Propertie53

Oil and Natural Gas Properties - Schedule of Net Changes in Capitalized Exploratory Well Costs (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Net changes in capitalized exploratory well costs (excluding any related leasehold costs)
Beginning of period		$ 1,727,181	$ 1,186,464	$ 777,823
Amounts charged to expense	[1]	(1,489,960)	(177,361)	(165,459)
End of period		836,747	1,727,181	1,186,464
Exploration well costs
Net changes in capitalized exploratory well costs (excluding any related leasehold costs)
Beginning of period		1,572,090
Additions to capitalized exploration		499,985	630,395	522,892
End of period		582,115	1,572,090
Capitalized interest
Net changes in capitalized exploratory well costs (excluding any related leasehold costs)
Beginning of period		155,091
Additions to capitalized exploration		99,541	87,683	$ 51,208
End of period		$ 254,632	$ 155,091
[1]	Amounts represent dry hole costs related to exploratory wells which did not encounter commercial hydrocarbons or where it was determined that sufficient progress was not being made.

Oil and Natural Gas Propertie54

Oil and Natural Gas Properties - Schedule of Cumulative Costs of Capitalized Exploratory Well Costs (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cumulative costs of capitalized exploratory well costs (excluding any related leasehold costs)
Cumulative costs	$ 836,747	$ 1,727,181	$ 1,186,464	$ 777,823
Well costs capitalized for a period greater than one year after completion of drilling	609,893	1,225,747
Exploration well costs
Cumulative costs of capitalized exploratory well costs (excluding any related leasehold costs)
Cumulative costs	582,115	1,572,090
Capitalized interest
Cumulative costs of capitalized exploratory well costs (excluding any related leasehold costs)
Cumulative costs	$ 254,632	$ 155,091

Long-term Debt, Net - Schedule

Long-term Debt, Net - Schedule of Long-term Debt, Net (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Debt instrument
Long-term debt, net	$ 2,479,349	$ 1,981,895
10.75% first lien notes due 2021
Debt instrument
Principal outstanding	500,000
Unamortized discount	(34,416)
Carrying amount	465,584
7.75% second lien notes due 2023
Debt instrument
Principal outstanding	584,732
Unamortized discount	(54,856)
Carrying amount	529,876
2.625% convertible senior notes due 2019
Debt instrument
Principal outstanding	763,446	1,380,000
Unamortized discount	(109,689)	(258,565)
Carrying amount	653,757	1,121,435
3.125% convertible senior notes due 2024
Debt instrument
Principal outstanding	1,204,145	1,300,000
Unamortized discount	(374,013)	(439,540)
Carrying amount	$ 830,132	$ 860,460

Long-term Debt, Net - Schedul56

Long-term Debt, Net - Schedule of Long-term Debt, Net (Parenthetical) (Details)	Dec. 31, 2016
10.75% first lien notes due 2021
Debt instrument
Effective interest rate	12.60%
7.75% second lien notes due 2023
Debt instrument
Effective interest rate	9.60%
2.625% convertible senior notes due 2019
Debt instrument
Effective interest rate	8.40%
3.125% convertible senior notes due 2024
Debt instrument
Effective interest rate	9.00%

Long-term Debt, Net - Additiona

Long-term Debt, Net - Additional Information (Details) $ / shares in Units, shares in Millions	Dec. 06, 2016USD ($)shares	May 13, 2014USD ($)$ / shares	Dec. 17, 2012USD ($)$ / shares	Dec. 31, 2016USD ($)$ / shares	Dec. 31, 2015USD ($)	Dec. 31, 2014
Debt instrument
Compensating cash balance				$ 200,000,000
Notes
Debt instrument
Repurchase price as a percentage of principal amount of debt instrument		100.00%	100.00%
Specified minimum percentage of principal amount, the holders of which may declare all principal, accrued and unpaid interest to be due and payable immediately, upon the occurrence of an Event of Default		25.00%	25.00%
Percentage of principal amount, which may be declared by holders of a specified principal amount to be due and payable immediately upon occurrence of an Event of Default		100.00%	100.00%
2.625% convertible senior notes due 2019
Debt instrument
Interest rate (as a percent)	2.625%			2.625%
Aggregate principal amount of notes issued	$ 616,600,000
Debt conversion, common stock shares issued | shares	30
Debt instrument maturity date				Dec. 1, 2019
Debt instrument payment terms				Interest is payable semi–annually in arrears on June 1 and December 1 of each year.
Initial conversion rate of common stock			28.023
Initial conversion price per share of common stock (in dollars per share) | $ / shares			$ 35.68
Carrying amount of the equity components			$ 381,400,000
Debt issue cost allocated to the equity component			$ 9,100,000
3.125% convertible senior notes due 2024
Debt instrument
Interest rate (as a percent)	3.125%			3.125%		3.125%
Aggregate principal amount of notes issued	$ 95,900,000
Debt instrument maturity date				May 15, 2024
Debt instrument payment terms				Interest is payable semi–annually in arrears on May 15 and November 15 of each year.
Initial conversion rate of common stock		43.3604
Initial conversion price per share of common stock (in dollars per share) | $ / shares		$ 23.06
Carrying amount of the equity components		$ 464,700,000
Debt issue cost allocated to the equity component		$ 11,100,000
Number of days within 30 consecutive trading days in which the closing price of the entity's common stock must exceed the conversion price for the notes to be redeemable				20 days
Number of consecutive trading days during which the closing price of the entity's common stock must exceed the conversion price for at least 20 days in order for the notes to be redeemable				30 days
Minimum sale price of common stock to determine eligibility of conversion | $ / shares				$ 30
Number of business days after any five consecutive trading day period during the note measurement period				5 days
Number of consecutive trading days before five consecutive business days during the note measurement period				5 days
Convertibility of debt, trading price of debt test, percentage of closing price of stock used in calculation				98.00%
10.75% first lien notes
Debt instrument
Interest rate (as a percent)	10.75%			10.75%
Aggregate principal amount of notes issued	$ 500,000,000
Percentage of aggregate principal amount for cash	98.00%
Derivative liabilities	$ 24,800,000
Debt instrument maturity date				Dec. 6, 2021
Debt instrument payment terms				Interest is payable semi–annually in arrears on each June 1 and December 1 of each year.
Debt instrument redemption, description				Prior to December 1, 2018, we may redeem the First Lien Notes, at our option, at a redemption price equal to 100% of the outstanding principal amount of such notes plus the applicable premium (as defined in the First Lien Indenture). On and after December 1, 2018, the First Lien Notes may be redeemed in multiples of $1,000 principal amount at a redemption price equal to 100% of the First Lien Notes to be redeemed, plus accrued and unpaid interest to, but excluding, the redemption date.
10.75% first lien notes | Prior to December 1, 2018
Debt instrument
Percentage of aggregate principal amount for cash				100.00%
10.75% first lien notes | On or after December 1, 2018
Debt instrument
Percentage of aggregate principal amount for cash				100.00%
Debt instrument multiples of principle amount plus accrued and unpaid interest redemption				$ 1,000
10.75% first lien notes | Minimum
Debt instrument
Compensating cash balance				$ 200,000,000
10.75% first lien notes | Cobalt International Energy Overseas Ltd
Debt instrument
Percentage of debt secured guaranteed	65.00%
7.75% second lien notes
Debt instrument
Interest rate (as a percent)	7.75%			7.75%
Aggregate principal amount of notes issued	$ 584,732,000
Derivative liabilities	22,800,000
Debt instrument maturity date				Dec. 1, 2023
Debt instrument payment terms				Interest is payable semi–annually in arrears on each June 1 and December 1 of each year
Facility Agreement
Debt instrument
Amount outstanding				$ 0
Facility Agreement | GOM#1
Debt instrument
Maximum borrowing capacity					$ 150,000,000
Write off of debt issuance cost				$ 3,300,000
General and administrative expenses
Debt instrument
Transaction related costs	$ 19,600,000

Long-term Debt, Net - Schedul58

Long-term Debt, Net - Schedule of Maturities of Long-term Debt (Details) $ in Thousands	Dec. 31, 2016USD ($)
Maturities Of Long Term Debt [Abstract]
Principal outstanding, 2019	$ 763,446
Principal outstanding, 2021	500,000
Principal outstanding, Thereafter	$ 1,788,877

Asset Retirement Obligations -

Asset Retirement Obligations - Schedule of Changes in Asset Retirement Obligation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Changes in asset retirement obligation
Beginning of period	$ 3,167
Liabilities incurred		$ 3,068
Revisions	2,806
Accretion	550	99
End of period	$ 6,523	$ 3,167

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Details) $ in Millions	Nov. 02, 2014Stockholder	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	May 31, 2016Well
Commitments And Contingencies Disclosure [Abstract]
Number of purported stockholders | Stockholder	2
Number of exploration wells | Well					2
Office and delay rental expense | $		$ 9.2	$ 12.4	$ 12.8

Commitments and Contingencies61

Commitments and Contingencies - Schedule of Estimated Contractual Commitments (Details) $ in Thousands	Dec. 31, 2016USD ($)
Contractual obligation and commitments
2,017	$ 179,294
2,018	5,831
2,019	5,980
2,020	6,049
2,021	6,096
Thereafter	8,163
Drilling Rig Commitments
Contractual obligation and commitments
2,017	85,269
Social Payment Obligations
Contractual obligation and commitments
2,017	86,473
2,018	74
Delay Rental Payments
Contractual obligation and commitments
2,017	5,243
2,018	3,388
2,019	3,575
2,020	3,595
2,021	3,595
Thereafter	7,492
Operating Leases
Contractual obligation and commitments
2,017	2,309
2,018	2,369
2,019	2,405
2,020	2,454
2,021	2,501
Thereafter	$ 671

Equity-Based Compensation - Add

Equity-Based Compensation - Additional Information (Details)	12 Months Ended
	Dec. 31, 2016USD ($)Installment$ / sharesshares	Dec. 31, 2015USD ($)$ / sharesshares	Dec. 31, 2014USD ($)$ / sharesshares
Equity Based Compensation
Shares available for grant under the plan | shares	7,700,000
Shares authorized under the plan | shares	25,700,000
Contractual term for options granted	10 years
Vesting service period	1 year	1 year
Restricted stock awards with performance and service condition
Equity Based Compensation
Granted (in shares) | shares	600,000	400,000
Restricted stock awards
Equity Based Compensation
Granted (in shares) | shares	3,898,052
Number of equal vesting installments | Installment	3
Fair value granted	$ 6,300,000	$ 30,500,000	$ 33,100,000
Fair value vested	$ 4,600,000	1,400,000	11,500,000
Weighted average remaining contractual terms for options outstanding	5 years 4 months 24 days
Weighted average remaining contractual terms for options exercisable	3 years 8 months 12 days
Unrecognized compensation cost	$ 15,600,000
Period for recognition of unrecognized compensation cost	1 year 7 months 6 days
Units vested | shares	2,494,643
Vested (in dollars per share) | $ / shares	$ 11.33
Weighted average fair value granted | $ / shares	$ 1.43
Non-qualified stock options
Equity Based Compensation
Weighted average remaining contractual terms for options outstanding	6 years 8 months 12 days
Weighted average remaining contractual terms for options exercisable	5 years 9 months 18 days
Unrecognized compensation cost	$ 400,000
Period for recognition of unrecognized compensation cost	9 months 18 days
Fair value granted	$ 4,000,000	5,900,000	14,200,000
Fair value vested	14,500,000	$ 12,300,000	16,100,000
Intrinsic value, outstanding	0
Intrinsic value, exercisable	$ 0
Non-qualified stock options | Vesting in three years
Equity Based Compensation
Vesting percentage	50.00%
Non-qualified stock options | Vesting in fourth year
Equity Based Compensation
Vesting percentage	50.00%
Performance stock units
Equity Based Compensation
Granted (in shares) | shares	283,750
Number of equal vesting installments | Installment	3
Weighted average remaining contractual terms for options outstanding	9 years 7 months 6 days
Unrecognized compensation cost	$ 200,000
Period for recognition of unrecognized compensation cost	2 years 7 months 6 days
Weighted average fair value granted | $ / shares	$ 0.75
Restricted stock units
Equity Based Compensation
Granted (in shares) | shares	3,491,352
Number of equal vesting installments | Installment	3
Fair value vested	$ 800,000		$ 700,000
Weighted average remaining contractual terms for options outstanding	9 years 1 month 6 days
Weighted average remaining contractual terms for options exercisable	9 years 1 month 6 days
Unrecognized compensation cost	$ 4,100,000
Period for recognition of unrecognized compensation cost	2 years 2 months 12 days
Units vested | shares	596,823	0
Vested (in dollars per share) | $ / shares	$ 2.44
Weighted average fair value granted | $ / shares	$ 2.44
Stock appreciation rights (SARs)
Equity Based Compensation
Granted (in shares) | shares	0
Number of equal vesting installments | Installment	3
Weighted average remaining contractual terms for options outstanding	8 years 1 month 6 days
Weighted average remaining contractual terms for options exercisable	8 years 1 month 6 days
Unrecognized compensation cost	$ 10,000
Period for recognition of unrecognized compensation cost	1 year 1 month 6 days
Intrinsic value, outstanding	$ 0
Intrinsic value, exercisable	$ 0
Weighted average grant date fair value		$ 4,200,000
Non-employee director grants
Equity Based Compensation
Shares available for grant under the plan | shares	600,000
Shares authorized under the plan | shares	1,500,000
Non-employee director grants | Restricted stock units
Equity Based Compensation
Granted (in shares) | shares	400,000
Grant date fair value	$ 800,000
Non-employee director grants | Retainer awards | Common Stock
Equity Based Compensation
Granted (in shares) | shares	300,000	50,000	30,000
Weighted average fair value granted | $ / shares	$ 1.89	$ 9.49	$ 17.52

Equity-Based Compensation - Sch

Equity-Based Compensation - Schedule of Weighted Average Assumptions Used to Estimate the Fair Value of Stock Awards (Details)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Restricted stock awards
Assumptions used to determine the fair value of stock award granted
Expected volatility	55.02%	49.79%
Risk-free interest rate	2.03%	1.77%
Dividend yield	0.00%	0.00%
Expected life (years)	5 years 8 months 12 days	10 years
Non-qualified stock options
Assumptions used to determine the fair value of stock award granted
Expected volatility	55.02%	54.97%	57.27%
Risk-free interest rate	2.03%	1.84%	1.69%
Dividend yield	0.00%	0.00%	0.00%
Expected life (years)	5 years 8 months 12 days	5 years 6 months	5 years 6 months

Equity-Based Compensation - S64

Equity-Based Compensation - Schedule of Activity Related to Restricted Stock Awards/Units (Details) - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Restricted stock awards
Number of Shares
Nonvested at the beginning of the period (in shares)	5,780,239
Granted (in shares)	3,898,052
Vested (in shares)	(2,494,643)
Forfeited (in shares)	(1,061,890)
Nonvested at the end of the period (in shares)	6,121,758	5,780,239
Exercisable at the end of the period (in shares)	755,657
Weighted Average Grant Date Fair Value Per Share
Nonvested at the beginning of the period (in dollars per share)	$ 11.59
Granted (in dollars per share)	1.43
Vested (in dollars per share)	11.33
Forfeited (in dollars per share)	12.70
Nonvested at the end of the period (in dollars per share)	5	$ 11.59
Exercisable at the end of the period (in dollars per share	$ 6.73
Restricted stock units
Number of Shares
Granted (in shares)	3,491,352
Vested (in shares)	(596,823)	0
Forfeited (in shares)	(457,097)
Nonvested at the end of the period (in shares)	2,437,432
Exercisable at the end of the period (in shares)	358,606
Weighted Average Grant Date Fair Value Per Share
Granted (in dollars per share)	$ 2.44
Vested (in dollars per share)	2.44
Forfeited (in dollars per share)	2.44
Nonvested at the end of the period (in dollars per share)	2.44
Exercisable at the end of the period (in dollars per share	$ 2.44

Equity-Based Compensation - S65

Equity-Based Compensation - Schedule of Activity Related to Stock Awards (Details) - Non-qualified stock options	12 Months Ended
	Dec. 31, 2016$ / sharesshares
Number of Stock Options
Outstanding at the beginning of the period (in shares) | shares	3,766,941
Granted (in shares) | shares	1,129,944
Forfeited (in shares) | shares	(588,744)
Outstanding at the end of the period (in shares) | shares	4,308,141
Exercisable at the end of the period (in shares) | shares	3,110,337
Weighted Average Exercise Price
Outstanding at the beginning of the period (in dollars per share) | $ / shares	$ 17.23
Granted (in dollars per share) | $ / shares	3.50
Forfeited (in dollars per share) | $ / shares	19.69
Outstanding at the end of the period (in dollars per share) | $ / shares	13.29
Exercisable at the end of the period (in dollars per share) | $ / shares	$ 16.75

Equity-Based Compensation - S66

Equity-Based Compensation - Schedule of Weighted Average Assumptions Used to Estimate Fair Value of Performance Stock Units (Details) - Performance stock units	12 Months Ended
	Dec. 31, 2016
Assumptions used to determine the fair value of stock award granted
Expected volatility	64.31%
Risk-free interest rate	0.80%

Equity-Based Compensation - S67

Equity-Based Compensation - Schedule of Activity Related to Performance Stock Units (Details) - Performance stock units	12 Months Ended
	Dec. 31, 2016$ / sharesshares
Number of Shares
Granted (in shares) | shares	283,750
Nonvested at the end of the period (in shares) | shares	283,750
Weighted Average Grant Date Fair Value Per Share
Granted (in dollars per share) | $ / shares	$ 0.75
Nonvested at the end of the period (in dollars per share) | $ / shares	$ 0.75

Equity-Based Compensation - S68

Equity-Based Compensation - Schedule Weighted Average Assumptions Used to Estimate Fair Value of Stock Appreciation Rights (Details) - Stock appreciation rights (SARs)	12 Months Ended
	Dec. 31, 2015
Assumptions used to determine the fair value of stock award granted
Expected volatility	54.97%
Risk-free interest rate	1.84%
Dividend yield	0.00%
Expected life (years)	5 years 6 months

Equity-Based Compensation - S69

Equity-Based Compensation - Schedule of Activity Related to Stock Appreciation Rights (Details) - Stock appreciation rights (SARs)	12 Months Ended
	Dec. 31, 2016$ / sharesshares
Number of Shares
Nonvested at the beginning of the period (in shares) | shares	1,452,332
Forfeited (in shares) | shares	(595,566)
Nonvested at the end of the period (in shares) | shares	856,766
Exercisable at the end of the period (in shares) | shares	698,424
Weighted Average Exercise Price Per Share
Nonvested at the beginning of the period (in dollars per share) | $ / shares	$ 8.87
Forfeited (in dollars per share) | $ / shares	8.87
Nonvested at the end of the period (in dollars per share) | $ / shares	8.87
Exercisable at the end of the period (in dollars per share) | $ / shares	$ 8.87

Equity-Based Compensation - S70

Equity-Based Compensation - Schedule of Recognized Equity-based Compensation Costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Equity Based Compensation
Compensation costs	$ 14,889	$ 27,748	$ 31,742
Liability awards	(1,354)	1,451
Equity awards
Equity Based Compensation
Compensation costs	$ 16,243	$ 26,297	$ 31,742

Employee Benefit Plan - Additio

Employee Benefit Plan - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Compensation And Retirement Disclosure [Abstract]
Minimum period following date of hire after which employees become eligible to participate in the Plan	3 months
Employee contribution match in plan (as a percent)	6.00%
Expenses recorded in benefit contributions to the Plan	$ 1.5	$ 1.7	$ 1

Income Taxes - Schedule of Prov

Income Taxes - Schedule of Provision for Income Taxes (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Deferred taxes:
Total	$ 0	$ 0	$ 0

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax [Line Items]
Income tax expense or benefit	$ 0	$ 0	$ 0
Unrecognized tax benefits	0	0
Accrued interest or penalties associated with unrecognized tax benefits	0	$ 0
Federal
Income Tax [Line Items]
Net operating loss carryforwards	$ 2,000,000,000
Net operating loss carryforwards begins to expire	2,026
State
Income Tax [Line Items]
Net operating loss carryforwards	$ 82,800,000
Net operating loss carryforwards begins to expire	2,025
Foreign
Income Tax [Line Items]
Net operating loss carryforwards	$ 85,600,000
Net operating loss carryforwards begins to expire	2,016

Income Taxes - Schedule of Geog

Income Taxes - Schedule of Geographic Sources of Loss (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
U.S.	$ (2,313,482)	$ (490,190)	$ (307,025)
Foreign	(29,827)	(204,236)	(203,738)
Net loss	$ (2,343,309)	$ (694,426)	$ (510,763)

Income Taxes - Schedule of Effe

Income Taxes - Schedule of Effective Tax Rate on Loss (Details)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Effective tax rate on loss differs form U.S. statutory rates
Income tax expense (benefit) at the federal statutory rate	35.00%	35.00%	35.00%
State income taxes, net of federal income tax benefit	0.10%	0.10%	0.20%
Foreign income tax	41.50%	13.50%	21.80%
Other	(4.00%)	(0.50%)	(1.80%)
Valuation allowance	(72.60%)	(48.10%)	(55.20%)

Income Taxes - Schedule of Tax

Income Taxes - Schedule of Tax Effects of Temporary Differences and Net Operating Losses (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Long-term deferred tax asset:
Seismic and exploration costs	$ 2,227,489	$ 733,183
Stock based compensation	27,342	26,995
Domestic NOL carry forwards	695,434	568,050
Foreign NOL carry forwards	43,969	42,625
Other	11,522	(88,837)
Valuation allowance	(2,597,708)	(896,355)
Total long-term deferred tax asset	408,048	385,661
Long-term deferred tax liability:
Oil and natural gas properties	(238,475)	(152,043)
Total long-term deferred tax liability	(408,048)	(385,661)
2019 notes
Long-term deferred tax liability:
Convertible senior notes	(61,944)	(85,339)
2024 notes
Long-term deferred tax liability:
Convertible senior notes	$ (107,629)	$ (148,279)

Earnings Per Share - Schedule o

Earnings Per Share - Schedule of Earnings Per Share, Basic and Diluted Loss Per Share Computations (Details) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Earnings Per Share [Abstract]
Weighted average common shares outstanding (basic and diluted)	412,080	408,535	407,116
Anti-dilutive shares excluded from diluted loss per share	101,740	104,693	80,498

Earnings Per Share - Schedule78

Earnings Per Share - Schedule of Earnings Per Share, Basic and Diluted Loss Per Share Computations (Parenthetical) (Details)	12 Months Ended
	Dec. 31, 2016	Dec. 06, 2016	Dec. 31, 2014
2.625% convertible senior notes due 2019
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Interest rate (as a percent)	2.625%	2.625%
Debt instrument maturity year	2,019
3.125% convertible senior notes due 2024
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Interest rate (as a percent)	3.125%	3.125%	3.125%
Debt instrument maturity year	2,024

Other Supplemental Information

Other Supplemental Information - Schedule of Cash, Cash Equivalents and Restricted Cash Recorded in Consolidated Balance Sheets (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash And Cash Equivalents [Abstract]
Cash and cash equivalents	$ 613,534	$ 80,171
Restricted cash	2,517	58,715
Cash, cash equivalents and restricted cash	$ 616,051	$ 138,886	$ 258,721	$ 192,460

Other Supplemental Informatio80

Other Supplemental Information - Schedule of Supplemental Cash flows and Noncash Transactions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Supplemental cash flows information:
Cash paid for interest	$ 78,320	$ 78,410	$ 56,764
Noncash transactions - changes in accrued capital expenditures	$ (69,667)	$ (47,580)	$ (56,129)

Other Supplement Information -

Other Supplement Information - Schedule of Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Schedule Of Accrued Liabilities [Line Items]
Accrued AFE costs	$ 73,808	$ 202,439
Social obligation payments	86,473	115,110
Interest	13,793	7,843
Bonuses	8,900	12,300
General expenses	5,849	5,467
Seismic and other operating costs	5,625	9,782
Other	4,799	3,330
Total accrued liabilities	227,418	369,692
Angolan
Schedule Of Accrued Liabilities [Line Items]
Angolan consumption tax and withholding on services	9,796	$ 13,421
Block 9
Schedule Of Accrued Liabilities [Line Items]
Funds from release of letter of credit on Block 9	$ 18,375

Other Matters - Additional Info

Other Matters - Additional Information (Details) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Sep. 30, 2016	Dec. 31, 2016
Other Commitments [Line Items]
Severance costs associated with workforce reduction plan		$ 9,900
Accrued severance costs		900
Loss on amendment of contract		95,908
Accrued contract amendment costs		19,582
Contract Termination
Other Commitments [Line Items]
Loss on amendment of contract	$ 95,900
Payment of loss on contract termination		$ 76,300
Contract termination date		Mar. 31, 2017
Accrued contract amendment costs		$ 19,600

Quarterly Data (Unaudited) - Sc

Quarterly Data (Unaudited) - Schedule of Quarterly Data 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
Selected Quarterly Financial Information [Abstract]
Revenues	$ 7,768	$ 4,228	$ 3,173	$ 1,636
Gross profit	5,225	1,856	1,470	680
Net loss	$ (1,872,940)	$ (218,205)	$ (205,549)	$ (46,615)	$ (486,835)	$ (59,164)	$ (66,810)	$ (81,617)
Basic and diluted loss per share	$ (4.47)	$ (0.53)	$ (0.50)	$ (0.11)	$ (1.19)	$ (0.14)	$ (0.16)	$ (0.20)	$ (5.69)	$ (1.70)	$ (1.25)

Quarterly Data (Unaudited) - 84

Quarterly Data (Unaudited) - Schedule of Quarterly Data Unaudited (Parenthetical) (Details) - USD ($) $ in Thousands	3 Months Ended				12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Dec. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Exploratory Wells Drilled [Line Items]
Dry hole costs and impairments	$ 1,761,400		$ 155,800	$ 422,400	$ 1,967,180	$ 462,234	$ 236,930
Charge related to amendment of drilling contract					$ (95,908)
U.S. Gulf of Mexico
Exploratory Wells Drilled [Line Items]
Charge related to amendment of drilling contract		$ 95,900
Angolan
Exploratory Wells Drilled [Line Items]
Dry hole costs and impairments	$ 1,691,800
Goodfellow exploratory well and underlying leases
Exploratory Wells Drilled [Line Items]
Dry hole costs and impairments			$ 149,900
Proved oil and natural gas properties
Exploratory Wells Drilled [Line Items]
Dry hole costs and impairments				256,800
Lontra exploratory well
Exploratory Wells Drilled [Line Items]
Dry hole costs and impairments				$ 151,400

Supplementary Information on 85

Supplementary Information on Oil and Natural Gas Activities (Unaudited) - Schedule of Capitalized Costs Relating to Oil and Natural Gas Producing Activities (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Extractive Industries [Abstract]
Proved oil and natural gas properties	$ 118,245	$ 71,463
Unproved oil and natural gas properties, net	980,844	2,287,570
Gross capitalized costs	1,099,089	2,359,033
Accumulated depreciation, depletion and amortization	(20,204)
Net capitalized costs	$ 1,078,885	$ 2,359,033

Supplementary Information on 86

Supplementary Information on Oil and Natural Gas Activities (Unaudited) - Schedule of Costs Incurred in Oil and Natural Gas Property Development Activities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Extractive Industries [Abstract]
Acquisition of unproved oil and natural gas properties	$ 3,715	$ 35,993	$ 27,784
Exploration costs:
Capitalized	599,526	718,078	574,100
Expensed	58,170	61,844	85,567
Development costs	39,111	145,021	90,642
Total	$ 700,522	$ 960,936	$ 778,093

Supplementary Information on 87

Supplementary Information on Oil and Natural Gas Activities (Unaudited) - Schedule of Changes in Estimated Proved and Estimated Proved Developed Reserves (Details)	12 Months Ended
	Dec. 31, 2016MMBoeMMBblsBcf	Dec. 31, 2015MMBoeMMBblsBcf	Dec. 31, 2014MMBoeMMBblsBcf	Dec. 31, 2013MMBoeMMBblsBcf
Proved developed and undeveloped energy reserves:
Beginning of the year | MMBoe	6.2	9	8.5
Extensions and discoveries | MMBoe			0.5
Revisions of previous estimates | MMBoe	(2.5)	(2.8)
Production | MMBoe	(0.4)
End of the year | MMBoe	3.3	6.2	9
Proved developed energy reserves:
Proved developed energy reserves | MMBoe	2.1
Proved undeveloped energy reserves:
Proved undeveloped energy reserves | MMBoe	1.2	6.2	9	8.5
Oil (MMBbls)
Proved developed and undeveloped reserves:
Beginning of the year	5.6	8.4	7.9
Extensions and discoveries			0.5
Revisions of previous estimates	(2.2)	(2.8)
Production	(0.4)
End of the year	3	5.6	8.4
Proved developed reserves:
Proved developed reserves	1.9
Proved undeveloped reserves:
Proved undeveloped reserves	1.1	5.6	8.4	7.9
Natural Gas (Bcf)
Proved developed and undeveloped reserves:
Beginning of the year | Bcf	1.8	3.7	3.4
Extensions and discoveries | Bcf			0.3
Revisions of previous estimates | Bcf	(0.5)	(1.9)
Production | Bcf	(0.1)
End of the year | Bcf	1.2	1.8	3.7
Proved developed reserves:
Proved developed reserves | Bcf	0.8
Proved undeveloped reserves:
Proved undeveloped reserves | Bcf	0.4	1.8	3.7	3.4
Natural Gas Liquids (MMBbls)
Proved developed and undeveloped reserves:
Beginning of the year	0.3
Revisions of previous estimates	(0.2)	0.3
End of the year	0.1	0.3
Proved developed reserves:
Proved developed reserves	0.1
Proved undeveloped reserves:
Proved undeveloped reserves		0.3

Supplementary Information on 88

Supplementary Information on Oil and Natural Gas Activities (Unaudited) - Additional Information (Details)	12 Months Ended
	Dec. 31, 2016$ / bbl$ / Mcf	Dec. 31, 2015$ / bbl$ / Mcf	Dec. 31, 2014$ / bbl$ / Mcf
Supplemental Information On Oil And Gas Exploration And Production Activities Disclosure [Line Items]
Future net cash flows discounted at an annual rate	10.00%
Oil (MMBbls)
Supplemental Information On Oil And Gas Exploration And Production Activities Disclosure [Line Items]
Average resulting price (in dollars per Bbl, NGL or Mcf)	40.32	50.78	95.24
Natural Gas Liquids
Supplemental Information On Oil And Gas Exploration And Production Activities Disclosure [Line Items]
Average resulting price (in dollars per Bbl, NGL or Mcf)	19.23	15.23	0
Natural Gas
Supplemental Information On Oil And Gas Exploration And Production Activities Disclosure [Line Items]
Average resulting price (in dollars per Bbl, NGL or Mcf) | $ / Mcf	2.056	(0.182)	4.770

Supplementary Information on 89

Supplementary Information on Oil and Natural Gas Activities (Unaudited) - Schedule of Standardized Measure of Discounted Future Net Cash Flows Relating to Estimated Proved Oil, Natural Gas and Natural Gas Liquids Reserves (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Future net cash flows relating to estimated proved oil, natural gas and natural gas liquids reserves based on the standardized measure
Future cash inflows	$ 123,889	$ 288,705	$ 814,394
Future production and development costs	(86,103)	(186,053)	(257,016)
Future net cash flows	37,786	102,652	557,378
10% annual premium (discount) for estimated timing of cash flows	1,164	(45,077)	(192,094)
Standardized measure of discounted future net cash flows	$ 38,950	$ 57,575	$ 365,284	$ 276,633

Supplementary Information on 90

Supplementary Information on Oil and Natural Gas Activities (Unaudited) - Schedule of Changes in Standardized Measure of Future Net Cash Flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Extractive Industries [Abstract]
Standardized measure at beginning of year	$ 57,575	$ 365,284	$ 276,633
Sales and transfers of oil, natural gas and natural gas liquids produced, net of production costs	(9,231)
Net changes in prices and production costs	(31,738)	(314,367)	(36,869)
Development costs incurred during the period	45,611
Revisions and other	(23,579)	(122,584)	17,351
Accretion of discount	5,757	36,528	27,663
Changes in estimated future development costs	(822)	99,964	49,700
Changes in timing and other	(4,623)	(7,250)	30,806
Standardized measure, ending	$ 38,950	$ 57,575	$ 365,284

Subsequent Events (Unaudited) -

Subsequent Events (Unaudited) - Additional Information (Details) - USD ($)	1 Months Ended	12 Months Ended
	Jan. 31, 2017	Dec. 31, 2016	Dec. 06, 2016
7.75% second lien notes due 2023
Subsequent Event [Line Items]
Aggregate principal amount of notes issued			$ 584,732,000
Debt instrument maturity year		2,023
2.625% convertible senior notes due 2019
Subsequent Event [Line Items]
Aggregate principal amount of notes issued			616,600,000
Debt instrument maturity year		2,019
3.125% convertible senior notes due 2024
Subsequent Event [Line Items]
Aggregate principal amount of notes issued			$ 95,900,000
Debt instrument maturity year		2,024
Subsequent event | 7.75% second lien notes due 2023
Subsequent Event [Line Items]
Aggregate principal amount of notes issued	$ 139,200,000
Debt instrument maturity year	2,023
Subsequent event | 2.625% convertible senior notes due 2019
Subsequent Event [Line Items]
Aggregate principal amount of notes issued	$ 137,800,000
Debt instrument maturity year	2,019
Subsequent event | 3.125% convertible senior notes due 2024
Subsequent Event [Line Items]
Aggregate principal amount of notes issued	$ 60,000,000
Debt instrument maturity year	2,024