Kosmos Energy (KOS) 10-K25 Feb 202019 FY Annual reportFinancial data

Company Profile

Cover Page

Cover Page - USD ($)	12 Months Ended
Cover Page - USD ($)	Dec. 31, 2019	Feb. 14, 2020
Cover page.
Document Type	10-K
Document Annual Report	true
Document Transition Report	false
Entity File Number	001-35167
Entity Registrant Name	Kosmos Energy Ltd.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	98-0686001
Entity Address, Address Line One	8176 Park Lane
Entity Address, City or Town	Dallas,
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	75231
City Area Code	214
Local Phone Number	445 9600
Title of 12(b) Security	Common Stock $0.01 par value
Trading Symbol	KOS
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Public Float	$ 2,220,129,484
Entity Common Stock, Shares Outstanding		405,098,215
Documents Incorporated by Reference	Part III, Items 10‑14, is incorporated by reference from the Proxy Statement for the Annual Meeting of Shareholders which will be filed with the Securities and Exchange Commission not later than 120 days subsequent to December 31, 2019 . Certain exhibits previously filed with the Securities and Exchange Commission are incorporated by reference into Part IV of this report.
Entity Central Index Key	0001509991
Document Period End Date	Dec. 31, 2019
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Current assets:
Cash and cash equivalents	$ 224,502	$ 173,515
Restricted cash	4,302	4,527
Receivables:
Joint interest billings, net	81,424	64,572
Oil sales	64,142	48,164
Related party	0	5,580
Other	28,727	21,690
Inventories	114,412	84,827
Prepaid expenses and other	36,192	68,040
Derivatives	12,856	38,785
Total current assets	566,557	509,700
Property and equipment:
Oil and gas properties, net	3,624,751	3,444,864
Other property, net	17,581	14,837
Property and equipment, net	3,642,332	3,459,701
Other assets:
Equity method investment	0	51,896
Restricted cash	542	7,574
Long-term receivables	43,430	19,002
Deferred financing costs, net of accumulated amortization of $14,681 and $12,065 at December 31, 2019 and December 31, 2018, respectively	6,321	8,937
Deferred tax assets	32,779	14,004
Derivatives	2,302	14,312
Other	22,969	3,063
Total assets	4,317,232	4,088,189
Current liabilities:
Accounts payable	149,483	176,540
Accrued liabilities	380,704	195,596
Derivatives	8,914	12,172
Total current liabilities	539,101	384,308
Long-term liabilities:
Long-term debt, net	2,008,063	2,120,547
Derivatives	11,478	10,181
Asset retirement obligations	230,526	145,336
Deferred tax liabilities	653,221	477,179
Other long-term liabilities	33,141	9,160
Total long-term liabilities	2,936,429	2,762,403
Stockholders’ equity:
Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at December 31, 2019 and December 31, 2018	0	0
Common stock, $0.01 par value; 2,000,000,000 authorized shares; 445,779,367 and 442,914,675 issued at December 31, 2019 and December 31, 2018, respectively	4,458	4,429
Additional paid-in capital	2,297,221	2,341,249
Accumulated deficit	(1,222,970)	(1,167,193)
Treasury stock, at cost, 44,263,269 shares at December 31, 2019 and 2018, respectively	(237,007)	(237,007)
Total stockholders’ equity	841,702	941,478
Total liabilities and stockholders’ equity	$ 4,317,232	$ 4,088,189

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Statement of Financial Position [Abstract]
Deferred financing costs, accumulated amortization	$ 14,681	$ 12,065
Preference shares, par value (in dollars per share)	$ 0.01	$ 0.01
Preference shares, authorized shares	200,000,000	200,000,000
Preference shares, issued shares	0	0
Common shares, par value (in dollars per share)	$ 0.01	$ 0.01
Common shares, authorized shares	2,000,000,000	2,000,000,000
Common shares, issued shares	445,779,367	442,914,675
Treasury stock shares	44,263,269	44,263,269

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Revenues and other income:
Oil and gas revenue									$ 1,499,416	$ 886,666	$ 578,139
Gain on sale of assets									10,528	7,666	0
Other income, net									(35)	8,037	58,697
Total revenues and other income	$ 460,215	$ 356,970	$ 395,934	$ 296,790	$ 309,500	$ 250,219	$ 215,473	$ 127,177	1,509,909	902,369	636,836
Costs and expenses:
Oil and gas production									402,613	224,727	126,850
Facilities insurance modifications, net									(24,254)	6,955	(820)
Exploration expenses									180,955	301,492	216,050
General and administrative									110,010	99,856	68,302
Depletion, depreciation and amortization									563,861	329,835	255,203
Interest and other financing costs, net									155,074	101,176	77,595
Derivatives, net									71,885	(31,430)	59,968
(Gain) loss on equity method investments, net									0	(72,881)	6,252
Other expenses, net									24,648	(6,501)	5,291
Total costs and expenses	462,492	317,435	346,495	358,370	22,475	364,912	364,091	201,751	1,484,792	953,229	814,691
Income (loss) before income taxes									25,117	(50,860)	(177,855)
Income tax expense									80,894	43,131	44,937
Net income (loss)	$ (35,773)	$ 16,065	$ 16,837	$ (52,906)	$ 185,565	$ (126,057)	$ (103,273)	$ (50,226)	$ (55,777)	$ (93,991)	$ (222,792)
Net loss per share:
Basic (in dollars per share)	$ (0.09)	$ 0.04	$ 0.04	$ (0.13)	$ 0.44	$ (0.31)	$ (0.26)	$ (0.13)	$ (0.14)	$ (0.23)	$ (0.57)
Diluted (in dollars per share)	$ (0.09)	$ 0.04	$ 0.04	$ (0.13)	$ 0.43	$ (0.31)	$ (0.26)	$ (0.13)	$ (0.14)	$ (0.23)	$ (0.57)
Weighted average number of shares used to compute net loss per share:
Basic (in shares)									401,368	404,585	388,375
Diluted (in shares)									401,368	404,585	388,375
Dividends declared per common share (in dollars per share)										$ 0	$ 0

CONSOLIDATED STATEMENTS OF SHAR

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY - USD ($) shares in Thousands, $ in Thousands	Total	Common Stock	Additional Paid-in Capital	Accumulated Deficit	Treasury Stock
Balance (in shares) at Dec. 31, 2016		395,859
Balance at Dec. 31, 2016	$ 1,081,199	$ 3,959	$ 1,975,247	$ (850,410)	$ (47,597)
Increase (Decrease) in Shareholders' Equity
Equity-based compensation	40,899		40,899
Restricted stock awards and units (in shares)		2,740
Restricted stock awards and units	0	$ 27	(27)
Purchase of treasury stock / tax withholdings	(2,194)		(1,594)		(600)
Net loss	(222,792)			(222,792)
Balance (in shares) at Dec. 31, 2017		398,599
Balance at Dec. 31, 2017	897,112	$ 3,986	2,014,525	(1,073,202)	(48,197)
Increase (Decrease) in Shareholders' Equity
Acquisition of oil and gas properties (in shares)		34,994
Acquisition of oil and gas properties	307,944	$ 350	307,594
Equity-based compensation	36,464		36,464
Restricted stock awards and units (in shares)		9,322
Restricted stock awards and units	0	$ 93	(93)
Purchase of treasury stock / tax withholdings	(206,051)		(17,241)		(188,810)
Net loss	(93,991)			(93,991)
Balance (in shares) at Dec. 31, 2018		442,915
Balance at Dec. 31, 2018	941,478	$ 4,429	2,341,249	(1,167,193)	(237,007)
Increase (Decrease) in Shareholders' Equity
Dividends ($0.1808 per share)	(74,813)		(74,813)
Equity-based compensation	32,797		32,797
Restricted stock awards and units (in shares)		2,864
Restricted stock awards and units	0	$ 29	(29)
Purchase of treasury stock / tax withholdings	(1,983)		(1,983)
Net loss	(55,777)			(55,777)
Balance (in shares) at Dec. 31, 2019		445,779
Balance at Dec. 31, 2019	$ 841,702	$ 4,458	$ 2,297,221	$ (1,222,970)	$ (237,007)

CONSOLIDATED STATEMENTS OF SH_2

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (Parenthetical)	12 Months Ended
	Dec. 31, 2019$ / shares
Additional Paid-in Capital
Dividends declared per common stock (in dollars per share)	$ 0.1808

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Operating activities
Net loss	$ (55,777)	$ (93,991)	$ (222,792)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation and amortization (including deferred financing costs)	573,118	339,214	265,407
Deferred income taxes	(90,370)	9,145	9,505
Unsuccessful well costs and leasehold impairments	87,813	123,199	43,201
Change in fair value of derivatives	67,436	(29,960)	71,822
Cash settlements on derivatives, net (including $(36.3) million and $(137.1) million and $38.7 million on commodity hedges during 2019, 2018, and 2017)	(31,458)	(137,942)	25,888
Equity-based compensation	32,370	35,230	39,913
Gain on sale of assets	(10,528)	(7,666)	0
Loss on extinguishment of debt	24,794	4,324	0
Distributions in excess of equity in earnings / (Undistributed equity in earnings)	0	(45)	6,252
Other	9,069	2,865	5,952
Changes in assets and liabilities:
(Increase) decrease in receivables	(29,735)	175,954	29,365
(Increase) decrease in inventories	(28,970)	8,848	1,653
(Increase) decrease in prepaid expenses and other	34,586	(18,731)	(31,710)
Increase (decrease) in accounts payable	(83,921)	7,440	(94,434)
Increase (decrease) in accrued liabilities	129,723	(157,393)	86,595
Net cash provided by (used in) operating activities	628,150	260,491	236,617
Investing activities
Oil and gas assets	(340,217)	(213,806)	(140,495)
Other property	(11,796)	(7,935)	(2,858)
Acquisition of oil and gas properties, net of cash acquired	0	(961,764)	0
Equity method investment	0	0	(231,280)
Return of investment from KTIPI	0	184,664	0
Proceeds on sale of assets	15,000	13,703	222,068
Notes receivable from partners	(26,918)	0	0
Net cash provided by (used in) investing activities	(363,931)	(985,138)	(152,565)
Financing activities
Borrowings under long-term debt	175,000	1,175,000	200,000
Payments on long-term debt	(425,000)	(325,000)	(250,000)
Net proceeds from issuance of senior notes	641,875	0	0
Redemption of senior secured notes	(535,338)	0	0
Purchase of treasury stock / tax withholdings	(1,983)	(206,051)	(2,194)
Dividends	(72,599)	0	0
Deferred financing costs	(2,444)	(38,672)	(67)
Net cash provided by (used in) financing activities	(220,489)	605,277	(52,261)
Net increase (decrease) in cash, cash equivalents and restricted cash	43,730	(119,370)	31,791
Cash, cash equivalents and restricted cash at beginning of period	229,346	185,616	304,986
Cash, cash equivalents and restricted cash at end of period	185,616	304,986	273,195
Cash paid for:
Interest, net of capitalized interest	99,928	83,831	55,381
Income taxes	43,909	45,984	48,815
Non-cash activity:
Contribution to equity method investment	0	0	133,893
Dissolution of equity method investment	0	0	(122,407)
Common stock issued for acquisition of oil and gas properties	$ 0	$ 307,944	$ 0

CONSOLIDATED STATEMENTS OF CA_2

CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Statement of Cash Flows [Abstract]
Cash settlements on commodity hedges derivatives	$ (36.3)	$ (137.1)	$ 38.7

Organization

Organization	12 Months Ended
Organization	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization	Organization Kosmos Energy Ltd. changed its jurisdiction of incorporation from Bermuda to the State of Delaware (the "Redomestication") in December 2018. All outstanding common shares of Kosmos Energy Ltd., an exempted company incorporated pursuant to the laws of Bermuda, were automatically converted by operation of law, on a one-for-one basis, into shares of common stock of Kosmos Energy Ltd., a company incorporated pursuant to the laws of Delaware. The number of shares of the Company’s common stock outstanding immediately after the Redomestication was the same as the number of common shares of Kosmos Energy Ltd. outstanding immediately prior to the Redomestication. Kosmos Energy Ltd. was originally incorporated pursuant to the laws of Bermuda in January 2011 to become a holding company for Kosmos Energy Holdings. As part of the Redomestication, we transferred all of our equity interests in Kosmos Energy Holdings to a new, wholly-owned subsidiary, Kosmos Energy Delaware Holdings, LLC, a Delaware limited liability company. As a holding company, Kosmos Energy Ltd.’s management operations are conducted through a wholly-owned subsidiary, Kosmos Energy, LLC. The terms “Kosmos,” the “Company,” “we,” “us,” “our,” “ours,” and similar terms refer to Kosmos Energy Ltd. and its wholly-owned subsidiaries, unless the context indicates otherwise. Kosmos is a full-cycle deepwater independent oil and gas exploration and production company focused along the Atlantic Margins. Our key assets include production offshore Ghana, Equatorial Guinea and U.S. Gulf of Mexico, as well as a world-class gas development offshore Mauritania and Senegal. We also maintain a sustainable exploration program balanced between proven basin infrastructure-led exploration (Equatorial Guinea and U.S. Gulf of Mexico), emerging basins (Mauritania, Senegal and Suriname) and frontier basins (Cote d'Ivoire, Namibia, Sao Tome and Principe, and South Africa). Kosmos is listed on the NYSE and LSE and is traded under the ticker symbol KOS. Kosmos is engaged in a single line of business, which is the exploration and production of oil and natural gas. We have operations in four

Accounting Policies

Accounting Policies	12 Months Ended
Accounting Policies	Dec. 31, 2019
Accounting Policies [Abstract]
Accounting Policies	Accounting Policies Principles of Consolidation The accompanying consolidated financial statements include the accounts of Kosmos Energy Ltd. and its wholly-owned subsidiaries. They also include the Company’s share of the undivided interest in certain assets, liabilities, revenues and expenses. Investments in corporate joint ventures, which we exercise significant influence over, are accounted for using the equity method of accounting. All intercompany transactions have been eliminated. Investments in companies that are partially owned by the Company are integral to the Company’s operations. The other parties, who also have an equity interest in these companies, are independent third parties that share in the business results according to their ownership. Kosmos does not invest in these companies in order to remove liabilities from its balance sheet. Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosures of contingent assets and liabilities. Actual results could differ from these estimates. Reclassifications Certain prior period amounts have been reclassified to conform with the current year presentation. Such reclassifications had no material impact on our reported net income (loss), current assets, total assets, current liabilities, total liabilities, shareholders’ equity or cash flows, except as disclosed related to the adoption of recent accounting pronouncements. Cash, Cash Equivalents and Restricted Cash December 31, 2019 2018 2017 (In thousands) Cash and cash equivalents $ 224,502 $ 173,515 $ 233,412 Restricted cash - current 4,302 4,527 56,380 Restricted cash - long-term 542 7,574 15,194 Total cash, cash equivalents and restricted cash shown in the consolidated statements of cash flows $ 229,346 $ 185,616 $ 304,986 Cash and cash equivalents includes demand deposits and funds invested in highly liquid instruments with original maturities of three months or less at the date of purchase. In accordance with certain of our petroleum contracts, we have posted letters of credit related to performance guarantees for our minimum work obligations. Certain of these letters of credit are cash collateralized in accounts held by us and as such are classified as restricted cash. Upon completion of the minimum work obligations and/or entering into the next phase of the petroleum contract, the requirement to post the existing letters of credit will be satisfied and the cash collateral will be released. However, additional letters of credit may be required should we choose to move into the next phase of certain of our petroleum contracts. As of December 31, 2019 and 2018 , we had $4.3 million and $4.5 million , respectively, of current restricted cash and $0.3 million and $7.4 million , respectively, of long‑term restricted cash used to cash collateralize performance guarantees related to our petroleum contracts. As of December 31, 2019 and 2018, we also had $0.2 million in other long-term restricted cash. Receivables Our receivables consist of joint interest billings, oil and gas sales, related party and other receivables. For our oil sales receivable in Ghana, we require a letter of credit to be posted to secure the outstanding receivable. Receivables from joint interest owners are stated at amounts due, net of any allowances for doubtful accounts. We determine our allowance by considering the length of time past due, future net revenues of the debtor’s ownership interest in oil and natural gas properties we operate, and the owner’s ability to pay its obligation, among other things. We had an allowance for doubtful accounts of $2.7 million and $1.2 million in current joint interest billings receivables as of December 31, 2019 and 2018 , respectively. Inventories Inventories consisted of $112.3 million and $83.4 million (including $22.1 million acquired through the DGE acquisition) of materials and supplies and $2.1 million and $1.4 million of hydrocarbons as of December 31, 2019 and 2018 , respectively. The Company’s materials and supplies inventory primarily consists of casing and wellheads and is stated at the lower of cost, using the weighted average cost method, or net realizable value. We recorded write downs of $4.6 million , $0.3 million and $0.9 million during the years ended December 31, 2019 , 2018 and 2017 for materials and supplies inventories as other expenses, net in the consolidated statements of operations and other in the consolidated statements of cash flows. Hydrocarbon inventory is carried at the lower of cost, using the weighted average cost method, or net realizable value. Hydrocarbon inventory costs include expenditures and other charges incurred in bringing the inventory to its existing condition. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory costs. Leases (Policy applicable beginning January 1, 2019) In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842).” ASU 2016-02 was issued to increase transparency and comparability across organizations by recognizing substantially all leases on the balance sheet through the concept of right-of-use lease assets and liabilities. Under prior accounting guidance, lessees did not recognize lease assets or liabilities for leases classified as operating leases. The ASU was effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years with early adoption permitted. In July 2018, the FASB issued ASU 2018-11, which added a transition option permitting entities to apply the provisions of the new standard at its adoption date instead of the earliest comparative period presented in the consolidated financial statements. Under this transition option, comparative reporting would not be required, and the provisions of the standard would be applied prospectively to leases in effect at the date of adoption. The Company adopted the guidance prospectively during the first quarter of 2019. As part of our adoption, we elected not to reassess historical lease classification, recognize short-term leases on our balance sheet, nor separate lease and non-lease components for our real estate leases. The adoption and implementation of this ASU resulted in a $21.7 million increase in assets and liabilities related to our leasing activities, which primarily consists of office leases. Our adoption of ASU 2016-02 did not impact retained earnings or other components of equity as of December 31, 2018. We account for leases in accordance with ASC Topic 842, Leases, (“ASC 842”). We determine if an arrangement is a lease at contract inception. A lease exists when a contract conveys to the customer the right to control the use of identified property, plant, or equipment for a period of time in exchange for consideration. The definition of a lease embodies two conditions: (1) there is an identified asset in the contract that is land or a depreciable asset (i.e., property, plant, and equipment), and (2) the customer has the right to control the use of the identified asset. In the normal course of business, the Company enters into various lease agreements for real estate and equipment related to its exploration, development and production activities that are currently accounted for as operating leases. Operating leases are included in Other assets, Accrued liabilities, and Other long-term liabilities on our consolidated balance sheets. The lease liabilities are initially and subsequently measured at the present value of the unpaid lease payments at the lease commencement date. Key estimates and judgments include how we determined: (1) the discount rate we use to discount the unpaid lease payments to present value; (2) lease term; and (3) lease payments. 1. ASC 842 requires a lessee to discount its unpaid lease payments using the interest rate implicit in the lease or, if that rate cannot be readily determined, its incremental borrowing rate. As most of our leases where we are the lessee do not provide an implicit rate, we use our incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. Our incremental borrowing rate for a lease is the rate of interest we would have to pay on a collateralized basis to borrow an amount equal to the lease payments under similar terms. 2. The lease term for all of our leases includes the non-cancellable period of the lease plus any additional periods covered by either an option to extend (or not to terminate) the lease that we are reasonably certain to exercise, or an option to extend (or not to terminate) the lease controlled by the lessor. 3. Lease payments included in the measurement of the lease asset or liability comprise the following: fixed payments (including in-substance fixed payments), variable payments that depend on index or rate, and the exercise price of a lessee option to purchase the underlying asset if we are reasonably certain to exercise. Amounts expected to be payable under residual value guarantee are also lease payments included in the measurement of the lease liability. The Right-of-use ("ROU") asset is initially measured at cost, which comprises the initial amount of the lease liability adjusted for lease payments made at or before the lease commencement date, plus any initial direct costs incurred less any lease incentives received. For operating leases, the ROU asset is subsequently measured throughout the lease term at the carrying amount of the lease liability, plus initial direct costs, plus (minus) any prepaid (accrued) lease payments, less the unamortized balance of lease incentives received. Lease expense for lease payments is recognized on a straight-line basis over the lease term. We monitor for events or changes in circumstances that require a reassessment of a lease. When a reassessment results in the re-measurement of a lease liability, a corresponding adjustment is made to the carrying amount of the corresponding ROU asset unless doing so would reduce the carrying amount of the ROU asset to an amount less than zero. In that case, the amount of the adjustment that would result in a negative ROU asset balance is recorded in profit or loss. We have lease agreements which include lease and non-lease components. We have elected to combine lease and non-lease components for all lease contracts. We have elected not to recognize ROU assets and lease liabilities for all short-term leases that have a lease term of 12 months or less. We recognize the lease payments associated with our short-term leases as an expense on a straight-line basis over the lease term. We adopted ASU 2016-02 using a modified retrospective transition approach as of the effective date as permitted by the amendments in ASU 2018-11, which provides an alternative modified retrospective transition method. As a result, we were not required to adjust our comparative period financial information for effects of the standard or make the new required lease disclosures for periods before the date of adoption (i.e. January 1, 2019). We have elected to adopt the package of transition practical expedients and, therefore, have not reassessed (1) whether existing or expired contracts contain a lease, (2) lease classification for existing or expired leases or (3) the accounting for initial direct costs that were previously capitalized. We did not elect the practical expedient to use hindsight for leases existing at the adoption date. Exploration and Development Costs The Company follows the successful efforts method of accounting for its oil and gas properties. Acquisition costs for proved and unproved properties are capitalized when incurred. Costs of unproved properties are transferred to proved properties when a determination that proved reserves have been found. Exploration costs, including geological and geophysical costs and costs of carrying unproved properties, are expensed as incurred. Exploratory drilling costs are capitalized when incurred. If exploratory wells are determined to be commercially unsuccessful or dry holes, the applicable costs are expensed and recorded in exploration expense on the consolidated statement of operations. Costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized. Costs incurred to operate and maintain wells and equipment and to lift oil and natural gas to the surface are expensed as oil and gas production expense. The Company evaluates unproved property periodically for impairment. The impairment assessment considers results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of such projects. If it is determined that future appraisal drilling or development activities are unlikely to occur, the associated capitalized costs are recorded as exploration expense in the consolidated statement of operations. Depletion, Depreciation and Amortization Proved properties and support equipment and facilities are depleted using the unit‑of‑production method based on estimated proved oil and natural gas reserves. Capitalized exploratory drilling costs that result in a discovery of proved reserves and development costs are depleted using the unit‑of‑production method based on estimated proved developed oil and natural gas reserves for the related field. Depreciation and amortization of other property is computed using the straight-line method over the assets’ estimated useful lives (not to exceed the lease term for leasehold improvements), ranging from one to eight years . Years Depreciated Leasehold improvements 1 to 8 Office furniture, fixtures and computer equipment 3 to 7 Vehicles 5 Amortization of deferred financing costs is computed using the straight‑line method over the life of the related debt. Capitalized Interest Interest costs from external borrowings are capitalized on major projects with an expected construction period of one year or longer. Capitalized interest is added to the cost of the underlying asset and is depleted on the unit‑of‑production method in the same manner as the underlying assets. Asset Retirement Obligations The Company accounts for asset retirement obligations as required by ASC 410—Asset Retirement and Environmental Obligations. Under these standards, the fair value of a liability for an asset retirement obligation is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. If a reasonable estimate of fair value cannot be made in the period the asset retirement obligation is incurred, the liability is recognized when a reasonable estimate of fair value can be made. If a tangible long‑lived asset with an existing asset retirement obligation is acquired, a liability for that obligation is recognized at the asset’s acquisition or in service date. In addition, a liability for the fair value of a conditional asset retirement obligation is recorded if the fair value of the liability can be reasonably estimated. We capitalize the asset retirement costs by increasing the carrying amount of the related long‑lived asset by the same amount as the liability. We record increases in the discounted abandonment liability resulting from the passage of time in depletion, depreciation and amortization in the consolidated statement of operations. Impairment of Long‑lived Assets The Company reviews its long‑lived assets for impairment when changes in circumstances indicate that the carrying amount of an asset may not be recoverable. ASC 360—Property, Plant and Equipment requires an impairment loss to be recognized if the carrying amount of a long‑lived asset is not recoverable and exceeds its fair value. The carrying amount of a long‑lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. That assessment shall be based on the carrying amount of the asset at the date it is tested for recoverability, whether in use or under development. An impairment loss shall be measured as the amount by which the carrying amount of a long‑lived asset exceeds its fair value. Assets to be disposed of and assets not expected to provide any future service potential to the Company are recorded at the lower of carrying amount or fair value less cost to sell. We believe the assumptions used in our undiscounted cash flow analysis to test for impairment indicators are appropriate and result in a reasonable estimate of future cash flows. The undiscounted cash flows from the analysis exceeded the carrying amount of our long-lived assets. The most significant assumptions are the pricing and production estimates used in undiscounted cash flow analysis. Where unproved reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the evaluation. In order to evaluate the sensitivity of the assumptions, we assumed a hypothetical reduction in our production profile which still showed no impairment. If we experience declines in oil pricing, increases in our estimated future expenditures or a decrease in our estimated production profile our long-lived assets could be at risk for impairment. Derivative Instruments and Hedging Activities We utilize oil derivative contracts to mitigate our exposure to commodity price risk associated with our anticipated future oil production. These derivative contracts consist of collars, put options, call options and swaps. We also have used interest rate derivative contracts to mitigate our exposure to interest rate fluctuations related to our long‑term debt. Our derivative financial instruments are recorded on the balance sheet as either assets or liabilities and are measured at fair value. We do not apply hedge accounting to our derivative contracts. See Note 9—Derivative Financial Instruments. Estimates of Proved Oil and Natural Gas Reserves Reserve quantities and the related estimates of future net cash flows affect our periodic calculations of depletion and assessment of impairment of our oil and natural gas properties. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. As additional proved reserves are discovered, reserve quantities and future cash flows will be estimated by independent petroleum consultants and prepared in accordance with guidelines established by the Securities and Exchange Commission (“SEC”) and the Financial Accounting Standards Board (“FASB”). The accuracy of these reserve estimates is a function of: • the engineering and geological interpretation of available data; • estimates of the amount and timing of future operating cost, production taxes, development cost and workover cost; • the accuracy of various mandated economic assumptions; and • the judgments of the persons preparing the estimates. Revenue Recognition We recognize revenues on the volumes sold of hydrocarbons sold to a purchaser. The volumes sold may be more or less than the volumes to which we are entitled based on our ownership interest in the property. These differences result in a condition known in the industry as a production imbalance. A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves on such property. As of December 31, 2019 and 2018 , we had no oil and gas imbalances recorded in our consolidated financial statements. Our oil and gas revenues are recognized when hydrocarbons have been sold to a purchaser at a fixed or determinable price, title has transferred and collection is probable. Certain revenues are based on provisional price contracts which contain an embedded derivative that is required to be separated from the host contract for accounting purposes. The host contract is the receivable from oil sales at the spot price on the date of sale. The embedded derivative, which is not designated as a hedge, is marked to market through oil and gas revenue each period until the final settlement occurs, which generally is limited to the month after the sale. Oil and gas revenue is composed of the following: Years Ended December 31, 2019 2018 2017 Revenues from contract with customer - Equatorial Guinea $ 297,831 $ — $ — Revenues from contract with customer - Ghana 740,464 741,033 590,642 Revenues from contract with customers - U.S. Gulf of Mexico 459,960 147,596 — Provisional oil sales contracts 1,161 (1,963 ) (12,503 ) Oil and gas revenue $ 1,499,416 $ 886,666 $ 578,139 Equity‑based Compensation For equity‑based compensation awards, compensation expense is recognized in the Company’s financial statements over the awards’ vesting periods based on their grant date fair value. The Company utilizes (i) the closing stock price on the date of grant to determine the fair value of service vesting restricted stock awards and restricted stock units and (ii) a Monte Carlo simulation to determine the fair value of restricted stock awards and restricted stock units with a combination of market and service vesting criteria. Forfeitures are recognized in the period in which they occur. Restructuring Charges The Company accounts for restructuring charges and related termination benefits in accordance with ASC 712-Compensation-Nonretirement Postemployment Benefits. Under these standards, the costs associated with termination benefits are recorded during the period in which the liability is incurred. During the year ended December 31, 2019, we recognized $11.5 million in restructuring charges for employee severance and related benefit costs incurred as part of a corporate reorganization in Other expenses, net in the consolidated statement of operations. Treasury Stock We record treasury stock purchases at cost. Our treasury stock purchases are from our employees that surrendered shares to the Company to satisfy their statutory tax withholding requirements and are not part of a formal stock repurchase plan. In November 2018, Kosmos repurchased 35 million shares of our common stock from funds affiliated with Warburg Pincus LLC in a privately negotiated transaction at a price per share of $5.38 . The total aggregate purchase price for the share repurchase was approximately $188 million . The remainder of our treasury stock is forfeited restricted stock awards granted under our long‑term incentive plan. Income Taxes The Company accounts for income taxes as required by ASC 740—Income Taxes. Under this method, deferred income taxes are determined based on the difference between the financial statement and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts expected to be realized. On a quarterly basis, management evaluates the need for and adequacy of valuation allowances based on the expected realizability of the deferred tax assets and adjusts the amount of such allowances, if necessary. We recognize tax benefits from uncertain tax positions only if it is more likely than not that the tax position will be sustained upon examination by the tax authorities, based on the technical merits of the position. Accordingly, we measure tax benefits from such positions based on the most likely outcome to be realized. Foreign Currency Translation The U.S. dollar is the functional currency for all of the Company’s material foreign operations. Foreign currency transaction gains and losses and adjustments resulting from translating monetary assets and liabilities denominated in foreign currencies are included in other expenses. Cash balances held in foreign currencies are not significant, and as such, the effect of exchange rate changes is not material to any reporting period. Concentration of Credit Risk Our revenue can be materially affected by current economic conditions and the price of oil. However, based on the current demand for crude oil and the fact that alternative purchasers are readily available, we believe that the loss of our marketing agent and/or any of the purchasers identified by our marketing agent would not have a long‑term material adverse effect on our financial position or results of international operations. For our U.S. Gulf of Mexico operations, crude oil and natural gas are transported to customers using third-party pipelines. For the years ended December 31, 2019 and 2018 , revenue from Phillips 66 Company made up approximately 20% and 11% , respectively, of our total consolidated revenue and was included in our U.S. Gulf of Mexico segment. Recent Accounting Standards Recently Adopted In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842).” ASU 2016-02 was issued to increase transparency and comparability across organizations by recognizing substantially all leases on the balance sheet through the concept of right-of-use lease assets and liabilities. Under current accounting guidance, lessees do not recognize lease assets or liabilities for leases classified as operating leases. The ASU is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years with early adoption permitted. In July 2018, the FASB issued ASU 2018-11, which added a transition option permitting entities to apply the provisions of the new standard at its adoption date instead of the earliest comparative period presented in the consolidated financial statements. Under this transition option, comparative reporting would not be required, and the provisions of the standard would be applied prospectively to leases in effect at the date of adoption. The Company adopted the guidance prospectively during the first quarter of 2019. As part of our adoption, we elected not to reassess historical lease classification, recognize short-term leases on our balance sheet, nor separate lease and non-lease components for our real estate leases. The adoption and implementation of this ASU resulted in a $21.7 million increase in assets and liabilities related to our leasing activities which primarily consists of office leases. Our adoption of ASU 2016-02 did not impact retained earnings or other components of equity as of December 31, 2018. Not Yet Adopted In June 2016, ASU 2016-13, "Measurement of Credit Losses on Financial Instruments," was issued requiring measurement of all expected credit losses for certain types of financial instruments, including trade receivables, held at the reporting date based on historical experience, current conditions and reasonable and supportable forecasts. This standard is effective January 1, 2020, and we do not expect it to have a significant impact on our consolidated financial statements.

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
Acquisitions and Divestitures	Dec. 31, 2019
Business Combinations [Abstract]
Acquisitions and Divestitures	Acquisitions and Divestitures 2019 Transactions During the first quarter of 2019, we entered into a petroleum contract covering offshore Marine XXI block with the Republic of the Congo, subject to governmental approvals. Upon approval, we will hold an 85% participating interest and be the operator. The Congolese national oil company, SNPC, has a 15% carried interest during the exploration period. Should a commercial discovery be made, SNPC's 15% carried interest will convert to a participating interest of at least 15% . The petroleum contract covers approximately 2,350 square kilometers, with a first exploration period of four years and includes a work program to acquire and interpret 2,200 square kilometers of 3D seismic. There are two optional exploration phases, each for a period of three years , which are subject to additional work program commitments. In March 2019, we completed an agreement with a subsidiary of Ophir Energy plc ("Ophir") to acquire the remaining interest in Block EG-24, offshore Equatorial Guinea, which increased our participating interest to 80% and named Kosmos as operator. The Equatorial Guinean national oil company, GEPetrol, has a 20% carried interest during the exploration period. Should a commercial discovery be made, GEPetrol's 20% carried interest will convert to a 20% participating interest. In September 2019, we completed a farm-in agreement with OK Energy to acquire a 45% non-operated interest in the Northern Cape Ultra Deep block offshore the Republic of South Africa. The petroleum contract covers approximately 6,930 square kilometers at water depths ranging from 2,500 to 3,100 meters and has an initial exploration phase of two years . In November 2019, we completed a farm-out agreement with Shell Sao Tome and Principe B.V. to farm-out a 20% participating interest in Block 6 and a 30% participating interest in Block 11, offshore Sao Tome and Principe, resulting in our participating interests in Blocks 6 and 11 being 25% and 35% , respectively. During the year ended December 31, 2019, we recognized a $10.5 million gain related to the farm-out of Blocks 6 and 11 offshore Sao Tome and Principe. 2018 Transactions In March 2018, as part of our alliance with BP, we entered into petroleum contracts covering Blocks 10 and 13 with the Democratic Republic of Sao Tome and Principe. We presently have a 35% participating interest in the blocks and the operator, BP, holds a 50% participating interest. The national petroleum agency, Agencia Nacional Do Petroleo De Sao Tome E Principe ("ANP-STP") has a 15% carried interest in the blocks through exploration. The petroleum contracts cover approximately 13,600 square kilometers, with a first exploration period of four years from the effective date (March 2018). The exploration periods can be extended an additional four years at our election subject to fulfilling specific work obligations. The first exploration period work programs include a 13,500 square kilometer 3D seismic acquisition requirement across the two blocks. In June 2018, we completed a farm-in agreement with a subsidiary of Ophir for Block EG-24, offshore Equatorial Guinea, whereby we acquired our initial non-operated participating interest of 40% . As part of the agreement, we reimbursed a portion of Ophir's previously incurred exploration costs and agreed to carry Ophir's share of the costs. The petroleum contract covers approximately 3,500 square kilometers, with a first exploration period of three years from the effective date (March 2018) which can be extended up to four additional years at our election subject to fulfilling specific work obligations. The first exploration period work program includes a 3,000 square kilometer 3D seismic acquisition requirement which was completed in November 2018. The Equatorial Guinean national oil company, GEPetrol, has a 20% carried interest during the exploration period. Should a commercial discovery be made, GEPetrol's 20% carried interest will convert to a 20% participating interest. In September 2018, we completed the acquisition of DGE, a deepwater company operating in the U.S. Gulf of Mexico, from First Reserve Corporation and other shareholders for a total consideration of $1.275 billion , comprised of $952.6 million in cash, $307.9 million in Kosmos common stock and $14.9 million of transaction related costs. We funded the cash portion of the purchase price using cash on hand and drawings under our existing credit facilities. We also received $200.0 million of additional firm commitments under the Facility, which provided further liquidity to the Company. The DGE acquisition was accounted for under the asset acquisition method and the purchase price allocation is shown below. The purchase price allocation was based on the estimated relative fair value of identifiable assets acquired and liabilities assumed. The estimated fair value measurements of oil and gas assets acquired and asset retirement obligations liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair value of oil and gas properties and asset retirement obligations were measured using the discounted cash flow technique of valuation. Significant inputs to the valuation of oil and gas properties include estimates of: (i) reserves, (ii) future operating and development costs, (iii) future commodity prices, (iv) future plugging and abandonment costs, (v) estimated future cash flows, and (vi) a market-based weighted average cost of capital rate. Purchase Price Allocation (in thousands) Fair value of assets acquired: Proved oil and gas properties $ 1,037,511 Unproved oil and gas properties 298,159 Accounts receivable and other 180,989 Total assets acquired $ 1,516,659 Fair value of liabilities assumed: Accrued liabilities and other $ 126,530 Asset retirement obligations 74,482 Derivative liabilities 40,265 Total liabilities assumed $ 241,277 Purchase price: Cash consideration paid $ 952,586 Fair value of common stock(1) 307,944 Transaction related costs 14,852 Total purchase price $ 1,275,382 ______________________________________ (1) Based on 34,993,585 shares of common stock issued at a price of $8.80 per share, which was the opening Kosmos common stock price on September 14, 2018, the closing date of the acquisition. As a result of the DGE acquisition, we included $147.6 million of revenues and $30.5 million of direct operating expenses in our consolidated statements of operations for the period from September 14, 2018 to December 31, 2018. In October 2018, Kosmos entered into a strategic exploration alliance with Shell Exploration Company B.V. (“Shell”) to jointly explore in Southern West Africa. Initially the alliance will focus on Namibia where Kosmos has completed a farm-in to Shell's acreage in PEL 39, and Sao Tome and Principe where we have entered into exclusive negotiations for Shell to take an interest in Kosmos’ acreage in Blocks 5, 6, 11, and 12. As part of the alliance, our two companies intend to jointly evaluate opportunities in adjacent geographies. This alliance is consistent with Kosmos’ strategy of partnering with supermajors to leverage complementary skill sets. Shell has deep expertise in carbonate plays, while Kosmos brings significant knowledge of the Cretaceous in West Africa. Furthermore, by working with Shell, Kosmos has a partner with the expertise to efficiently move exploration successes through the development stage. 2017 Transactions In December 2016, we announced transactions with affiliates of BP in Mauritania and Senegal following a competitive farm-out process for our interests in our blocks offshore Mauritania and Senegal. The Mauritania and Senegal transactions closed in January 2017 and February 2017, respectively. In Mauritania, BP acquired a 62% participating interest in our four Mauritania licenses (C6, C8, C12 and C13). In Senegal, BP acquired a 49.99% interest in KBSL, our majority owned affiliate company which held a 60% participating interest in the Cayar Offshore Profond and Saint Louis Offshore Profond blocks (the "Senegal Blocks") offshore Senegal. Previously we indicated that KBSL would hold a 65% participating interest upon the completion of our exercise in December 2016 of an option to increase our equity in each contract area by 5% in exchange for carrying Timis Corporation Limited’s (“Timis”) paying interest share of a third well in either contract area, subject to a maximum gross well cost of $120.0 million . However, we agreed to withdraw the exercise of this call option upon completion of an agreement between BP and Timis by which BP acquired Timis’ entire 30% participating interest in the Senegal Blocks. The transaction between BP and Timis was completed and KBSL’s participating interest in these blocks remained at 60% . In consideration for these transactions, Kosmos received $162 million in cash up front during the first quarter of 2017 and will receive $228 million exploration and appraisal carry (increased from $221 million upon completion of the transfer of a 30% working interest to BP Senegal Investments Limited), up to $533 million in a development carry and variable consideration up to $2 per barrel for up to 1 billion barrels of liquids, structured as a production royalty, subject to future liquids discovery and prevailing oil prices. The effective date of these transactions was July 1, 2016, with BP paying interim costs from the effective date to the closing dates. We reduced our unproved property balance by $221.9 million for the consideration received as a result of these transactions including the upfront cash and interim costs from the transaction date to the effective date. See Note 7—Equity Method Investments for further discussion of our investment in KBSL. In November 2015, we entered into a line of credit agreement with Timis, whereby Timis had the right to draw up to $30.0 million on the line of credit to offset its joint interest billings arising from costs under the Senegal Blocks petroleum agreements. The line of credit agreement was terminated in April 2017 when Timis entered into an agreement with BP to acquire Timis' 30% participating interest in the Senegal Blocks. As a result of the termination of this credit agreement, Kosmos received $16 million in August 2017 representing payment in full of outstanding amounts drawn on the line of credit. In September 2017, we closed a farm-in agreement with Tullow Mauritania Limited, a subsidiary of Tullow Oil plc (“Tullow”), to acquire a 15% non-operated participating interest in Block C18 offshore Mauritania. Based on the terms of the agreement, we reimbursed Tullow a portion of past and interim period costs and will partially carry future costs. In the fourth quarter of 2017, through a joint venture with an affiliate of Trident Energy ("Trident"), we acquired all of the equity interest of Hess International Petroleum Inc., a subsidiary of Hess Corporation ("Hess"), which holds an 85% paying interest ( 80.75% revenue interest) in the Ceiba Field and Okume Complex assets. Under the terms of the agreement, Kosmos and Trident each own 50% of Hess International Petroleum Inc. Hess International Petroleum Inc. was subsequently renamed Kosmos-Trident International Petroleum Inc. ("KTIPI"). Kosmos is primarily responsible for exploration and subsurface evaluation while Trident is primarily responsible for production operations and optimization. The gross acquisition price was $650 million effective as of January 1, 2017. After post closing entries Kosmos paid net cash of approximately $231 million , with a combination of cash on hand and availability under the Facility. The transaction was accounted for as an equity method investment. See Note 7—Equity Method Investments for further discussion of our investment in KTIPI. In October 2017, we entered into petroleum contracts covering Blocks EG-21, S, and W with the Republic of Equatorial Guinea. We had an 80% participating interest and were the operator in all three blocks. In August 2018, we closed a farm-out agreement with Trident, whereby they acquired a 40% participating interest in blocks EG-21, S, and W, resulting in a $7.7 million gain. After giving effect to the farm-out agreement, we hold a 40% participating interest and remain the operator in all three blocks. The Equatorial Guinean national oil company, Guinea Equatorial De Petroleos ("GEPetrol"), has a 20% carried participating interest during the exploration period. Should a commercial discovery be made, GEPetrol's 20% carried interest will convert to a 20% participating interest. The petroleum contracts cover approximately 6,000 square kilometers, with a first exploration period of five years from the effective date (March 2018). The first exploration period consists of two sub-periods of three and two years , respectively. The first exploration sub-period work program includes a 6,000 square kilometer 3D seismic acquisition requirement across the three blocks. In December 2017, as part of our Alliance with BP, we entered into petroleum contracts covering Blocks CI-526, CI-602, CI-603, CI-707 and CI-708 with the Government of Cote d'Ivoire. We have a 45% participating interest and are the operator in all five blocks. BP has a 45% participating interest in the blocks and the Cote d'Ivoire national oil company, PETROCI Holding ("PETROCI"), currently has a 10% carried interest. The petroleum contracts cover approximately 17,000 square kilometers, with a first exploration period of three years . The first exploration period work program includes a 12,000 square kilometer 3D seismic acquisition across the five blocks.

Joint Interest Billings and Rel

Joint Interest Billings and Related Party Receivables	12 Months Ended
Joint Interest Billings and Related Party Receivables	Dec. 31, 2019
Joint Interest Billings
Joint Interest Billings and Related Party Receivables	Joint Interest Billings, Related Party Receivables and Notes Receivables Joint Interest Billings The Company’s joint interest billings consist of receivables from partners with interests in common oil and gas properties operated by the Company for shared costs. Joint interest billings are classified on the face of the consolidated balance sheets as current and long-term receivables based on when collection is expected to occur. In Ghana, the contractor group funded GNPC’s 5% share of the Tweneboa, Enyenra and Ntomme (“TEN”) development costs. The block partners are being reimbursed for such costs plus interest out of a portion of GNPC’s TEN production revenues. As of December 31, 2019 and 2018 , the current portion of the joint interest billing receivables due from GNPC for the TEN fields development costs were $14.0 million and $14.0 million , respectively, and the long-term portion were $16.0 million and $14.0 million . Related Party Receivables The Company's related party receivables consists primarily of receivables from Trident who, until January 2019, we shared a 50% interest in KTIPI. As of December 31, 2019 and 2018 the balance due from Trident consists of zero and $5.6 million related to joint interest billings for the exploration blocks and Kosmos' support of KTIPI operations. Subsequent to the unwind of KTIPI, Trident is no longer considered a related party. Notes Receivables In February 2019, Kosmos and BP signed Carry Advance Agreements with the national oil companies of Mauritania and Senegal which obligate us separately to finance the respective national oil company’s share of certain development costs incurred through first gas production for Greater Tortue Ahmeyim Phase 1, currently projected in 2022. Kosmos’ share for the two agreements combined is up to $239.7 million , which is to be repaid with interest through the national oil companies’ share of future revenues. As of December 31, 2019 , the balance due from the national oil companies was $27.4 million , which is classified as Long-term receivables in our consolidated balance sheets.

Property and Equipment

Property and Equipment	12 Months Ended
Property and Equipment	Dec. 31, 2019
Property, Plant and Equipment [Abstract]
Property and Equipment	Property and Equipment Property and equipment is stated at cost and consisted of the following: December 31, 2019 2018 (In thousands) Oil and gas properties: Proved properties $ 4,904,648 $ 4,236,489 Unproved properties 814,065 759,472 Total oil and gas properties 5,718,713 4,995,961 Accumulated depletion (2,093,962 ) (1,551,097 ) Oil and gas properties, net 3,624,751 3,444,864 Other property 61,598 51,987 Accumulated depreciation (44,017 ) (37,150 ) Other property, net 17,581 14,837 Property and equipment, net $ 3,642,332 $ 3,459,701 We recorded depletion expense of $542.9 million , $316.3 million and $244.9 million and depreciation expense of $6.9 million , $4.6 million and $3.4 million for the years ended December 31, 2019 , 2018 and 2017 , respectively. The increase to oil and gas properties from 2018 to 2019 primarily relates to proportionate consolidation resulting from the unwind of our equity method investment in KTIPI. See Note 7 — Equity Method Investments for additional information.

Suspended Well Costs

Suspended Well Costs	12 Months Ended
Suspended Well Costs	Dec. 31, 2019
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Suspended Well Costs	Suspended Well Costs The Company capitalizes exploratory well costs as unproved properties within oil and gas properties until a determination is made that the well has either found proved reserves or is impaired. If proved reserves are found, the capitalized exploratory well costs are reclassified to proved properties. Well costs are charged to exploration expense if the exploratory well is determined to be impaired. The following table reflects the Company’s capitalized exploratory well costs on completed wells as of and during the years ended December 31, 2019 , 2018 and 2017 . The table excludes $3.0 million , $65.6 million and $43.2 million in costs that were capitalized and subsequently expensed during the same year for the years ended December 31, 2019 , 2018 and 2017 , respectively. During 2017, the exploratory well costs associated with the Mahogany and Teak fields were reclassified to proved property as they were unitized into the Jubilee Unit as part of the Greater Jubilee Full Field Development Plan. Years Ended December 31, 2019 2018 2017 (In thousands) Beginning balance $ 367,665 $ 410,113 $ 734,463 Additions to capitalized exploratory well costs pending the determination of proved reserves 78,125 10,518 69,567 Additions associated with the acquisition of DGE — 26,224 — Reclassification due to determination of proved reserves(1) — (26,224 ) (176,881 ) Divestitures(2) — — (206,400 ) Contribution of oil and gas property to equity method investment - KBSL — — (131,764 ) Dissolution of equity method investment - KBSL — — 121,128 Capitalized exploratory well costs charged to expense(3) — (52,966 ) — Ending balance $ 445,790 $ 367,665 $ 410,113 ______________________________________ (1) Represents the reclassification of Nearly Headless Nick well costs associated with the DGE acquisition in 2018 and inclusion of the Mahogany and Teak discoveries in the Jubilee Unit in 2017. (2) Represents the reduction in basis of suspended well costs associated with the Mauritania and Senegal transactions with BP (3) Primarily related to Akasa and Wawa wells as we wrote off $38.1 million and $13.6 million , respectively, of previously capitalized costs exploratory well costs to exploration expense during the third quarter of 2018. These impairments are included in our Ghana segment. The following table provides aging of capitalized exploratory well costs based on the date drilling was completed and the number of projects for which exploratory well costs have been capitalized for more than one year since the completion of drilling: Years Ended December 31, 2019 2018 2017 (In thousands, except well counts) Exploratory well costs capitalized for a period of one year or less $ 29,121 $ — $ 67,159 Exploratory well costs capitalized for a period of one to two years 78,245 299,253 291,252 Exploratory well costs capitalized for a period of three years or longer 338,424 68,412 51,702 Ending balance $ 445,790 $ 367,665 $ 410,113 Number of projects that have exploratory well costs that have been capitalized for a period greater than one year 3 3 5 As of December 31, 2019 , the projects with exploratory well costs capitalized for more than one year since the completion of drilling are related to the Greater Tortue Ahmeyim Unit, which crosses the Mauritania and Senegal maritime border, BirAllah discovery (formerly known as the Marsouin discovery) in Block C8 offshore Mauritania, and the Yakaar and Teranga discoveries in the Cayar Offshore Profond block offshore Senegal. Greater Tortue Ahmeyim Unit — In May 2015, we completed the Tortue-1 exploration well in Block C8 offshore Mauritania, which encountered hydrocarbon pay. Three additional wells have been drilled in the unit development area of the Greater Tortue Ahmeyim field, Ahmeyim-2 in Mauritania and Guembeul-1 and Greater Tortue Ahmeyim-1 in Senegal. We completed a drill stem test on the Tortue‑1 well in August 2017, which confirmed the production capabilities of the Greater Tortue Ahmeyim unit. In December 2018, we made a final investment decision to develop Phase 1 of the Greater Tortue Ahmeyim unit, with first gas production currently estimated in 2022. Additionally, in February 2020 the Tortue Phase 1 SPA was executed. BirAllah Discovery — In November 2015, we completed the Marsouin-1 exploration well in the northern part of Block C8 offshore Mauritania, which encountered hydrocarbon pay. Following additional evaluation, a decision regarding commerciality is expected be made. During the fourth quarter of 2019, we completed the nearby Orca-1 exploration well which encountered hydrocarbon pay. Following additional evaluation, a decision regarding commerciality is expected to be made. The Bir Allah and Orca discoveries are being analyzed as a joint development.

Equity Method Investments

Equity Method Investments	12 Months Ended
Equity Method Investments	Dec. 31, 2019
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investments	Equity Method Investments Kosmos BP Senegal Limited As part of our transaction in Senegal with BP in February 2017, our participating interests in the Cayar Offshore Profond and Saint Louis Offshore Profond Blocks ("Senegal Blocks") were contributed to KBSL, a corporate joint venture in which we owned a 50.01% interest which was accounted for under the equity method of accounting. In October 2017, KBSL transferred a 30% participating interest in the Senegal Blocks to BP Senegal Investments Limited in exchange for its outstanding shares of KBSL. As a result, KBSL became a wholly-owned subsidiary of Kosmos, and no longer is accounted for under the equity method of accounting. After the transfer, KBSL has a 30% working interest in the Senegal Blocks. Our initial contribution to KBSL was $133.9 million , which was recorded at our carrying costs. Our share of losses in KBSL during the period it was accounted for as an equity method investment is reflected in our consolidated statements of operations as (Gain) loss on equity method investments, net . During the year ended December 31, 2017, we recognized $11.5 million related to our share of losses in KBSL. Equatorial Guinea As part of our acquisition of KTIPI in 2017, a corporate joint venture entity in which we owned a 50% interest until January 2019, we acquired an indirect participating interest in Block G offshore Equatorial Guinea. The objective of this transaction was to acquire the Ceiba Field and Okume Complex with the intent to optimize production and increase reserves. Below is a summary of financial information for KTIPI presented on a 100% basis for 2018. The financial information for 2019 is presented as part of our consolidated financial statements based on our direct 40.375% ownership in the Ceiba Field and Okume Complex. December 31, 2018 (In thousands) Assets Total current assets $ 149,950 Property and equipment, net 271,627 Other assets 21 Total assets $ 421,598 Liabilities and shareholders' deficit Total current liabilities $ 226,311 Total long term liabilities 536,178 Shareholders' deficit: Total shareholders' deficit (340,891 ) Total liabilities and shareholders' deficit $ 421,598 Year Ended December 31, 2018 Period November 28, 2017 through December 31, 2017 (In thousands) Revenues and other income: Oil and gas revenue $ 721,299 $ 54,615 Other income (477 ) 294 Total revenues and other income 720,822 54,909 Costs and expenses: Oil and gas production 147,685 15,509 Depletion and depreciation 126,983 10,738 Other expenses, net 429 (19 ) Total costs and expenses 275,097 26,228 Income before income taxes 445,725 28,681 Income tax expense 156,981 6,588 Net income $ 288,744 $ 22,093 Kosmos' share of net income $ 144,372 $ 11,046 Basis difference amortization(1) 71,491 5,812 Equity in earnings - KTIPI $ 72,881 $ 5,234 ______________________________________ (1) The basis difference, which is associated with oil and gas properties and subject to amortization, has been allocated to the Ceiba Field and Okume Complex. We amortize the basis difference using the unit-of-production method. When evaluating our equity method investments for impairment, we review our ability to recover the carrying amount of such investments or the entity’s ability to sustain earnings that justify its carrying amount. As of December 31, 2018, we determined that we had the ability to recover the carrying amount of our equity method investment in KTIPI. As such, no impairment has been recorded. Our initial investment has been increased for our net share of equity in earnings as adjusted for our basis differential and reduced by cash dividends received. During the year ended December 31, 2018, we received $257.5 million of cash dividends from KTIPI. Effective as of January 1, 2019, our outstanding shares in KTIPI were transferred to Trident in exchange for a 40.375% undivided interest in the Ceiba Field and Okume Complex. As a result, our interest in the Ceiba Field and Okume Complex is accounted for under the proportionate consolidation method of accounting going forward. This transaction was accounted for as an asset acquisition. The carrying value of the equity method investment was allocated to the undivided interest acquired and net working capital based on the estimated relative fair value of the acquired assets. The estimated fair value measurements of oil and gas assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair value of oil and gas properties and asset retirement obligations were measured using the discounted cash flow technique of valuation. Significant inputs to the valuation of oil and gas properties include estimates of: (i) reserves, (ii) future operating and development costs, (iii) future commodity prices, (iv) future plugging and abandonment costs, (v) estimated future cash flows, and (vi) a market-based weighted average cost of capital rate. Carrying Value Allocation (in thousands) Assets acquired: Proved oil and gas properties $ 372,144 Unproved oil and gas properties 103,909 Prepaids and other 7,273 Total assets acquired $ 483,326 Liabilities assumed: Asset retirement obligations $ 114,395 Deferred tax liabilities 247,636 Accrued liabilities and other 69,399 Total liabilities assumed $ 431,430 Carrying value: Equity method investment carrying value at December 31, 2018 $ 51,896

Debt

Debt	12 Months Ended
Debt	Dec. 31, 2019
Debt Disclosure [Abstract]
Debt	Debt December 31, 2019 2018 (In thousands) Outstanding debt principal balances: Facility $ 1,400,000 $ 1,325,000 Corporate Revolver — 325,000 Senior Notes 650,000 — Senior Secured Notes — 525,000 Total 2,050,000 2,175,000 Unamortized deferred financing costs and discounts(1) (41,937 ) (54,453 ) Long-term debt, net $ 2,008,063 $ 2,120,547 ________________________________________ (1) Includes $32.8 million and $40.5 million of unamortized deferred financing costs related to the Facility and $9.1 million and $14.0 million of unamortized deferred financing costs and discounts related to the Senior Notes as of December 31, 2019 and December 31, 2018 , respectively. Facility In February 2018, the Company amended and restated the Facility with a total commitment of $1.5 billion from a number of financial institutions with additional commitments up to $0.5 billion being available if the existing financial institutions increase their commitments or if commitments from new financial institutions are added. In November 2018, the Company exercised its option with existing financial institutions to provide the Company with an additional commitment of $100 million in the aggregate under the Facility. The borrowing base calculation includes value related to the Jubilee, TEN, Ceiba and Okume fields. The Facility supports our oil and gas exploration, appraisal and development programs and corporate activities. As part of the debt refinancing in February 2018, the repayment of borrowings under the existing facility attributable to financial institutions that did not participate in the amended Facility was accounted for as an extinguishment of debt, and $4.1 million of existing unamortized debt issuance costs and deferred interest attributable to those participants was expensed in interest and other financing costs, net in the first quarter of 2018 . As of December 31, 2019 , we have $32.8 million of unamortized issuance costs related to the Facility, which will be amortized over the remaining term of the Facility. In December 2018, the Company entered into letter agreements with existing financial institutions, which provided the Company with an additional commitment of $100 million in the aggregate under the Facility effective January 31, 2019. This took the total commitments to $1.7 billion as of January 31, 2019. In March 2019, following the lender's annual redetermination, the available borrowing base under our Facility was limited to the Facility size of $1.7 billion . The commitments were reduced by $100.0 million to $1.6 billion following the Senior Notes issuance in April 2019. As of December 31, 2019 , borrowings under the Facility totaled $1.4 billion and the undrawn availability under the Facility was $200.0 million , which includes the additional commitments as referenced above. Interest is the aggregate of the applicable margin ( 3.25% to 4.50% , depending on the length of time that has passed from the date the Facility was entered into) and LIBOR . Interest is payable on the last day of each interest period (and, if the interest period is longer than six months , on the dates falling at six-month intervals after the first day of the interest period). We pay commitment fees on the undrawn and unavailable portion of the total commitments, if any. As part of the amendment and restatement process in February 2018, commitment fees were lowered from 40% to 30% per annum of the then-applicable respective margin when a commitment is available for utilization and, equal to 20% per annum of the then-applicable respective margin when a commitment is not available for utilization. We recognize interest expense in accordance with ASC 835—Interest, which requires interest expense to be recognized using the effective interest method. We determined the effective interest rate based on the estimated level of borrowings under the Facility. The Facility provides a revolving credit and letter of credit facility. The availability period for the revolving credit facility expires one month prior to the final maturity date. The letter of credit facility expires on the final maturity date. The available facility amount is subject to borrowing base constraints and, beginning on March 31, 2022, outstanding borrowings will be constrained by an amortization schedule. The Facility has a final maturity date of March 31, 2025. As of December 31, 2019 , we had no letters of credit issued under the Facility. Kosmos has the right to cancel all the undrawn commitments under the amended and restated Facility. The amount of funds available to be borrowed under the Facility, also known as the borrowing base amount, is determined each year on March 31, as amended. The borrowing base amount is based on the sum of the net present value of net cash flows and relevant capital expenditures reduced by certain percentages as well as value attributable to certain assets’ reserves and/or resources in Ghana and Equatorial Guinea. If an event of default exists under the Facility, the lenders can accelerate the maturity and exercise other rights and remedies, including the enforcement of security granted pursuant to the Facility over certain assets held by our subsidiaries. The Facility contains customary cross default provisions. We were in compliance with the financial covenants contained in the Facility as of the September 30, 2019 (the most recent assessment date). Corporate Revolver In August 2018, we amended and restated the Corporate Revolver maintaining the borrowing capacity at $400.0 million , extending the maturity date from November 2018 to May 2022 and lowering the margin 100 basis points to 5% . This results in lower commitment fees on the undrawn portion of the total commitments, which is 30% per annum of the respective margin. The Corporate Revolver is available for general corporate purposes and for oil and gas exploration, appraisal and development programs. As of December 31, 2019 , we have $6.3 million of net deferred financing costs related to the Corporate Revolver, which will be amortized over the remaining term. These deferred financing costs are included in the Other assets section of our consolidated balance sheets. As of December 31, 2019 , there were no borrowings outstanding under the Corporate Revolver and the undrawn availability under the Corporate Revolver was $400.0 million . Interest is the aggregate of the applicable margin ( 5.0% ); LIBOR ; and mandatory cost (if any, as defined in the Corporate Revolver). Interest is payable on the last day of each interest period (and, if the interest period is longer than six months , on the dates falling at six‑month intervals after the first day of the interest period). We pay commitment fees on the undrawn portion of the total commitments. Commitment fees for the lenders are equal to 30% per annum of the respective margin when a commitment is available for utilization. The Corporate Revolver expires on May 31, 2022 . The available amount is not subject to borrowing base constraints. Kosmos has the right to cancel all the undrawn commitments under the Corporate Revolver. The Company is required to repay certain amounts due under the Corporate Revolver with sales of certain subsidiaries or sales of certain assets. If an event of default exists under the Corporate Revolver, the lenders can accelerate the maturity and exercise other rights and remedies, including the enforcement of security granted pursuant to the Corporate Revolver over certain assets held by us. We were in compliance with the financial covenants contained in the Corporate Revolver as of September 30, 2019 (the most recent assessment date). The Corporate Revolver contains customary cross default provisions. Revolving Letter of Credit Facility In July 2013, we entered into a revolving letter of credit facility agreement (“LC Facility”). The size of the LC Facility was $75.0 million , as amended in July 2015, with additional commitments up to $50.0 million being available if the existing lender increases its commitment or if commitments from new financial institutions are added. In July 2016, we amended and restated the LC Facility, extending the maturity date to July 2019. Other amendments included increasing the margin from 0.5% to 0.8% per annum on amounts outstanding, adding a commitment fee payable quarterly in arrears at an annual rate equal to 0.65% on the available commitment amount and providing for issuance fees to be payable to the lender per new issuance of a letter of credit. We may voluntarily cancel any commitments available under the LC Facility at any time. During the first quarter of 2017, the LC Facility size was increased to $115.0 million and in April 2017, we reduced the size of our LC Facility to $70 million . In February 2018, the LC Facility was increased to $73 million to facilitate the issuance of additional letters of credit. In July 2018 and December 2018, the LC Facility size was voluntarily reduced to $40.0 million and $20.0 million , respectively, based on the expiration of several large outstanding letters of credit. The LC Facility expired in July 2019, however, as of December 31, 2019 , there were five outstanding letters of credit totaling $3.1 million under the LC Facility, which will remain outstanding until the respective letters of credit expire. The LC Facility contains customary cross default provisions. In 2019, we issued two letters of credit totaling $20.4 million under a new letter of credit arrangement, which does not currently require cash collateral. 7.875% Senior Secured Notes due 2021 During August 2014, the Company issued $300.0 million of Senior Secured Notes and received net proceeds of approximately $292.5 million after deducting discounts, commissions and deferred financing costs. The Company used the net proceeds to repay a portion of the outstanding indebtedness under the Facility and for general corporate purposes. During April 2015, we issued an additional $225.0 million of Senior Secured Notes and received net proceeds of $206.8 million after deducting discounts, commissions and other expenses. We used the net proceeds to repay a portion of the outstanding indebtedness under the Facility and for general corporate purposes. The additional $225.0 million of Senior Secured Notes have identical terms to the initial $300.0 million Senior Secured Notes, other than the date of issue, the initial price, the first interest payment date and the first date from which interest accrued. In April 2019, all of the Senior Secured Notes were redeemed for $543.8 million , including accrued interest and the early redemption premium. The redemption resulted in a $22.9 million loss on extinguishment of debt, which is included in Interest and other financing costs, net on the consolidated statement of operations. 7.125% Senior Notes due 2026 In April 2019, the Company issued $650.0 million of 7.125% Senior Notes and received net proceeds of approximately $640.0 million after deducting commissions and other expenses. We used the net proceeds to redeem all of the Senior Secured Notes, repay a portion of the outstanding indebtedness under the Corporate Revolver and pay fees and expenses related to the redemption, repayment and the issuance of the Senior Notes. The Senior Notes mature on April 4, 2026. We will pay interest in arrears on the Senior Notes each April 4 and October 4, commencing on October 4, 2019. The Senior Notes are senior, unsecured obligations of Kosmos Energy Ltd. and rank equal in right of payment with all of its existing and future senior indebtedness (including all borrowings under the Corporate Revolver) and rank effectively junior in right of payment to all of its existing and future secured indebtedness (including all borrowings under the Facility). The Senior Notes are guaranteed on a senior, unsecured basis by certain subsidiaries owning the Company's Gulf of Mexico assets, and on a subordinated, unsecured basis by certain subsidiaries that guarantee the Facility. At any time prior to April 4, 2022, and subject to certain conditions, the Company may, on one or more occasions, redeem up to 40% of the original principal amount of the Senior Notes with an amount not to exceed the net cash proceeds of certain equity offerings at a redemption price of 107.1% of the outstanding principal amount of the Senior Notes, together with accrued and unpaid interest and premium, if any, to, but excluding, the date of redemption. Additionally, at any time prior to April 4, 2022 the Company may, on any one or more occasions, redeem all or a part of the Senior Notes at a redemption price equal to 100% , plus any accrued and unpaid interest, and plus a “make-whole” premium. On or after April 4, 2022, the Company may redeem all or a part of the Senior Notes at the redemption prices (expressed as percentages of principal amount) set forth below plus accrued and unpaid interest: Year Percentage On or after April 4, 2022, but before April 4, 2023 103.6 % On or after April 4, 2023, but before April 4, 2024 101.8 % On or after April 4, 2024 and thereafter 100.0 % We may also redeem the Senior Notes in whole, but not in part, at any time if changes in tax laws impose certain withholding taxes on amounts payable on the Senior Notes at a price equal to the principal amount of the Senior Notes plus accrued interest and additional amounts, if any, as may be necessary so that the net amount received by each holder after any withholding or deduction on payments of the Senior Notes will not be less than the amount such holder would have received if such taxes had not been withheld or deducted. Upon the occurrence of a change of control triggering event as defined under the Senior Notes indenture, the Company will be required to make an offer to repurchase the Senior Notes at a repurchase price equal to 101% of the principal amount, plus accrued and unpaid interest to, but excluding, the date of repurchase. If we sell assets, under certain circumstances outlined in the Senior Notes indenture, we will be required to use the net proceeds to make an offer to purchase the Senior Notes at an offer price in cash in an amount equal to 100% of the principal amount of the Senior Notes, plus accrued and unpaid interest to, but excluding, the repurchase date. The Senior Notes indenture restricts our ability and the ability of our restricted subsidiaries to, among other things: incur or guarantee additional indebtedness, create liens, pay dividends or make distributions in respect of capital stock, purchase or redeem capital stock, make investments or certain other restricted payments, sell assets, enter into agreements that restrict the ability of our subsidiaries to make dividends or other payments to us, enter into transactions with affiliates, or effect certain consolidations, mergers or amalgamations. These covenants are subject to a number of important qualifications and exceptions. Certain of these covenants will be terminated if the Senior Notes are assigned an investment grade rating by both Standard & Poor’s Rating Services and Fitch Ratings Inc. and no default or event of default has occurred and is continuing. At December 31, 2019 , the estimated repayments of debt during the five years and thereafter are as follows: Payments Due by Year Total 2020 2021 2022 2023 2024 Thereafter (In thousands) Principal debt repayments(1) $ 2,050,000 $ — $ 174,800 $ 284,200 $ 271,600 $ 440,829 $ 878,571 (1) Includes the scheduled maturities for the $650.0 million aggregate principal amount of Senior Notes issued in April 2019 and borrowings under the Facility. The scheduled maturities of debt related to the Facility are based on, as of December 31, 2019 , our level of borrowings and our estimated future available borrowing base commitment levels in future periods. Any increases or decreases in the level of borrowings or increases or decreases in the available borrowing base would impact the scheduled maturities of debt during the next five years and thereafter. Interest and other financing costs, net Interest and other financing costs, net incurred during the period comprised of the following: Years Ended December 31, 2019 2018 2017 (In thousands) Interest expense $ 145,507 $ 114,134 $ 92,687 Amortization—deferred financing costs 9,257 9,379 10,204 Loss on extinguishment of debt 24,794 4,324 — Capitalized interest (28,077 ) (28,331 ) (30,282 ) Deferred interest 1,919 (1,138 ) 2,577 Interest income (3,692 ) (3,455 ) (3,422 ) Other, net 5,366 6,263 5,831 Interest and other financing costs, net $ 155,074 $ 101,176 $ 77,595

Derivative Financial Instrument

Derivative Financial Instruments	12 Months Ended
Derivative Financial Instruments	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Financial Instruments	Derivative Financial Instruments We use financial derivative contracts to manage exposures to commodity price and interest rate fluctuations. We do not hold or issue derivative financial instruments for trading purposes. We manage market and counterparty credit risk in accordance with our policies and guidelines. In accordance with these policies and guidelines, our management determines the appropriate timing and extent of derivative transactions. We have included an estimate of non-performance risk in the fair value measurement of our derivative contracts as required by ASC 820—Fair Value Measurements and Disclosures. Oil Derivative Contracts The following table sets forth the volumes in barrels underlying the Company’s outstanding oil derivative contracts and the weighted average prices per Bbl for those contracts as of December 31, 2019 . Volumes and weighted average prices are net of any offsetting derivative contracts entered into. Weighted Average Price per Bbl Term Type of Contract Index MBbl Net Deferred Premium Payable/(Receivable) Swap Sold Put Floor Ceiling 2020: January — December Three-way collars Dated Brent 6,000 $ 0.45 $ — $ 45.00 $ 57.50 $ 80.18 January — December Swaps with sold puts Dated Brent 2,000 — 60.53 48.75 — — January — December Put spread Dated Brent 6,000 0.75 — 50.00 59.17 — January — December Sold calls(1) Dated Brent 8,000 1.17 — — — 85.00 2021: January — December Swaps with sold puts Dated Brent 2,000 — 60.56 47.50 — — January — December Sold calls(1) Dated Brent 6,000 — — — — 71.67 ______________________________________ (1) Represents call option contracts sold to counterparties to enhance other derivative positions. In February 2020, we entered into put option contracts for 3.7 MMBbl from February 2020 through December 2020 to move the previous three-way collar sold puts at a weighted average price of $42.50 per barrel to $50.00 per barrel. We used part of the proceeds from the trades to enter into swap and sold put contracts for 2.0 MMBbl from January 2021 through December 2021 with a fixed price of $60.00 per barrel and a sold put price of $50.00 per barrel. The contracts are indexed to Dated Brent prices. See Note 10—Fair Value Measurements for additional information regarding the Company’s derivative instruments. The following tables disclose the Company’s derivative instruments as of December 31, 2019 and 2018 and gain/(loss) from derivatives during the years ended December 31, 2019 , 2018 and 2017 . Estimated Fair Value Asset (Liability) December 31, Type of Contract Balance Sheet Location 2019 2018 (In thousands) Derivatives not designated as hedging instruments: Derivative assets: Commodity(1) Derivatives assets—current $ 12,856 $ 38,350 Provisional oil sales Receivables: Oil sales (3,287 ) 435 Commodity(2) Derivatives assets—long-term 2,302 14,312 Derivative liabilities: Commodity(3) Derivatives liabilities—current (8,914 ) (12,172 ) Commodity(4) Derivatives liabilities—long-term (11,478 ) (10,181 ) Total derivatives not designated as hedging instruments $ (8,521 ) $ 30,744 ______________________________________ (1) Includes net deferred premiums payable of $1.0 million and $1.6 million related to commodity derivative contracts as of December 31, 2019 and 2018 , respectively. (2) Includes net deferred premiums payable of $0.3 million and $1.3 million related to commodity derivative contracts as of December 31, 2019 and 2018 , respectively. (3) Includes net deferred premiums payable of $5.5 million and $18.0 million related to commodity derivative contracts as of December 31, 2019 and 2018 , respectively. (4) Includes net deferred premiums payable of $0.3 million and $0.5 million related to commodity derivative contracts as of December 31, 2019 and 2018 , respectively. Amount of Gain/(Loss) Years Ended December 31, Type of Contract Location of Gain/(Loss) 2019 2018 2017 (In thousands) Derivatives not designated as hedging instruments: Commodity(1) Oil and gas revenue $ 1,161 $ (1,963 ) $ (12,502 ) Commodity Derivatives, net (71,885 ) 31,430 (59,968 ) Interest rate Interest expense — 493 648 Total derivatives not designated as hedging instruments $ (70,724 ) $ 29,960 $ (71,822 ) ______________________________________ (1) Amounts represent the change in fair value of our provisional oil sales contracts. Offsetting of Derivative Assets and Derivative Liabilities Our derivative instruments which are subject to master netting arrangements with our counterparties only have the right of offset when there is an event of default. As of December 31, 2019 and 2018 , there was not an event of default and, therefore, the associated gross asset or gross liability amounts related to these arrangements are presented on the consolidated balance sheets.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
Fair Value Measurements	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements In accordance with ASC 820—Fair Value Measurements and Disclosures, fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. We prioritize the inputs used in measuring fair value into the following fair value hierarchy: • Level 1—quoted prices for identical assets or liabilities in active markets. • Level 2—quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs derived principally from or corroborated by observable market data by correlation or other means. • Level 3—unobservable inputs for the asset or liability. The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in its entirety. The following tables present the Company’s assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2019 and 2018 , for each fair value hierarchy level: Fair Value Measurements Using: Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs (Level 1) (Level 2) (Level 3) Total (In thousands) December 31, 2019 Assets: Commodity derivatives $ — $ 15,158 $ — $ 15,158 Provisional oil sales — (3,287 ) — (3,287 ) Liabilities: Commodity derivatives — (20,392 ) — (20,392 ) Total $ — $ (8,521 ) $ — $ (8,521 ) December 31, 2018 Assets: Commodity derivatives $ — $ 52,662 $ — $ 52,662 Provisional oil sales — 435 — 435 Liabilities: Commodity derivatives — (22,353 ) — (22,353 ) Total $ — $ 30,744 $ — $ 30,744 The book values of cash and cash equivalents and restricted cash approximate fair value based on Level 1 inputs. Joint interest billings, oil sales and other receivables, and accounts payable and accrued liabilities approximate fair value due to the short‑term nature of these instruments. Our long‑term receivables, after any allowances for doubtful accounts, and other long-term assets approximate fair value. The estimates of fair value of these items are based on Level 2 inputs. Commodity Derivatives Our commodity derivatives represent crude oil collars, put options, call options and swaps for notional barrels of oil at fixed Dated Brent, NYMEX WTI or Argus LLS oil prices. The values attributable to our oil derivatives are based on (i) the contracted notional volumes, (ii) independent active futures price quotes for the respective index, (iii) a credit‑adjusted yield curve applicable to each counterparty by reference to the credit default swap (“CDS”) market and (iv) an independently sourced estimate of volatility for the respective index. The volatility estimate was provided by certain independent brokers who are active in buying and selling oil options and was corroborated by market‑quoted volatility factors. The deferred premium is included in the fair market value of the commodity derivatives. See Note 9—Derivative Financial Instruments for additional information regarding the Company’s derivative instruments. Provisional Oil Sales The value attributable to the provisional oil sales derivative is based on (i) the sales volumes and (ii) the difference in the independent active futures price quotes for the respective index over the term of the pricing period designated in the sales contract and the spot price on the lifting date. Debt The following table presents the carrying values and fair values at December 31, 2019 and 2018 : December 31, 2019 December 31, 2018 Carrying Value Fair Value Carrying Value Fair Value (In thousands) Senior Notes $ 642,550 $ 664,957 $ — $ — Senior Secured Notes — — 511,873 525,026 Corporate Revolver — — 325,000 325,000 Facility 1,400,000 1,400,000 1,325,000 1,325,000 Total $ 2,042,550 $ 2,064,957 $ 2,161,873 $ 2,175,026 The carrying value of our Senior Notes and Senior Secured Notes represents the principal amounts outstanding less unamortized discounts. The fair value of our Senior Notes is based on quoted market prices, which results in a Level 1 fair value measurement. The carrying value of the Facility approximates fair value since it is subject to short-term floating interest rates that approximate the rates available to us for those periods.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
Asset Retirement Obligations	Dec. 31, 2019
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Asset Retirement Obligations The following table summarizes the changes in the Company’s asset retirement obligations: December 31, 2019 2018 (In thousands) Asset retirement obligations: Beginning asset retirement obligations $ 151,953 $ 66,595 Additions associated with Equatorial Guinea - Ceiba Field and Okume Complex 114,395 — Additions associated with the acquisition of DGE — 74,482 Liabilities incurred during period 11,218 5,311 Liabilities settled during period (7,156 ) (3,345 ) Revisions in estimated retirement obligations (49,471 ) — Accretion expense 14,114 8,910 Ending asset retirement obligations $ 235,053 $ 151,953 The asset retirement obligations reflect the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with our oil and gas properties. The Company utilizes current cost experience to estimate the expected cash outflows for retirement obligations. The Company estimates the ultimate productive life of the properties, a risk-adjusted discount rate, and an inflation factor in order to determine the current present value of this obligation. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation, a corresponding adjustment is made to the oil and gas property balance. The revisions in estimated retirement obligations during 2019 are related to changes in the estimated abandonment date in certain of our fields. Effective as of January 1, 2019, our outstanding shares in KTIPI were transferred to Trident in exchange for a 40.375%

Equity-based Compensation

Equity-based Compensation	12 Months Ended
Equity-based Compensation	Dec. 31, 2019
Share-based Payment Arrangement [Abstract]
Equity-based Compensation	Equity‑based Compensation Restricted Stock Awards and Restricted Stock Units Our Long-Term Incentive Plan ("LTIP") provides for the granting of incentive awards in the form of stock options, stock appreciation rights, restricted stock awards, restricted stock units, among other award types. In January 2018 and January 2015, the board of directors approved amendments to the plan which added 11.0 million and 15.0 million shares, respectively, to the plan which were approved at the corresponding Annual General Meeting. The LTIP as amended provides for the issuance of 50.5 million shares pursuant to awards under the plan. As of December 31, 2019 , the Company had approximately 10.6 million shares that remain available for issuance under the LTIP. We record equity-based compensation expense equal to the fair value of share‑based payments over the vesting periods of the LTIP awards. We recorded compensation expense from awards granted under our LTIP of $32.4 million , $35.2 million and $40.0 million during the years ended December 31, 2019 , 2018 and 2017 , respectively. The total tax benefit for the years ended December 31, 2019 , 2018 and 2017 was $4.9 million , $6.6 million and $13.2 million , respectively. Additionally, we expensed a net tax shortfall (windfall) related to equity‑based compensation of $1.2 million , $(0.4) million and $3.1 million for the years ended December 31, 2019 , 2018 and 2017 , respectively. The fair value of awards vested during 2019 , 2018 and 2017 was approximately $20.3 million , $85.1 million , and $21.2 million , respectively. The Company granted both restricted stock awards and restricted stock units with service vesting criteria and granted both restricted stock awards and restricted stock units with a combination of market and service vesting criteria under the LTIP. Substantially, all of these awards vest over a three year period. Restricted stock awards are issued and included in the number of outstanding shares upon the date of grant and, if such awards are forfeited, they become treasury stock. Upon vesting, restricted stock units become issued and outstanding stock. The following table reflects the outstanding restricted stock awards as of December 31, 2019 : Service Vesting Restricted Stock Awards Weighted- Average Grant-Date Fair Value Market / Service Vesting Restricted Stock Awards Weighted- Average Grant-Date Fair Value (In thousands) (In thousands) Outstanding at December 31, 2016: 488 $ 8.83 — $ — Granted — — — — Forfeited — — — — Vested (268 ) 8.97 — — Outstanding at December 31, 2017: 220 8.64 — — Granted — — — — Forfeited — — — — Vested (220 ) 8.64 — — Outstanding at December 31, 2018: — — — — There has been no additional restricted stock activity subsequent to December 31, 2018. The following table reflects the outstanding restricted stock units as of December 31, 2019 : Service Vesting Restricted Stock Units Weighted- Average Grant-Date Fair Value Market / Service Vesting Restricted Stock Units Weighted-Average Grant-Date Fair Value (In thousands) (In thousands) Outstanding at December 31, 2016: 4,160 $ 6.91 7,194 $ 12.29 Granted 2,085 6.43 2,175 9.50 Forfeited (137 ) 6.91 (21 ) 6.21 Vested (1,925 ) 7.51 (896 ) 15.43 Outstanding at December 31, 2017: 4,183 6.39 8,452 11.26 Granted 2,402 7.07 8,111 12.38 Forfeited (229 ) 6.40 (302 ) 8.95 Vested (2,241 ) 6.95 (9,545 ) 13.75 Outstanding at December 31, 2018: 4,115 6.42 6,716 9.02 Granted 3,228 5.01 3,195 6.02 Forfeited (591 ) 5.90 (813 ) 7.93 Vested (2,021 ) 5.95 (1,300 ) 6.32 Outstanding at December 31, 2019: 4,731 5.71 7,798 8.42 As of December 31, 2019 , total equity‑based compensation to be recognized on unvested restricted stock units is $27.4 million over a weighted average period of 1.8 years . For restricted stock units with a combination of market and service vesting criteria, the number of shares of common stock to be issued is determined by comparing the Company’s total shareholder return with the total shareholder return of a predetermined group of peer companies over the performance period and can vest up to 200% of the awards granted. The grant date fair value ranged from $4.83 to $15.71 per award. The Monte Carlo simulation model utilizes multiple input variables that determine the probability of satisfying the market condition stipulated in the award grant and calculates the fair value of the award. The expected volatility utilized in the model was estimated using our historical volatility and the historical volatilities of our peer companies and ranged from 44.0% to 52.0% . The risk‑free interest rate was based on the U.S. treasury rate for a term commensurate with the expected life of the grant ranged from 0.8% to 2.5% for restricted stock units. The expected quarterly dividends ranged from $0.045 to $0.050 commensurate with our current dividend experience. In January 2020 , we granted 2.7 million service vesting restricted stock units and 2.6 million market and service vesting restricted stock units to our employees under our long-term incentive plan. We expect to recognize approximately $40.8 million of non-cash compensation expense related to these grants over the next three years .

Income Taxes

Income Taxes	12 Months Ended
Income Taxes	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes Kosmos Energy Ltd. changed its jurisdiction of incorporation from Bermuda to the State of Delaware in December 2018. The company was not subject to taxation at the parent company level for the year ended December 31, 2017. We provide for income taxes based on the laws and rates in effect in the countries in which our operations are conducted. The relationship between our pre‑tax income or loss from continuing operations and our income tax expense or benefit varies from period to period as a result of various factors which include changes in total pre‑tax income or loss, the jurisdictions in which our income (loss) is earned and the tax laws in those jurisdictions. On December 22, 2017, the President of the United States signed P.L. 115-97, the Tax Cut and Jobs Act (the Tax Reform Act), into law. Many of the provisions of the Tax Reform Act are effective beginning January 1, 2018, most notable of which is the reduction in the U.S. corporate income tax rate from 35% to 21%. Accounting Standards Codification Topic 740 requires deferred tax assets and liabilities be adjusted for the effect of changes in tax laws or tax rates during the period that includes the date of enactment. Accordingly, we have recorded a $16.7 million charge to deferred tax expense in December 2017 as a result of reducing our net deferred tax assets. Effective January 1, 2019, our outstanding shares in KTIPI were transferred to Trident in exchange for a 40.375% undivided interest in the Ceiba Field and Okume Complex and Trident became the operator. As a result, our interest in the Ceiba Field and Okume Complex will be accounted for under the proportionate consolidation method of accounting going forward. The following discussion reflects the proportionate consolidation of our Equatorial Guinean operations related to the Ceiba Field and Okume Complex for the year ended December 31, 2019. For years ended prior to 2019 KTIPI was accounted for as an Equity Method Investment. The components of loss before income taxes were as follows: Years Ended December 31, 2019 2018 2017 (In thousands) United States $ (149,919 ) $ 41,026 $ 6,068 Bermuda — (73,979 ) (66,914 ) Foreign—other 175,036 (17,907 ) (117,009 ) Income (loss) before income taxes $ 25,117 $ (50,860 ) $ (177,855 ) The components of the provision for income taxes attributable to our income (loss) before income taxes consist of the following: Years Ended December 31, 2019 2018 2017 (In thousands) Current: United States $ 185 $ 122 $ 10,976 Bermuda — — — Foreign—other 171,079 33,864 24,456 Total current 171,264 33,986 35,432 Deferred: United States (18,776 ) 8,514 15,310 Bermuda — — — Foreign—other (71,594 ) 631 (5,805 ) Total deferred (90,370 ) 9,145 9,505 Income tax expense $ 80,894 $ 43,131 $ 44,937 Our reconciliation of income tax expense (benefit) computed by applying our statutory rate and the reported effective tax rate on income or (loss) from continuing operations is as follows: Years Ended December 31, 2019 2018 2017 (In thousands) Tax at statutory rate(1) $ 5,275 $ (10,681 ) $ — Foreign income (loss) taxed at different rates 32,690 5,013 9,381 Net non-taxable expense / insurance recoveries (13,352 ) 3,256 (30 ) West Leo arbitration settlement — (2,834 ) 1,736 Non-deductible insurance premiums 2,625 — — Non-deductible compensation 3,545 2,643 1,680 Deferred tax liability - undistributed earnings — (2,565 ) 2,565 Non-deductible and other items 3,998 656 3,790 Equity earnings - net of tax — (15,305 ) — Tax shortfall (windfall) on equity-based compensation, net 1,224 (387 ) 3,086 Change in valuation allowance 44,889 63,335 6,008 Change in U.S. tax rate — — 16,721 Total tax expense $ 80,894 $ 43,131 $ 44,937 Effective tax rate(2) 322 % 85 % 25 % ______________________________________ (1) On December 28, 2018, we changed our jurisdiction of incorporation from Bermuda to the State of Delaware. Kosmos Energy Ltd. discontinued as a Bermuda exempted company pursuant to Section 132G of the Companies Act 1981 of Bermuda and, pursuant to Section 265 of the General Corporation Law of the State of Delaware (the “DGCL”), continued its existence under the DGCL as a corporation organized in the State of Delaware. As a result, the statutory tax rate for the 2019 and 2018 reconciliation of income tax expense is the U.S. statutory tax rate of 21% . Our 2017 reconciliation of income tax expense is based on the Bermuda statutory tax rate of 0% . (2) The effective tax rate during the years ended December 31, 2019 , 2018 and 2017 , were impacted by losses of $132.1 million , $261.2 million and $164.4 million , respectively, incurred in jurisdictions in which we are not subject to taxes and therefore do not generate any income tax benefits or where there are valuation allowances offsetting the corresponding deferred tax assets. The effective tax rate for the United States is approximately 12% , 84% and 433% for the years ended December 31, 2019 , 2018 and 2017 , respectively. The effective tax rate in the United States is impacted by the effect the sum of non-deductible expenditures and equity-based compensation tax shortfalls and tax windfalls equal to the difference between the income tax benefit recognized for financial statement reporting purposes compared to the income tax benefit realized for tax return purposes. The effective tax rate for Ghana is approximately 29% , 36% and 49% for the years ended December 31, 2019 , 2018 and 2017 , respectively. The effective tax rate in Ghana is impacted by non-deductible expenditures, including amounts associated with damage to the turret bearing, which we expect to recover from insurance proceeds. Any such insurance recoveries would not be subject to income tax. The effective tax rate for Equatorial Guinea is approximately 37% for the year ended December 31, 2019 and is impacted by non-deductible expenditures. Our operations in other foreign jurisdictions have a 0% effective tax rate because they reside in countries with a 0% statutory rate or we have incurred losses in those countries and have full valuation allowances against the corresponding net deferred tax assets. Deferred tax assets and liabilities, which are computed on the estimated income tax effect of temporary differences between financial and tax bases in assets and liabilities, are determined using the tax rates expected to be in effect when taxes are actually paid or recovered. In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. The tax effects of significant temporary differences giving rise to deferred tax assets and liabilities are as follows: December 31, 2019 2018 (In thousands) Deferred tax assets: Foreign capitalized operating expenses $ 175,330 $ 128,809 Foreign net operating losses 19,576 28,050 United States net operating losses 58,903 59,336 United States deferred interest expense 15,426 — Equity compensation 13,700 11,408 Unrealized derivative losses 1,471 — Asset retirement obligation and other 43,159 29,450 Total deferred tax assets 327,565 257,053 Valuation allowance (201,749 ) (156,860 ) Total deferred tax assets, net 125,816 100,193 Deferred tax liabilities: Depletion, depreciation and amortization related to property and equipment (746,258 ) (547,389 ) Unrealized derivative gains — (15,979 ) Total deferred tax liabilities (746,258 ) (563,368 ) Net deferred tax liability $ (620,442 ) $ (463,175 ) The Company has foreign net operating loss carryforwards of $68.8 million . Of these losses, we expect $0.6 million , $0.5 million , $15.6 million , $0.7 million , and $1.4 million to expire in 2020, 2021, 2022, 2023, and 2024, respectively, and $50.0 million do not expire. All of these losses currently have offsetting valuation allowances. The Company has $280.5 million of United States net operating loss that will not expire. The Company is open to tax examinations in the United States for federal income tax return years 2016 through 2018 and in Ghana to federal income tax return years 2014 through 2018. As of December 31, 2019 , the Company had no material uncertain tax positions. The Company’s policy is to recognize potential interest and penalties related to income tax matters in income tax expense.

Net Income (Loss) Per Share

Net Income (Loss) Per Share	12 Months Ended
Net Income (Loss) Per Share	Dec. 31, 2019
Earnings Per Share [Abstract]
Net Income (Loss) Per Share	Net Income (Loss) Per Share In the calculation of basic net income per share, participating securities are allocated earnings based on actual dividend distributions received plus a proportionate share of undistributed net income, if any. We calculate basic net income per share under the two‑class method. Diluted net income (loss) per share is calculated under both the two-class method and the treasury stock method and the more dilutive of the two calculations is presented. The computation of diluted net income (loss) per share reflects the potential dilution that could occur if all outstanding awards under our LTIP were converted into shares of common stock or resulted in the issuance of shares of common stock that would then share in the earnings of the Company. During periods in which the Company realizes a loss from continuing operations securities would not be dilutive to net loss per share and conversion into shares of common stock is assumed not to occur. Basic net income (loss) per share is computed as (i) net income (loss), (ii) less income allocable to participating securities (iii) divided by weighted average basic shares outstanding. The Company’s diluted net income (loss) per share is computed as (i) basic net income (loss), (ii) plus diluted adjustments to income allocable to participating securities (iii) divided by weighted average diluted shares outstanding. Years Ended December 31, 2019 2018 2017 (In thousands, except per share data) Numerator: Net loss allocable to common stockholders $ (55,777 ) $ (93,991 ) $ (222,792 ) Denominator: Weighted average number of shares outstanding: Basic 401,368 404,585 388,375 Restricted stock awards and units(1)(2) — — — Diluted 401,368 404,585 388,375 Net loss per share: Basic $ (0.14 ) $ (0.23 ) $ (0.57 ) Diluted $ (0.14 ) $ (0.23 ) $ (0.57 ) ______________________________________ (1) Our service vesting restricted stock awards represent participating securities because they participate in non-forfeitable dividends with common equity owners. Income allocable to participating securities represents the distributed and undistributed earnings attributable to the participating securities. Our restricted stock awards with market and service vesting criteria and all restricted stock units are not considered to be participating securities and, therefore, are excluded from the basic net income (loss) per share calculation. Our service vesting restricted stock awards do not participate in undistributed net losses because they are not contractually obligated to do so and, therefore, are excluded from the basic net income (loss) per share calculation in periods we are in a net loss position. All restricted stock awards were fully vested in January 2018. (2) For the years ended December 31, 2019 , 2018 and 2017 , we excluded 15.3 million , 10.6 million and 12.9 million outstanding restricted stock awards and restricted stock units, respectively, from the computations of diluted net income per share because the effect would have been anti‑dilutive. All restricted stock awards were fully vested in January 2018.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
Commitments and Contingencies	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies From time to time, we are involved in litigation, regulatory examinations and administrative proceedings primarily arising in the ordinary course of our business in jurisdictions in which we do business. Although the outcome of these matters cannot be predicted with certainty, management believes none of these matters, either individually or in the aggregate, would have a material effect upon the Company’s financial position; however, an unfavorable outcome could have a material adverse effect on our results from operations for a specific interim period or year. The Jubilee Field in Ghana covers an area within both the WCTP and DT petroleum contract areas. It was agreed the Jubilee Field would be unitized for optimal resource recovery. Kosmos and its partners executed a comprehensive unitization and unit operating agreement, the Jubilee UUOA, to unitize the Jubilee Field and govern each party’s respective rights and duties in the Jubilee Unit, which was effective July 16, 2009. Pursuant to the terms of the Jubilee UUOA, the tract participations are subject to a process of redetermination. The initial redetermination process was completed on October 14, 2011. As a result of the initial redetermination process, our Unit Interest is 24.1% . These consolidated financial statements are based on these redetermined tract participations. Our unit interest may change in the future should another redetermination occur. The Greater Tortue Ahmeyim Unit, which includes the Ahmeyim discovery in Mauritania Block C8 and the Guembeul discovery in the Senegal Saint Louis Offshore Profond Block, straddles the border between Mauritania and Senegal. To optimize resource recovery in this field, we entered into the GTA UUOA in February 2019 with the governments of Mauritania and Senegal. The GTA UUOA governs interests in and development of the Greater Tortue Ahmeyim Field and created the Greater Tortue Ahmeyim Unit from portions of the Mauritania Block C8 and the Senegal Saint Louis Offshore Profond Block areas. These interest percentages are subject to redetermination of the participating interests in the Greater Tortue Ahmeyim Field pursuant to the terms of the GTA UUOA. These consolidated financial statements are based our current payment interest on development activities in the Greater Tortue Ahmeyim Unit of 26.7% . Our unit interest may change in the future should a redetermination occur. We currently have a commitment to drill one exploration well in each of Sao Tome and Principe and Namibia and two exploration wells in Mauritania. In Sao Tome and Principe, we also have 3D seismic acquisition requirements of approximately 13,500 square kilometers. In South Africa, we have 2D seismic acquisition requirements of approximately 500 line kilometers. Leases We have commitments under operating leases primarily related to office leases. Our leases have initial lease terms ranging from 1 year to ten years . Certain lease agreements contain provisions for future rent increases. The components of lease cost for the year ended December 31, 2019 is as follows: December 31, 2019 (In thousands) Operating lease cost $ 5,480 Short-term lease cost 15,874 Total lease cost $ 21,354 Other information related to operating leases at December 31, 2019 , is as follows: December 31, 2019 (In thousands, except lease term and discount rate) Balance sheet classifications Other assets (right-of-use assets) $ 20,008 Accrued liabilities (current maturities of leases) 1,139 Other long-term liabilities (non-current maturities of leases) 22,240 Weighted average remaining lease term 8.8 years Weighted average discount rate 9.8 % The table below presents supplemental cash flow information related to leases during the year ended December 31, 2019 : December 31, 2019 (In thousands) Operating cash flows for operating leases $ 5,082 Investing cash flows for operating leases $ 13,855 Future minimum rental commitments under our leases at December 31, 2019 , are as follows: Operating Leases(1) (In thousands) 2020 $ 3,379 2021 4,201 2022 4,264 2023 4,327 2024 3,491 Thereafter 16,112 Total undiscounted lease payments $ 35,774 Less: Imputed interest (12,395 ) Total lease liabilities $ 23,379 __________________________________ (1) Does not include purchase commitments for jointly owned fields and facilities where we are not the operator and excludes commitments for exploration activities, including well commitments, in our petroleum contracts. Performance Obligations As of December 31, 2019 and 2018 , the Company had performance bonds totaling $222.0 million and $200.9 million , respectively, for our supplemental bonding requirements stipulated by the Bureau of Ocean Energy Management ("BOEM") and $3.7 million and $3.7 million , respectively, to another operator related to costs anticipated for the plugging and abandonment of certain wells and the removal of certain facilities in its U.S. Gulf of Mexico fields. As of December 31, 2019 and 2018 , we had zero and $0.6 million , respectively of cash collateral against these secured performance bonds which is classified as Other long term assets in our consolidated balance sheets. Dividends On February 24, 2020, we announced our quarterly cash dividend of $0.0452 per common share. The dividend is payable on March 26, 2020 to stockholders of record on March 5, 2020.

Additional Financial Informatio

Additional Financial Information	12 Months Ended
Additional Financial Information	Dec. 31, 2019
Additional Financial Information
Additional Financial Information	Additional Financial Information Accrued Liabilities Accrued liabilities consisted of the following: December 31, 2019 2018 (In thousands) Accrued liabilities: Exploration, development and production $ 152,490 $ 92,613 Current asset retirement obligations 4,527 6,617 General and administrative expenses 44,575 39,373 Interest 33,584 18,152 Income taxes 103,566 8,958 Taxes other than income 3,375 4,613 Derivatives 4,837 441 Revenue payable 32,482 24,379 Other 1,268 450 $ 380,704 $ 195,596 Gain on sale of assets During the year ended December 31, 2019, we recognized a $10.5 million gain related to the farm-out of Blocks 6 and 11 offshore Sao Tome and Principe. During the year ended December 31, 2018, we recognized a $7.7 million gain related to the farm-out of Blocks EG-21, S, and W offshore Equatorial Guinea to Trident. Other Income, net Other income, net which includes Loss of Production Income (“LOPI”) payments, consisted of zero , zero and $58.7 million for the years ended December 31, 2019 , 2018 and 2017 , respectively. Our LOPI coverage for the turret bearing issue on the Jubilee FPSO ended in May 2017. Oil and Gas Production Oil and gas production expense included insurance recoveries related to our increased cost of working covered by our LOPI policy of zero , zero , and $17.1 million for the years ended December 31, 2019 , 2018 and 2017 , respectively. Facilities Insurance Modifications, net Facilities insurance modifications, net consists of costs associated with the long-term solution to convert the Jubilee FPSO to a permanently spread moored facility, net of any insurance reimbursements. Other Expenses, net Other expenses, net incurred during the period is comprised of the following: Years Ended December 31, 2019 2018 2017 (In thousands) Loss on disposal of inventory $ 4,590 $ 280 $ 866 Gain on insurance settlements (3,509 ) — (461 ) Loss on ARO liability settlements 193 — — Disputed charges and related costs, net of recoveries 4,149 (9,753 ) 4,962 Restructuring charges 11,528 — — Other, net 7,697 2,972 (76 ) Other expenses, net $ 24,648 $ (6,501 ) $ 5,291 The disputed charges and related costs are expenditures arising from Tullow Ghana Limited’s contract with Seadrill for use of the West Leo drilling rig once partner-approved 2016 work program objectives were concluded. Tullow charged such expenditures to the Deepwater Tano (“DT”) joint account. Kosmos disputed through arbitration that these expenditures were chargeable to the DT joint account on the basis that the Seadrill West Leo drilling rig contract was not approved by the DT operating committee pursuant to the DT Joint Operating Agreement. In July 2018, the International Chamber of Commerce ("ICC") issued its Final Award in the arbitration in favor of Kosmos. As a result, we recovered from Tullow Ghana Limited disputed charges in the amount of $12.9 million in the form of cash payments and offsets against other unrelated joint venture costs, which include amounts previously paid under protest as well as certain costs and fees incurred pursuing the arbitration.

Business Segment Information

Business Segment Information	12 Months Ended
Business Segment Information	Dec. 31, 2019
Segment Reporting [Abstract]
Business Segment Information	Business Segment Information Kosmos is engaged in a single line of business, which is the exploration and development of oil and gas. At December 31, 2019 , the Company had operations in four geographic reporting segments: Ghana, Equatorial Guinea, Mauritania/Senegal and the U.S. Gulf of Mexico. To assess performance of the reporting segments, the Chief Operating Decision Maker ("CODM") reviews capital expenditures. Capital expenditures, as defined by the Company, may not be comparable to similarly titled measures used by other companies and should be considered in conjunction with our consolidated financial statements and notes thereto. Financial information for each area is presented below: Ghana Equatorial Guinea Mauritania / Senegal U.S. Gulf of Mexico Corporate & Other Eliminations Total (in thousands) Year ended December 31, 2019 Revenues and other income: Oil and gas revenue $ 738,909 $ 300,547 $ — $ 459,960 $ — $ — $ 1,499,416 Gain on sale of assets — — — — 10,528 — 10,528 Other income, net 5 — — 1,194 155,866 (157,100 ) (35 ) Total revenues and other income 738,914 300,547 — 461,154 166,394 (157,100 ) 1,509,909 Costs and expenses: Oil and gas production 188,207 90,607 — 123,799 — — 402,613 Facilities insurance modifications, net (24,254 ) — — — — — (24,254 ) Exploration expenses 204 13,350 11,181 115,765 40,455 — 180,955 General and administrative 18,618 6,643 8,222 25,456 159,539 (108,468 ) 110,010 Depletion, depreciation and amortization 268,866 75,565 62 214,592 4,776 — 563,861 Interest and other financing costs, net(1) 72,226 (634 ) (26,537 ) 21,266 95,887 (7,134 ) 155,074 Derivatives, net — — — 30,387 41,498 — 71,885 Other expenses, net 40,382 (563 ) 12,056 2,691 11,580 (41,498 ) 24,648 Total costs and expenses 564,249 184,968 4,984 533,956 353,735 (157,100 ) 1,484,792 Income (loss) before income taxes 174,665 115,579 (4,984 ) (72,802 ) (187,341 ) — 25,117 Income tax expense 50,293 49,192 — (8,419 ) (10,172 ) — 80,894 Net income (loss) $ 124,372 $ 66,387 $ (4,984 ) $ (64,383 ) $ (177,169 ) $ — $ (55,777 ) Consolidated capital expenditures $ 98,285 $ 63,798 $ 12,556 $ 232,891 $ 33,206 $ — $ 440,736 As of December 31, 2019 Property and equipment, net $ 1,487,114 $ 464,420 $ 438,800 $ 1,216,453 $ 35,545 $ — $ 3,642,332 Total assets $ 1,654,266 $ 650,607 $ 581,317 $ 3,251,420 $ 12,144,312 $ (13,964,690 ) $ 4,317,232 ______________________________________ (1) Interest expense is recorded based on actual third-party and intercompany debt agreements. Capitalized interest is recorded on the business unit where the assets reside. Ghana Equatorial Guinea(1) Mauritania / Senegal U.S. Gulf of Mexico(2) Corporate & Other Eliminations(3) Total (in thousands) Year ended December 31, 2018 Revenues and other income: Oil and gas revenue $ 739,070 $ 360,649 $ — $ 147,596 $ — $ (360,649 ) $ 886,666 Gain on sale of assets — 7,666 — — — — 7,666 Other income, net (17 ) (238 ) — 11 $ 150,635 (142,354 ) 8,037 Total revenues and other income 739,053 368,077 — 147,607 150,635 (503,003 ) 902,369 Costs and expenses: Oil and gas production 189,104 73,843 — 30,470 5,153 (73,843 ) 224,727 Facilities insurance modifications, net 6,955 — — — — — 6,955 Exploration expenses 58,276 38,164 7,262 66,962 131,180 (352 ) 301,492 General and administrative 19,342 5,351 5,220 10,534 168,542 (109,133 ) 99,856 Depletion, depreciation and amortization 265,805 134,983 61 59,835 4,134 (134,983 ) 329,835 Interest and other financing costs, net(3) 86,738 (12 ) (25,386 ) 7,487 39,483 (7,134 ) 101,176 Derivatives, net — — — (57,615 ) 26,185 — (31,430 ) Loss on equity method investments, net — — — — — (72,881 ) (72,881 ) Other expenses, net 16,414 (814 ) (23 ) 598 3,510 (26,186 ) (6,501 ) Total costs and expenses 642,634 251,515 (12,866 ) 118,271 378,187 (424,512 ) 953,229 Income (loss) before income taxes 96,419 116,562 12,866 29,336 (227,552 ) (78,491 ) (50,860 ) Income tax expense (benefit) 34,494 78,491 — 6,163 2,474 (78,491 ) 43,131 Net income (loss) $ 61,925 $ 38,071 $ 12,866 $ 23,173 $ (230,026 ) $ — $ (93,991 ) Consolidated capital expenditures $ 105,942 $ 32,156 $ 11,962 $ 95,993 $ 139,381 $ — $ 385,434 As of December 31, 2018 Property and equipment, net $ 1,698,194 $ 3,919 $ 411,448 $ 1,308,670 $ 37,470 $ — $ 3,459,701 Total assets $ 1,930,071 $ 55,302 $ 536,620 $ 3,512,989 $ 10,349,488 $ (12,296,281 ) $ 4,088,189 ______________________________________ (1) Includes our proportionate share of our equity method investment in KTIPI, including our basis difference which is reflected in depletion, depreciation and amortization for the year ended December 31, 2018 , except for capital expenditures. See Note 7 - Equity Method Investments for additional information regarding our equity method investments. (2) Represents activity commencing September 14, 2018, the DGE acquisition date. (3) Includes elimination of proportionate consolidation amounts recorded for KTIPI to reconcile to (Gain) loss on equity method investments, net as reported in the consolidated statements of operations. (4) Interest expense is recorded based on actual third-party and intercompany debt agreements. Capitalized interest is recorded on the business unit where the assets reside. Ghana Equatorial Guinea(1) Mauritania / Senegal U.S. Gulf of Mexico Corporate & Other Eliminations(2) Total (in thousands) Year ended December 31, 2017 Revenues and other income: Oil and gas revenue $ 578,139 $ 27,308 $ — $ — $ — $ (27,308 ) $ 578,139 Gain on sale of assets — — — — — — — Other income, net 5 147 — — $ 219,968 (161,423 ) 58,697 Total revenues and other income 578,144 27,455 — — 219,968 (188,731 ) 636,836 Costs and expenses: Oil and gas production 137,584 7,755 — — (10,734 ) (7,755 ) 126,850 Facilities insurance modifications, net (820 ) — — — — — (820 ) Exploration expenses 394 86 71,456 — 144,114 — 216,050 General and administrative 14,836 672 8,298 — 138,661 (94,165 ) 68,302 Depletion, depreciation and amortization 251,890 11,181 20 — 3,293 (11,181 ) 255,203 Interest and other financing costs, net(3) 71,592 — (16,065 ) — 29,202 (7,134 ) 77,595 Derivatives, net — — — — 59,968 — 59,968 Loss on equity method investments, net — — 11,486 — — (5,234 ) 6,252 Other expenses, net 64,768 — 867 — (376 ) (59,968 ) 5,291 Total costs and expenses 540,244 19,694 76,062 — 364,128 (185,437 ) 814,691 Income (loss) before income taxes 37,900 7,761 (76,062 ) — (144,160 ) (3,294 ) (177,855 ) Income tax expense (benefit) 18,649 3,294 3 — 26,285 (3,294 ) 44,937 Net income (loss) $ 19,251 $ 4,467 $ (76,065 ) $ — $ (170,445 ) $ — $ (222,792 ) Consolidated capital expenditures $ 5,545 $ 1,995 $ (80,929 ) $ — $ 130,821 $ — $ 57,432 As of December 31, 2017 Property and equipment, net $ 1,901,127 $ 1,908 $ 381,422 $ — $ 33,371 $ — $ 2,317,828 Total assets $ 2,263,824 $ 237,835 $ 570,044 $ — $ 8,671,437 $ (8,550,537 ) $ 3,192,603 ______________________________________ (1) Includes our proportionate share of our equity method investment in KTIPI, including our basis difference which is reflected in depletion, depreciation and amortization for the year ended December 31, 2017, except for capital expenditures. See Note 7 - Equity Method Investments for additional information regarding our equity method investments. (2) Includes elimination of proportionate consolidation amounts recorded for KTIPI to reconcile to (Gain) loss on equity method investments, net as reported in the consolidated statements of operations. (3) Interest expense is recorded based on actual third-party and intercompany debt agreements. Capitalized interest is recorded on the business unit where the assets reside. Years Ended December 31, 2019 2018 2017 (In thousands) Consolidated capital expenditures: Consolidated Statements of Cash Flows - Investing activities: Oil and gas assets $ 340,217 $ 213,806 $ 140,495 Other property 11,796 7,935 2,858 Adjustments: Changes in capital accruals 33,717 26,669 (6,337 ) Exploration expense, excluding unsuccessful well costs and leasehold impairments(1) 93,142 178,293 172,849 Capitalized interest (28,077 ) (28,331 ) (30,282 ) Proceeds on sale of assets (16,713 ) (13,703 ) (222,068 ) Other 6,654 765 (83 ) Total consolidated capital expenditures $ 440,736 $ 385,434 $ 57,432 ______________________________________ (1) Unsuccessful well costs are included in oil and gas assets when incurred.

Supplemental Quarterly Financia

Supplemental Quarterly Financial Information (Unaudited)	12 Months Ended
Supplemental Quarterly Financial Information (Unaudited)	Dec. 31, 2019
Quarterly Financial Information Disclosure [Abstract]
Supplemental Quarterly Financial Information (Unaudited)	Supplemental Quarterly Financial Information (Unaudited) Quarter Ended March 31, June 30, September 30, December 31, (In thousands, except per share data) 2019 Revenues and other income $ 296,790 $ 395,934 $ 356,970 $ 460,215 Costs and expenses 358,370 346,495 317,435 462,492 Net income (loss) (52,906 ) 16,837 16,065 (35,773 ) Net income (loss) per share: Basic(1) (0.13 ) 0.04 0.04 (0.09 ) Diluted(1) (0.13 ) 0.04 0.04 (0.09 ) 2018 Revenues and other income $ 127,177 $ 215,473 $ 250,219 $ 309,500 Costs and expenses 201,751 364,091 364,912 22,475 Net income (loss) (50,226 ) (103,273 ) (126,057 ) 185,565 Net income (loss) per share: Basic(1) (0.13 ) (0.26 ) (0.31 ) 0.44 Diluted(1) (0.13 ) (0.26 ) (0.31 ) 0.43 _______________________________ (1) The sum of the quarterly earnings per share information may not add to the annual earnings per share information as a result of rounding.

Condensed Parent Company Financ

Condensed Parent Company Financial Statements	12 Months Ended
Condensed Parent Company Financial Statements	Dec. 31, 2019
Condensed Financial Information Disclosure [Abstract]
Schedule I - Condensed Parent Company Financial Statements	Schedule I—Condensed Parent Company Financial Statements Under the terms of agreements governing the indebtedness of subsidiaries of Kosmos Energy Ltd. for 2019 , 2018 and 2017 (collectively “KEL,” the “Parent Company”), such subsidiaries may be restricted from making dividend payments, loans or advances to KEL. Schedule I of Article 5‑04 of Regulation S‑X requires the condensed financial information of the Parent Company to be filed when the restricted net assets of consolidated subsidiaries exceed 25 percent of consolidated net assets as of the end of the most recently completed fiscal year. The following condensed parent‑only financial statements of KEL have been prepared in accordance with Rule 12‑04, Schedule I of Regulation S‑X and included herein. The Parent Company’s 100% investment in its subsidiaries has been recorded using the equity basis of accounting in the accompanying condensed parent‑only financial statements. The condensed financial statements should be read in conjunction with the consolidated financial statements of Kosmos Energy Ltd. and subsidiaries and notes thereto. The terms “Kosmos,” the “Company,” and similar terms refer to Kosmos Energy Ltd. and its wholly-owned subsidiaries, unless the context indicates otherwise. Certain prior period amounts have been reclassified to conform with the current year presentation. Such reclassifications had no impact on our reported net income, current assets, total assets, current liabilities, total liabilities or shareholders equity. KOSMOS ENERGY LTD. CONDENSED PARENT COMPANY BALANCE SHEETS (In thousands, except share data) December 31, 2019 2018 Assets Current assets: Cash and cash equivalents $ 6,422 $ 6,776 Receivables from subsidiaries 3,819 2,890 Note receivable from subsidiary — 7,941 Prepaid expenses and other 428 313 Total current assets 10,669 17,920 Investment in subsidiaries at equity 1,159,560 1,432,468 Long-term note receivable from subsidiary 518,844 607,943 Deferred financing costs, net of accumulated amortization of $14,681 and $12,065 at December 31, 2019 and December 31, 2018, respectively 6,321 8,937 Restricted cash 305 305 Long-term deferred tax asset 17,265 (1,132 ) Total assets $ 1,712,964 $ 2,066,441 Liabilities and shareholders’ equity Current liabilities: Accounts payable $ — $ 975 Accrued liabilities 11,942 18,972 Total current liabilities 11,942 19,947 Long-term debt 640,856 836,016 Long-term note payable to subsidiary 217,000 269,000 Other long-term liabilities 1,464 — Shareholders’ equity: Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at December 31, 2019 and December 31, 2018 — — Common stock, $0.01 par value; 2,000,000,000 authorized shares; 445,779,367 and 442,914,675 issued at December 31, 2019 and December 31, 2018, respectively 4,458 4,429 Additional paid-in capital 2,297,221 2,341,249 Accumulated deficit (1,222,970 ) (1,167,193 ) Treasury stock, at cost, 44,263,269 shares at December 31, 2019 and 2018, respectively (237,007 ) (237,007 ) Total shareholders’ equity 841,702 941,478 Total liabilities and shareholders’ equity $ 1,712,964 $ 2,066,441 CONDENSED PARENT COMPANY STATEMENTS OF OPERATIONS (In thousands) Years Ended December 31, 2019 2018 2017 Revenues and other income: Oil and gas revenue $ — $ — $ — Total revenues and other income — — — Costs and expenses: General and administrative 40,840 47,279 51,544 General and administrative recoveries—related party (30,822 ) (36,197 ) (40,266 ) Interest and other financing costs, net 86,104 66,055 55,596 Interest and other financing costs, net—related party (7,144 ) (7,941 ) — Other expenses, net 10 49 40 Equity in (earnings) losses of subsidiaries (15,064 ) 23,614 155,878 Total costs and expenses 73,924 92,859 222,792 Loss before income taxes (73,924 ) (92,859 ) (222,792 ) Income tax expense (18,147 ) 1,132 — Net loss $ (55,777 ) $ (93,991 ) $ (222,792 ) Dividends declared per common share $ 0.1808 $ — $ — CONDENSED PARENT COMPANY STATEMENTS OF CASH FLOWS (In thousands) Years Ended December 31, 2019 2018 2017 Operating activities Net loss $ (55,777 ) $ (93,991 ) $ (222,792 ) Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: Equity in (earnings) losses of subsidiaries (15,064 ) 23,614 155,878 Equity-based compensation 32,370 35,230 39,913 Depreciation and amortization 5,039 7,292 3,070 Deferred income taxes (18,397 ) 1,132 — Loss on extinguishment of debt 22,913 — — Other — 268 3,884 Changes in assets and liabilities: Decrease in receivables 427 1,234 986 (Increase) decrease in prepaid expenses and other (115 ) (23 ) 127 (Increase) decrease due to/from related party 43,974 (42,163 ) 14,463 Increase (decrease) in accounts payable and accrued liabilities (8,754 ) 816 1,179 Net cash provided by (used in) operating activities 6,616 (66,591 ) (3,292 ) Investing activities Investment in subsidiaries 287,972 (36,192 ) 4,691 Net cash provided by (used in) investing activities 287,972 (36,192 ) 4,691 Financing activities Borrowings under long-term debt — 400,000 — Payments on long-term debt (325,000 ) (75,000 ) — Net proceeds from issuance of senior notes 641,875 — — Redemption of senior secured notes (535,338 ) — — Purchase of treasury stock / tax withholdings (1,983 ) (206,051 ) (2,194 ) Dividends (72,599 ) — — Deferred financing costs (1,897 ) (9,382 ) — Net cash provided by (used in) financing activities (294,942 ) 109,567 (2,194 ) Net increase (decrease) in cash and cash equivalents (354 ) 6,784 (795 ) Cash, cash equivalents and restricted cash at beginning of period 7,081 297 1,092 Cash, cash equivalents and restricted cash at end of period $ 6,727 $ 7,081 $ 297 Non-cash activity: Issuance of common stock for related party receivable $ — $ 307,944 $ —

Valuation and Qualifying Accoun

Valuation and Qualifying Accounts	12 Months Ended
Valuation and Qualifying Accounts	Dec. 31, 2019
SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract]
Valuation and Qualifying Accounts	Valuation and Qualifying Accounts For the Years Ended December 31, 2019 , 2018 and 2017 Additions Description Balance January 1, Charged to Costs and Expenses Charged To Other Accounts Deductions From Reserves Balance December 31, 2019 Allowance for doubtful receivables $ 1,211 $ 1,324 $ 228 $ (15 ) $ 2,748 Allowance for deferred tax assets $ 156,860 $ 44,889 $ — $ — $ 201,749 2018 Allowance for doubtful receivables $ — $ 1,211 $ — $ — $ 1,211 Allowance for deferred tax assets $ 93,525 $ 63,335 $ — $ — $ 156,860 2017 Allowance for doubtful receivables $ 574 $ 77 $ — $ (651 ) $ — Allowance for deferred tax assets $ 87,517 $ 6,008 $ — $ — $ 93,525 Schedules other than Schedule I and Schedule II have been omitted because they are not applicable or the required information is presented in the consolidated financial statements or the notes to consolidated financial statements.

Accounting Policies (Policies)

Accounting Policies (Policies)	12 Months Ended
Accounting Policies (Policies)	Dec. 31, 2019
Accounting Policies [Abstract]
Principles of Consolidation	Principles of Consolidation The accompanying consolidated financial statements include the accounts of Kosmos Energy Ltd. and its wholly-owned subsidiaries. They also include the Company’s share of the undivided interest in certain assets, liabilities, revenues and expenses. Investments in corporate joint ventures, which we exercise significant influence over, are accounted for using the equity method of accounting. All intercompany transactions have been eliminated. Investments in companies that are partially owned by the Company are integral to the Company’s operations. The other parties, who also have an equity interest in these companies, are independent third parties that share in the business results according to their ownership. Kosmos does not invest in these companies in order to remove liabilities from its balance sheet.
Use of Estimates	Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosures of contingent assets and liabilities. Actual results could differ from these estimates.
Reclassifications	Reclassifications Certain prior period amounts have been reclassified to conform with the current year presentation. Such reclassifications had no material impact on our reported net income (loss), current assets, total assets, current liabilities, total liabilities, shareholders’ equity or cash flows, except as disclosed related to the adoption of recent accounting pronouncements.
Cash, Cash Equivalents and Restricted Cash	Cash, Cash Equivalents and Restricted Cash December 31, 2019 2018 2017 (In thousands) Cash and cash equivalents $ 224,502 $ 173,515 $ 233,412 Restricted cash - current 4,302 4,527 56,380 Restricted cash - long-term 542 7,574 15,194 Total cash, cash equivalents and restricted cash shown in the consolidated statements of cash flows $ 229,346 $ 185,616 $ 304,986 Cash and cash equivalents includes demand deposits and funds invested in highly liquid instruments with original maturities of three months or less at the date of purchase.
Receivables	Receivables
Inventories	Inventories Inventories consisted of $112.3 million and $83.4 million (including $22.1 million acquired through the DGE acquisition) of materials and supplies and $2.1 million and $1.4 million of hydrocarbons as of December 31, 2019 and 2018 , respectively. The Company’s materials and supplies inventory primarily consists of casing and wellheads and is stated at the lower of cost, using the weighted average cost method, or net realizable value. We recorded write downs of $4.6 million , $0.3 million and $0.9 million during the years ended December 31, 2019 , 2018 and 2017 for materials and supplies inventories as other expenses, net in the consolidated statements of operations and other in the consolidated statements of cash flows. Hydrocarbon inventory is carried at the lower of cost, using the weighted average cost method, or net realizable value. Hydrocarbon inventory costs include expenditures and other charges incurred in bringing the inventory to its existing condition. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory costs.
Leases (Policy applicable beginning January 1, 2019)	Leases (Policy applicable beginning January 1, 2019) In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842).” ASU 2016-02 was issued to increase transparency and comparability across organizations by recognizing substantially all leases on the balance sheet through the concept of right-of-use lease assets and liabilities. Under prior accounting guidance, lessees did not recognize lease assets or liabilities for leases classified as operating leases. The ASU was effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years with early adoption permitted. In July 2018, the FASB issued ASU 2018-11, which added a transition option permitting entities to apply the provisions of the new standard at its adoption date instead of the earliest comparative period presented in the consolidated financial statements. Under this transition option, comparative reporting would not be required, and the provisions of the standard would be applied prospectively to leases in effect at the date of adoption. The Company adopted the guidance prospectively during the first quarter of 2019. As part of our adoption, we elected not to reassess historical lease classification, recognize short-term leases on our balance sheet, nor separate lease and non-lease components for our real estate leases. The adoption and implementation of this ASU resulted in a $21.7 million increase in assets and liabilities related to our leasing activities, which primarily consists of office leases. Our adoption of ASU 2016-02 did not impact retained earnings or other components of equity as of December 31, 2018. We account for leases in accordance with ASC Topic 842, Leases, (“ASC 842”). We determine if an arrangement is a lease at contract inception. A lease exists when a contract conveys to the customer the right to control the use of identified property, plant, or equipment for a period of time in exchange for consideration. The definition of a lease embodies two conditions: (1) there is an identified asset in the contract that is land or a depreciable asset (i.e., property, plant, and equipment), and (2) the customer has the right to control the use of the identified asset. In the normal course of business, the Company enters into various lease agreements for real estate and equipment related to its exploration, development and production activities that are currently accounted for as operating leases. Operating leases are included in Other assets, Accrued liabilities, and Other long-term liabilities on our consolidated balance sheets. The lease liabilities are initially and subsequently measured at the present value of the unpaid lease payments at the lease commencement date. Key estimates and judgments include how we determined: (1) the discount rate we use to discount the unpaid lease payments to present value; (2) lease term; and (3) lease payments. 1. ASC 842 requires a lessee to discount its unpaid lease payments using the interest rate implicit in the lease or, if that rate cannot be readily determined, its incremental borrowing rate. As most of our leases where we are the lessee do not provide an implicit rate, we use our incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. Our incremental borrowing rate for a lease is the rate of interest we would have to pay on a collateralized basis to borrow an amount equal to the lease payments under similar terms. 2. The lease term for all of our leases includes the non-cancellable period of the lease plus any additional periods covered by either an option to extend (or not to terminate) the lease that we are reasonably certain to exercise, or an option to extend (or not to terminate) the lease controlled by the lessor. 3. Lease payments included in the measurement of the lease asset or liability comprise the following: fixed payments (including in-substance fixed payments), variable payments that depend on index or rate, and the exercise price of a lessee option to purchase the underlying asset if we are reasonably certain to exercise. Amounts expected to be payable under residual value guarantee are also lease payments included in the measurement of the lease liability. The Right-of-use ("ROU") asset is initially measured at cost, which comprises the initial amount of the lease liability adjusted for lease payments made at or before the lease commencement date, plus any initial direct costs incurred less any lease incentives received. For operating leases, the ROU asset is subsequently measured throughout the lease term at the carrying amount of the lease liability, plus initial direct costs, plus (minus) any prepaid (accrued) lease payments, less the unamortized balance of lease incentives received. Lease expense for lease payments is recognized on a straight-line basis over the lease term. We monitor for events or changes in circumstances that require a reassessment of a lease. When a reassessment results in the re-measurement of a lease liability, a corresponding adjustment is made to the carrying amount of the corresponding ROU asset unless doing so would reduce the carrying amount of the ROU asset to an amount less than zero. In that case, the amount of the adjustment that would result in a negative ROU asset balance is recorded in profit or loss. We have lease agreements which include lease and non-lease components. We have elected to combine lease and non-lease components for all lease contracts. We have elected not to recognize ROU assets and lease liabilities for all short-term leases that have a lease term of 12 months or less. We recognize the lease payments associated with our short-term leases as an expense on a straight-line basis over the lease term. We adopted ASU 2016-02 using a modified retrospective transition approach as of the effective date as permitted by the amendments in ASU 2018-11, which provides an alternative modified retrospective transition method. As a result, we were not required to adjust our comparative period financial information for effects of the standard or make the new required lease disclosures for periods before the date of adoption (i.e. January 1, 2019). We have elected to adopt the package of transition practical expedients and, therefore, have not reassessed (1) whether existing or expired contracts contain a lease, (2) lease classification for existing or expired leases or (3) the accounting for initial direct costs that were previously capitalized. We did not elect the practical expedient to use hindsight for leases existing at the adoption date.
Exploration and Development Costs	Exploration and Development Costs The Company follows the successful efforts method of accounting for its oil and gas properties. Acquisition costs for proved and unproved properties are capitalized when incurred. Costs of unproved properties are transferred to proved properties when a determination that proved reserves have been found. Exploration costs, including geological and geophysical costs and costs of carrying unproved properties, are expensed as incurred. Exploratory drilling costs are capitalized when incurred. If exploratory wells are determined to be commercially unsuccessful or dry holes, the applicable costs are expensed and recorded in exploration expense on the consolidated statement of operations. Costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized. Costs incurred to operate and maintain wells and equipment and to lift oil and natural gas to the surface are expensed as oil and gas production expense. The Company evaluates unproved property periodically for impairment. The impairment assessment considers results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of such projects. If it is determined that future appraisal drilling or development activities are unlikely to occur, the associated capitalized costs are recorded as exploration expense in the consolidated statement of operations.
Depletion, Depreciation and Amortization	Depletion, Depreciation and Amortization Proved properties and support equipment and facilities are depleted using the unit‑of‑production method based on estimated proved oil and natural gas reserves. Capitalized exploratory drilling costs that result in a discovery of proved reserves and development costs are depleted using the unit‑of‑production method based on estimated proved developed oil and natural gas reserves for the related field. Depreciation and amortization of other property is computed using the straight-line method over the assets’ estimated useful lives (not to exceed the lease term for leasehold improvements), ranging from one to eight years . Years Depreciated Leasehold improvements 1 to 8 Office furniture, fixtures and computer equipment 3 to 7 Vehicles 5 Amortization of deferred financing costs is computed using the straight‑line method over the life of the related debt.
Capitalized Interest	Capitalized Interest Interest costs from external borrowings are capitalized on major projects with an expected construction period of one year or longer. Capitalized interest is added to the cost of the underlying asset and is depleted on the unit‑of‑production method in the same manner as the underlying assets.
Asset Retirement Obligations	Asset Retirement Obligations The Company accounts for asset retirement obligations as required by ASC 410—Asset Retirement and Environmental Obligations. Under these standards, the fair value of a liability for an asset retirement obligation is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. If a reasonable estimate of fair value cannot be made in the period the asset retirement obligation is incurred, the liability is recognized when a reasonable estimate of fair value can be made. If a tangible long‑lived asset with an existing asset retirement obligation is acquired, a liability for that obligation is recognized at the asset’s acquisition or in service date. In addition, a liability for the fair value of a conditional asset retirement obligation is recorded if the fair value of the liability can be reasonably estimated. We capitalize the asset retirement costs by increasing the carrying amount of the related long‑lived asset by the same amount as the liability. We record increases in the discounted abandonment liability resulting from the passage of time in depletion, depreciation and amortization in the consolidated statement of operations.
Impairment of Long-lived Assets	Impairment of Long‑lived Assets The Company reviews its long‑lived assets for impairment when changes in circumstances indicate that the carrying amount of an asset may not be recoverable. ASC 360—Property, Plant and Equipment requires an impairment loss to be recognized if the carrying amount of a long‑lived asset is not recoverable and exceeds its fair value. The carrying amount of a long‑lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. That assessment shall be based on the carrying amount of the asset at the date it is tested for recoverability, whether in use or under development. An impairment loss shall be measured as the amount by which the carrying amount of a long‑lived asset exceeds its fair value. Assets to be disposed of and assets not expected to provide any future service potential to the Company are recorded at the lower of carrying amount or fair value less cost to sell. We believe the assumptions used in our undiscounted cash flow analysis to test for impairment indicators are appropriate and result in a reasonable estimate of future cash flows. The undiscounted cash flows from the analysis exceeded the carrying amount of our long-lived assets. The most significant assumptions are the pricing and production estimates used in undiscounted cash flow analysis. Where unproved reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the evaluation. In order to evaluate the sensitivity of the assumptions, we assumed a hypothetical reduction in our production profile which still showed no
Derivative Instruments and Hedging Activities	Derivative Instruments and Hedging Activities
Estimates of Proved Oil and Natural Gas Reserves	Estimates of Proved Oil and Natural Gas Reserves Reserve quantities and the related estimates of future net cash flows affect our periodic calculations of depletion and assessment of impairment of our oil and natural gas properties. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. As additional proved reserves are discovered, reserve quantities and future cash flows will be estimated by independent petroleum consultants and prepared in accordance with guidelines established by the Securities and Exchange Commission (“SEC”) and the Financial Accounting Standards Board (“FASB”). The accuracy of these reserve estimates is a function of: • the engineering and geological interpretation of available data; • estimates of the amount and timing of future operating cost, production taxes, development cost and workover cost; • the accuracy of various mandated economic assumptions; and • the judgments of the persons preparing the estimates.
Revenue Recognition	Revenue Recognition We recognize revenues on the volumes sold of hydrocarbons sold to a purchaser. The volumes sold may be more or less than the volumes to which we are entitled based on our ownership interest in the property. These differences result in a condition known in the industry as a production imbalance. A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves on such property. As of December 31, 2019 and 2018 , we had no oil and gas imbalances recorded in our consolidated financial statements. Our oil and gas revenues are recognized when hydrocarbons have been sold to a purchaser at a fixed or determinable price, title has transferred and collection is probable. Certain revenues are based on provisional price contracts which contain an embedded derivative that is required to be separated from the host contract for accounting purposes. The host contract is the receivable from oil sales at the spot price on the date of sale. The embedded derivative, which is not designated as a hedge, is marked to market through oil and gas revenue each period until the final settlement occurs, which generally is limited to the month after the sale.
Equity-based Compensation	Equity‑based Compensation For equity‑based compensation awards, compensation expense is recognized in the Company’s financial statements over the awards’ vesting periods based on their grant date fair value. The Company utilizes (i) the closing stock price on the date of grant to determine the fair value of service vesting restricted stock awards and restricted stock units and (ii) a Monte Carlo simulation to determine the fair value of restricted stock awards and restricted stock units with a combination of market and service vesting criteria. Forfeitures are recognized in the period in which they occur.
Restructuring Charges	Restructuring Charges The Company accounts for restructuring charges and related termination benefits in accordance with ASC 712-Compensation-Nonretirement Postemployment Benefits. Under these standards, the costs associated with termination benefits are recorded during the period in which the liability is incurred. During the year ended December 31, 2019, we recognized $11.5 million in restructuring charges for employee severance and related benefit costs incurred as part of a corporate reorganization in Other expenses, net in the consolidated statement of operations.
Treasury Stock	Treasury Stock We record treasury stock purchases at cost. Our treasury stock purchases are from our employees that surrendered shares to the Company to satisfy their statutory tax withholding requirements and are not part of a formal stock repurchase plan. In November 2018, Kosmos repurchased 35 million shares of our common stock from funds affiliated with Warburg Pincus LLC in a privately negotiated transaction at a price per share of $5.38 . The total aggregate purchase price for the share repurchase was approximately $188 million . The remainder of our treasury stock is forfeited restricted stock awards granted under our long‑term incentive plan.
Income Taxes	Income Taxes The Company accounts for income taxes as required by ASC 740—Income Taxes. Under this method, deferred income taxes are determined based on the difference between the financial statement and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts expected to be realized. On a quarterly basis, management evaluates the need for and adequacy of valuation allowances based on the expected realizability of the deferred tax assets and adjusts the amount of such allowances, if necessary. We recognize tax benefits from uncertain tax positions only if it is more likely than not that the tax position will be sustained upon examination by the tax authorities, based on the technical merits of the position. Accordingly, we measure tax benefits from such positions based on the most likely outcome to be realized.
Foreign Currency Translation	Foreign Currency Translation The U.S. dollar is the functional currency for all of the Company’s material foreign operations. Foreign currency transaction gains and losses and adjustments resulting from translating monetary assets and liabilities denominated in foreign currencies are included in other expenses. Cash balances held in foreign currencies are not significant, and as such, the effect of exchange rate changes is not material to any reporting period.
Concentration of Credit Risk	Concentration of Credit Risk
Recent Accounting Standards	Recent Accounting Standards Recently Adopted In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842).” ASU 2016-02 was issued to increase transparency and comparability across organizations by recognizing substantially all leases on the balance sheet through the concept of right-of-use lease assets and liabilities. Under current accounting guidance, lessees do not recognize lease assets or liabilities for leases classified as operating leases. The ASU is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years with early adoption permitted. In July 2018, the FASB issued ASU 2018-11, which added a transition option permitting entities to apply the provisions of the new standard at its adoption date instead of the earliest comparative period presented in the consolidated financial statements. Under this transition option, comparative reporting would not be required, and the provisions of the standard would be applied prospectively to leases in effect at the date of adoption. The Company adopted the guidance prospectively during the first quarter of 2019. As part of our adoption, we elected not to reassess historical lease classification, recognize short-term leases on our balance sheet, nor separate lease and non-lease components for our real estate leases. The adoption and implementation of this ASU resulted in a $21.7 million increase in assets and liabilities related to our leasing activities which primarily consists of office leases. Our adoption of ASU 2016-02 did not impact retained earnings or other components of equity as of December 31, 2018. Not Yet Adopted In June 2016, ASU 2016-13, "Measurement of Credit Losses on Financial Instruments," was issued requiring measurement of all expected credit losses for certain types of financial instruments, including trade receivables, held at the reporting date based on historical experience, current conditions and reasonable and supportable forecasts. This standard is effective January 1, 2020, and we do not expect it to have a significant impact on our consolidated financial statements.

Accounting Policies (Tables)

Accounting Policies (Tables)	12 Months Ended
Accounting Policies (Tables)	Dec. 31, 2019
Accounting Policies [Abstract]
Schedule of cash and cash equivalents	December 31, 2019 2018 2017 (In thousands) Cash and cash equivalents $ 224,502 $ 173,515 $ 233,412 Restricted cash - current 4,302 4,527 56,380 Restricted cash - long-term 542 7,574 15,194 Total cash, cash equivalents and restricted cash shown in the consolidated statements of cash flows $ 229,346 $ 185,616 $ 304,986
Schedule of estimated useful lives of other property	Depreciation and amortization of other property is computed using the straight-line method over the assets’ estimated useful lives (not to exceed the lease term for leasehold improvements), ranging from one to eight years . Years Depreciated Leasehold improvements 1 to 8 Office furniture, fixtures and computer equipment 3 to 7 Vehicles 5
Schedule of oil and gas revenue	Oil and gas revenue is composed of the following: Years Ended December 31, 2019 2018 2017 Revenues from contract with customer - Equatorial Guinea $ 297,831 $ — $ — Revenues from contract with customer - Ghana 740,464 741,033 590,642 Revenues from contract with customers - U.S. Gulf of Mexico 459,960 147,596 — Provisional oil sales contracts 1,161 (1,963 ) (12,503 ) Oil and gas revenue $ 1,499,416 $ 886,666 $ 578,139

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	12 Months Ended
Acquisitions and Divestitures (Tables)	Dec. 31, 2019
Business Combinations [Abstract]
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]	Purchase Price Allocation (in thousands) Fair value of assets acquired: Proved oil and gas properties $ 1,037,511 Unproved oil and gas properties 298,159 Accounts receivable and other 180,989 Total assets acquired $ 1,516,659 Fair value of liabilities assumed: Accrued liabilities and other $ 126,530 Asset retirement obligations 74,482 Derivative liabilities 40,265 Total liabilities assumed $ 241,277 Purchase price: Cash consideration paid $ 952,586 Fair value of common stock(1) 307,944 Transaction related costs 14,852 Total purchase price $ 1,275,382 ______________________________________ (1) Based on 34,993,585 shares of common stock issued at a price of $8.80 per share, which was the opening Kosmos common stock price on September 14, 2018, the closing date of the acquisition.

Property and Equipment (Tables)

Property and Equipment (Tables)	12 Months Ended
Property and Equipment (Tables)	Dec. 31, 2019
Property, Plant and Equipment [Abstract]
Schedule of property and equipment	Property and equipment is stated at cost and consisted of the following: December 31, 2019 2018 (In thousands) Oil and gas properties: Proved properties $ 4,904,648 $ 4,236,489 Unproved properties 814,065 759,472 Total oil and gas properties 5,718,713 4,995,961 Accumulated depletion (2,093,962 ) (1,551,097 ) Oil and gas properties, net 3,624,751 3,444,864 Other property 61,598 51,987 Accumulated depreciation (44,017 ) (37,150 ) Other property, net 17,581 14,837 Property and equipment, net $ 3,642,332 $ 3,459,701

Suspended Well Costs (Tables)

Suspended Well Costs (Tables)	12 Months Ended
Suspended Well Costs (Tables)	Dec. 31, 2019
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Schedule of capitalized exploratory well costs	The following table reflects the Company’s capitalized exploratory well costs on completed wells as of and during the years ended December 31, 2019 , 2018 and 2017 . The table excludes $3.0 million , $65.6 million and $43.2 million in costs that were capitalized and subsequently expensed during the same year for the years ended December 31, 2019 , 2018 and 2017 , respectively. During 2017, the exploratory well costs associated with the Mahogany and Teak fields were reclassified to proved property as they were unitized into the Jubilee Unit as part of the Greater Jubilee Full Field Development Plan. Years Ended December 31, 2019 2018 2017 (In thousands) Beginning balance $ 367,665 $ 410,113 $ 734,463 Additions to capitalized exploratory well costs pending the determination of proved reserves 78,125 10,518 69,567 Additions associated with the acquisition of DGE — 26,224 — Reclassification due to determination of proved reserves(1) — (26,224 ) (176,881 ) Divestitures(2) — — (206,400 ) Contribution of oil and gas property to equity method investment - KBSL — — (131,764 ) Dissolution of equity method investment - KBSL — — 121,128 Capitalized exploratory well costs charged to expense(3) — (52,966 ) — Ending balance $ 445,790 $ 367,665 $ 410,113 ______________________________________ (1) Represents the reclassification of Nearly Headless Nick well costs associated with the DGE acquisition in 2018 and inclusion of the Mahogany and Teak discoveries in the Jubilee Unit in 2017. (2) Represents the reduction in basis of suspended well costs associated with the Mauritania and Senegal transactions with BP (3) Primarily related to Akasa and Wawa wells as we wrote off $38.1 million and $13.6 million , respectively, of previously capitalized costs exploratory well costs to exploration expense during the third quarter of 2018. These impairments are included in our Ghana segment.
Schedule of aging of capitalized exploratory well costs and number of projects for which exploratory well costs were capitalized for more than one year	The following table provides aging of capitalized exploratory well costs based on the date drilling was completed and the number of projects for which exploratory well costs have been capitalized for more than one year since the completion of drilling: Years Ended December 31, 2019 2018 2017 (In thousands, except well counts) Exploratory well costs capitalized for a period of one year or less $ 29,121 $ — $ 67,159 Exploratory well costs capitalized for a period of one to two years 78,245 299,253 291,252 Exploratory well costs capitalized for a period of three years or longer 338,424 68,412 51,702 Ending balance $ 445,790 $ 367,665 $ 410,113 Number of projects that have exploratory well costs that have been capitalized for a period greater than one year 3 3 5

Equity Method Investments (Tabl

Equity Method Investments (Tables)	12 Months Ended
Equity Method Investments (Tables)	Dec. 31, 2019
Equity Method Investments and Joint Ventures [Abstract]
Summary of financial information of KTIPI	Below is a summary of financial information for KTIPI presented on a 100% basis for 2018. The financial information for 2019 is presented as part of our consolidated financial statements based on our direct 40.375% ownership in the Ceiba Field and Okume Complex. December 31, 2018 (In thousands) Assets Total current assets $ 149,950 Property and equipment, net 271,627 Other assets 21 Total assets $ 421,598 Liabilities and shareholders' deficit Total current liabilities $ 226,311 Total long term liabilities 536,178 Shareholders' deficit: Total shareholders' deficit (340,891 ) Total liabilities and shareholders' deficit $ 421,598 Year Ended December 31, 2018 Period November 28, 2017 through December 31, 2017 (In thousands) Revenues and other income: Oil and gas revenue $ 721,299 $ 54,615 Other income (477 ) 294 Total revenues and other income 720,822 54,909 Costs and expenses: Oil and gas production 147,685 15,509 Depletion and depreciation 126,983 10,738 Other expenses, net 429 (19 ) Total costs and expenses 275,097 26,228 Income before income taxes 445,725 28,681 Income tax expense 156,981 6,588 Net income $ 288,744 $ 22,093 Kosmos' share of net income $ 144,372 $ 11,046 Basis difference amortization(1) 71,491 5,812 Equity in earnings - KTIPI $ 72,881 $ 5,234 ______________________________________ (1) The basis difference, which is associated with oil and gas properties and subject to amortization, has been allocated to the Ceiba Field and Okume Complex. We amortize the basis difference using the unit-of-production method.

Debt (Tables)

Debt (Tables)	12 Months Ended
Debt (Tables)	Dec. 31, 2019
Debt Disclosure [Abstract]
Schedule of debt	December 31, 2019 2018 (In thousands) Outstanding debt principal balances: Facility $ 1,400,000 $ 1,325,000 Corporate Revolver — 325,000 Senior Notes 650,000 — Senior Secured Notes — 525,000 Total 2,050,000 2,175,000 Unamortized deferred financing costs and discounts(1) (41,937 ) (54,453 ) Long-term debt, net $ 2,008,063 $ 2,120,547 ________________________________________ (1) Includes $32.8 million and $40.5 million of unamortized deferred financing costs related to the Facility and $9.1 million and $14.0 million of unamortized deferred financing costs and discounts related to the Senior Notes as of December 31, 2019 and December 31, 2018 , respectively.
Schedule of estimated repayments of debt	At December 31, 2019 , the estimated repayments of debt during the five years and thereafter are as follows: Payments Due by Year Total 2020 2021 2022 2023 2024 Thereafter (In thousands) Principal debt repayments(1) $ 2,050,000 $ — $ 174,800 $ 284,200 $ 271,600 $ 440,829 $ 878,571 (1) Includes the scheduled maturities for the $650.0 million aggregate principal amount of Senior Notes issued in April 2019 and borrowings under the Facility. The scheduled maturities of debt related to the Facility are based on, as of December 31, 2019 , our level of borrowings and our estimated future available borrowing base commitment levels in future periods. Any increases or decreases in the level of borrowings or increases or decreases in the available borrowing base would impact the scheduled maturities of debt during the next five years and thereafter.
Schedule of interest and other financing costs, net	Interest and other financing costs, net incurred during the period comprised of the following: Years Ended December 31, 2019 2018 2017 (In thousands) Interest expense $ 145,507 $ 114,134 $ 92,687 Amortization—deferred financing costs 9,257 9,379 10,204 Loss on extinguishment of debt 24,794 4,324 — Capitalized interest (28,077 ) (28,331 ) (30,282 ) Deferred interest 1,919 (1,138 ) 2,577 Interest income (3,692 ) (3,455 ) (3,422 ) Other, net 5,366 6,263 5,831 Interest and other financing costs, net $ 155,074 $ 101,176 $ 77,595

Derivative Financial Instrume_2

Derivative Financial Instruments (Tables)	12 Months Ended
Derivative Financial Instruments (Tables)	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of oil derivative contracts	The following table sets forth the volumes in barrels underlying the Company’s outstanding oil derivative contracts and the weighted average prices per Bbl for those contracts as of December 31, 2019 . Volumes and weighted average prices are net of any offsetting derivative contracts entered into. Weighted Average Price per Bbl Term Type of Contract Index MBbl Net Deferred Premium Payable/(Receivable) Swap Sold Put Floor Ceiling 2020: January — December Three-way collars Dated Brent 6,000 $ 0.45 $ — $ 45.00 $ 57.50 $ 80.18 January — December Swaps with sold puts Dated Brent 2,000 — 60.53 48.75 — — January — December Put spread Dated Brent 6,000 0.75 — 50.00 59.17 — January — December Sold calls(1) Dated Brent 8,000 1.17 — — — 85.00 2021: January — December Swaps with sold puts Dated Brent 2,000 — 60.56 47.50 — — January — December Sold calls(1) Dated Brent 6,000 — — — — 71.67 ______________________________________ (1) Represents call option contracts sold to counterparties to enhance other derivative positions. In February 2020, we entered into put option contracts for
Schedule of derivative instruments by balance sheet location	The following tables disclose the Company’s derivative instruments as of December 31, 2019 and 2018 and gain/(loss) from derivatives during the years ended December 31, 2019 , 2018 and 2017 . Estimated Fair Value Asset (Liability) December 31, Type of Contract Balance Sheet Location 2019 2018 (In thousands) Derivatives not designated as hedging instruments: Derivative assets: Commodity(1) Derivatives assets—current $ 12,856 $ 38,350 Provisional oil sales Receivables: Oil sales (3,287 ) 435 Commodity(2) Derivatives assets—long-term 2,302 14,312 Derivative liabilities: Commodity(3) Derivatives liabilities—current (8,914 ) (12,172 ) Commodity(4) Derivatives liabilities—long-term (11,478 ) (10,181 ) Total derivatives not designated as hedging instruments $ (8,521 ) $ 30,744 ______________________________________ (1) Includes net deferred premiums payable of $1.0 million and $1.6 million related to commodity derivative contracts as of December 31, 2019 and 2018 , respectively. (2) Includes net deferred premiums payable of $0.3 million and $1.3 million related to commodity derivative contracts as of December 31, 2019 and 2018 , respectively. (3) Includes net deferred premiums payable of $5.5 million and $18.0 million related to commodity derivative contracts as of December 31, 2019 and 2018 , respectively. (4) Includes net deferred premiums payable of $0.3 million and $0.5 million related to commodity derivative contracts as of December 31, 2019 and 2018 , respectively.
Schedule of derivative instruments by location of gain/(loss)	Amount of Gain/(Loss) Years Ended December 31, Type of Contract Location of Gain/(Loss) 2019 2018 2017 (In thousands) Derivatives not designated as hedging instruments: Commodity(1) Oil and gas revenue $ 1,161 $ (1,963 ) $ (12,502 ) Commodity Derivatives, net (71,885 ) 31,430 (59,968 ) Interest rate Interest expense — 493 648 Total derivatives not designated as hedging instruments $ (70,724 ) $ 29,960 $ (71,822 ) ______________________________________ (1) Amounts represent the change in fair value of our provisional oil sales contracts.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
Fair Value Measurements (Tables)	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Schedule of company's assets and liabilities that are measured at fair value on a recurring basis	The following tables present the Company’s assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2019 and 2018 , for each fair value hierarchy level: Fair Value Measurements Using: Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs (Level 1) (Level 2) (Level 3) Total (In thousands) December 31, 2019 Assets: Commodity derivatives $ — $ 15,158 $ — $ 15,158 Provisional oil sales — (3,287 ) — (3,287 ) Liabilities: Commodity derivatives — (20,392 ) — (20,392 ) Total $ — $ (8,521 ) $ — $ (8,521 ) December 31, 2018 Assets: Commodity derivatives $ — $ 52,662 $ — $ 52,662 Provisional oil sales — 435 — 435 Liabilities: Commodity derivatives — (22,353 ) — (22,353 ) Total $ — $ 30,744 $ — $ 30,744
Schedule of carrying values and fair values of financial instruments that are not carried at fair value	The following table presents the carrying values and fair values at December 31, 2019 and 2018 : December 31, 2019 December 31, 2018 Carrying Value Fair Value Carrying Value Fair Value (In thousands) Senior Notes $ 642,550 $ 664,957 $ — $ — Senior Secured Notes — — 511,873 525,026 Corporate Revolver — — 325,000 325,000 Facility 1,400,000 1,400,000 1,325,000 1,325,000 Total $ 2,042,550 $ 2,064,957 $ 2,161,873 $ 2,175,026

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
Asset Retirement Obligations (Tables)	Dec. 31, 2019
Asset Retirement Obligation Disclosure [Abstract]
Schedule of changes in asset retirement obligations	The following table summarizes the changes in the Company’s asset retirement obligations: December 31, 2019 2018 (In thousands) Asset retirement obligations: Beginning asset retirement obligations $ 151,953 $ 66,595 Additions associated with Equatorial Guinea - Ceiba Field and Okume Complex 114,395 — Additions associated with the acquisition of DGE — 74,482 Liabilities incurred during period 11,218 5,311 Liabilities settled during period (7,156 ) (3,345 ) Revisions in estimated retirement obligations (49,471 ) — Accretion expense 14,114 8,910 Ending asset retirement obligations $ 235,053 $ 151,953

Equity-based Compensation (Tabl

Equity-based Compensation (Tables)	12 Months Ended
Equity-based Compensation (Tables)	Dec. 31, 2019
Share-based Payment Arrangement [Abstract]
Schedule of plan activity	The following table reflects the outstanding restricted stock awards as of December 31, 2019 : Service Vesting Restricted Stock Awards Weighted- Average Grant-Date Fair Value Market / Service Vesting Restricted Stock Awards Weighted- Average Grant-Date Fair Value (In thousands) (In thousands) Outstanding at December 31, 2016: 488 $ 8.83 — $ — Granted — — — — Forfeited — — — — Vested (268 ) 8.97 — — Outstanding at December 31, 2017: 220 8.64 — — Granted — — — — Forfeited — — — — Vested (220 ) 8.64 — — Outstanding at December 31, 2018: — — — — There has been no additional restricted stock activity subsequent to December 31, 2018. The following table reflects the outstanding restricted stock units as of December 31, 2019 : Service Vesting Restricted Stock Units Weighted- Average Grant-Date Fair Value Market / Service Vesting Restricted Stock Units Weighted-Average Grant-Date Fair Value (In thousands) (In thousands) Outstanding at December 31, 2016: 4,160 $ 6.91 7,194 $ 12.29 Granted 2,085 6.43 2,175 9.50 Forfeited (137 ) 6.91 (21 ) 6.21 Vested (1,925 ) 7.51 (896 ) 15.43 Outstanding at December 31, 2017: 4,183 6.39 8,452 11.26 Granted 2,402 7.07 8,111 12.38 Forfeited (229 ) 6.40 (302 ) 8.95 Vested (2,241 ) 6.95 (9,545 ) 13.75 Outstanding at December 31, 2018: 4,115 6.42 6,716 9.02 Granted 3,228 5.01 3,195 6.02 Forfeited (591 ) 5.90 (813 ) 7.93 Vested (2,021 ) 5.95 (1,300 ) 6.32 Outstanding at December 31, 2019: 4,731 5.71 7,798 8.42

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
Income Taxes (Tables)	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Schedule of components of income (loss) before income taxes	The components of loss before income taxes were as follows: Years Ended December 31, 2019 2018 2017 (In thousands) United States $ (149,919 ) $ 41,026 $ 6,068 Bermuda — (73,979 ) (66,914 ) Foreign—other 175,036 (17,907 ) (117,009 ) Income (loss) before income taxes $ 25,117 $ (50,860 ) $ (177,855 )
Schedule of components of the provision for income taxes attributable to the entity's income (loss) before income taxes	The components of the provision for income taxes attributable to our income (loss) before income taxes consist of the following: Years Ended December 31, 2019 2018 2017 (In thousands) Current: United States $ 185 $ 122 $ 10,976 Bermuda — — — Foreign—other 171,079 33,864 24,456 Total current 171,264 33,986 35,432 Deferred: United States (18,776 ) 8,514 15,310 Bermuda — — — Foreign—other (71,594 ) 631 (5,805 ) Total deferred (90,370 ) 9,145 9,505 Income tax expense $ 80,894 $ 43,131 $ 44,937
Schedule of reconciliation of income tax expense and the reported effective tax rate	Our reconciliation of income tax expense (benefit) computed by applying our statutory rate and the reported effective tax rate on income or (loss) from continuing operations is as follows: Years Ended December 31, 2019 2018 2017 (In thousands) Tax at statutory rate(1) $ 5,275 $ (10,681 ) $ — Foreign income (loss) taxed at different rates 32,690 5,013 9,381 Net non-taxable expense / insurance recoveries (13,352 ) 3,256 (30 ) West Leo arbitration settlement — (2,834 ) 1,736 Non-deductible insurance premiums 2,625 — — Non-deductible compensation 3,545 2,643 1,680 Deferred tax liability - undistributed earnings — (2,565 ) 2,565 Non-deductible and other items 3,998 656 3,790 Equity earnings - net of tax — (15,305 ) — Tax shortfall (windfall) on equity-based compensation, net 1,224 (387 ) 3,086 Change in valuation allowance 44,889 63,335 6,008 Change in U.S. tax rate — — 16,721 Total tax expense $ 80,894 $ 43,131 $ 44,937 Effective tax rate(2) 322 % 85 % 25 % ______________________________________ (1) On December 28, 2018, we changed our jurisdiction of incorporation from Bermuda to the State of Delaware. Kosmos Energy Ltd. discontinued as a Bermuda exempted company pursuant to Section 132G of the Companies Act 1981 of Bermuda and, pursuant to Section 265 of the General Corporation Law of the State of Delaware (the “DGCL”), continued its existence under the DGCL as a corporation organized in the State of Delaware. As a result, the statutory tax rate for the 2019 and 2018 reconciliation of income tax expense is the U.S. statutory tax rate of 21% . Our 2017 reconciliation of income tax expense is based on the Bermuda statutory tax rate of 0% . (2) The effective tax rate during the years ended December 31, 2019 , 2018 and 2017 , were impacted by losses of $132.1 million , $261.2 million and $164.4 million
Schedule of tax effects of significant temporary differences to deferred tax assets and liabilities	The tax effects of significant temporary differences giving rise to deferred tax assets and liabilities are as follows: December 31, 2019 2018 (In thousands) Deferred tax assets: Foreign capitalized operating expenses $ 175,330 $ 128,809 Foreign net operating losses 19,576 28,050 United States net operating losses 58,903 59,336 United States deferred interest expense 15,426 — Equity compensation 13,700 11,408 Unrealized derivative losses 1,471 — Asset retirement obligation and other 43,159 29,450 Total deferred tax assets 327,565 257,053 Valuation allowance (201,749 ) (156,860 ) Total deferred tax assets, net 125,816 100,193 Deferred tax liabilities: Depletion, depreciation and amortization related to property and equipment (746,258 ) (547,389 ) Unrealized derivative gains — (15,979 ) Total deferred tax liabilities (746,258 ) (563,368 ) Net deferred tax liability $ (620,442 ) $ (463,175 )

Net Income (Loss) Per Share (Ta

Net Income (Loss) Per Share (Tables)	12 Months Ended
Net Income (Loss) Per Share (Tables)	Dec. 31, 2019
Earnings Per Share [Abstract]
Schedule of reconciliation between net income (loss) and the amounts used to compute basic and diluted net income (loss) per share and the weighted average shares outstanding used to compute basic and diluted net income (loss) per share	Years Ended December 31, 2019 2018 2017 (In thousands, except per share data) Numerator: Net loss allocable to common stockholders $ (55,777 ) $ (93,991 ) $ (222,792 ) Denominator: Weighted average number of shares outstanding: Basic 401,368 404,585 388,375 Restricted stock awards and units(1)(2) — — — Diluted 401,368 404,585 388,375 Net loss per share: Basic $ (0.14 ) $ (0.23 ) $ (0.57 ) Diluted $ (0.14 ) $ (0.23 ) $ (0.57 ) ______________________________________ (1) Our service vesting restricted stock awards represent participating securities because they participate in non-forfeitable dividends with common equity owners. Income allocable to participating securities represents the distributed and undistributed earnings attributable to the participating securities. Our restricted stock awards with market and service vesting criteria and all restricted stock units are not considered to be participating securities and, therefore, are excluded from the basic net income (loss) per share calculation. Our service vesting restricted stock awards do not participate in undistributed net losses because they are not contractually obligated to do so and, therefore, are excluded from the basic net income (loss) per share calculation in periods we are in a net loss position. All restricted stock awards were fully vested in January 2018. (2) For the years ended December 31, 2019 , 2018 and 2017 , we excluded 15.3 million , 10.6 million and 12.9 million outstanding restricted stock awards and restricted stock units, respectively, from the computations of diluted net income per share because the effect would have been anti‑dilutive. All restricted stock awards were fully vested in January 2018.

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
Commitments and Contingencies (Tables)	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Schedule of components of lease cost	The table below presents supplemental cash flow information related to leases during the year ended December 31, 2019 : December 31, 2019 (In thousands) Operating cash flows for operating leases $ 5,082 Investing cash flows for operating leases $ 13,855 The components of lease cost for the year ended December 31, 2019 is as follows: December 31, 2019 (In thousands) Operating lease cost $ 5,480 Short-term lease cost 15,874 Total lease cost $ 21,354
Schedule of other information leases	Other information related to operating leases at December 31, 2019 , is as follows: December 31, 2019 (In thousands, except lease term and discount rate) Balance sheet classifications Other assets (right-of-use assets) $ 20,008 Accrued liabilities (current maturities of leases) 1,139 Other long-term liabilities (non-current maturities of leases) 22,240 Weighted average remaining lease term 8.8 years Weighted average discount rate 9.8 %
Schedule of future minimum rental commitments	Future minimum rental commitments under our leases at December 31, 2019 , are as follows: Operating Leases(1) (In thousands) 2020 $ 3,379 2021 4,201 2022 4,264 2023 4,327 2024 3,491 Thereafter 16,112 Total undiscounted lease payments $ 35,774 Less: Imputed interest (12,395 ) Total lease liabilities $ 23,379 __________________________________ (1) Does not include purchase commitments for jointly owned fields and facilities where we are not the operator and excludes commitments for exploration activities, including well commitments, in our petroleum contracts.

Additional Financial Informat_2

Additional Financial Information (Tables)	12 Months Ended
Additional Financial Information (Tables)	Dec. 31, 2019
Additional Financial Information
Schedule of accrued liabilities	Accrued liabilities consisted of the following: December 31, 2019 2018 (In thousands) Accrued liabilities: Exploration, development and production $ 152,490 $ 92,613 Current asset retirement obligations 4,527 6,617 General and administrative expenses 44,575 39,373 Interest 33,584 18,152 Income taxes 103,566 8,958 Taxes other than income 3,375 4,613 Derivatives 4,837 441 Revenue payable 32,482 24,379 Other 1,268 450 $ 380,704 $ 195,596
Schedule of other expenses, net incurred	Other expenses, net incurred during the period is comprised of the following: Years Ended December 31, 2019 2018 2017 (In thousands) Loss on disposal of inventory $ 4,590 $ 280 $ 866 Gain on insurance settlements (3,509 ) — (461 ) Loss on ARO liability settlements 193 — — Disputed charges and related costs, net of recoveries 4,149 (9,753 ) 4,962 Restructuring charges 11,528 — — Other, net 7,697 2,972 (76 ) Other expenses, net $ 24,648 $ (6,501 ) $ 5,291

Business Segment Information (T

Business Segment Information (Tables)	12 Months Ended
Business Segment Information (Tables)	Dec. 31, 2019
Segment Reporting [Abstract]
Schedule of Business Segment Information	Ghana Equatorial Guinea Mauritania / Senegal U.S. Gulf of Mexico Corporate & Other Eliminations Total (in thousands) Year ended December 31, 2019 Revenues and other income: Oil and gas revenue $ 738,909 $ 300,547 $ — $ 459,960 $ — $ — $ 1,499,416 Gain on sale of assets — — — — 10,528 — 10,528 Other income, net 5 — — 1,194 155,866 (157,100 ) (35 ) Total revenues and other income 738,914 300,547 — 461,154 166,394 (157,100 ) 1,509,909 Costs and expenses: Oil and gas production 188,207 90,607 — 123,799 — — 402,613 Facilities insurance modifications, net (24,254 ) — — — — — (24,254 ) Exploration expenses 204 13,350 11,181 115,765 40,455 — 180,955 General and administrative 18,618 6,643 8,222 25,456 159,539 (108,468 ) 110,010 Depletion, depreciation and amortization 268,866 75,565 62 214,592 4,776 — 563,861 Interest and other financing costs, net(1) 72,226 (634 ) (26,537 ) 21,266 95,887 (7,134 ) 155,074 Derivatives, net — — — 30,387 41,498 — 71,885 Other expenses, net 40,382 (563 ) 12,056 2,691 11,580 (41,498 ) 24,648 Total costs and expenses 564,249 184,968 4,984 533,956 353,735 (157,100 ) 1,484,792 Income (loss) before income taxes 174,665 115,579 (4,984 ) (72,802 ) (187,341 ) — 25,117 Income tax expense 50,293 49,192 — (8,419 ) (10,172 ) — 80,894 Net income (loss) $ 124,372 $ 66,387 $ (4,984 ) $ (64,383 ) $ (177,169 ) $ — $ (55,777 ) Consolidated capital expenditures $ 98,285 $ 63,798 $ 12,556 $ 232,891 $ 33,206 $ — $ 440,736 As of December 31, 2019 Property and equipment, net $ 1,487,114 $ 464,420 $ 438,800 $ 1,216,453 $ 35,545 $ — $ 3,642,332 Total assets $ 1,654,266 $ 650,607 $ 581,317 $ 3,251,420 $ 12,144,312 $ (13,964,690 ) $ 4,317,232 ______________________________________ (1) Interest expense is recorded based on actual third-party and intercompany debt agreements. Capitalized interest is recorded on the business unit where the assets reside. Ghana Equatorial Guinea(1) Mauritania / Senegal U.S. Gulf of Mexico(2) Corporate & Other Eliminations(3) Total (in thousands) Year ended December 31, 2018 Revenues and other income: Oil and gas revenue $ 739,070 $ 360,649 $ — $ 147,596 $ — $ (360,649 ) $ 886,666 Gain on sale of assets — 7,666 — — — — 7,666 Other income, net (17 ) (238 ) — 11 $ 150,635 (142,354 ) 8,037 Total revenues and other income 739,053 368,077 — 147,607 150,635 (503,003 ) 902,369 Costs and expenses: Oil and gas production 189,104 73,843 — 30,470 5,153 (73,843 ) 224,727 Facilities insurance modifications, net 6,955 — — — — — 6,955 Exploration expenses 58,276 38,164 7,262 66,962 131,180 (352 ) 301,492 General and administrative 19,342 5,351 5,220 10,534 168,542 (109,133 ) 99,856 Depletion, depreciation and amortization 265,805 134,983 61 59,835 4,134 (134,983 ) 329,835 Interest and other financing costs, net(3) 86,738 (12 ) (25,386 ) 7,487 39,483 (7,134 ) 101,176 Derivatives, net — — — (57,615 ) 26,185 — (31,430 ) Loss on equity method investments, net — — — — — (72,881 ) (72,881 ) Other expenses, net 16,414 (814 ) (23 ) 598 3,510 (26,186 ) (6,501 ) Total costs and expenses 642,634 251,515 (12,866 ) 118,271 378,187 (424,512 ) 953,229 Income (loss) before income taxes 96,419 116,562 12,866 29,336 (227,552 ) (78,491 ) (50,860 ) Income tax expense (benefit) 34,494 78,491 — 6,163 2,474 (78,491 ) 43,131 Net income (loss) $ 61,925 $ 38,071 $ 12,866 $ 23,173 $ (230,026 ) $ — $ (93,991 ) Consolidated capital expenditures $ 105,942 $ 32,156 $ 11,962 $ 95,993 $ 139,381 $ — $ 385,434 As of December 31, 2018 Property and equipment, net $ 1,698,194 $ 3,919 $ 411,448 $ 1,308,670 $ 37,470 $ — $ 3,459,701 Total assets $ 1,930,071 $ 55,302 $ 536,620 $ 3,512,989 $ 10,349,488 $ (12,296,281 ) $ 4,088,189 ______________________________________ (1) Includes our proportionate share of our equity method investment in KTIPI, including our basis difference which is reflected in depletion, depreciation and amortization for the year ended December 31, 2018 , except for capital expenditures. See Note 7 - Equity Method Investments for additional information regarding our equity method investments. (2) Represents activity commencing September 14, 2018, the DGE acquisition date. (3) Includes elimination of proportionate consolidation amounts recorded for KTIPI to reconcile to (Gain) loss on equity method investments, net as reported in the consolidated statements of operations. (4) Interest expense is recorded based on actual third-party and intercompany debt agreements. Capitalized interest is recorded on the business unit where the assets reside. Ghana Equatorial Guinea(1) Mauritania / Senegal U.S. Gulf of Mexico Corporate & Other Eliminations(2) Total (in thousands) Year ended December 31, 2017 Revenues and other income: Oil and gas revenue $ 578,139 $ 27,308 $ — $ — $ — $ (27,308 ) $ 578,139 Gain on sale of assets — — — — — — — Other income, net 5 147 — — $ 219,968 (161,423 ) 58,697 Total revenues and other income 578,144 27,455 — — 219,968 (188,731 ) 636,836 Costs and expenses: Oil and gas production 137,584 7,755 — — (10,734 ) (7,755 ) 126,850 Facilities insurance modifications, net (820 ) — — — — — (820 ) Exploration expenses 394 86 71,456 — 144,114 — 216,050 General and administrative 14,836 672 8,298 — 138,661 (94,165 ) 68,302 Depletion, depreciation and amortization 251,890 11,181 20 — 3,293 (11,181 ) 255,203 Interest and other financing costs, net(3) 71,592 — (16,065 ) — 29,202 (7,134 ) 77,595 Derivatives, net — — — — 59,968 — 59,968 Loss on equity method investments, net — — 11,486 — — (5,234 ) 6,252 Other expenses, net 64,768 — 867 — (376 ) (59,968 ) 5,291 Total costs and expenses 540,244 19,694 76,062 — 364,128 (185,437 ) 814,691 Income (loss) before income taxes 37,900 7,761 (76,062 ) — (144,160 ) (3,294 ) (177,855 ) Income tax expense (benefit) 18,649 3,294 3 — 26,285 (3,294 ) 44,937 Net income (loss) $ 19,251 $ 4,467 $ (76,065 ) $ — $ (170,445 ) $ — $ (222,792 ) Consolidated capital expenditures $ 5,545 $ 1,995 $ (80,929 ) $ — $ 130,821 $ — $ 57,432 As of December 31, 2017 Property and equipment, net $ 1,901,127 $ 1,908 $ 381,422 $ — $ 33,371 $ — $ 2,317,828 Total assets $ 2,263,824 $ 237,835 $ 570,044 $ — $ 8,671,437 $ (8,550,537 ) $ 3,192,603 ______________________________________ (1) Includes our proportionate share of our equity method investment in KTIPI, including our basis difference which is reflected in depletion, depreciation and amortization for the year ended December 31, 2017, except for capital expenditures. See Note 7 - Equity Method Investments for additional information regarding our equity method investments. (2) Includes elimination of proportionate consolidation amounts recorded for KTIPI to reconcile to (Gain) loss on equity method investments, net as reported in the consolidated statements of operations. (3) Interest expense is recorded based on actual third-party and intercompany debt agreements. Capitalized interest is recorded on the business unit where the assets reside. Years Ended December 31, 2019 2018 2017 (In thousands) Consolidated capital expenditures: Consolidated Statements of Cash Flows - Investing activities: Oil and gas assets $ 340,217 $ 213,806 $ 140,495 Other property 11,796 7,935 2,858 Adjustments: Changes in capital accruals 33,717 26,669 (6,337 ) Exploration expense, excluding unsuccessful well costs and leasehold impairments(1) 93,142 178,293 172,849 Capitalized interest (28,077 ) (28,331 ) (30,282 ) Proceeds on sale of assets (16,713 ) (13,703 ) (222,068 ) Other 6,654 765 (83 ) Total consolidated capital expenditures $ 440,736 $ 385,434 $ 57,432 ______________________________________ (1)

Supplemental Quarterly Financ_2

Supplemental Quarterly Financial Information (Unaudited) (Table)	12 Months Ended
	Dec. 31, 2019
Quarterly Financial Information Disclosure [Abstract]
Schedule of Supplemental Quarterly Financial Information (Unaudited)	Quarter Ended March 31, June 30, September 30, December 31, (In thousands, except per share data) 2019 Revenues and other income $ 296,790 $ 395,934 $ 356,970 $ 460,215 Costs and expenses 358,370 346,495 317,435 462,492 Net income (loss) (52,906 ) 16,837 16,065 (35,773 ) Net income (loss) per share: Basic(1) (0.13 ) 0.04 0.04 (0.09 ) Diluted(1) (0.13 ) 0.04 0.04 (0.09 ) 2018 Revenues and other income $ 127,177 $ 215,473 $ 250,219 $ 309,500 Costs and expenses 201,751 364,091 364,912 22,475 Net income (loss) (50,226 ) (103,273 ) (126,057 ) 185,565 Net income (loss) per share: Basic(1) (0.13 ) (0.26 ) (0.31 ) 0.44 Diluted(1) (0.13 ) (0.26 ) (0.31 ) 0.43 _______________________________ (1) The sum of the quarterly earnings per share information may not add to the annual earnings per share information as a result of rounding.

Organization (Details)

Organization (Details) - segment	12 Months Ended
Organization (Details) - segment	Dec. 31, 2019	Dec. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of reportable geographic areas	4	4

Accounting Policies - Cash, Cas

Accounting Policies - Cash, Cash Equivalents, and Restricted Cash (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Accounting Policies [Abstract]
Cash and cash equivalents	$ 224,502	$ 173,515	$ 233,412
Restricted cash - current	4,302	4,527	56,380
Restricted cash - long-term	542	7,574	15,194
Total cash, cash equivalents and restricted cash shown in the consolidated statements of cash flows	$ 229,346	$ 185,616	$ 304,986	$ 273,195

Accounting Policies - Narrative

Accounting Policies - Narrative (Details) - USD ($) $ / shares in Units, shares in Millions	1 Months Ended	12 Months Ended
	Nov. 30, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Jan. 01, 2019
Restricted Cash
Restricted cash - current		$ 4,302,000	$ 4,527,000	$ 56,380,000
Restricted cash - long-term		542,000	7,574,000	15,194,000
Receivables
Allowance for doubtful accounts		2,700,000	1,200,000
Inventories
Materials and supplies inventory		112,300,000	83,400,000
Hydrocarbons inventory		2,100,000	1,400,000
Write down of materials and supplies		4,590,000	280,000	866,000
Impairment of Long-lived Assets
Impairment of oil and gas		0
Revenue Recognition
Oil and gas imbalances		0	0
Restructuring Charges
Restructuring charges		11,528,000	$ 0	$ 0
Treasury Stock
Shares repurchased (in shares)	35
Shares repurchased price (in dollars per share)	$ 5.38
Shares repurchased	$ 188,000,000
Concentration of Credit Risk
Operating lease asset		20,008,000
Lease liability		23,379,000
Accounting Standards Update 2016-02
Concentration of Credit Risk
Operating lease asset					$ 21,700,000
Lease liability					$ 21,700,000
DGE Acquisition
Inventories
Inventory acquired		$ 22,100,000
Sales Revenue \| Customer Concentration Risk
Concentration of Credit Risk
Concentration risk percentage		20.00%	11.00%
Minimum
Depletion, Depreciation and Amortization
Estimated useful lives (in years)		1 year
Maximum
Depletion, Depreciation and Amortization
Estimated useful lives (in years)		8 years
Capitalized Interest \| Minimum
Capitalized Interest
Expected construction period for capitalization of interest costs on major projects		1 year
Restricted Cash \| Petroleum Agreements - Performance Guarantees
Restricted Cash
Restricted cash - current		$ 4,300,000	$ 4,500,000
Restricted cash - long-term		300,000	7,400,000
Restricted Cash \| Non-Petroleum Agreements
Restricted Cash
Restricted cash - long-term		$ 200,000	$ 200,000

Accounting Policies - Useful Li

Accounting Policies - Useful Lives (Details)	12 Months Ended
Accounting Policies - Useful Lives (Details)	Dec. 31, 2019
Minimum
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	1 year
Maximum
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	8 years
Leasehold improvements \| Minimum
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	1 year
Leasehold improvements \| Maximum
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	8 years
Office furniture, fixtures and computer equipment \| Minimum
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	3 years
Office furniture, fixtures and computer equipment \| Maximum
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	7 years
Vehicles
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	5 years

Accounting Policies - Summary o

Accounting Policies - Summary of Oil and Gas Revenue (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disaggregation of Revenue [Line Items]
Provisional oil sales contracts	$ (70,724)	$ 29,960	$ (71,822)
Oil and gas revenue	1,499,416	886,666	578,139
Equatorial Guinea
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	297,831	0	0
Ghana
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	740,464	741,033	590,642
Gulf of Mexico
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	459,960	147,596	0
Oil and gas revenue
Disaggregation of Revenue [Line Items]
Provisional oil sales contracts	1,161	(1,963)	(12,503)
Oil and gas revenue	$ 1,499,416	$ 886,666	$ 578,139

Acquisitions and Divestitures -

Acquisitions and Divestitures - 2019 Acquisitions (Details) $ in Thousands	1 Months Ended						3 Months Ended	12 Months Ended
	Nov. 30, 2019	Sep. 30, 2019km²meter	Mar. 31, 2019km²	Aug. 31, 2018km²sub_period	Jun. 30, 2018km²	Oct. 31, 2017	Mar. 31, 2019km²sub_period	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Business Acquisition [Line Items]
Gain on sale of assets \| $								$ 10,528	$ 7,666	$ 0
Block 6
Business Acquisition [Line Items]
Participating interest percentage	25.00%
Block 11
Business Acquisition [Line Items]
Participating interest percentage	35.00%
Petroleum Agreement \| Marine XXI Block
Business Acquisition [Line Items]
Participating interest percentage							85.00%
Area of petroleum exploration			2,350				2,350
Initial exploration period							4 years
3D seismic requirements (in square kilometers)							2,200
Number of sub-periods \| sub_period							2
First sub exploration period							3 years
Petroleum Agreement \| Block EG-21 and Block S and Block W
Business Acquisition [Line Items]
Participating interest percentage						80.00%
Area of petroleum exploration				6,000
Initial exploration period				5 years
3D seismic requirements (in square kilometers)				6,000
Number of sub-periods \| sub_period				2
First sub exploration period				3 years
Farm-in Agreement \| Block EG-24
Business Acquisition [Line Items]
Area of petroleum exploration					3,500
Initial exploration period					3 years
3D seismic requirements (in square kilometers)					3,000
First sub exploration period					4 years
Participation interest acquired			80.00%		40.00%
Farm-in Agreement \| Northern Cape Ultra Deep Block
Business Acquisition [Line Items]
Area of petroleum exploration		6,930
Initial exploration period		2 years
Participation interest acquired		45.00%
Farm-out Agreements \| Block EG-21 and Block S and Block W
Business Acquisition [Line Items]
Participating interest percentage				40.00%
Gain on sale of assets \| $									$ 7,700
Farm-out Agreements \| Blocks 6 and 11
Business Acquisition [Line Items]
Gain on sale of assets \| $								$ 10,500
SNPC \| Petroleum Agreement \| Marine XXI Block
Business Acquisition [Line Items]
Carried participating interest			15.00%				15.00%
Percentage converted from carried to participating			15.00%				15.00%
Guinea Equatorial De Petroleos \| Petroleum Agreement \| Block EG-21 and Block S and Block W
Business Acquisition [Line Items]
Carried participating interest				20.00%
Percentage converted from carried to participating				20.00%
Guinea Equatorial De Petroleos \| Farm-in Agreement \| Block EG-24
Business Acquisition [Line Items]
Carried participating interest			20.00%				20.00%
Percentage converted from carried to participating			20.00%				20.00%
Shell Sao Tome and Principe B.V. \| Farm-out Agreements \| Block 6
Business Acquisition [Line Items]
Participating interest percentage	20.00%
Shell Sao Tome and Principe B.V. \| Farm-out Agreements \| Block 11
Business Acquisition [Line Items]
Participating interest percentage	30.00%
Minimum \| Farm-in Agreement \| Northern Cape Ultra Deep Block
Business Acquisition [Line Items]
Water depths \| meter		2,500
Maximum \| Farm-in Agreement \| Northern Cape Ultra Deep Block
Business Acquisition [Line Items]
Water depths \| meter		3,100

Acquisitions and Divestitures_2

Acquisitions and Divestitures - 2018 Acquisitions (Details)	1 Months Ended					4 Months Ended
Acquisitions and Divestitures - 2018 Acquisitions (Details)	Mar. 31, 2019	Oct. 31, 2018company	Sep. 30, 2018USD ($)	Jun. 30, 2018km²	Mar. 31, 2018km²block	Dec. 31, 2018USD ($)	Nov. 30, 2018USD ($)	Feb. 28, 2018USD ($)
Business Acquisition [Line Items]
Number of companies in alliance \| company		2
Deep Gulf Energy, LP
Business Acquisition [Line Items]
Total purchase price			$ 1,275,382,000
Cash consideration paid			952,586,000
Fair value of common stock			307,944,000
Transaction related costs			14,852,000
Revenue of acquiree since acquisition date						$ 147,600,000
Operating expenses of acquiree since acquisition date						30,500,000
Blocks 10 and 13 \| Petroleum Agreement
Business Acquisition [Line Items]
Participating interest percentage					35.00%
Area of petroleum exploration \| km²					13,600
Initial exploration period					4 years
First sub exploration period					4 years
3D seismic requirements (in square kilometers) \| km²					13,500
Number of blocks \| block					2
Block EG-24 \| Farm-in Agreement
Business Acquisition [Line Items]
Area of petroleum exploration \| km²				3,500
Initial exploration period				3 years
First sub exploration period				4 years
3D seismic requirements (in square kilometers) \| km²				3,000
Participation interest acquired	80.00%			40.00%
BP \| Blocks 10 and 13 \| Petroleum Agreement
Business Acquisition [Line Items]
Participating interest percentage					50.00%
ANP STP \| Blocks 10 and 13 \| Petroleum Agreement
Business Acquisition [Line Items]
Carried participating interest					15.00%
Guinea Equatorial De Petroleos \| Block EG-24 \| Farm-in Agreement
Business Acquisition [Line Items]
Carried participating interest	20.00%
Percentage converted from carried to participating	20.00%
Common Stock \| Deep Gulf Energy, LP
Business Acquisition [Line Items]
Fair value of common stock			307,900,000
Revolving Credit Facility \| Facility
Business Acquisition [Line Items]
Additional commitments			$ 200,000,000			$ 100,000,000	$ 100,000,000	$ 500,000,000

Acquisitions and Divestitures_3

Acquisitions and Divestitures - 2018 Acquisitions Schedule (Details) - Deep Gulf Energy, LP - USD ($) $ / shares in Units, $ in Thousands	Sep. 14, 2018	Sep. 30, 2018
Fair value of assets acquired:
Proved oil and gas properties		$ 1,037,511
Unproved oil and gas properties		298,159
Accounts receivable and other		180,989
Total assets acquired		1,516,659
Fair value of liabilities assumed:
Accrued liabilities and other		126,530
Asset retirement obligations		74,482
Derivative liabilities		40,265
Total liabilities assumed		241,277
Cash consideration paid		952,586
Fair value of common stock		307,944
Transaction related costs		14,852
Total purchase price		1,275,382
Common Stock
Fair value of liabilities assumed:
Fair value of common stock		$ 307,900
Common shares issued (in shares)	34,993,585
Common Stock
Fair value of liabilities assumed:
Share price (in dollars per share)	$ 8.80

Acquisitions and Divestitures_4

Acquisitions and Divestitures - 2017 Acquisitions (Details) km² in Thousands

1 Months Ended

3 Months Ended

12 Months Ended

Aug. 31, 2018USD ($)km²sub_periodblock

Dec. 31, 2017USD ($)km²blockMBbls

Oct. 31, 2017block

Sep. 30, 2017

Aug. 31, 2017USD ($)

Apr. 30, 2017

Feb. 28, 2017

Jan. 31, 2017instrument

Dec. 31, 2016USD ($)

Dec. 31, 2017USD ($)MBbls

Mar. 31, 2017USD ($)

Dec. 31, 2017USD ($)$ / bblMBbls

Dec. 31, 2018km²

Nov. 30, 2015USD ($)

Kosmos BP Senegal Limited | Cayar Offshore Profond And Saint Louis Offshore Profond Blocks

Acquisitions and Divestitures

Participating interest percentage

60.00%

Farm-out Agreements | Block EG-21 and Block S and Block W

Acquisitions and Divestitures

Participating interest percentage

40.00%

Gain on sale of assets

$ 7,700,000

Sales and Purchase Agreement | Kosmos BP Senegal Limited | Cayar Offshore Profond And Saint Louis Offshore Profond Blocks

Acquisitions and Divestitures

Participating interest percentage

60.00%

65.00%

Equity increase in each contract area

5.00%

Sales and Purchase Agreement and Farm-out Agreements | Mauritania And Senegal Offshore Block

Acquisitions and Divestitures

Reduction of oil and gas properties with unproved reserves

$ 221,900,000

Petroleum Agreement | Block EG-21 and Block S and Block W

Acquisitions and Divestitures

Participating interest percentage

80.00%

Number of blocks | block

Area of petroleum exploration | km²

Initial exploration period

5 years

Number of sub-periods | sub_period

First sub exploration period

3 years

Second sub exploration period

2 years

3D seismic requirements (in square kilometers) | km²

Petroleum Agreement | Block CI-526, Block CI-602, Block CI-603, Block CI-707, and Block CI-708

Acquisitions and Divestitures

Participating interest percentage

45.00%

Number of blocks | block

Area of petroleum exploration | km²

Initial exploration period

3 years

3D seismic requirements (in square kilometers) | km²

Timis Corporation Limited | Cayar Offshore Profond And Saint Louis Offshore Profond Blocks

Acquisitions and Divestitures

Participating interest percentage

30.00%

BP | Farm-out Agreements | Block C6 Block C8 Block C12 and Block C13 Mauritania

Acquisitions and Divestitures

Participation interest acquired

62.00%

Number of blocks covered by farm-out agreements | instrument

BP | Sales and Purchase Agreement | Kosmos BP Senegal Limited

Acquisitions and Divestitures

Participation interest acquired

49.99%

BP | Sales and Purchase Agreement and Farm-out Agreements | Mauritania And Senegal Offshore Block

Acquisitions and Divestitures

Upfront amount of cash received

$ 162,000,000

Spending by third party for exploration and appraisal costs

228,000,000

Spending by third party for exploration and appraisal costs, initial estimate

221,000,000

Spending by third party for Kosmos' development costs

$ 533,000,000

BP | Petroleum Agreement | Block CI-526, Block CI-602, Block CI-603, Block CI-707, and Block CI-708

Acquisitions and Divestitures

Participating interest percentage

45.00%

Timis Corporation Limited

Acquisitions and Divestitures

Line of credit agreement maximum

$ 30,000,000

Amount received, result of agreement termination

$ 16,000,000

Timis Corporation Limited | Cayar Offshore Profond And Saint Louis Offshore Profond Blocks

Acquisitions and Divestitures

Participating interest percentage

30.00%

Timis Corporation Limited | Farm-in Agreement | Cayar Offshore Profond And Saint Louis Offshore Profond Blocks

Acquisitions and Divestitures

Maximum cost per contingent exploration well

$ 120,000,000

Tullow | Farm-in Agreement | Block C18 Offshore Mauritania

Acquisitions and Divestitures

Participating interest percentage

15.00%

Hess | Ceiba Field and Okume Complex Assets

Acquisitions and Divestitures

Paying interest

85.00%

Revenue interests

80.75%

Trident Energy | Farm-out Agreements | Block EG-21 and Block S and Block W

Acquisitions and Divestitures

Participation interest acquired

40.00%

Guinea Equatorial De Petroleos | Petroleum Agreement | Block EG-21 and Block S and Block W

Acquisitions and Divestitures

Carried participating interest

20.00%

Percentage converted from carried to participating

20.00%

PETROCI | Petroleum Agreement | Block CI-526, Block CI-602, Block CI-603, Block CI-707, and Block CI-708

Acquisitions and Divestitures

Carried participating interest

10.00%

Hess | Sales and Purchase Agreement | Ceiba Field and Okume Complex Assets

Acquisitions and Divestitures

Total purchase price

$ 650,000,000

Cash consideration paid

$ 231,000,000

Maximum | BP | Farm-out Agreements | Mauritania And Senegal Offshore Block

Acquisitions and Divestitures

Amount of potential and variable consideration per barrel | $ / bbl

Number of barrels | MBbls

1,000,000,000

Kosmos BP Senegal Ltd | BP Senegal Investments Limited | Cayar Offshore Profond And Saint Louis Offshore Profond Blocks

Acquisitions and Divestitures

Working interest transferred

30.00%

Hess | Sales and Purchase Agreement | Ceiba Field and Okume Complex Assets

Acquisitions and Divestitures

Ownership percentage

50.00%

Hess | Trident Energy | Sales and Purchase Agreement | Ceiba Field and Okume Complex Assets

Acquisitions and Divestitures

Ownership percentage

50.00%

Joint Interest Billings and R_2

Joint Interest Billings and Related Party Receivables (Details) $ in Thousands	1 Months Ended	12 Months Ended
	Feb. 28, 2019USD ($)Agreement	Dec. 31, 2014	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)
Joint interest billings
Joint interest billings, net			$ 81,424	$ 64,572
Long-term receivables			43,430	19,002
Related party receivable			0	5,580
TEN Discoveries \| GNPC
Joint interest billings
Joint interest billings, net			14,000	14,000
Long-term receivables			16,000	$ 14,000
TEN Discoveries \| GNPC
Joint interest billings
GNPC's paying interest (as a percent)		5.00%
Kosmos-Trident International Petroleum Inc.
Joint interest billings
Ownership percentage				50.00%
Kosmos-Trident International Petroleum Inc. \| Trident Energy
Joint interest billings
Ownership percentage				50.00%
Kosmos-Trident International Petroleum Inc.
Joint interest billings
Related party receivable			0	$ 5,600
Carry Advance Agreements \| National Oil Companies Of Mauritania And Senegal
Joint interest billings
Long-term receivables			$ 27,400
Number of agreements \| Agreement	2
Share of development costs to be financed, up to	$ 239,700

Property and Equipment (Details

Property and Equipment (Details) - USD ($) $ in Thousands	12 Months Ended
Property and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Oil and gas properties:
Proved properties	$ 4,904,648	$ 4,236,489
Unproved properties	814,065	759,472
Total oil and gas properties	5,718,713	4,995,961
Accumulated depletion	(2,093,962)	(1,551,097)
Oil and gas properties, net	3,624,751	3,444,864
Other property	61,598	51,987
Accumulated depreciation	(44,017)	(37,150)
Other property, net	17,581	14,837
Property and equipment, net	3,642,332	3,459,701	$ 2,317,828
Depletion expense	542,900	316,300	244,900
Depreciation expense	$ 6,900	$ 4,600	$ 3,400

Suspended Well Costs - Schedule

Suspended Well Costs - Schedule of Suspended Well Costs (Details) $ in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2018USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2019USD ($)project	Dec. 31, 2018USD ($)project	Dec. 31, 2017USD ($)project
Reconciliation of capitalized exploratory well costs on completed wells
Beginning balance	$ 410,113	$ 367,665	$ 410,113	$ 734,463
Additions to capitalized exploratory well costs pending the determination of proved reserves		78,125	10,518	69,567
Additions associated with the acquisition of DGE		0	26,224	0
Reclassification due to determination of proved reserves		0	(26,224)	(176,881)
Divestitures		0	0	(206,400)
Contribution of oil and gas property to equity method investment - KBSL		0	0	(131,764)
Dissolution of equity method investment - KBSL		0	0	121,128
Capitalized exploratory well costs charged to expense		0	(52,966)	0
Ending balance		445,790	367,665	410,113
Aging of capitalized exploratory well costs and number of projects for which exploratory well costs were capitalized for more than one year
Exploratory well costs capitalized for a period of one year or less					$ 29,121	$ 0	$ 67,159
Exploratory well costs capitalized for a period of one to two years					78,245	299,253	291,252
Exploratory well costs capitalized for a period of three years or longer					338,424	68,412	51,702
Ending balance	410,113	$ 367,665	$ 410,113	$ 410,113	$ 445,790	$ 367,665	$ 410,113
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year \| project					3	3	5
Akasa Discovery
Reconciliation of capitalized exploratory well costs on completed wells
Capitalized exploratory well costs charged to expense	(38,100)
Wawa Discovery
Reconciliation of capitalized exploratory well costs on completed wells
Capitalized exploratory well costs charged to expense	$ (13,600)

Suspended Well Costs - Narrativ

Suspended Well Costs - Narrative (Details) $ in Millions	1 Months Ended	12 Months Ended
Suspended Well Costs - Narrative (Details) $ in Millions	May 31, 2015exploration_well	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Capitalized Contract Cost [Line Items]
Capitalized exploratory well costs subsequently expensed in the same period \| $		$ 3	$ 65.6	$ 43.2
Greater Tortue Ahmeyim Project
Capitalized Contract Cost [Line Items]
Number of additional wells drilled \| exploration_well	3

Equity Method Investments - Nar

Equity Method Investments - Narrative (Details) - USD ($)	Jan. 01, 2019	Dec. 31, 2017	Oct. 31, 2017	Feb. 28, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Schedule of Equity Method Investments [Line Items]
Contribution to equity method investment					$ 0	$ 0	$ 133,893,000
Loss on equity method investments, net					$ 0	$ (72,881,000)	6,252,000
Ceiba Field and Okume Complex Acquisition
Schedule of Equity Method Investments [Line Items]
Ownership percentage	40.375%
Kosmos BP Senegal Limited
Schedule of Equity Method Investments [Line Items]
Ownership percentage				50.01%
Contribution to equity method investment				$ 133,900,000
Loss on equity method investments, net							$ 11,500,000
Kosmos-Trident International Petroleum Inc.
Schedule of Equity Method Investments [Line Items]
Ownership percentage						50.00%
Loss on equity method investments, net		$ (5,234,000)				$ (72,881,000)
Summary of financial information						100.00%
Impairment of equity method investment						$ 0
Cash dividends						$ 257,500,000
Cayar Offshore Profond And Saint Louis Offshore Profond Blocks \| BP Senegal Investments Limited \| Kosmos BP Senegal Limited
Schedule of Equity Method Investments [Line Items]
Participating interest transferred			30.00%
Cayar Offshore Profond And Saint Louis Offshore Profond Blocks \| Kosmos BP Senegal Limited
Schedule of Equity Method Investments [Line Items]
Working interest					30.00%

Equity Method Investments - Sum

Equity Method Investments - Summary of Financial Information (Details) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Costs and expenses:
Equity in earnings - KTIPI		$ 0	$ 72,881	$ (6,252)
Kosmos-Trident International Petroleum Inc.
Assets
Total current assets			149,950
Property and equipment, net			271,627
Other assets			21
Total assets			421,598
Liabilities and shareholders' deficit
Total current liabilities			226,311
Total long term liabilities			536,178
Shareholders' deficit:
Total shareholders' deficit			(340,891)
Total liabilities and shareholders' deficit			421,598
Revenues and other income:
Oil and gas revenue	$ 54,615		721,299
Other income	294		(477)
Total revenues and other income	54,909		720,822
Costs and expenses:
Oil and gas production	15,509		147,685
Depletion and depreciation	10,738		126,983
Other expenses, net	(19)		429
Total costs and expenses	26,228		275,097
Income before income taxes	28,681		445,725
Income tax expense	6,588		156,981
Net income	22,093		288,744
Kosmos' share of net income	11,046		144,372
Basis difference amortization	5,812		71,491
Equity in earnings - KTIPI	$ 5,234		$ 72,881

Equity Method Investments - Ass

Equity Method Investments - Asset Acquisition (Details) - USD ($) $ in Thousands	Jan. 01, 2019	Dec. 31, 2019	Dec. 31, 2018
Schedule of Equity Method Investments [Line Items]
Asset retirement obligations		$ 11,218	$ 5,311
Investment in subsidiaries at equity		$ 0	$ 51,896
Ceiba Field and Okume Complex Acquisition
Schedule of Equity Method Investments [Line Items]
Proved oil and gas properties	$ 372,144
Unproved oil and gas properties	103,909
Prepaids and other	7,273
Total assets acquired	483,326
Asset retirement obligations	114,395
Deferred tax liabilities	247,636
Accrued liabilities and other	69,399
Total liabilities assumed	$ 431,430

Debt - Schedule of Debt (Detail

Debt - Schedule of Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Outstanding debt principal	$ 2,050,000	$ 2,175,000
Unamortized issuance costs and discount	(41,937)	(54,453)
Long-term debt	2,008,063	2,120,547
Senior Notes
Debt Instrument [Line Items]
Unamortized issuance costs and discount	(9,100)	(14,000)
Facility \| Revolving Credit Facility
Debt Instrument [Line Items]
Outstanding debt principal	1,400,000	1,325,000
Unamortized issuance costs and discount	(32,800)	(40,500)
Corporate Revolver \| Revolving Credit Facility
Debt Instrument [Line Items]
Outstanding debt principal	0	325,000
7.125% Senior Notes due 2026 \| Senior Notes
Debt Instrument [Line Items]
Outstanding debt principal	650,000	0
7.875% Senior Notes Due 2021 \| Senior Notes
Debt Instrument [Line Items]
Outstanding debt principal	$ 0	$ 525,000

Debt - Facility (Details)

Debt - Facility (Details) - USD ($)	Jan. 31, 2018	Apr. 30, 2019	Feb. 28, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Mar. 31, 2019	Jan. 31, 2019	Nov. 30, 2018	Sep. 30, 2018
Debt Instrument [Line Items]
Loss on extinguishment of debt				$ 24,794,000	$ 4,324,000	$ 0
Revolving Credit Facility \| Facility
Debt Instrument [Line Items]
Total commitment		$ 1,600,000,000	$ 1,500,000,000				$ 1,700,000,000	$ 1,700,000,000
Additional commitments			500,000,000		$ 100,000,000				$ 100,000,000	$ 200,000,000
Loss on extinguishment of debt			$ 4,100,000
Net deferred financing costs				32,800,000
Commitment reduction		$ 100,000,000
Amount outstanding				1,400,000,000
Undrawn availability				$ 200,000,000
Interval period for payment of interest				6 months
Commitment fee percentage of the then-applicable margin when commitment is available for utilization	40.00%		30.00%
Commitment fee percentage of the then-applicable margin when commitment is not available for utilization				20.00%
Availability period of revolving-credit				1 month
Amount outstanding under letters of credit				$ 0
Revolving Credit Facility \| Facility \| LIBOR \| Minimum
Debt Instrument [Line Items]
Applicable margin (as a percent)				3.25%
Revolving Credit Facility \| Facility \| LIBOR \| Maximum
Debt Instrument [Line Items]
Applicable margin (as a percent)				4.50%

Debt - Corporate Revolver (Deta

Debt - Corporate Revolver (Details) - USD ($)	1 Months Ended	12 Months Ended
Debt - Corporate Revolver (Details) - USD ($)	Aug. 31, 2018	Dec. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Deferred financing costs, net		$ 6,321,000	$ 8,937,000
Revolving Credit Facility \| Corporate Revolver
Debt Instrument [Line Items]
Total commitment	$ 400,000,000
Change in basis points	1.00%
Applicable margin (as a percent)	5.00%
Commitment fee percentage	30.00%	30.00%
Deferred financing costs, net		$ 6,300,000
Undrawn availability		$ 400,000,000
Interval period for payment of interest		6 months
Revolving Credit Facility \| Corporate Revolver \| LIBOR
Debt Instrument [Line Items]
Applicable margin (as a percent)		5.00%

Debt - Revolving Letter of Cred

Debt - Revolving Letter of Credit Facility (Details)	Jun. 30, 2016	Jul. 31, 2016	Dec. 31, 2019USD ($)letter_of_credit	Dec. 31, 2018USD ($)	Jul. 31, 2018USD ($)	Feb. 28, 2018USD ($)	Apr. 30, 2017USD ($)	Mar. 31, 2017USD ($)	Jul. 31, 2015USD ($)
Revolving Letter of Credit Facility
Debt Instrument [Line Items]
Total commitment				$ 20,000,000	$ 40,000,000	$ 73,000,000	$ 70,000,000	$ 115,000,000	$ 75,000,000
Additional commitments									$ 50,000,000
Applicable margin (as a percent)	0.50%	0.80%
Commitment fee percentage		0.65%
Number of letters of credit \| letter_of_credit			5
Amount outstanding			$ 3,100,000
Letter of Credit Arrangement
Debt Instrument [Line Items]
Number of letters of credit \| letter_of_credit			2
Amount outstanding			$ 20,400,000

Debt - Senior Notes (Details)

Debt - Senior Notes (Details) - USD ($)	1 Months Ended			12 Months Ended
Debt - Senior Notes (Details) - USD ($)	Apr. 30, 2019	Apr. 30, 2015	Aug. 31, 2014	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Loss on extinguishment of debt				$ 24,794,000	$ 4,324,000	$ 0
7.875% Senior Notes Due 2021 \| Senior Notes
Debt Instrument [Line Items]
Interest rate			7.875%
Senior notes offering face amount		$ 225,000,000	$ 300,000,000
Proceeds, net of offering discounts and deferred financing costs		$ 206,800,000	$ 292,500,000
Debt redeemed	$ 543,800,000
Loss on extinguishment of debt	$ 22,900,000
Senior Notes 7.125% Due 2026 \| Senior Notes
Debt Instrument [Line Items]
Interest rate	7.125%
Senior notes offering face amount	$ 650,000,000
Proceeds, net of offering discounts and deferred financing costs	$ 640,000,000
Redemption price percentage following change of control	101.00%
Redemption price percentage following sell of certain assets	100.00%
Senior Notes 7.125% Due 2026 \| Any Time Prior to April 4, 2022 \| Senior Notes
Debt Instrument [Line Items]
Maximum percentage of principal amount available to be redeemed with proceeds from equity offerings	40.00%
Redemption price percentage	107.10%
Senior Notes 7.125% Due 2026 \| Any Time Prior to April 4, 2022 with Make-whole Premium \| Senior Notes
Debt Instrument [Line Items]
Redemption price, as a percent of the of principal amount	100.00%

Debt - Redemption Prices (Detai

Debt - Redemption Prices (Details) - Senior Notes - Senior Notes 7.125% Due 2026	1 Months Ended
	Apr. 30, 2019
On or after April 4, 2022, but before April 4, 2023
Debt Instrument [Line Items]
Redemption price, as a percent of the of principal amount	103.60%
On or after April 4, 2023, but before April 4, 2024
Debt Instrument [Line Items]
Redemption price, as a percent of the of principal amount	101.80%
On or after April 4, 2024 and thereafter
Debt Instrument [Line Items]
Redemption price, as a percent of the of principal amount	100.00%

Debt - Maturities (Details)

Debt - Maturities (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Scheduled maturities of debt during the five year period and thereafter
Total	$ 2,050,000	$ 2,175,000
2020	0
2021	174,800
2022	284,200
2023	271,600
2024	440,829
Thereafter	878,571
Debt Instrument [Line Items]
Outstanding debt principal	2,050,000	2,175,000
Senior Notes \| Senior Notes 7.125% Due 2026
Scheduled maturities of debt during the five year period and thereafter
Total	650,000	0
Debt Instrument [Line Items]
Outstanding debt principal	$ 650,000	$ 0

Debt - Debt Interest (Details)

Debt - Debt Interest (Details) - USD ($) $ in Thousands	12 Months Ended
Debt - Debt Interest (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Debt Disclosure [Abstract]
Interest expense	$ 145,507	$ 114,134	$ 92,687
Amortization—deferred financing costs	9,257	9,379	10,204
Loss on extinguishment of debt	24,794	4,324	0
Capitalized interest	(28,077)	(28,331)	(30,282)
Deferred interest	1,919	(1,138)	2,577
Interest income	(3,692)	(3,455)	(3,422)
Other, net	5,366	6,263	5,831
Interest and other financing costs, net	$ 155,074	$ 101,176	$ 77,595

Derivative Financial Instrume_3

Derivative Financial Instruments - Oil Derivative Contracts (Details) - Dated Brent	Jan. 31, 2020$ / bbl	Feb. 24, 2020$ / bblMBbls	Dec. 31, 2019$ / bblMBbls
Term January 2020 To December 2020 \| Three-way collars
Derivative Financial Instruments
Volumes (in MBbl) \| MBbls			6,000
Weighted Average Price per Bbl [Abstract]
Net deferred premium payable/(receivable) (USD per Bbl)			0.45
Swap (USD per Bbl)			0
Put (USD per Bbl)			45
Floor (USD per Bbl)			57.50
Ceiling (USD per Bbl)			80.18
Term January 2020 To December 2020 \| Swaps with sold puts
Derivative Financial Instruments
Volumes (in MBbl) \| MBbls			2,000
Weighted Average Price per Bbl [Abstract]
Net deferred premium payable/(receivable) (USD per Bbl)			0
Swap (USD per Bbl)			60.53
Put (USD per Bbl)			48.75
Floor (USD per Bbl)			0
Ceiling (USD per Bbl)			0
Term January 2020 To December 2020 \| Put spread
Derivative Financial Instruments
Volumes (in MBbl) \| MBbls			6,000
Weighted Average Price per Bbl [Abstract]
Net deferred premium payable/(receivable) (USD per Bbl)			0.75
Swap (USD per Bbl)			0
Put (USD per Bbl)			50
Floor (USD per Bbl)			59.17
Ceiling (USD per Bbl)			0
Term January 2020 To December 2020 \| Sold calls
Derivative Financial Instruments
Volumes (in MBbl) \| MBbls			8,000
Weighted Average Price per Bbl [Abstract]
Net deferred premium payable/(receivable) (USD per Bbl)			1.17
Swap (USD per Bbl)			0
Put (USD per Bbl)			0
Floor (USD per Bbl)			0
Ceiling (USD per Bbl)			85
January 2021 - December 2021 \| Swaps with sold puts
Derivative Financial Instruments
Volumes (in MBbl) \| MBbls			2,000
Weighted Average Price per Bbl [Abstract]
Net deferred premium payable/(receivable) (USD per Bbl)			0
Swap (USD per Bbl)			60.56
Put (USD per Bbl)			47.50
Floor (USD per Bbl)			0
Ceiling (USD per Bbl)			0
January 2021 - December 2021 \| Sold calls
Derivative Financial Instruments
Volumes (in MBbl) \| MBbls			6,000
Weighted Average Price per Bbl [Abstract]
Net deferred premium payable/(receivable) (USD per Bbl)			0
Swap (USD per Bbl)			0
Put (USD per Bbl)			0
Floor (USD per Bbl)			0
Ceiling (USD per Bbl)			71.67
Subsequent Event \| February 2020 - December 2020 \| Three-way collars
Derivative Financial Instruments
Volumes (in MBbl) \| MBbls		3,700
Weighted Average Price per Bbl [Abstract]
Put (USD per Bbl)	42.50	50
Subsequent Event \| January 2021 - December 2021 \| Swaps with sold puts
Derivative Financial Instruments
Volumes (in MBbl) \| MBbls		2,000
Weighted Average Price per Bbl [Abstract]
Put (USD per Bbl)		50
Fixed (usd per bbl)		60

Derivative Financial Instrume_4

Derivative Financial Instruments - Derivative Instruments and Gain/(Loss) from Derivatives (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Derivative instruments, Balance Sheet Location
Derivatives assets—current	$ 12,856	$ 38,785
Derivatives assets—long-term	2,302	14,312
Derivatives liabilities—current	(8,914)	(12,172)
Derivatives liabilities—long-term	(11,478)	(10,181)
Not designated as hedging instruments
Derivative instruments, Balance Sheet Location
Total derivatives not designated as hedging instruments	(8,521)	30,744
Commodity derivatives \| Not designated as hedging instruments
Derivative instruments, Balance Sheet Location
Derivatives assets—current	12,856	38,350
Derivatives assets—long-term	2,302	14,312
Derivatives liabilities—current	(8,914)	(12,172)
Derivatives liabilities—long-term	(11,478)	(10,181)
Deferred premium payable, current	1,000	1,600
Deferred premium payable, noncurrent	300	1,300
Net deferred premiums payable related to commodity derivative contracts - current liabilities	5,500	18,000
Net deferred premiums payable related to commodity derivative contracts - non current liabilities	300	500
Receivables: Oil sales \| Provisional Oil Sales \| Not designated as hedging instruments
Derivative instruments, Balance Sheet Location
Derivatives assets—current	$ (3,287)	$ 435

Derivative Financial Instrume_5

Derivative Financial Instruments - Location of Gain (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Derivative instruments, Location of Gain/(Loss)
Derivative, not designated as hedge, gain (loss)	$ (70,724)	$ 29,960	$ (71,822)
Commodity derivatives \| Oil and gas revenue
Derivative instruments, Location of Gain/(Loss)
Derivative, not designated as hedge, gain (loss)	1,161	(1,963)	(12,502)
Commodity derivatives \| Derivatives, net
Derivative instruments, Location of Gain/(Loss)
Derivative, not designated as hedge, gain (loss)	(71,885)	31,430	(59,968)
Interest rate contracts \| Interest expense
Derivative instruments, Location of Gain/(Loss)
Derivative, not designated as hedge, gain (loss)	$ 0	$ 493	$ 648

Fair Value Measurements (Detail

Fair Value Measurements (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Carrying Value
Liabilities:
Long-term debt	$ 2,042,550	$ 2,161,873
Fair Value
Liabilities:
Long-term debt	2,064,957	2,175,026
Recurring basis
Liabilities:
Total derivatives not designated as hedging instruments	(8,521)	30,744
Recurring basis \| Commodity derivatives
Assets:
Derivative asset, fair value	15,158	52,662
Liabilities:
Derivative liability, fair value	(20,392)	(22,353)
Recurring basis \| Provisional Oil Sales
Assets:
Derivative asset, fair value	(3,287)	435
Recurring basis \| Level 1
Liabilities:
Total derivatives not designated as hedging instruments	0	0
Recurring basis \| Level 1 \| Commodity derivatives
Assets:
Derivative asset, fair value	0	0
Liabilities:
Derivative liability, fair value	0	0
Recurring basis \| Level 1 \| Provisional Oil Sales
Assets:
Derivative asset, fair value	0	0
Recurring basis \| Level 2
Liabilities:
Total derivatives not designated as hedging instruments	(8,521)	30,744
Recurring basis \| Level 2 \| Commodity derivatives
Assets:
Derivative asset, fair value	15,158	52,662
Liabilities:
Derivative liability, fair value	(20,392)	(22,353)
Recurring basis \| Level 2 \| Provisional Oil Sales
Assets:
Derivative asset, fair value	(3,287)	435
Recurring basis \| Level 3
Liabilities:
Total derivatives not designated as hedging instruments	0	0
Recurring basis \| Level 3 \| Commodity derivatives
Assets:
Derivative asset, fair value	0	0
Liabilities:
Derivative liability, fair value	0	0
Recurring basis \| Level 3 \| Provisional Oil Sales
Assets:
Derivative asset, fair value	0	0
Senior Notes 7.125% Due 2026 \| Senior Notes \| Carrying Value
Liabilities:
Long-term debt	642,550	0
Senior Notes 7.125% Due 2026 \| Senior Notes \| Fair Value
Liabilities:
Long-term debt	664,957	0
7.875% Senior Notes Due 2021 \| Senior Notes \| Carrying Value
Liabilities:
Long-term debt	0	511,873
7.875% Senior Notes Due 2021 \| Senior Notes \| Fair Value
Liabilities:
Long-term debt	0	525,026
Corporate Revolver \| Revolving Credit Facility \| Carrying Value
Liabilities:
Long-term debt	0	325,000
Corporate Revolver \| Revolving Credit Facility \| Fair Value
Liabilities:
Long-term debt	0	325,000
Facility \| Revolving Credit Facility \| Carrying Value
Liabilities:
Long-term debt	1,400,000	1,325,000
Facility \| Revolving Credit Facility \| Fair Value
Liabilities:
Long-term debt	$ 1,400,000	$ 1,325,000

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	Jan. 01, 2019	Dec. 31, 2019	Dec. 31, 2018
Asset retirement obligations:
Beginning asset retirement obligations	$ 151,953	$ 151,953	$ 66,595
Liabilities incurred during period		11,218	5,311
Liabilities settled during period		(7,156)	(3,345)
Revisions in estimated retirement obligations		(49,471)	0
Accretion expense		14,114	8,910
Ending asset retirement obligations		235,053	151,953
DGE
Asset retirement obligations:
Additions associated with an acquisition		0	74,482
Equatorial Guinea
Asset retirement obligations:
Additions associated with an acquisition		$ 114,395	$ 0
Ceiba Field and Okume Complex Acquisition
Asset retirement obligations:
Liabilities incurred during period	$ 114,395
Ownership percentage	40.375%

Equity-based Compensation - Nar

Equity-based Compensation - Narrative (Details) - USD ($)	1 Months Ended			12 Months Ended
Equity-based Compensation - Narrative (Details) - USD ($)	Jan. 31, 2020	Jan. 31, 2018	Jan. 31, 2015	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Equity-based Compensation
Net tax shortfall (windfall) related to equity-based compensation				$ 3,545,000	$ 2,643,000	$ 1,680,000
LTIP
Equity-based Compensation
Additional shares authorized (in shares)		11,000,000	15,000,000
Number of shares authorized (in shares)				50,500,000
Number of shares remaining available for grant (in shares)				10,600,000
Compensation expense recognized				$ 32,400,000	35,200,000	40,000,000
Tax benefit				4,900,000	6,600,000	13,200,000
Net tax shortfall (windfall) related to equity-based compensation				$ 1,200,000	(400,000)	3,100,000
LTIP \| Minimum
Equity-based Compensation
Vesting period				3 years
LTIP \| Restricted Stock Awards and Restricted Stock Units
Equity-based Compensation
Fair value of awards vested				$ 20,300,000	$ 85,100,000	$ 21,200,000
LTIP \| Market/Service Vesting Restricted Stock Awards
Equity-based Compensation
Granted (in dollars per share)					$ 0	$ 0
LTIP \| Market/Service Vesting Restricted Stock Units
Equity-based Compensation
Granted (in dollars per share)				$ 6.02	12.38	9.50
LTIP \| Market/Service Vesting Restricted Stock Units \| Subsequent Event
Equity-based Compensation
Granted (in shares)	2,600,000
LTIP \| Market/Service Vesting Restricted Stock Units \| Minimum
Equity-based Compensation
Granted (in dollars per share)				$ 4.83
Expected volatility				44.00%
Risk-free interest rate				0.80%
Expected quarterly dividends (in dollars per share)				$ 0.045
LTIP \| Market/Service Vesting Restricted Stock Units \| Maximum
Equity-based Compensation
Vesting percentage of the awards granted				200.00%
Granted (in dollars per share)				$ 15.71
Expected volatility				52.00%
Risk-free interest rate				2.50%
Expected quarterly dividends (in dollars per share)				$ 0.050
LTIP \| Service Vesting Restricted Stock Units
Equity-based Compensation
Granted (in dollars per share)				$ 5.01	$ 7.07	$ 6.43
LTIP \| Service Vesting Restricted Stock Units \| Subsequent Event
Equity-based Compensation
Granted (in shares)	2,700,000
LTIP \| Restricted stock units
Equity-based Compensation
Compensation expense not yet recognized				$ 27,400,000
Weighted average period over which compensation expense is to be recognized				1 year 9 months 18 days
LTIP \| Restricted stock units \| Subsequent Event
Equity-based Compensation
Compensation expense not yet recognized	$ 40,800,000
Weighted average period over which compensation expense is to be recognized	3 years

Equity-based Compensation - Sch

Equity-based Compensation - Schedule of Awards (Details) - LTIP - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Service Vesting Restricted Stock Awards
Outstanding unvested awards activity
Outstanding at the beginning of the period (in shares)	0	220	488
Granted (in shares)		0	0
Forfeited (in shares)		0	0
Vested (in shares)		(220)	(268)
Outstanding at the end of the period (in shares)		0	220
Weighted-Average Grant-Date Fair Value
Outstanding at beginning of the period (in dollars per share)	$ 0	$ 8.64	$ 8.83
Granted (in dollars per share)		0	0
Forfeited (in dollars per share)		0	0
Vested (in dollars per share)		8.64	8.97
Outstanding at the end of the period (in dollars per share)		$ 0	$ 8.64
Market/Service Vesting Restricted Stock Awards
Outstanding unvested awards activity
Outstanding at the beginning of the period (in shares)	0	0	0
Granted (in shares)		0	0
Forfeited (in shares)		0	0
Vested (in shares)		0	0
Outstanding at the end of the period (in shares)		0	0
Weighted-Average Grant-Date Fair Value
Outstanding at beginning of the period (in dollars per share)	$ 0	$ 0	$ 0
Granted (in dollars per share)		0	0
Forfeited (in dollars per share)		0	0
Vested (in dollars per share)		0	0
Outstanding at the end of the period (in dollars per share)		$ 0	$ 0
Service Vesting Restricted Stock Units
Outstanding unvested awards activity
Outstanding at the beginning of the period (in shares)	4,115	4,183	4,160
Granted (in shares)	3,228	2,402	2,085
Forfeited (in shares)	(591)	(229)	(137)
Vested (in shares)	(2,021)	(2,241)	(1,925)
Outstanding at the end of the period (in shares)	4,731	4,115	4,183
Weighted-Average Grant-Date Fair Value
Outstanding at beginning of the period (in dollars per share)	$ 6.42	$ 6.39	$ 6.91
Granted (in dollars per share)	5.01	7.07	6.43
Forfeited (in dollars per share)	5.90	6.40	6.91
Vested (in dollars per share)	5.95	6.95	7.51
Outstanding at the end of the period (in dollars per share)	$ 5.71	$ 6.42	$ 6.39
Market/Service Vesting Restricted Stock Units
Outstanding unvested awards activity
Outstanding at the beginning of the period (in shares)	6,716	8,452	7,194
Granted (in shares)	3,195	8,111	2,175
Forfeited (in shares)	(813)	(302)	(21)
Vested (in shares)	(1,300)	(9,545)	(896)
Outstanding at the end of the period (in shares)	7,798	6,716	8,452
Weighted-Average Grant-Date Fair Value
Outstanding at beginning of the period (in dollars per share)	$ 9.02	$ 11.26	$ 12.29
Granted (in dollars per share)	6.02	12.38	9.50
Forfeited (in dollars per share)	7.93	8.95	6.21
Vested (in dollars per share)	6.32	13.75	15.43
Outstanding at the end of the period (in dollars per share)	$ 8.42	$ 9.02	$ 11.26

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) - USD ($) $ in Millions	Jan. 01, 2019	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Taxes
Tax Cuts and Jobs Act of 2017, income tax expense (benefit)		$ 16.7
Effective tax rate			322.00%	85.00%	25.00%
Federal statutory income tax rate percent			21.00%	21.00%
Foreign net operating loss carryforwards			$ 68.8
Foreign net operating loss carryforwards expiring in 2020			0.6
Foreign net operating loss carryforwards expiring in 2021			0.5
Foreign net operating loss carryforwards expiring in 2022			15.6
Foreign net operating loss carryforwards expiring in 2023			0.7
Foreign net operating loss carryforwards expiring in 2024			1.4
Foreign net operating loss carryforwards not expiring			50
Material uncertain tax positions			$ 0
Ceiba Field and Okume Complex Acquisition
Income Taxes
Ownership percentage	40.375%
United States
Income Taxes
Effective tax rate			12.00%	84.00%	433.00%
Foreign net operating loss carryforwards not expiring			$ 280.5
Ghana
Income Taxes
Effective tax rate			29.00%	36.00%	49.00%
Equatorial Guinea
Income Taxes
Effective tax rate			37.00%
Foreign—other
Income Taxes
Effective tax rate			0.00%
Federal statutory income tax rate percent			0.00%

Income Taxes - Components of In

Income Taxes - Components of Income (Loss) and Provision for Income Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Taxes
Income (loss) before income taxes	$ 25,117	$ (50,860)	$ (177,855)
Components of the provision for income taxes attributable to income (loss) before income taxes
Current	171,264	33,986	35,432
Deferred	(90,370)	9,145	9,505
Income tax expense	80,894	43,131	44,937
Reconciliation of income tax expense and the reported effective tax rate
Tax at statutory rate	5,275	(10,681)	0
Foreign income (loss) taxed at different rates	32,690	5,013	9,381
Net non-taxable expense / insurance recoveries	(13,352)	3,256	(30)
West Leo arbitration settlement	0	(2,834)	1,736
Non-deductible insurance premiums	2,625	0	0
Non-deductible compensation	3,545	2,643	1,680
Deferred tax liability - undistributed earnings	0	(2,565)	2,565
Non-deductible and other items	3,998	656	3,790
Equity earnings - net of tax	0	(15,305)	0
Tax shortfall (windfall) on equity-based compensation, net	1,224	(387)	3,086
Change in valuation allowance	44,889	63,335	6,008
Change in U.S. tax rate	$ 0	$ 0	$ 16,721
Effective tax rate	322.00%	85.00%	25.00%
Federal statutory income tax rate percent	21.00%	21.00%
Impact of losses incurred in jurisdictions in which company is not subject to taxes on effective tax rate	$ 132,100	$ 261,200	$ 164,400
United States
Income Taxes
Income (loss) before income taxes	(149,919)	41,026	6,068
Components of the provision for income taxes attributable to income (loss) before income taxes
Current	185	122	10,976
Deferred	(18,776)	8,514	15,310
Bermuda
Income Taxes
Income (loss) before income taxes	0	(73,979)	(66,914)
Components of the provision for income taxes attributable to income (loss) before income taxes
Current	0	0	0
Deferred	0	0	0
Foreign—other
Income Taxes
Income (loss) before income taxes	175,036	(17,907)	(117,009)
Components of the provision for income taxes attributable to income (loss) before income taxes
Current	171,079	33,864	24,456
Deferred	$ (71,594)	$ 631	$ (5,805)
Bermuda
Reconciliation of income tax expense and the reported effective tax rate
Federal statutory income tax rate percent			0.00%

Income Taxes - Deferred Taxes (

Income Taxes - Deferred Taxes (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Deferred tax assets:
Foreign capitalized operating expenses	$ 175,330	$ 128,809
Foreign net operating losses	19,576	28,050
United States net operating losses	58,903	59,336
United States deferred interest expense	15,426	0
Equity compensation	13,700	11,408
Unrealized derivative losses	1,471	0
Asset retirement obligation and other	43,159	29,450
Total deferred tax assets	327,565	257,053
Valuation allowance	(201,749)	(156,860)
Total deferred tax assets, net	125,816	100,193
Deferred tax liabilities:
Depletion, depreciation and amortization related to property and equipment	(746,258)	(547,389)
Unrealized derivative gains	0	(15,979)
Total deferred tax liabilities	(746,258)	(563,368)
Net deferred tax liability	$ (620,442)	$ (463,175)

Net Income (Loss) Per Share (De

Net Income (Loss) Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Numerator:
Net loss allocable to common stockholders	$ (35,773)	$ 16,065	$ 16,837	$ (52,906)	$ 185,565	$ (126,057)	$ (103,273)	$ (50,226)	$ (55,777)	$ (93,991)	$ (222,792)
Weighted average number of shares outstanding:
Basic (in shares)									401,368	404,585	388,375
Restricted stock awards and units (in shares)									0	0	0
Diluted (in shares)									401,368	404,585	388,375
Net loss per share:
Basic (in dollars per share)	$ (0.09)	$ 0.04	$ 0.04	$ (0.13)	$ 0.44	$ (0.31)	$ (0.26)	$ (0.13)	$ (0.14)	$ (0.23)	$ (0.57)
Diluted (in dollars per share)	$ (0.09)	$ 0.04	$ 0.04	$ (0.13)	$ 0.43	$ (0.31)	$ (0.26)	$ (0.13)	$ (0.14)	$ (0.23)	$ (0.57)
Outstanding restricted stock awards and units excluded from the computations of diluted net income per share (in shares)									15,300	10,600	12,900

Commitments and Contingencies -

Commitments and Contingencies - Narrative (Details) $ / shares in Units, $ in Millions	Feb. 24, 2020$ / shares	Oct. 14, 2011	Feb. 28, 2019	Dec. 31, 2019USD ($)km²meterexploration_well	Dec. 31, 2018USD ($)$ / shares	Dec. 31, 2017$ / shares
Commitments and contingencies
Dividends declared per common stock (in dollars per share) \| $ / shares					$ 0	$ 0
Subsequent Event
Commitments and contingencies
Dividends declared per common stock (in dollars per share) \| $ / shares	$ 0.0452
Minimum
Commitments and contingencies
Lease agreements term				1 year
Maximum
Commitments and contingencies
Lease agreements term				10 years
Sao Tome and Principe
Commitments and contingencies
Number of exploration wells \| exploration_well				1
3D seismic requirements (in square kilometers) \| km²				13,500
Namibia
Commitments and contingencies
Number of exploration wells \| exploration_well				1
Mauritania
Commitments and contingencies
Number of exploration wells \| exploration_well				2
South Africa
Commitments and contingencies
2D seismic requirements \| meter				500
U.S. Gulf of Mexico \| Surety Bond
Commitments and contingencies
Cash collateral \| $				$ 0	$ 0.6
U.S. Gulf of Mexico \| Bureau Of Ocean Energy Management \| Surety Bond
Commitments and contingencies
Required performance bonds \| $				222	200.9
U.S. Gulf of Mexico \| Third Party \| Surety Bond
Commitments and contingencies
Required performance bonds \| $				$ 3.7	$ 3.7
Jubilee UUOA
Commitments and contingencies
Unit interest after redetermination process (as a percent)		24.10%
GTA UUOA
Commitments and contingencies
Payment interest on development activities			26.70%

Commitments and Contingencies_2

Commitments and Contingencies - Components of Lease Costs (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)
Leases [Abstract]
Operating lease cost	$ 5,480
Short-term lease cost	15,874
Total lease cost	$ 21,354

Commitments and Contingencies_3

Commitments and Contingencies - Other Information Related to Operating Leases (Details) $ in Thousands	Dec. 31, 2019USD ($)
Leases [Abstract]
Other assets (right-of-use assets)	$ 20,008
Accrued liabilities (current maturities of leases)	1,139
Other long-term liabilities (non-current maturities of leases)	$ 22,240
Weighted average remaining lease term	8 years 9 months 18 days
Weighted average discount rate	9.80%

Commitments and Contingencies_4

Commitments and Contingencies - Supplemental Cash Flow Information Related to Leases (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)
Leases [Abstract]
Operating cash flows for operating leases	$ 5,082
Investing cash flows for operating leases	$ 13,855

Commitments and Contingencies_5

Commitments and Contingencies - Future Minimum Rental Commitments (Details) $ in Thousands	Dec. 31, 2019USD ($)
Leases [Abstract]
2020	$ 3,379
2021	4,201
2022	4,264
2023	4,327
2024	3,491
Thereafter	16,112
Total undiscounted lease payments	35,774
Less: Imputed interest	(12,395)
Total lease liabilities	$ 23,379

Additional Financial Informat_3

Additional Financial Information - Schedule of Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Accrued liabilities:
Exploration, development and production	$ 152,490	$ 92,613
Current asset retirement obligations	4,527	6,617
General and administrative expenses	44,575	39,373
Interest	33,584	18,152
Income taxes	103,566	8,958
Taxes other than income	3,375	4,613
Derivatives	4,837	441
Revenue payable	32,482	24,379
Other	1,268	450
Accrued liabilities	$ 380,704	$ 195,596

Additional Financial Informat_4

Additional Financial Information - Narrative (Details) - USD ($)	1 Months Ended	12 Months Ended
	Jul. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Trading Activity, Gains and Losses, Net [Line Items]
Gain on sale of assets		$ 10,528,000	$ 7,666,000	$ 0
Other Income, net		0	0	58,700,000
Recoveries	$ 12,900,000
Oil and Gas Production Expense
Trading Activity, Gains and Losses, Net [Line Items]
Insurance recoveries		$ 0	0	$ 17,100,000
Farm-out Agreements \| Block EG-21 and Block S and Block W
Trading Activity, Gains and Losses, Net [Line Items]
Gain on sale of assets			$ 7,700,000

Additional Financial Informat_5

Additional Financial Information - Other Expenses, Net (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Additional Financial Information
Loss on disposal of inventory	$ 4,590	$ 280	$ 866
Gain on insurance settlements	(3,509)	0	(461)
Loss on ARO liability settlements	193	0	0
Disputed charges and related costs, net of recoveries	4,149	(9,753)	4,962
Restructuring charges	11,528	0	0
Other, net	7,697	2,972	(76)
Other expenses, net	$ 24,648	$ (6,501)	$ 5,291

Business Segment Information -

Business Segment Information - Financial Information (Details) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019USD ($)	Sep. 30, 2019USD ($)	Jun. 30, 2019USD ($)	Mar. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Sep. 30, 2018USD ($)	Jun. 30, 2018USD ($)	Mar. 31, 2018USD ($)	Dec. 31, 2019USD ($)segment	Dec. 31, 2018USD ($)segment	Dec. 31, 2017USD ($)
Segment Reporting Information [Line Items]
Number of reportable segments \| segment									4	4
Oil and gas revenue									$ 1,499,416	$ 886,666	$ 578,139
Gain on sale of assets									10,528	7,666	0
Other income, net									(35)	8,037	58,697
Total revenues and other income	$ 460,215	$ 356,970	$ 395,934	$ 296,790	$ 309,500	$ 250,219	$ 215,473	$ 127,177	1,509,909	902,369	636,836
Oil and gas production									402,613	224,727	126,850
Facilities insurance modifications, net									(24,254)	6,955	(820)
Exploration expenses									180,955	301,492	216,050
General and administrative									110,010	99,856	68,302
Depletion, depreciation and amortization									563,861	329,835	255,203
Interest and other financing costs, net									155,074	101,176	77,595
Derivatives, net									71,885	(31,430)	59,968
Loss on equity method investments, net									0	(72,881)	6,252
Other expenses, net									24,648	(6,501)	5,291
Total costs and expenses	462,492	317,435	346,495	358,370	22,475	364,912	364,091	201,751	1,484,792	953,229	814,691
Income (loss) before income taxes									25,117	(50,860)	(177,855)
Income tax expense (benefit)									80,894	43,131	44,937
Net income (loss)	(35,773)	$ 16,065	$ 16,837	$ (52,906)	185,565	$ (126,057)	$ (103,273)	$ (50,226)	(55,777)	(93,991)	(222,792)
Consolidated capital expenditures									440,736	385,434	57,432
Property and equipment, net	3,642,332				3,459,701				3,642,332	3,459,701	2,317,828
Total assets	4,317,232				4,088,189				4,317,232	4,088,189	3,192,603
Corporate & Other
Segment Reporting Information [Line Items]
Oil and gas revenue									0	0	0
Gain on sale of assets									10,528	0	0
Other income, net									155,866	150,635	219,968
Total revenues and other income									166,394	150,635	219,968
Oil and gas production									0	5,153	(10,734)
Facilities insurance modifications, net									0	0	0
Exploration expenses									40,455	131,180	144,114
General and administrative									159,539	168,542	138,661
Depletion, depreciation and amortization									4,776	4,134	3,293
Interest and other financing costs, net									95,887	39,483	29,202
Derivatives, net									41,498	26,185	59,968
Loss on equity method investments, net										0	0
Other expenses, net									11,580	3,510	(376)
Total costs and expenses									353,735	378,187	364,128
Income (loss) before income taxes									(187,341)	(227,552)	(144,160)
Income tax expense (benefit)									(10,172)	2,474	26,285
Net income (loss)									(177,169)	(230,026)	(170,445)
Consolidated capital expenditures									33,206	139,381	130,821
Property and equipment, net	35,545				37,470				35,545	37,470	33,371
Total assets	12,144,312				10,349,488				12,144,312	10,349,488	8,671,437
Eliminations
Segment Reporting Information [Line Items]
Oil and gas revenue									0	(360,649)	(27,308)
Gain on sale of assets									0	0	0
Other income, net									(157,100)	(142,354)	(161,423)
Total revenues and other income									(157,100)	(503,003)	(188,731)
Oil and gas production									0	(73,843)	(7,755)
Facilities insurance modifications, net									0	0	0
Exploration expenses									0	(352)	0
General and administrative									(108,468)	(109,133)	(94,165)
Depletion, depreciation and amortization									0	(134,983)	(11,181)
Interest and other financing costs, net									(7,134)	(7,134)	(7,134)
Derivatives, net									0	0	0
Loss on equity method investments, net										(72,881)	(5,234)
Other expenses, net									(41,498)	(26,186)	(59,968)
Total costs and expenses									(157,100)	(424,512)	(185,437)
Income (loss) before income taxes									0	(78,491)	(3,294)
Income tax expense (benefit)									0	(78,491)	(3,294)
Net income (loss)									0	0	0
Consolidated capital expenditures									0	0	0
Property and equipment, net	0				0				0	0	0
Total assets	(13,964,690)				(12,296,281)				(13,964,690)	(12,296,281)	(8,550,537)
Ghana \| Operating Segments
Segment Reporting Information [Line Items]
Oil and gas revenue									738,909	739,070	578,139
Gain on sale of assets									0	0	0
Other income, net									5	(17)	5
Total revenues and other income									738,914	739,053	578,144
Oil and gas production									188,207	189,104	137,584
Facilities insurance modifications, net									(24,254)	6,955	(820)
Exploration expenses									204	58,276	394
General and administrative									18,618	19,342	14,836
Depletion, depreciation and amortization									268,866	265,805	251,890
Interest and other financing costs, net									72,226	86,738	71,592
Derivatives, net									0	0	0
Loss on equity method investments, net										0	0
Other expenses, net									40,382	16,414	64,768
Total costs and expenses									564,249	642,634	540,244
Income (loss) before income taxes									174,665	96,419	37,900
Income tax expense (benefit)									50,293	34,494	18,649
Net income (loss)									124,372	61,925	19,251
Consolidated capital expenditures									98,285	105,942	5,545
Property and equipment, net	1,487,114				1,698,194				1,487,114	1,698,194	1,901,127
Total assets	1,654,266				1,930,071				1,654,266	1,930,071	2,263,824
Equatorial Guinea \| Operating Segments
Segment Reporting Information [Line Items]
Oil and gas revenue									300,547	360,649	27,308
Gain on sale of assets									0	7,666	0
Other income, net									0	(238)	147
Total revenues and other income									300,547	368,077	27,455
Oil and gas production									90,607	73,843	7,755
Facilities insurance modifications, net									0	0	0
Exploration expenses									13,350	38,164	86
General and administrative									6,643	5,351	672
Depletion, depreciation and amortization									75,565	134,983	11,181
Interest and other financing costs, net									(634)	(12)	0
Derivatives, net									0	0	0
Loss on equity method investments, net										0	0
Other expenses, net									(563)	(814)	0
Total costs and expenses									184,968	251,515	19,694
Income (loss) before income taxes									115,579	116,562	7,761
Income tax expense (benefit)									49,192	78,491	3,294
Net income (loss)									66,387	38,071	4,467
Consolidated capital expenditures									63,798	32,156	1,995
Property and equipment, net	464,420				3,919				464,420	3,919	1,908
Total assets	650,607				55,302				650,607	55,302	237,835
Mauritania / Senegal \| Operating Segments
Segment Reporting Information [Line Items]
Oil and gas revenue									0	0	0
Gain on sale of assets									0	0	0
Other income, net									0	0	0
Total revenues and other income									0	0	0
Oil and gas production									0	0	0
Facilities insurance modifications, net									0	0	0
Exploration expenses									11,181	7,262	71,456
General and administrative									8,222	5,220	8,298
Depletion, depreciation and amortization									62	61	20
Interest and other financing costs, net									(26,537)	(25,386)	(16,065)
Derivatives, net									0	0	0
Loss on equity method investments, net										0	11,486
Other expenses, net									12,056	(23)	867
Total costs and expenses									4,984	(12,866)	76,062
Income (loss) before income taxes									(4,984)	12,866	(76,062)
Income tax expense (benefit)									0	0	3
Net income (loss)									(4,984)	12,866	(76,065)
Consolidated capital expenditures									12,556	11,962	(80,929)
Property and equipment, net	438,800				411,448				438,800	411,448	381,422
Total assets	581,317				536,620				581,317	536,620	570,044
U.S. Gulf of Mexico \| Operating Segments
Segment Reporting Information [Line Items]
Oil and gas revenue									459,960	147,596	0
Gain on sale of assets									0	0	0
Other income, net									1,194	11	0
Total revenues and other income									461,154	147,607	0
Oil and gas production									123,799	30,470	0
Facilities insurance modifications, net									0	0	0
Exploration expenses									115,765	66,962	0
General and administrative									25,456	10,534	0
Depletion, depreciation and amortization									214,592	59,835	0
Interest and other financing costs, net									21,266	7,487	0
Derivatives, net									30,387	(57,615)	0
Loss on equity method investments, net										0	0
Other expenses, net									2,691	598	0
Total costs and expenses									533,956	118,271	0
Income (loss) before income taxes									(72,802)	29,336	0
Income tax expense (benefit)									(8,419)	6,163	0
Net income (loss)									(64,383)	23,173	0
Consolidated capital expenditures									232,891	95,993	0
Property and equipment, net	1,216,453				1,308,670				1,216,453	1,308,670	0
Total assets	$ 3,251,420				$ 3,512,989				$ 3,251,420	$ 3,512,989	$ 0

Business Segment Information _2

Business Segment Information - Consolidated Capital Expenditures (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Segment Reporting [Abstract]
Oil and gas assets	$ 340,217	$ 213,806	$ 140,495
Other property	11,796	7,935	2,858
Changes in capital accruals	33,717	26,669	(6,337)
Exploration expense, excluding unsuccessful well costs and leasehold impairments	93,142	178,293	172,849
Capitalized interest	(28,077)	(28,331)	(30,282)
Proceeds on sale of assets	(16,713)	(13,703)	(222,068)
Other	6,654	765	(83)
Consolidated capital expenditures	$ 440,736	$ 385,434	$ 57,432

Supplemental Quarterly Financ_3

Supplemental Quarterly Financial Information (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Revenues and other income	$ 460,215	$ 356,970	$ 395,934	$ 296,790	$ 309,500	$ 250,219	$ 215,473	$ 127,177	$ 1,509,909	$ 902,369	$ 636,836
Costs and expenses	462,492	317,435	346,495	358,370	22,475	364,912	364,091	201,751	1,484,792	953,229	814,691
Net loss	$ (35,773)	$ 16,065	$ 16,837	$ (52,906)	$ 185,565	$ (126,057)	$ (103,273)	$ (50,226)	$ (55,777)	$ (93,991)	$ (222,792)
Earnings Per Share [Abstract]
Basic (in dollars per share)	$ (0.09)	$ 0.04	$ 0.04	$ (0.13)	$ 0.44	$ (0.31)	$ (0.26)	$ (0.13)	$ (0.14)	$ (0.23)	$ (0.57)
Diluted (in dollars per share)	$ (0.09)	$ 0.04	$ 0.04	$ (0.13)	$ 0.43	$ (0.31)	$ (0.26)	$ (0.13)	$ (0.14)	$ (0.23)	$ (0.57)

Condensed Parent Company Fina_2

Condensed Parent Company Financial Statements - Balance Sheet (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 224,502	$ 173,515	$ 233,412
Prepaid expenses and other	36,192	68,040
Total current assets	566,557	509,700
Investment in subsidiaries at equity	0	51,896
Deferred financing costs, net of accumulated amortization of $14,681 and $12,065 at December 31, 2019 and December 31, 2018, respectively	6,321	8,937
Restricted cash	542	7,574	15,194
Long-term deferred tax asset	32,779	14,004
Total assets	4,317,232	4,088,189	3,192,603
Current liabilities:
Accounts payable	149,483	176,540
Accrued liabilities	380,704	195,596
Total current liabilities	539,101	384,308
Long-term debt, net	2,008,063	2,120,547
Other long-term liabilities	33,141	9,160
Stockholders’ equity:
Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at December 31, 2019 and December 31, 2018	0	0
Common stock, $0.01 par value; 2,000,000,000 authorized shares; 445,779,367 and 442,914,675 issued at December 31, 2019 and December 31, 2018, respectively	4,458	4,429
Additional paid-in capital	2,297,221	2,341,249
Accumulated deficit	(1,222,970)	(1,167,193)
Treasury stock, at cost, 44,263,269 shares at December 31, 2019 and 2018, respectively	(237,007)	(237,007)
Total stockholders’ equity	841,702	941,478	$ 897,112	$ 1,081,199
Total liabilities and stockholders’ equity	4,317,232	4,088,189
Parent company
Current assets:
Cash and cash equivalents	6,422	6,776
Receivables from subsidiaries	3,819	2,890
Note receivable from subsidiary	0	7,941
Prepaid expenses and other	428	313
Total current assets	10,669	17,920
Investment in subsidiaries at equity	1,159,560	1,432,468
Long-term note receivable from subsidiary	518,844	607,943
Deferred financing costs, net of accumulated amortization of $14,681 and $12,065 at December 31, 2019 and December 31, 2018, respectively	6,321	8,937
Restricted cash	305	305
Long-term deferred tax asset	17,265	(1,132)
Total assets	1,712,964	2,066,441
Current liabilities:
Accounts payable	0	975
Accrued liabilities	11,942	18,972
Total current liabilities	11,942	19,947
Long-term debt, net	640,856	836,016
Long-term note payable to subsidiary	217,000	269,000
Other long-term liabilities	1,464	0
Stockholders’ equity:
Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at December 31, 2019 and December 31, 2018	0	0
Common stock, $0.01 par value; 2,000,000,000 authorized shares; 445,779,367 and 442,914,675 issued at December 31, 2019 and December 31, 2018, respectively	4,458	4,429
Additional paid-in capital	2,297,221	2,341,249
Accumulated deficit	(1,222,970)	(1,167,193)
Treasury stock, at cost, 44,263,269 shares at December 31, 2019 and 2018, respectively	(237,007)	(237,007)
Total stockholders’ equity	841,702	941,478
Total liabilities and stockholders’ equity	$ 1,712,964	$ 2,066,441

Condensed Parent Company Fina_3

Condensed Parent Company Financial Statements - Balance Sheet (Parenthetical) (Details) - USD ($) $ / shares in Units, $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Condensed Balance Sheet Statements, Captions [Line Items]
Deferred financing costs, accumulated amortization	$ 14,681	$ 12,065
Preference shares, par value (in dollars per share)	$ 0.01	$ 0.01
Preference shares, authorized shares	200,000,000	200,000,000
Preference shares, issued shares	0	0
Common shares, par value (in dollars per share)	$ 0.01	$ 0.01
Common shares, authorized shares	2,000,000,000	2,000,000,000
Common shares, issued shares	445,779,367	442,914,675
Treasury stock shares	44,263,269	44,263,269
Parent company
Condensed Balance Sheet Statements, Captions [Line Items]
Deferred financing costs, accumulated amortization	$ 14,681	$ 12,065
Preference shares, par value (in dollars per share)	$ 0.01	$ 0.01
Preference shares, authorized shares	200,000,000	200,000,000
Preference shares, issued shares	0	0
Common shares, par value (in dollars per share)	$ 0.01	$ 0.01
Common shares, authorized shares	2,000,000,000	2,000,000,000
Common shares, issued shares	445,779,367	442,914,675
Treasury stock shares	44,263,269	44,263,269

Condensed Parent Company Fina_4

Condensed Parent Company Financial Statements - Statement of Operations (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Revenues and other income:
Oil and gas revenue									$ 1,499,416	$ 886,666	$ 578,139
Total revenues and other income	$ 460,215	$ 356,970	$ 395,934	$ 296,790	$ 309,500	$ 250,219	$ 215,473	$ 127,177	1,509,909	902,369	636,836
Costs and expenses:
General and administrative									110,010	99,856	68,302
Interest and other financing costs, net									155,074	101,176	77,595
Other expenses, net									24,648	(6,501)	5,291
Total costs and expenses	462,492	317,435	346,495	358,370	22,475	364,912	364,091	201,751	1,484,792	953,229	814,691
Income (loss) before income taxes									25,117	(50,860)	(177,855)
Income tax expense (benefit)									80,894	43,131	44,937
Net income (loss)	$ (35,773)	$ 16,065	$ 16,837	$ (52,906)	$ 185,565	$ (126,057)	$ (103,273)	$ (50,226)	(55,777)	$ (93,991)	$ (222,792)
Dividends declared per common share (in dollars per share)										$ 0	$ 0
Parent company
Revenues and other income:
Oil and gas revenue									0	$ 0	$ 0
Total revenues and other income									0	0	0
Costs and expenses:
General and administrative									40,840	47,279	51,544
General and administrative recoveries—related party									(30,822)	(36,197)	(40,266)
Interest and other financing costs, net									86,104	66,055	55,596
Interest and other financing costs, net—related party									(7,144)	(7,941)	0
Other expenses, net									10	49	40
Equity in (earnings) losses of subsidiaries									(15,064)	23,614	155,878
Total costs and expenses									73,924	92,859	222,792
Income (loss) before income taxes									(73,924)	(92,859)	(222,792)
Income tax expense (benefit)									(18,147)	1,132	0
Net income (loss)									$ (55,777)	$ (93,991)	$ (222,792)
Dividends declared per common share (in dollars per share)									$ 0.1808	$ 0	$ 0

Condensed Parent Company Fina_5

Condensed Parent Company Financial Statements - Statements of Cash Flows (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Operating activities
Net loss	$ (35,773)	$ 16,065	$ 16,837	$ (52,906)	$ 185,565	$ (126,057)	$ (103,273)	$ (50,226)	$ (55,777)	$ (93,991)	$ (222,792)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Equity-based compensation									32,370	35,230	39,913
Depreciation and amortization									573,118	339,214	265,407
Deferred income taxes									(90,370)	9,145	9,505
Loss on extinguishment of debt									24,794	4,324	0
Other									9,069	2,865	5,952
Changes in assets and liabilities:
Decrease in receivables									(29,735)	175,954	29,365
(Increase) decrease in prepaid expenses and other									34,586	(18,731)	(31,710)
Net cash provided by (used in) operating activities									628,150	260,491	236,617
Investing activities
Net cash provided by (used in) investing activities									(363,931)	(985,138)	(152,565)
Financing activities
Payments on long-term debt									(425,000)	(325,000)	(250,000)
Net proceeds from issuance of senior notes									641,875	0	0
Redemption of senior secured notes									(535,338)	0	0
Purchase of treasury stock / tax withholdings									(1,983)	(206,051)	(2,194)
Dividends									(72,599)	0	0
Deferred financing costs									(2,444)	(38,672)	(67)
Net cash provided by (used in) financing activities									(220,489)	605,277	(52,261)
Net increase (decrease) in cash, cash equivalents and restricted cash									43,730	(119,370)	31,791
Cash, cash equivalents and restricted cash at end of period				185,616				304,986	185,616	304,986	273,195
Cash, cash equivalents and restricted cash at beginning of period	229,346				185,616				229,346	185,616	304,986
Parent company
Operating activities
Net loss									(55,777)	(93,991)	(222,792)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Equity in (earnings) losses of subsidiaries									(15,064)	23,614	155,878
Equity-based compensation									32,370	35,230	39,913
Depreciation and amortization									5,039	7,292	3,070
Deferred income taxes									(18,397)	1,132	0
Loss on extinguishment of debt									22,913	0	0
Other									0	268	3,884
Changes in assets and liabilities:
Decrease in receivables									427	1,234	986
(Increase) decrease in prepaid expenses and other									(115)	(23)	127
(Increase) decrease due to/from related party									43,974	(42,163)	14,463
Increase (decrease) in accounts payable and accrued liabilities									(8,754)	816	1,179
Net cash provided by (used in) operating activities									6,616	(66,591)	(3,292)
Investing activities
Investment in subsidiaries									287,972	(36,192)	4,691
Net cash provided by (used in) investing activities									287,972	(36,192)	4,691
Financing activities
Borrowings under long-term debt									0	400,000	0
Payments on long-term debt									(325,000)	(75,000)	0
Net proceeds from issuance of senior notes									641,875	0	0
Redemption of senior secured notes									(535,338)	0	0
Purchase of treasury stock / tax withholdings									(1,983)	(206,051)	(2,194)
Dividends									(72,599)	0	0
Deferred financing costs									(1,897)	(9,382)	0
Net cash provided by (used in) financing activities									(294,942)	109,567	(2,194)
Net increase (decrease) in cash, cash equivalents and restricted cash									(354)	6,784	(795)
Cash, cash equivalents and restricted cash at end of period				$ 7,081				$ 297	7,081	297	1,092
Cash, cash equivalents and restricted cash at beginning of period	$ 6,727				$ 7,081				6,727	7,081	297
Non-cash activity:
Issuance of common stock for related party receivable									$ 0	$ 307,944	$ 0

Valuation and Qualifying Acco_2

Valuation and Qualifying Accounts (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Allowance for doubtful receivables
Changes in valuation and qualifying Accounts
Balance at the beginning of the period	$ 1,211	$ 0	$ 574
Charged to Costs and Expenses	1,324	1,211	77
Charged To Other Accounts	228	0	0
Deductions From Reserves	(15)	0	(651)
Balance at the end of the period	2,748	1,211	0
Allowance for deferred tax assets
Changes in valuation and qualifying Accounts
Balance at the beginning of the period	156,860	93,525	87,517
Charged to Costs and Expenses	44,889	63,335	6,008
Charged To Other Accounts	0	0	0
Deductions From Reserves	0	0	0
Balance at the end of the period	$ 201,749	$ 156,860	$ 93,525