10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)
☒	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2019

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from               to              

Commission file number:  001-35167

Kosmos Energy Ltd.

(Exact name of registrant as specified in its charter)

Delaware		98-0686001
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)
8176 Park Lane
Dallas,	Texas	75231
(Address of principal executive offices)		(Zip Code)

 

Title of each class	Trading Symbol	Name of each exchange on which registered:
Common Stock $0.01 par value	KOS	New York Stock Exchange
		London Stock Exchange

Registrant’s telephone number, including area code: +1 214 445 9600

Not applicable

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes ☒  No ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes ☒  No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	☒	Accelerated filer	☐
Non-accelerated filer	☐	Smaller reporting company	☐
(Do not check if a smaller reporting company)
		Emerging growth company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes ☐  No ☒

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

Class	Outstanding at November 1, 2019
Common Shares, $0.01 par value	401,516,098

TABLE OF CONTENTS

Unless otherwise stated in this report, references to “Kosmos,” “we,” “us” or “the company” refer to Kosmos Energy Ltd. and its wholly owned subsidiaries. We have provided definitions for some of the industry terms used in this report in the “Glossary and Selected Abbreviations” beginning on page 3.

	Page
PART I. FINANCIAL INFORMATION
Glossary and Select Abbreviations	3
Item 1. Financial Statements	8
Consolidated Balance Sheets	8
Consolidated Statements of Operations	9
Consolidated Statements of Stockholders’ Equity	10
Consolidated Statements of Cash Flows	11
Notes to Consolidated Financial Statements	12
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	38
Item 3. Quantitative and Qualitative Disclosures about Market Risk	54
Item 4. Controls and Procedures	56
PART II. OTHER INFORMATION
Item 1. Legal Proceedings	56
Item 1A. Risk Factors	56
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	56
Item 3. Defaults Upon Senior Securities	57
Item 4. Mine Safety Disclosures	57
Item 5. Other Information	57
Item 6. Exhibits	57
Signatures	58
Index to Exhibits	59

2

KOSMOS ENERGY LTD.

GLOSSARY AND SELECTED ABBREVIATIONS

The following are abbreviations and definitions of certain terms that may be used in this report. Unless listed below, all defined terms under Rule 4-10(a) of Regulation S-X shall have their statutorily prescribed meanings.

“2D seismic data”	Two-dimensional seismic data, serving as interpretive data that allows a view of a vertical cross-section beneath a prospective area.
“3D seismic data”	Three-dimensional seismic data, serving as geophysical data that depicts the subsurface strata in three dimensions. 3D seismic data typically provides a more detailed and accurate interpretation of the subsurface strata than 2D seismic data.
"ANP-STP"	Agencia Nacional Do Petroleo De Sao Tome E Principe.
“API”	A specific gravity scale, expressed in degrees, that denotes the relative density of various petroleum liquids. The scale increases inversely with density. Thus lighter petroleum liquids will have a higher API than heavier ones.
“ASC”	Financial Accounting Standards Board Accounting Standards Codification.
“ASU”	Financial Accounting Standards Board Accounting Standards Update.
“Barrel” or “Bbl”	A standard measure of volume for petroleum corresponding to approximately 42 gallons at 60 degrees Fahrenheit.
“BBbl”	Billion barrels of oil.
“BBoe”	Billion barrels of oil equivalent.
“Bcf”	Billion cubic feet.
“Boe”	Barrels of oil equivalent. Volumes of natural gas converted to barrels of oil using a conversion factor of 6,000 cubic feet of natural gas to one barrel of oil.
"BOEM"	Bureau of Ocean Energy Management.
“Boepd”	Barrels of oil equivalent per day.
“Bopd”	Barrels of oil per day.
"BP"	BP p.l.c.
“Bwpd”	Barrels of water per day.
“Debt cover ratio”	The “debt cover ratio” is broadly defined, for each applicable calculation date, as the ratio of (x) total long-term debt less cash and cash equivalents and restricted cash, to (y) the aggregate EBITDAX (see below) of the Company for the previous twelve months.

3

“Developed acreage”	The number of acres that are allocated or assignable to productive wells or wells capable of production.
“Development”	The phase in which an oil or natural gas field is brought into production by drilling development wells and installing appropriate production systems.
"DGE"	Deep Gulf Energy (together with its subsidiaries).
“Dry hole" or "Unsuccessful well”	A well that has not encountered a hydrocarbon bearing reservoir expected to produce in commercial quantities.
“EBITDAX”	Net income (loss) plus (i) exploration expense, (ii) depletion, depreciation and amortization expense, (iii) equity‑based compensation expense, (iv) unrealized (gain) loss on commodity derivatives (realized losses are deducted and realized gains are added back), (v) (gain) loss on sale of oil and gas properties, (vi) interest (income) expense, (vii) income taxes, (viii) loss on extinguishment of debt, (ix) doubtful accounts expense and (x) similar other material items which management believes affect the comparability of operating results. The Facility EBITDAX definition includes 50% of the EBITDAX adjustments of Kosmos-Trident International Petroleum Inc for the period it was an equity method investment and includes Last Twelve Months ("LTM") EBITDAX for any acquisitions and excludes LTM EBITDAX for any divestitures.
"ESP"	Electric submersible pump.
“E&P”	Exploration and production.
“FASB”	Financial Accounting Standards Board.
“Farm-in”	An agreement whereby a party acquires a portion of the participating interest in a block from the owner of such interest, usually in return for cash and/or for taking on a portion of future costs or other performance by the assignee as a condition of the assignment.
“Farm-out”	An agreement whereby the owner of the participating interest agrees to assign a portion of its participating interest in a block to another party for cash and/or for the assignee taking on a portion of future costs and/or other work as a condition of the assignment.
"FEED"	Front End Engineering Design.
“Field life cover ratio”	The “field life cover ratio” is broadly defined, for each applicable forecast period, as the ratio of (x) the forecasted net present value of net cash flow through depletion plus the net present value of the forecast of certain capital expenditures incurred in relation to the Ghana and Equatorial Guinea assets, to (y) the aggregate loan amounts outstanding under the Facility.
"FLNG"	Floating liquefied natural gas.
"FPS"	Floating production system.
“FPSO”	Floating production, storage and offloading vessel.
"GEPetrol"	Guinea Equatorial De Petroleos.

4

"GNPC"	Ghana National Petroleum Corporation.
"KBSL"	Kosmos BP Senegal Limited.
"KTIPI"	Kosmos-Trident International Petroleum Inc.
“Interest cover ratio”	The “interest cover ratio” is broadly defined, for each applicable calculation date, as the ratio of (x) the aggregate EBITDAX (see above) of the Company for the previous twelve months, to (y) interest expense less interest income for the Company for the previous twelve months.
“Loan life cover ratio”	The “loan life cover ratio” is broadly defined, for each applicable forecast period, as the ratio of (x) net present value of forecasted net cash flow through the final maturity date of the Facility plus the net present value of forecasted capital expenditures incurred in relation to the Ghana and Equatorial Guinea assets, to (y) the aggregate loan amounts outstanding under the Facility.
"LNG"	Liquefied natural gas.
“MBbl”	Thousand barrels of oil.
"MBoe"	Thousand barrels of oil equivalent.
“Mcf”	Thousand cubic feet of natural gas.
“Mcfpd”	Thousand cubic feet per day of natural gas.
“MMBbl”	Million barrels of oil.
“MMBoe”	Million barrels of oil equivalent.
"MMBtu"	Million British thermal units.
“MMcf”	Million cubic feet of natural gas.
“MMcfd”	Million cubic feet per day of natural gas.
"MMTPA"	Million metric tonnes per annum.
“Natural gas liquid” or “NGL”	Components of natural gas that are separated from the gas state in the form of liquids. These include propane, butane, and ethane, among others.
"Ophir"	Ophir Energy plc.
“Petroleum contract”	A contract in which the owner of hydrocarbons gives an E&P company temporary and limited rights, including an exclusive option to explore for, develop, and produce hydrocarbons from the lease area.

5

“Petroleum system”	A petroleum system consists of organic material that has been buried at a sufficient depth to allow adequate temperature and pressure to expel hydrocarbons and cause the movement of oil and natural gas from the area in which it was formed to a reservoir rock where it can accumulate.
“Plan of development” or “PoD”	A written document outlining the steps planned to be undertaken to develop a field.
“Productive well”	An exploratory or development well found to be capable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.
“Prospect(s)”	A potential trap that may contain hydrocarbons and is supported by the necessary amount and quality of geologic and geophysical data to indicate a probability of oil and/or natural gas accumulation ready to be drilled. The five required elements (generation, migration, reservoir, seal and trap) must be present for a prospect to work and if any of these fail neither oil nor natural gas may be present, at least not in commercial volumes.
“Proved reserves”	Estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be economically recoverable in future years from known reservoirs under existing economic and operating conditions, as well as additional reserves expected to be obtained through confirmed improved recovery techniques, as defined in SEC Regulation S-X 4-10(a)(2).
“Proved developed reserves”	Those proved reserves that can be expected to be recovered through existing wells and facilities and by existing operating methods.
“Proved undeveloped reserves”	Those proved reserves that are expected to be recovered from future wells and facilities, including future improved recovery projects which are anticipated with a high degree of certainty in reservoirs which have previously shown favorable response to improved recovery projects.
"SNPC"	Société Nationale des Pétroles du Congo.
“Shelf margin”	The path created by the change in direction of the shoreline in reaction to the filling of a sedimentary basin.
"Shell"	Shell Exploration Company B.V.
“Stratigraphy”	The study of the composition, relative ages and distribution of layers of sedimentary rock.
“Stratigraphic trap”	A stratigraphic trap is formed from a change in the character of the rock rather than faulting or folding of the rock and oil is held in place by changes in the porosity and permeability of overlying rocks.
“Structural trap”	A topographic feature in the earth’s subsurface that forms a high point in the rock strata. This facilitates the accumulation of oil and natural gas in the strata.
“Structural-stratigraphic trap”	A structural-stratigraphic trap is a combination trap with structural and stratigraphic features.

6

“Submarine fan”	A fan-shaped deposit of sediments occurring in a deep water setting where sediments have been transported via mass flow, gravity induced, processes from the shallow to deep water. These systems commonly develop at the bottom of sedimentary basins or at the end of large rivers.
“Three-way fault trap”	A structural trap where at least one of the components of closure is formed by offset of rock layers across a fault.
“Trap”	A configuration of rocks suitable for containing hydrocarbons and sealed by a relatively impermeable formation through which hydrocarbons will not migrate.
"Trident"	Trident Energy.
“Undeveloped acreage”	Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains discovered resources.

7

KOSMOS ENERGY LTD. 

CONSOLIDATED BALANCE SHEETS 

(In thousands, except share data)

	September 30, 2019			December 31, 2018
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	203,646		$	173,515
Restricted cash	7,745			4,527
Receivables:
Joint interest billings, net	54,409			64,572
Oil sales	54,612			48,164
Related party	—			5,580
Other	20,016			21,690
Inventories	140,218			84,827
Prepaid expenses and other	47,315			68,040
Derivatives	22,067			38,785
Total current assets	550,028			509,700
Property and equipment:
Oil and gas properties, net	3,780,989			3,444,864
Other property, net	18,047			14,837
Property and equipment, net	3,799,036			3,459,701
Other assets:
Equity method investment	—			51,896
Restricted cash	3,667			7,574
Long-term receivables	36,957			19,002
Deferred financing costs, net of accumulated amortization of $14,027 and $12,065 at September 30, 2019 and December 31, 2018, respectively	6,975			8,937
Deferred tax assets	37,838			14,004
Derivatives	10,535			14,312
Other	23,223			3,063
Total assets	$	4,468,259		$	4,088,189
Liabilities and stockholders’ equity
Current liabilities:
Accounts payable	$	171,495		$	176,540
Accrued liabilities	292,419			195,596
Derivatives	8,461			12,172
Total current liabilities	472,375			384,308
Long-term liabilities:
Long-term debt, net	2,106,202			2,120,547
Derivatives	2,699			10,181
Asset retirement obligations	284,526			145,336
Deferred tax liabilities	678,808			477,179
Other long-term liabilities	32,619			9,160
Total long-term liabilities	3,104,854			2,762,403
Stockholders’ equity:
Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at September 30, 2019 and December 31, 2018	—			—
Common stock, $0.01 par value; 2,000,000,000 authorized shares; 445,757,319 and 442,914,675 issued at September 30, 2019 and December 31, 2018, respectively	4,458			4,429
Additional paid-in capital	2,310,776			2,341,249
Accumulated deficit	(1,187,197		)	(1,167,193		)
Treasury stock, at cost, 44,263,269 and 44,263,269 shares at September 30, 2019 and December 31, 2018, respectively	(237,007		)	(237,007		)
Total stockholders’ equity	891,030			941,478
Total liabilities and stockholders’ equity	$	4,468,259		$	4,088,189

See accompanying notes.

8

KOSMOS ENERGY LTD.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2019			2018			2019			2018
Revenues and other income:
Oil and gas revenue	$	357,036		$	242,833		$	1,049,759		$	585,220
Gain on sale of assets	—			7,666			—			7,666
Other income, net	(66		)	(280		)	(65		)	(17		)
Total revenues and other income	356,970			250,219			1,049,694			592,869
Costs and expenses:
Oil and gas production	95,540			55,078			266,316			151,661
Facilities insurance modifications, net	12,569			12,334			(5,174		)	21,812
Exploration expenses	22,773			148,238			83,022			246,912
General and administrative	24,723			25,963			88,703			65,343
Depletion, depreciation and amortization	146,653			80,041			416,186			208,607
Interest and other financing costs, net	30,721			23,549			125,565			68,113
Derivatives, net	(27,016		)	57,357			35,884			236,107
Gain on equity method investments, net	—			(24,841		)	—			(59,637		)
Other expenses, net	11,472			(12,807		)	11,798			(8,164		)
Total costs and expenses	317,435			364,912			1,022,300			930,754
Income (loss) before income taxes	39,535			(114,693		)	27,394			(337,885		)
Income tax expense (benefit)	23,470			11,364			47,398			(58,329		)
Net income (loss)	$	16,065		$	(126,057	)	$	(20,004	)	$	(279,556	)
Net income (loss) per share:
Basic	$	0.04		$	(0.31	)	$	(0.05	)	$	(0.70	)
Diluted	$	0.04		$	(0.31	)	$	(0.05	)	$	(0.70	)
Weighted average number of shares used to compute net income (loss) per share:
Basic	401,466			404,536			401,319			399,026
Diluted	410,992			404,536			401,319			399,026
Dividends declared per common share	$	0.0452		$	—		$	0.1356		$	—

See accompanying notes.

9

KOSMOS ENERGY LTD.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In thousands)

(Unaudited)

					Additional
	Common Shares				Paid-in			Accumulated			Treasury
	Shares		Amount		Capital			Deficit			Stock			Total
2019:
Balance as of December 31, 2018	442,915		$	4,429	$	2,341,249		$	(1,167,193	)	$	(237,007	)	$	941,478
Dividends ($0.0452 per share)	—		—		(18,744		)	—			—			(18,744		)
Equity-based compensation	—		—		8,744			—			—			8,744
Restricted stock awards and units	2,610		26		(26		)	—			—			—
Purchase of treasury stock / tax withholdings	—		—		(1,979		)	—			—			(1,979		)
Net loss	—		—		—			(52,906		)	—			(52,906		)
Balance as of March 31, 2019	445,525		4,455		2,329,244			(1,220,099		)	(237,007		)	876,593
Dividends ($0.0452 per share)	—		—		(18,740		)	—			—			(18,740		)
Equity-based compensation	—		—		9,525			—			—			9,525
Restricted stock awards and units	113		1		(1		)	—			—			—
Purchase of treasury stock / tax withholdings	—		—		(4		)	—			—			(4		)
Net income	—		—		—			16,837			—			16,837
Balance as of June 30, 2019	445,638		4,456		2,320,024			(1,203,262		)	(237,007		)	884,211
Dividends ($0.0452 per share)	—		—		(18,753		)	—			—			(18,753		)
Equity-based compensation	—		—		9,507			—			—			9,507
Restricted stock awards and units	119		2		(2		)	—			—			—
Net income	—		—		—			16,065			—			16,065
Balance as of September 30, 2019	$	445,757	$	4,458	$	2,310,776		$	(1,187,197	)	$	(237,007	)	$	891,030
2018:
Balance as of December 31, 2017	398,599		$	3,986	$	2,014,525		$	(1,073,202	)	$	(48,197	)	$	897,112
Equity-based compensation	—		—		8,392			—			—			8,392
Restricted stock awards and units	6,380		64		(64		)	—			—			—
Purchase of treasury stock / tax withholdings	—		—		(11,364		)	—			(510		)	(11,874		)
Net loss	—		—		—			(50,226		)	—			(50,226		)
Balance as of March 31, 2018	404,979		4,050		2,011,489			(1,123,428		)	(48,707		)	843,404
Equity-based compensation	—		—		9,821			—			—			9,821
Restricted stock awards and units	2,578		26		(26		)	—			—			—
Purchase of treasury stock / tax withholdings	—		—		(5,821		)	—			—			(5,821		)
Net loss	—		—		—			(103,273		)	—			(103,273		)
Balance as of June 30, 2018	407,557		4,076		2,015,463			(1,226,701		)	(48,707		)	744,131
Acquisition of oil and gas properties	34,994		350		307,594									307,944
Equity-based compensation	—		—		8,915			—			—			8,915
Restricted stock awards and units	305		3		(3		)	—			—			—
Net loss	—		—		—			(126,057		)	—			(126,057		)
Balance as of September 30, 2018	$	442,856	$	4,429	$	2,331,969		$	(1,352,758	)	$	(48,707	)	$	934,933

See accompanying notes.

10

KOSMOS ENERGY LTD.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

	Nine Months Ended September 30,
	2019			2018
Operating activities
Net loss	$	(20,004	)	$	(279,556	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation and amortization	423,160			215,676
Deferred income taxes	(69,840		)	(84,095		)
Unsuccessful well costs and leasehold impairments	7,361			114,948
Change in fair value of derivatives	34,003			232,057
Cash settlements on derivatives, net (including $(27.0) million and $(107.3) million on commodity hedges during 2019 and 2018)	(24,701		)	(102,705		)
Equity-based compensation	27,382			25,975
Gain on sale of assets	—			(7,666		)
Loss on extinguishment of debt	24,794			4,324
Distributions in excess of equity in earnings	—			5,235
Other	9,600			1,237
Changes in assets and liabilities:
Decrease in receivables	12,886			59,318
(Increase) decrease in inventories	(51,943		)	3,978
(Increase) decrease in prepaid expenses and other	23,512			(9,732		)
Decrease in accounts payable	(61,909		)	(15,178		)
Increase (decrease) in accrued liabilities	65,975			(73,569		)
Net cash provided by operating activities	400,276			90,247
Investing activities
Oil and gas assets	(240,642		)	(149,305		)
Other property	(8,291		)	(3,560		)
Acquisition of oil and gas properties, net of cash acquired	—			(961,764		)
Return of investment from KTIPI	—			142,628
Proceeds on sale of assets	—			13,703
Notes receivable from partners	(19,565		)	—
Net cash used in investing activities	(268,498		)	(958,298		)
Financing activities
Borrowings under long-term debt	175,000			1,000,000
Payments on long-term debt	(325,000		)	(175,000		)
Net proceeds from issuance of senior notes	641,875			—
Redemption of senior secured notes	(535,338		)	—
Purchase of treasury stock / tax withholdings	(1,983		)	(17,695		)
Dividends	(54,447		)	—
Deferred financing costs	(2,443		)	(36,745		)
Net cash provided by (used in) financing activities	(102,336		)	770,560
Net increase (decrease) in cash, cash equivalents and restricted cash	29,442			(97,491		)
Cash, cash equivalents and restricted cash at beginning of period	185,616			304,986
Cash, cash equivalents and restricted cash at end of period	$	215,058		$	207,495
Supplemental cash flow information
Cash paid for:
Interest, net of capitalized interest	$	78,691		$	86,981
Income taxes	$	27,768		$	25,601
Non-cash activity:
Common stock issued for acquisition of oil and gas properties	$	—		$	307,944

 See accompanying notes.

11

KOSMOS ENERGY LTD.

Notes to Consolidated Financial Statements

(Unaudited)

1. Organization

Kosmos Energy Ltd. changed its jurisdiction of incorporation from Bermuda to the State of Delaware, in the United States of America, (the "Redomestication") in December 2018. 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 New York Stock Exchange and London Stock Exchange and is traded under the ticker symbol KOS.

Kosmos is engaged in a single line of business, which is the exploration, development, and production of oil and natural gas. Substantially all of our long-lived assets and all of our product sales are related to operations in four geographic areas: Ghana, Equatorial Guinea, Mauritania/Senegal and U.S. Gulf of Mexico. In addition, we have exploration activities in other countries in the Atlantic Margins.

2. Accounting Policies

General

The interim consolidated financial statements included in this report are unaudited and, in the opinion of management, include all adjustments of a normal recurring nature necessary for a fair presentation of the results for the interim periods. The results of the interim periods shown in this report are not necessarily indicative of the final results to be expected for the full year. The consolidated financial statements were prepared in accordance with the requirements of the Securities and Exchange Commission (“SEC”) for interim reporting. As permitted under those rules, certain notes or other financial information that are normally required by Generally Accepted Accounting Principles in the United States of America (“GAAP”) have been condensed or omitted from these interim consolidated financial statements. These consolidated financial statements and the accompanying notes should be read in conjunction with our audited consolidated financial statements for the year ended December 31, 2018, included in our annual report on Form 10-K.

Reclassifications

Certain prior period amounts have been reclassified to conform with the current presentation. Such reclassifications had no significant impact on our reported net income (loss), current assets, total assets, current liabilities, total liabilities, stockholders’ equity or cash flows. Additionally, as a result of our outstanding shares in KTIPI being transferred for an undivided interest in the Ceiba Field and Okume Complex (effective January 1, 2019), our previously reported equity method investment in KTIPI has been allocated to the respective assets and liabilities on a relative fair value basis. See Note 7 — Equity Method Investments for additional information. 

12

Cash, Cash Equivalents and Restricted Cash 

	September 30, 2019		December 31, 2018
	(In thousands)
Cash and cash equivalents	$	203,646	$	173,515
Restricted cash - current	7,745		4,527
Restricted cash - long-term	3,667		7,574
Total cash, cash equivalents and restricted cash shown in the consolidated statements of cash flows	$	215,058	$	185,616

Cash and cash equivalents include 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 respective 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.

Inventories

Inventories consisted of $123.6 million and $83.4 million of materials and supplies and $16.6 million and $1.4 million of hydrocarbons as of September 30, 2019 and December 31, 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.

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

13

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.

Revenue Recognition

We recognize revenues on the volumes 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 September 30, 2019 and December 31, 2018, we had no oil and gas imbalances recorded in our consolidated financial statements.

14

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:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
	(In thousands)
Revenues from contract with customer - Equatorial Guinea	$	54,894	$	—	$	207,173	$	—
Revenues from contract with customer - Ghana	173,613		215,581		502,413		557,459
Revenues from contract with customers - U.S. Gulf of Mexico	123,861		24,177		338,292		24,177
Provisional oil sales contracts	4,668		3,075		1,881		3,584
Oil and gas revenue	$	357,036	$	242,833	$	1,049,759	$	585,220

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 three months ended September 30, 2019 and 2018, revenue from Phillips 66 Company made up approximately 21% and 6%, respectively, and revenue from Shell Trading (US) Company made up approximately11% and 3%, respectively, of our total consolidated revenue and was included in our U.S. Gulf of Mexico segment. For the nine months ended September 30, 2019 and 2018, revenue from Phillips 66 Company made up approximately 22% and 3%, respectively, and revenue from Shell Trading (US) Company made up approximately 9% and 1%, respectively, of our total consolidated revenue and was included in our U.S. Gulf of Mexico segment.

Recent Accounting Standards

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 are evaluating its potential impact.

3. 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 customary governmental approvals. Upon approval, we will hold an 85% participating interest and will 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.

During the first quarter of 2019, Kosmos farmed-in to 18 BP-owned blocks in the Garden Banks area of the deepwater U.S. Gulf of Mexico. In addition, Kosmos can earn an interest in three BP blocks in other areas of the deepwater U.S. Gulf of Mexico. Kosmos is the designated operator.

15

During the first quarter of 2019, Kosmos executed a farm-in agreement with Chevron covering the right to earn an interest in a deepwater block in the U.S. Gulf of Mexico. Kosmos has been designated operator.

During the first quarter of 2019, Kosmos participated in the U.S. Gulf of Mexico Federal Lease Sale 252 and was awarded nine deepwater blocks. During the third quarter of 2019, Kosmos participated in the U.S. Gulf of Mexico Federal Lease Sale 253 and was awarded four deepwater blocks.

In March 2019, we completed an agreement to acquire Ophir's 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 May 2019, we entered into 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, subject to customary governmental approvals, resulting in our participating interests in Blocks 6 and 11 being 25% and 35%, respectively.

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.

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 and BP. We have a 35% participating interest in the blocks and the operator, BP, holds a 50% participating interest. The national petroleum agency, 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 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 future 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 August 2018, we closed a farm-out agreement with Trident, whereby they acquired a 40% participating interest in blocks EG-21, S, and W, offshore Equatorial Guinea, resulting in a $7.7 million gain. After giving effect to the farm-out agreement, we hold a 40% participating interest and are the operator in all three blocks. The Equatorial Guinean national oil company, GEPetrol, has a 20% carried participating interest during the exploration period. Should a commercial discovery be made, GEPetrol's 20% carried participating 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, which was completed in 2018.

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. The DGE acquisition was accounted for as an asset acquisition.

In October 2018, Kosmos entered into a strategic exploration alliance with 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. 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

16

working with Shell, Kosmos has a partner with the expertise to efficiently move exploration successes through the development stage. 

4. Joint Interest Billings, Related Party Receivables and Notes Receivables

Joint Interest Billings

The Company’s joint interest billings generally 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 2014, GNPC notified us and our block partners of its request for the contractor group to pay GNPC’s 5% share of the Tweneboa, Enyenra and Ntomme (“TEN”) development costs. The block partners are being reimbursed for such costs plus interest out of a portion of GNPC’s TEN production revenues. As of September 30, 2019 and December 31, 2018, the current portions 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 portions were $17.2 million and $14.0 million, respectively.

Related Party Receivables

The Company's related party receivables consists primarily of receivables from Trident which, until January 2019, we shared a 50% interest in KTIPI. As of December 31, 2018 the balance due from Trident consisted of $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 September 30, 2019, the balance due from the national oil companies was $19.8 million, which is classified as Long-term receivables in our consolidated balance sheets.

17

5. Property and Equipment

Property and equipment is stated at cost and consisted of the following:

	September 30, 2019			December 31, 2018
	(In thousands)
Oil and gas properties:
Proved properties	$	4,827,304		$	4,236,489
Unproved properties	898,855			759,472
Total oil and gas properties	5,726,159			4,995,961
Accumulated depletion	(1,945,170		)	(1,551,097		)
Oil and gas properties, net	3,780,989			3,444,864
Other property	59,515			51,987
Accumulated depreciation	(41,468		)	(37,150		)
Other property, net	18,047			14,837
Property and equipment, net	$	3,799,036		$	3,459,701

We recorded depletion expense of $139.1 million and $76.8 million for the three months ended September 30, 2019 and 2018, respectively, and $394.1 million and $199.7 million for the nine months ended September 30, 2019 and 2018, 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. 

6. Suspended Well Costs

The following table reflects the Company’s capitalized exploratory well costs on drilled wells as of and during the nine months ended September 30, 2019. The table excludes $1.4 million in costs that were capitalized and subsequently expensed during the same period.

	September 30, 2019
	(In thousands)
Beginning balance	$	367,665
Additions to capitalized exploratory well costs pending the determination of proved reserves	55,244
Reclassification due to determination of proved reserves	(10,711		)
Capitalized exploratory well costs charged to expense	—
Ending balance	$	412,198

18

The following table provides an 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:

	September 30, 2019		December 31, 2018
	(In thousands, except well counts)
Exploratory well costs capitalized for a period of one year or less	$	—	$	—
Exploratory well costs capitalized for a period of one to two years	77,995		299,253
Exploratory well costs capitalized for a period of three years or greater	334,203		68,412
Ending balance	$	412,198	$	367,665
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year	3		3

As of September 30, 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, the Bir Allah 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.

Bir Allah 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 to 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.

Yakaar and Teranga Discoveries — In May 2016, we completed the Teranga-1 exploration well in the Cayar Offshore Profond block offshore Senegal, which encountered hydrocarbon pay. In June 2017, we completed the Yakaar-1 exploration well in the Cayar Offshore Profond block offshore Senegal, which encountered hydrocarbon pay. In November 2017, an integrated Yakaar-Teranga appraisal plan was submitted to the government of Senegal. In September 2019, we completed the Yakaar-2 appraisal well which encountered hydrocarbon pay. The Yakaar-2 well was drilled approximately nine kilometers from the Yakaar-1 exploration well. Following additional evaluation, a decision regarding commerciality is expected to be made.

19

7. Equity Method Investments

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 stockholders' equity
Total current liabilities	$	226,311
Total long-term liabilities	536,178
Shareholders' equity:
Total shareholders' equity	(340,891		)
Total liabilities and shareholders' equity	$	421,598

	Three Months Ended September 30, 2018			Nine Months Ended September 30, 2018
	(In thousands)
Revenues and other income:
Oil and gas revenue	$	215,408		$	600,158
Other income	(72		)	44
Total revenues and other income	215,336			600,202
Costs and expenses:
Oil and gas production	40,334			115,366
Depletion, depreciation and amortization	33,044			108,996
Other expenses, net	(58		)	(211		)
Total costs and expenses	73,320			224,151
Income before income taxes	142,016			376,051
Income tax expense	50,796			134,047
Net income	$	91,220		$	242,004
Kosmos' share of net income	$	45,610		$	121,002
Basis difference amortization(1)	20,769			61,365
Equity in earnings - KTIPI	$	24,841		$	59,637

______________________________________

(1) The basis difference, which was associated with oil and gas properties and subject to amortization, has been allocated to the Ceiba Field and Okume Complex. We amortized the basis difference using the unit-of-production method.

20

With an effective date of January 1, 2019, our outstanding shares in KTIPI were transferred to Trident in exchange for a 40.375% undivided participating 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

8. Debt

	September 30, 2019			December 31, 2018
	(In thousands)
Outstanding debt principal balances:
Facility	$	1,500,000		$	1,325,000
Corporate Revolver	—			325,000
Senior Notes	650,000			—
Senior Secured Notes	—			525,000
Total	2,150,000			2,175,000
Unamortized deferred financing costs and discounts(1)	(43,798		)	(54,453		)
Long-term debt, net	$	2,106,202		$	2,120,547

__________________________________

(1) Includes $34.4 million and $40.5 million of unamortized deferred financing costs related to the Facility as of September 30, 2019 and December 31, 2018, respectively; $9.4 million of unamortized deferred financing costs and discounts related to the Senior Notes as of September 30, 2019; and $14.0 million of unamortized deferred financing costs and discounts related to the Senior Secured Notes as of December 31, 2018, respectively.

21

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. The borrowing base calculation includes value related to the Jubilee, TEN, Ceiba and Okume fields. 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 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 September 30, 2019, we have $34.4 million of unamortized issuance costs related to the Facility, which will be amortized over the remaining term of the Facility. As of September 30, 2019, the undrawn availability under the Facility was $100.0 million. The commitments were reduced by $100.0 million to $1.6 billion following the Senior Notes issuance in April 2019.

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 September 30, 2019, we had no letters of credit issued under the Facility.

We were in compliance with the financial covenants contained in the Facility as of September 30, 2019 (the most recent assessment date). The Facility contains customary cross default provisions.

Corporate Revolver

In August 2018, we amended and restated the Corporate Revolver from a number of financial institutions, 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 September 30, 2019, the undrawn availability under the Corporate Revolver was $400.0 million. As of September 30, 2019, we have $7.0 million of net deferred financing costs related to the Corporate Revolver, which will be amortized over its remaining term. 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

Our revolving letter of credit facility agreement (“LC Facility”) expired in July 2019, however, as of September 30, 2019, there were six outstanding letters of credit totaling $9.4 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 7.875% Senior Secured Notes due 2021 (the "Senior Secured Notes") and received net proceeds of approximately $292.5 million after deducting discounts, commissions and debt issue 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 had identical terms to the initial $300.0 million of 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.

22

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 (the "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.

23

At September 30, 2019, the estimated repayments of debt during the five fiscal year periods and thereafter are as follows:

	Payments Due by Year
	Total		2019(2)		2020		2021		2022		2023		Thereafter
	(In thousands)
Principal debt repayments(1)	$	2,150,000	$	—	$	—	$	274,800	$	284,200	$	271,600	$	1,319,400

__________________________________

(1) Includes the scheduled principal 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 September 30, 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.

(2) Represents payments for the period October 1, 2019 through December 31, 2019.

Interest and other financing costs, net

Interest and other financing costs, net incurred during the periods is comprised of the following:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
	(In thousands)
Interest expense	$	34,944		$	27,317		$	111,566		$	77,121
Amortization—deferred financing costs	2,285			2,346			6,974			7,069
Loss on extinguishment of debt	—			268			24,794			4,324
Capitalized interest	(7,077		)	(7,097		)	(21,330		)	(21,209		)
Deferred interest	290			(194		)	1,559			(1,284		)
Interest income	(972		)	(788		)	(2,215		)	(2,579		)
Other, net	1,251			1,697			4,217			4,671
Interest and other financing costs, net	$	30,721		$	23,549		$	125,565		$	68,113

9. 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.

24

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 September 30, 2019. Volumes and weighted average prices are net of any offsetting derivative contracts entered into.

				Weighted Average Price per Bbl
				Net Deferred
				Premium
Term	Type of Contract	Index	MBbl	Payable/(Receivable)		Swap		Sold Put		Floor		Ceiling
2019:
Oct — Dec	Three-way collars	Dated Brent	2,628	$	1.17	$	—	$	43.81	$	53.33	$	73.57
Oct — Dec	Sold calls(1)	Dated Brent	230	—		—		—		—		80.00
Oct — Dec	Swaps	NYMEX WTI	265	—		51.61		—		—		—
Oct — Dec	Collars	Argus LLS	250	—		—		—		60.00		88.75
2020:
Jan — Dec	Three-way collars	Dated Brent	6,000	$	0.45	$	—	$	45.00	$	57.50	$	80.18
Jan — Dec	Swaps with sold puts	Dated Brent	2,000	—		60.53		48.75		—		—
Jan — Dec	Put spread	Dated Brent	2,000	2.59		—		50.00		60.00		—
Jan — Dec	Sold calls(1)(2)	Dated Brent	8,000	1.17		—		—		—		85.00
2021:
Jan — Dec	Sold calls(1)	Dated Brent	1,000	$	—	$	—	$	—	$	—	$	75.00

__________________________________

(1) Represents call option contracts sold to counterparties to enhance other derivative positions.

(2) Deferred premium payable to be paid October 1, 2019 — December 31, 2019.

In October 2019, we entered into put option contracts for 2.0 MMBbls from January 2020 through December 2020 with a floor price of $57.50 per barrel and a sold put price of $50.00 per barrel. In addition, we sold 3.0 MMBbl of calls from January 2021 through December 2021 with an average strike price of $71.67 per barrel. The contracts are indexed to Dated Brent prices.

The following tables disclose the Company’s derivative instruments as of September 30, 2019 and December 31, 2018, and gain/(loss) from derivatives during the three and nine months ended September 30, 2019 and 2018, respectively:

		Estimated Fair Value
		Asset (Liability)
Type of Contract	Balance Sheet Location	September 30, 2019			December 31, 2018
		(In thousands)
Derivatives not designated as hedging instruments:
Derivative assets:
Commodity(1)	Derivatives assets—current	$	22,067		$	38,785
Commodity(2)	Derivatives assets—long-term	10,535			14,312
Derivative liabilities:
Commodity(3)	Derivatives liabilities—current	(8,461		)	(12,172		)
Commodity(4)	Derivatives liabilities—long-term	(2,699		)	(10,181		)
Total derivatives not designated as hedging instruments		$	21,442		$	30,744

__________________________________

(1) Includes zero and $0.4 million as of September 30, 2019 and December 31, 2018, respectively which represents our provisional oil sales contract. Also, includes net deferred premiums payable of $4.1 million and $1.6 million related to commodity derivative contracts as of September 30, 2019 and December 31, 2018, respectively.

(2) Includes net deferred premiums payable of $2.6 million and $1.3 million related to commodity derivative contracts as of September 30, 2019 and December 31, 2018, respectively.

25

(3) Includes net deferred premiums payable of $6.5 million and $18.0 million related to commodity derivative contracts as of September 30, 2019 and December 31, 2018, respectively.

(4) Includes net deferred premiums payable of zero and $0.5 million related to commodity derivative contracts as of September 30, 2019 and December 31, 2018, respectively.

		Amount of Gain/(Loss)					Amount of Gain/(Loss)
		Three Months Ended					Nine Months Ended
		September 30,					September 30,
Type of Contract	Location of Gain/(Loss)	2019		2018			2019			2018
		(In thousands)
Derivatives not designated as hedging instruments:
Commodity(1)	Oil and gas revenue	$	4,667	$	3,075		$	1,881		$	3,584
Commodity	Derivatives, net	27,016		(57,357		)	(35,884		)	(236,107		)
Interest rate	Interest expense	—		15			—			466
Total derivatives not designated as hedging instruments		$	31,683	$	(54,267	)	$	(34,003	)	$	(232,057	)

__________________________________

(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 September 30, 2019 and December 31, 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.

10. Fair Value Measurements

In accordance with ASC Topic 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.

26

The following tables present the Company’s assets and liabilities that are measured at fair value on a recurring basis as of September 30, 2019 and December 31, 2018, for each fair value hierarchy level:

	Fair Value Measurements Using:
	Quoted Prices in
	Active Markets for		Significant Other			Significant
	Identical Assets		Observable Inputs			Unobservable Inputs
	(Level 1)		(Level 2)			(Level 3)		Total
	(In thousands)
September 30, 2019
Assets:
Commodity derivatives	$	—	$	32,602		$	—	$	32,602
Liabilities:
Commodity derivatives	—		(11,160		)	—		(11,160		)
Total	$	—	$	21,442		$	—	$	21,442
December 31, 2018
Assets:
Commodity derivatives	$	—	$	53,097		$	—	$	53,097
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 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 provisional oil sales derivatives 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.

27

Debt

The following table presents the carrying values and fair values at September 30, 2019 and December 31, 2018:

	September 30, 2019				December 31, 2018
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In thousands)
Senior Notes	$	642,318	$	670,514	$	—	$	—
Senior Secured Notes	—		—		511,873		525,026
Corporate Revolver	—		—		325,000		325,000
Facility	1,500,000		1,500,000		1,325,000		1,325,000
Total	$	2,142,318	$	2,170,514	$	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 and Senior Secured 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.

11. Equity-based Compensation

Restricted Stock Units

We record equity-based compensation expense equal to the fair value of share-based payments over the vesting periods of the Long Term Incentive Plan (“LTIP”) awards. We recorded compensation expense from awards granted under our LTIP of $9.5 million and $8.9 million during the three months ended September 30, 2019 and 2018, respectively, and $27.4 million and $26.0 million during the nine months ended September 30, 2019 and 2018, respectively. The total tax benefit for the three months ended was $3.1 million and $1.6 million, respectively, and $5.9 million and $5.0 million during the nine months ended September 30, 2019 and 2018, respectively. Additionally, we recorded a net tax shortfall (windfall) related to equity-based compensation of nil and $0.1 million for the three months ended September 30, 2019 and 2018, respectively, and $1.2 million and $(0.3) million during the nine months ended September 30, 2019 and 2018, respectively. The fair value of awards vested during the three months ended September 30, 2019 and 2018 was approximately $0.7 million and $1.1 million, respectively, and $14.7 million and $83.1 million during the nine months ended September 30, 2019 and 2018, respectively. The Company granted restricted stock units with service vesting criteria and a combination of market and service vesting criteria under the LTIP. Substantially all these grants vest over three years. Upon vesting, restricted stock units become issued and outstanding stock.

The following table reflects the outstanding restricted stock units as of September 30, 2019:

			Weighted-		Market / Service		Weighted-
	Service Vesting		Average		Vesting		Average
	Restricted Stock		Grant-Date		Restricted Stock		Grant-Date
	Units		Fair Value		Units		Fair Value
	(In thousands)				(In thousands)
Outstanding at December 31, 2018	4,115		$	6.42	6,716		$	9.02
Granted(1)	3,096		4.96		3,160		6.02
Forfeited(1)	(134	)	6.11		(295	)	9.87
Vested	(1,999	)	5.92		(1,300	)	6.32
Outstanding at September 30, 2019	5,078		5.73		8,281		8.39

__________________________________

(1) The restricted stock units with a combination of market and service vesting criteria may vest between 0% and 200% of the originally granted units depending upon market performance conditions. Awards vesting over or under target shares of 100% results in additional shares granted or forfeited, respectively, in the period the market vesting criteria is determined.

28

As of September 30, 2019, total equity-based compensation to be recognized on unvested restricted stock units is $38.3 million over a weighted average period of 1.97 years. In March 2018, the board of directors approved an amendment to the LTIP to add 11.0 million shares to the plan, which was approved by our stockholders at the Annual General Meeting in June 2018. The LTIP provides for the issuance of 50.5 million shares pursuant to awards under the plan. At September 30, 2019, the Company had approximately 9.8 million shares that remain available for issuance under the LTIP.

For restricted stock units with a combination of market and service vesting criteria, the number of common shares to be issued is determined by comparing the Company’s total shareholder return with the total shareholder return of a predetermined group of peer companies over the performance period and can vest in up to 200% of the awards granted. The grant date fair value ranged from $4.83 to $12.96 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 and ranged from 0.8% to 2.5%.

12. Income Taxes

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. We evaluate our estimated annual effective income tax rate each quarter, based on current and forecasted business results and enacted tax laws, and apply this tax rate to our ordinary income or loss to calculate our estimated tax expense or benefit. The Company excludes zero tax rate and tax-exempt jurisdictions from our evaluation of the estimated annual effective income tax rate. The tax effect of discrete items are recognized in the period in which they occur at the applicable statutory tax rate. The company was not subject to taxation at the parent company level for the three and nine months ended September 30, 2018.

For 2019, the income tax provision consists of United States, Ghanaian, and Equatorial Guinean income taxes, and Texas margin taxes. For 2018, results from operations in Equatorial Guinea were reported net of tax, as Gain on equity method investments, net in our consolidated statement of operations, and were not included in our 2018 income tax provision. 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.

Income (loss) before income taxes is composed of the following:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2019		2018			2019			2018
	(In thousands)
United States	$	3,464	$	(53,136	)	$	(70,776	)	$	(49,967	)
Bermuda	—		(15,513		)	—			(47,474		)
Foreign—other	36,071		(46,044		)	98,170			(240,444		)
Income (loss) before income taxes	$	39,535	$	(114,693	)	$	27,394		$	(337,885	)

For the three months ended, September 30, 2019, and 2018, our effective tax rate was 59% and 10%, respectively. For the nine months ended, September 30, 2019, and 2018, our effective tax rate was 173% and 17%, respectively.

For the three and nine months ended September 30, 2019, our overall effective tax rate was impacted by the difference in our 21% U.S. income tax reporting rate and the 35% statutory tax rates applicable to our Ghanaian and Equatorial Guinean operations, non-deductible and non-taxable items associated with our U.S., Ghanaian, and Equatorial Guinean operations, and other losses and expenses, primarily related to exploration operations in tax-exempt jurisdictions or in taxable jurisdictions where we have valuation allowances against our deferred tax assets, and therefore, we do not realize any tax benefit on such losses or expenses.

For the three and nine months ended September 30, 2018, our overall effective tax rate was impacted by non-deductible and non-taxable items associated with our U.S. and Ghanaian operations and other losses and expenses, primarily related to

29

exploration operations in tax-exempt jurisdictions or in taxable jurisdictions where we have valuation allowances against our deferred tax assets, and therefore, we do not realize any tax benefit on such losses or expenses.

The Company files income tax returns in all jurisdictions where such requirements exist, however, our primary tax jurisdictions are the United States, Ghana and Equatorial Guinea. The Company is open to tax examinations in the United States, for federal income tax return years 2016 through 2018, in Ghana to federal income tax return years 2014 through 2018, and in Equatorial Guinea to federal income tax return year2018.

As of September 30, 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.

13. Net Income (Loss) Per Share

The following table is a 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:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2019		2018			2019			2018
	(In thousands, except per share data)
Numerator:
Net income (loss) allocable to common stockholders	$	16,065	$	(126,057	)	$	(20,004	)	$	(279,556	)
Denominator:
Weighted average number of shares outstanding:
Basic	401,466		404,536			401,319			399,026
Restricted stock units(1)	9,526		—			—			—
Diluted	410,992		404,536			401,319			399,026
Net income (loss) per share:
Basic	$	0.04	$	(0.31	)	$	(0.05	)	$	(0.70	)
Diluted	$	0.04	$	(0.31	)	$	(0.05	)	$	(0.70	)

__________________________________

(1) We excluded outstanding restricted stock awards and units of 0.7 million and 13.1 million for the three months ended September 30, 2019 and 2018, respectively, and 15.4 million and 14.5 million for the nine months ended September 30, 2019 and 2018, respectively, from the computations of diluted net income (loss) per share because the effect would have been anti-dilutive.  

14. Commitments and Contingencies

From time to time, we are involved in litigation, regulatory examinations and administrative proceedings primarily arising in the ordinary course of our business in jurisdictions in which we do business. Although the outcome of these matters cannot be predicted with certainty, management believes none of these matters, either individually or in the aggregate, would have a material effect upon the Company’s financial position; however, an unfavorable outcome could have a material adverse effect on our results from operations for a specific interim period or year.

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 one year to ten years. Certain lease agreements contain provisions for future rent increases.

30

The components of lease cost for the three months and nine months ended September 30, 2019 are as follows:

	Three months ended September 30, 2019		Nine Months Ended September 30, 2019
	(In thousands)
Operating lease cost	$	1,279	$	4,288
Short-term lease cost	960		1,547
Total lease cost	$	2,239	$	5,835

Other information related to operating leases at September 30, 2019, is as follows:

	September 30, 2019
(In thousands, except lease term and discount rate)
Balance sheet classifications
Other assets (right-of-use assets)	$	20,436
Accrued liabilities (current maturities of leases)	1,294
Other long-term liabilities (non-current maturities of leases)	22,480
Weighted average remaining lease term	9.1 years
Weighted average discount rate	9.8		%

The table below presents supplemental cash flow information related to leases during the nine months ended September 30, 2019:

	Nine Months Ended September 30, 2019
	(In thousands)
Operating cash flows for operating leases	$	3,077

Future minimum rental commitments under our leases at September 30, 2019, are as follows:

	Operating Leases(1)
	(In thousands)
2019(2)	$	483
2020	4,098
2021	4,148
2022	4,199
2023	4,249
Thereafter	19,480
Total undiscounted lease payments	$	36,657
Less: Imputed interest	(12,883		)
Total lease liabilities	$	23,774

__________________________________

(1) Does not include purchase commitments for jointly owned fields and facilities where we are not the operator and excludes commitments for exploration activities, including well commitments, in our petroleum contracts.

(2) Represents payments for the period from October 1, 2019 through December 31, 2019.

31

Performance Obligations

As of September 30, 2019 and December 31, 2018, the Company had performance bonds totaling $208.7 million and $200.9 million, respectively, for our supplemental bonding requirements stipulated by the 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 our U.S. Gulf of Mexico fields. As of September 30, 2019 and December 31, 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 November 1, 2019, we declared our quarterly cash dividend of $0.0452 per common share for the fourth quarter payable on December 23, 2019 to stockholders of record as of December 2, 2019.

15. Additional Financial Information

Accrued Liabilities

Accrued liabilities consisted of the following:

	September 30, 2019		December 31, 2018
	(In thousands)
Accrued liabilities:
Exploration, development and production	$	114,833	$	92,613
Revenue payable	33,721		24,379
Current asset retirement obligations	5,844		6,617
Operating leases	1,294		—
General and administrative expenses	31,913		39,373
Interest	27,913		18,152
Income taxes	69,938		8,958
Taxes other than income	2,060		4,613
Derivatives	2,975		441
Other	1,928		450
	$	292,419	$	195,596

32

Asset Retirement Obligations

The following table summarizes the changes in the Company's asset retirement obligations:

	September 30, 2019
	(In thousands)
Asset retirement obligations:
Beginning asset retirement obligations	$	151,953
Additions associated with Equatorial Guinea - Ceiba Field and Okume Complex	114,395
Liabilities incurred during period	9,706
Liabilities settled during period	(4,384		)
Revisions in estimated retirement obligations	905
Accretion expense	17,795
Ending asset retirement obligations	$	290,370

With an effective date 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 going forward is accounted for under the proportionate consolidation method of accounting, which includes additions to our asset retirement obligations.

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 related insurance reimbursements. During the three months ended September 30, 2019 and 2018, we incurred approximately $12.6 million and $12.3 million, respectively in expenditures with no offsetting insurance recoveries. During the nine months ended September 30, 2019 and 2018, we incurred approximately $34.8 million and $31.5 million, respectively in expenditures offset by approximately $40.0 million and $9.7 million, respectively in insurance recoveries.

Other Expenses, Net

Other expenses, net incurred during the period is comprised of the following:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019		2018
	(In thousands)
(Gain) loss on disposal of inventory	$	1,232		$	(2	)	$	1,419	$	(26	)
(Gain) loss on ARO liability settlements	(746		)	—			1,167		—
Disputed charges and related costs, net of recoveries	1,677			(12,682		)	1,663		(9,721		)
Other, net	9,309			(123		)	7,549		1,583
Other expenses, net	$	11,472		$	(12,807	)	$	11,798	$	(8,164	)

The disputed charges and related costs, net of recoveries arise from the final award issued by the International Chamber of Commerce ("ICC") in favor of Kosmos in its arbitration against Tullow Ghana Limited, related to expenditures arising from Tullow's contract with Seadrill for use of the West Leo drilling rig. Other, net is primarily related to an $8.7 million indirect tax settlement with tax authorities in Senegal.

33

16. Business Segment Information

Kosmos is engaged in a single line of business, which is the exploration, development and production of oil and gas. At September 30, 2019, substantially all of our long-lived assets and all of our product sales are related to operations in four geographic reporting segments: Ghana, Equatorial Guinea, Mauritania/Senegal and the U.S. Gulf of Mexico. In addition, we have exploration activities in other countries in the Atlantic Margins. 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)
Three months ended September 30, 2019
Revenues and other income:
Oil and gas revenue	$	177,797		$	55,378	$	—		$	123,861		$	—		$	—		$	357,036
Other income, net	1			—		—			200			5,706			(5,973		)	(66		)
Total revenues and other income	177,798			55,378		—			124,061			5,706			(5,973		)	356,970
Costs and expenses:
Oil and gas production	42,017			21,369		—			32,154			—			—			95,540
Facilities insurance modifications, net	12,569			—		—			—			—			—			12,569
Exploration expenses	82			2,437		1,260			10,625			8,369			—			22,773
General and administrative	3,886			1,719		2,678			7,002			38,897			(29,459		)	24,723
Depletion, depreciation and amortization	73,347			16,019		15			56,359			913			—			146,653
Interest and other financing costs, net(1)	16,821			—		(6,703		)	5,083			17,304			(1,784		)	30,721
Derivatives, net	—			—		—			(1,745		)	(25,271		)	—			(27,016		)
Other expenses, net	(25,357		)	615		9,141			550			1,253			25,270			11,472
Total costs and expenses	123,365			42,159		6,391			110,028			41,465			(5,973		)	317,435
Income (loss) before income taxes	54,433			13,219		(6,391		)	14,033			(35,759		)	—			39,535
Income tax expense (benefit)	10,585			6,110		—			2,942			3,833			—			23,470
Net income (loss)	$	43,848		$	7,109	$	(6,391	)	$	11,091		$	(39,592	)	$	—		$	16,065
Consolidated capital expenditures	$	28,398		$	15,397	$	842		$	49,629		$	13,127		$	—		$	107,393

34

	Ghana			Equatorial Guinea			Mauritania/Senegal			U.S. Gulf of Mexico			Corporate & Other			Eliminations			Total
	(In thousands)
Nine months ended September 30, 2019
Revenues and other income:
Oil and gas revenue	$	502,800		$	208,667		$	—		$	338,292		$	—		$	—		$	1,049,759
Other income, net	2			—			—			459			97,594			(98,120		)	(65		)
Total revenues and other income	502,802			208,667			—			338,751			97,594			(98,120		)	1,049,694
Costs and expenses:													—
Oil and gas production	117,027			60,645			—			88,644			—			—			266,316
Facilities insurance modifications, net	(5,174		)	—			—			—			—			—			(5,174		)
Exploration expenses	189			8,080			9,745			32,834			32,174			—			83,022
General and administrative	15,844			5,303			6,505			19,288			127,416			(85,653		)	88,703
Depletion, depreciation and amortization	204,108			55,323			46			153,768			2,941			—			416,186
Interest and other financing costs, net(1)	56,500			—			(20,020		)	16,654			77,782			(5,351		)	125,565
Derivatives, net	—			—			—			28,768			7,116			—			35,884
Other expenses, net	6,761			(1,629		)	9,783			2,695			1,304			(7,116		)	11,798
Total costs and expenses	395,255			127,722			6,059			342,651			248,733			(98,120		)	1,022,300
Income (loss) before income taxes	107,547			80,945			(6,059		)	(3,900		)	(151,139		)	—			27,394
Income tax expense (benefit)	30,285			33,403			—			(824		)	(15,466		)	—			47,398
Net income (loss)	$	77,262		$	47,542		$	(6,059	)	$	(3,076	)	$	(135,673	)	$	—		$	(20,004	)
Consolidated capital expenditures	$	96,861		$	36,448		$	7,132		$	136,688		$	41,177		$	—		$	318,306
As of September 30, 2019
Property and equipment, net	$	1,603,170		$	460,044		$	428,596		$	1,263,945		$	43,281		$	—		$	3,799,036
Total assets	$	1,844,328		$	489,564		$	568,743		$	3,309,044		$	12,078,321		$	(13,821,741	)	$	4,468,259

______________________________________

(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.

35

	Ghana			Equatorial Guinea(1)			Mauritania/Senegal			U.S. Gulf of Mexico(2)			Corporate & Other			Eliminations(3)			Total
	(In thousands)
Three months ended September 30, 2018
Revenues and other income:
Oil and gas revenue	$	218,656		$	107,704		$	—		$	24,177		$	—		$	(107,704	)	$	242,833
Gain on sale of assets	—			7,666			—			—			—			—			7,666
Other income, net	—			(317		)	—			—			78,166			(78,129		)	(280		)
Total revenues and other income	218,656			115,053			—			24,177			78,166			(185,833		)	250,219
Costs and expenses:
Oil and gas production	49,280			20,167			—			4,467			1,331			(20,167		)	55,078
Facilities insurance modifications, net	12,334			—			—			—			—			—			12,334
Exploration expenses	57,818			16,584			1,203			50,176			22,457			—			148,238
General and administrative	5,786			1,761			1,396			4,026			42,072			(29,078		)	25,963
Depletion, depreciation and amortization	70,799			37,291			15			8,190			1,037			(37,291		)	80,041
Interest and other financing costs, net(4)	21,989			(4		)	(6,441		)	2,085			7,704			(1,784		)	23,549
Derivatives, net	—			—			—			10,082			47,275			—			57,357
(Gain) loss on equity method investments, net	—			—			—			—			—			(24,841		)	(24,841		)
Other expenses, net	34,610			(976		)	(13		)	—			846			(47,274		)	(12,807		)
Total costs and expenses	252,616			74,823			(3,840		)	79,026			122,722			(160,435		)	364,912
Income (loss) before income taxes	(33,960		)	40,230			3,840			(54,849		)	(44,556		)	(25,398		)	(114,693		)
Income tax expense (benefit)	21,862			25,398			—			(12,324		)	1,826			(25,398		)	11,364
Net income (loss)	$	(55,822	)	$	14,832		$	3,840		$	(42,525	)	$	(46,382	)	$	—		$	(126,057	)
Consolidated capital expenditures	$	32,501		$	2,913		$	3,319		$	52,488		$	17,970		$	—		$	109,191

36

	Ghana			Equatorial Guinea(1)			Mauritania/Senegal			U.S. Gulf of Mexico(2)			Corporate & Other			Eliminations(3)			Total
	(In thousands)
Nine months ended September 30, 2018
Revenues and other income:
Oil and gas revenue	$	561,043		$	300,079		$	—		$	24,177		$	—		$	(300,079	)	$	585,220
Gain on sale of assets	—			7,666			—			—			—			—			7,666
Other income, net	(17		)	22			—			—			315,771			(315,793		)	(17		)
Total revenues and other income	561,026			307,767			—			24,177			315,771			(615,872		)	592,869
Costs and expenses:
Oil and gas production	143,860			57,683			—			4,467			3,334			(57,683		)	151,661
Facilities insurance modifications, net	21,812			—			—			—			—			—			21,812
Exploration expenses	58,076			33,665			6,603			50,176			98,392			—			246,912
General and administrative	15,651			3,768			3,628			4,026			122,558			(84,288		)	65,343
Depletion, depreciation and amortization	197,260			115,862			46			8,190			3,111			(115,862		)	208,607
Interest and other financing costs, net(4)	65,357			(9		)	(18,704		)	2,085			24,735			(5,351		)	68,113
Derivatives, net	—			—			—			10,082			226,025			—			236,107
(Gain) loss on equity method investments, net	—			—			—			—			—			(59,637		)	(59,637		)
Other expenses, net	216,319			(1,138		)	(13		)	—			2,695			(226,027		)	(8,164		)
Total costs and expenses	718,335			209,831			(8,440		)	79,026			480,850			(548,848		)	930,754
Income (loss) before income taxes	(157,309		)	97,936			8,440			(54,849		)	(165,079		)	(67,024		)	(337,885		)
Income tax expense (benefit)	(49,148		)	67,024			—			(12,324		)	3,143			(67,024		)	(58,329		)
Net income (loss)	$	(108,161	)	$	30,912		$	8,440		$	(42,525	)	$	(168,222	)	$	—		$	(279,556	)
Consolidated capital expenditures	$	71,330		$	27,891		$	9,633		$	52,488		$	102,651		$	—		$	263,993
As of September 30, 2018
Property and equipment, net	$	1,727,595		$	3,801		$	403,111		$	1,340,479		$	34,551		$	—		$	3,509,537
Total assets	$	2,073,825		$	145,823		$	465,352		$	3,473,501		$	10,660,832		$	(12,489,869	)	$	4,329,464

______________________________________

(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 three and nine months ended September 30, 2018, except for capital expenditures. See Note 7 - Equity Method Investments for additional information regarding our equity method investments.

(2) No activity prior to 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.

37

	Nine Months Ended September 30,
	2019			2018
	(In thousands)
Consolidated capital expenditures:
Consolidated Statements of Cash Flows - Investing activities:
Oil and gas assets	$	240,642		$	149,305
Other property	8,291			3,560
Adjustments:
Changes in capital accruals	11,083			13,965
Exploration expense, excluding unsuccessful well costs(1)	75,661			131,964
Capitalized interest	(21,330		)	(21,209		)
Proceeds on sale of assets	—			(13,703		)
Other	3,959			111
Total consolidated capital expenditures	$	318,306		$	263,993

______________________________________

(1) Unsuccessful well costs are included in oil and gas assets when incurred.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes thereto contained herein and our annual financial statements for the year ended December 31, 2018, included in our annual report on Form 10-K along with the section Management’s Discussion and Analysis of financial condition and Results of Operations contained in such annual report. Any terms used but not defined in the following discussion have the same meaning given to them in the annual report. Our discussion and analysis includes forward-looking statements that involve risks and uncertainties and should be read in conjunction with “Risk Factors” under Item 1A of this report and in the annual report, along with “Forward-Looking Information” at the end of this section for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.

Overview

We are 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).

Recent Developments

Ghana

Jubilee

During the third quarter of 2019, Jubilee production averaged approximately 90,300 Bopd (gross). Oil production rates remain constrained by gas handling capacity. Work to enhance gas handling capacity has been deferred by the operator to Q1 2020.

Tweneboa, Enyenra and Ntomme ("TEN")

During the third quarter of 2019, TEN production averaged approximately 66,000 Bopd (gross).

U.S. Gulf of Mexico

Production from the U.S. Gulf of Mexico averaged approximately 25,800 Boepd (net) for the third quarter of 2019.

In the second quarter of 2019, we announced the Gladden Deep exploration well located in Mississippi Canyon Block 800 (20.0% working interest) made an oil discovery. Gladden Deep is a subsea tieback that was brought online in September 2019 through the existing Gladden pipeline to the Medusa SPAR.

38

In August 2019, we entered into a letter of intent for a cross assignment of our interest in Mississippi Canyon Block 728 with Hess Corporation on their interest in an adjacent block, Mississippi Canyon Block 684, after which Kosmos will have a 40% interest in the two blocks, and Hess Corporation having a 60% interest.

In September 2019, we spud the Resolution prospect, located in Garden Banks Block 492 (50% working interest). We expect well results during the fourth quarter.

In October 2019, we drilled the Moneypenny prospect which was unsuccessful. The well was designed as an inexpensive exploration tail of an Odd Job development well.

During the third quarter of 2019, Kosmos participated in the U.S. Gulf of Mexico Federal Lease Sale 253 and was ultimately awarded four additional deepwater blocks.

Equatorial Guinea

Production in Equatorial Guinea averaged approximately 36,400 Bopd gross in the third quarter of 2019. Our ESP program is supporting field production with four ESPs completed during the first three quarters of 2019. We completed one more ESP conversion early in the fourth quarter of 2019.

In October 2019, the S-5 exploration well was drilled to a total depth of 4,400 meters offshore Equatorial Guinea, encountering 39 meters of net oil pay in high-quality Santonian reservoir. The well is located within tieback range of the Ceiba FPSO and work is currently ongoing to establish the scale of the discovered resource and evaluate the optimum development solution.

Mauritania and Senegal

Greater Tortue Ahmeyim Unit

In July 2019, we announced the Greater Tortue Ahmeyim-1 (GTA-1) appraisal well was drilled on the eastern anticline within the unit development area of Greater Tortue Ahmeyim field. The GTA-1 well encountered approximately 30 meters of net gas pay in high quality Albian reservoir. The well was drilled in approximately 2,500 meters of water, approximately 10 kilometers inboard of the Guembeul-1A and Tortue-1 wells, to a total depth of 4,884 meters.

Yakaar / Teranga

In September 2019, we announced the Yakaar-2 appraisal well was drilled approximately nine kilometers from the Yakaar-1 exploration well and further delineated the southern extension of the field. The Yakaar-2 well encountered approximately 30 meters of net gas pay in similar high-quality Cenomanian reservoir to the Yakaar-1 exploration well. The Yakaar-2 well was drilled in approximately 2,500 meters of water to a total depth of approximately 4,800 meters.

Bir Allah / Orca

In October 2019, we announced the Orca-1 exploration well, located in Block C-8 offshore Mauritania, made a major gas discovery. The Orca-1 well, which targeted a previously untested Albian play, encountered 36 meters of net gas pay in excellent quality reservoirs. In addition, the well extended the Cenomanian play fairway by confirming 11 meters of net gas pay in a down-structure position relative to the original Marsouin-1 discovery well. The location of the Orca-1 proved the structural and stratigraphic trap. The Orca-1 well was drilled in approximately 2,510 meters of water to a total measured depth of around 5,266 meters.

Republic of the Congo

In March 2019, we entered into a petroleum contract covering the offshore Marine XXI block with the Republic of the Congo, subject to customary governmental approvals. Upon approval, we will hold an 85% participating interest and are the operator. The Congolese national oil company, SPNC, has a 15% carried participating 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.

39

Sao Tome and Principe

In July 2019, the petroleum contract for Block 11 offshore Sao Tome and Principe was amended to remove any well commitment from the second exploration phase and add a contingent well to the third exploration phase in addition to the existing firm well. We also entered the second exploration phase which will expire in August 2021.

Republic of South Africa

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. Shell owns 45% of the block and is the operator and OK Energy retained 10%. 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.

40

Results of Operations

All of our results, as presented in the table below, represent operations from Jubilee and TEN fields in Ghana, the U.S. Gulf of Mexico (commencing September 14, 2018, the DGE acquisition date), and Equatorial Guinea, which was accounted for as an equity method investment during 2018. Certain operating results and statistics for the three and nine months ended September 30, 2019 and 2018 are included in the following tables:

	Three Months Ended September 30, 2019		Nine Months Ended September 30, 2019
	(In thousands, except per volume data)
Sales volumes:
Oil (MBbl)	5,698		16,239
Gas (MMcf)	1,189		4,653
NGL (MBbl)	142		393
Total (MBoe)	6,038		17,408
Revenues:
Oil sales	$	351,537	$	1,031,687
Gas sales	3,969		11,776
NGL sales	1,530		6,296
Total revenues	$	357,036	$	1,049,759
Average oil sales price per Bbl	$	61.69	$	63.53
Average gas sales price per Mcf	3.34		2.53
Average NGL sales price per Bbl	10.77		16.02
Average total sales price per Boe	59.13		60.30
Costs:
Oil and gas production, excluding workovers	$	87,410	$	245,476
Oil and gas production, workovers	8,130		20,840
Total oil and gas production costs	$	95,540	$	266,316
Depletion, depreciation and amortization	$	146,653	$	416,186
Average cost per Boe:
Oil and gas production, excluding workovers	$	14.48	$	14.10
Oil and gas production, workovers	1.35		1.20
Total oil and gas production costs	15.83		15.30
Depletion, depreciation and amortization	24.29		23.91
Oil and gas production cost and depletion costs	$	40.12	$	39.21

41

	Three Months Ended September 30, 2018								Nine Months Ended September 30, 2018
	Kosmos			Equity Method Investment - Equatorial Guinea(1)		Total			Kosmos		Equity Method Investment - Equatorial Guinea(1)		Total
	(In thousands, except per volume data)
Sales volumes:
Oil (MBbl)	3,247			1,448		4,695			8,076		4,278		12,354
Gas (MMcf)	309			—		309			309		—		309
NGL (MBbl)	24			—		24			24		—		24
Total (MBoe)	3,323			1,448		4,771			8,152		4,278		12,430
Revenues:
Oil sales	$	241,139		$	107,704	$	348,843		$	583,526	$	300,079	$	883,605
Gas sales	975			—		975			975		—		975
NGL sales	719			—		719			719		—		719
Total revenues	$	242,833		$	107,704	$	350,537		$	585,220	$	300,079	$	885,299
Average oil sales price per Bbl	$	74.27		$	74.38	$	74.30		$	72.25	$	70.14	$	71.52
Average gas sales price per Mcf	3.16			—		3.16			3.16		—		3.16
Average NGL sales price per Bbl	29.96			—		29.96			29.96		—		29.96
Average total sales price per Boe	73.08			74.38		73.47			71.79		70.14		71.22
Costs:
Oil and gas production, excluding workovers	$	55,363		$	20,167	$	75,530		$	149,517	$	57,683	$	207,200
Oil and gas production, workovers	(285		)	—		(285		)	2,144		—		2,144
Total oil and gas production costs	$	55,078		$	20,167	$	75,245		$	151,661	$	57,683	$	209,344
Depletion, depreciation and amortization	$	80,041		$	37,291	$	117,332		$	208,607	$	115,862	$	324,469
Average cost per Boe:
Oil and gas production, excluding workovers	$	16.66		$	13.93	$	15.83		$	18.34	$	13.48	$	16.67
Oil and gas production, workovers	(0.09		)	—		(0.06		)	0.26		—		0.17
Total oil and gas production costs	16.57			13.93		15.77			18.60		13.48		16.84
Depletion, depreciation and amortization	24.09			25.75		24.59			25.59		27.08		26.10
Oil and gas production cost and depletion costs	$	40.66		$	39.68	$	40.36		$	44.19	$	40.56	$	42.94

__________________________________

(1) For the three and nine months ended September 30, 2018, we have presented our 50% share of the results of operations, including our basis difference which is reflected in depletion, depreciation and amortization. Under the equity method of accounting, we only recognize our share of the net income of KTIPI as adjusted for our basis differential, which is recorded in (gain) loss on equity method investments, net in the consolidated statement of operations.

42

The following table shows the number of wells in the process of being drilled or in active completion stages, and the number of wells suspended or waiting on completion as of September 30, 2019:

	Actively Drilling or				Wells Suspended or
	Completing				Waiting on Completion
	Exploration		Development		Exploration		Development
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Ghana
Jubilee Unit	—	—	1	0.24	—	—	9	2.17
TEN	—	—	—	—	—	—	7	1.19
Equatorial Guinea
Block S	1	0.40	—	—	—	—	—	—
U.S. Gulf of Mexico
Nearly Headless Nick	1	0.22	—	—	—	—	—	—
Odd Job 214#2	—	—	—	—	—	—	1	0.61
Resolution	1	0.50	—	—	—	—	—	—
Mauritania
C8	1	0.28	—	—	3	0.84	1	0.28
Senegal
Saint Louis Offshore Profond	—	—	—	—	1	0.30	—	—
Cayar Profond	—	—	—	—	3	0.90	—	—
Total	4	1.40	1	0.24	7	2.04	18	4.25

43

The discussion of the results of operations and the period-to-period comparisons presented below analyze our historical results. The following discussion may not be indicative of future results.

Three months ended September 30, 2019 compared to three months ended September 30, 2018

	Three Months Ended
	September 30,						Increase
	2019			2018			(Decrease)
	(In thousands)
Revenues and other income:
Oil and gas revenue	$	357,036		$	242,833		$	114,203
Gain on sale of assets	—			7,666			(7,666		)
Other income, net	(66		)	(280		)	214
Total revenues and other income	356,970			250,219			106,751
Costs and expenses:
Oil and gas production	95,540			55,078			40,462
Facilities insurance modifications, net	12,569			12,334			235
Exploration expenses	22,773			148,238			(125,465		)
General and administrative	24,723			25,963			(1,240		)
Depletion, depreciation and amortization	146,653			80,041			66,612
Interest and other financing costs, net	30,721			23,549			7,172
Derivatives, net	(27,016		)	57,357			(84,373		)
Gain on equity method investment, net	—			(24,841		)	24,841
Other expenses, net	11,472			(12,807		)	24,279
Total costs and expenses	317,435			364,912			(47,477		)
Income (loss) before income taxes	39,535			(114,693		)	154,228
Income tax expense	23,470			11,364			12,106
Net income (loss)	$	16,065		$	(126,057	)	$	142,122

Oil and gas revenue.  Oil and gas revenue increased by $114.2 million as a result of having a full quarter of revenue from our U.S. Gulf of Mexico business unit during the three months ended September 30, 2019 related to the DGE acquisition versus 16 days of revenue in the previous year's period. The current year period also benefited from the inclusion of revenue from Equatorial Guinea on a consolidated basis for the three months ended September 30, 2019, which was previously accounted for as an equity method investment. The revenue increase from higher sales volumes was impacted by lower oil prices during the three months ended September 30, 2019, compared to the three months ended September 30, 2018. We sold 6,038 MBoe at an average realized price per barrel equivalent of $59.13 during the three months ended September 30, 2019 and 3,323 MBoe at an average realized price per barrel equivalent of $73.08 during the three months ended September 30, 2018.

Oil and gas production.  Oil and gas production costs increased by $40.5 million during the three months ended September 30, 2019, as compared to the three months ended September 30, 2018. This is a result of having a full quarter of oil and gas production costs from our U.S. Gulf of Mexico business unit during the three months ended September 30, 2019 related to the DGE acquisition, versus 16 days of costs in the previous year's period. The current year period was also impacted by the inclusion of Equatorial Guinea costs on a consolidated basis for the three months ended September 30, 2019, which was previously accounted for as an equity method investment.

Facilities insurance modifications, net. During the three months ended September 30, 2019, we incurred $12.6 million of facilities insurance modifications costs associated with the long-term solution to the Jubilee turret bearing issue versus $12.3 million during the three months ended September 30, 2018. During the three months ended September 30, 2019 and 2018, there were no offsetting hull and machinery insurance proceeds.

Exploration expenses.  Exploration expenses decreased by $125.5 million during the three months ended September 30, 2019, as compared to the three months ended September 30, 2018. The decrease is primarily a result of unsuccessful well costs recorded in 2018 associated with the write off of $57.7 million related to the Akasa-1 and Wawa-1 exploration wells in Ghana and

44

$12.6 million of unsuccessful well costs associated with our Suriname drilling. Additionally, we incurred approximately $50.0 million related to seismic acquisition costs in our Gulf of Mexico business unit during the three months ended September 30, 2018.

Depletion, depreciation and amortization.  Depletion, depreciation and amortization increased $66.6 million during the three months ended September 30, 2019, as compared with the three months ended September 30, 2018. The increase is a result of having a full quarter of depletion and depreciation costs from our U.S. Gulf of Mexico business unit during the three months ended September 30, 2019 related to the DGE acquisition, versus 16 days of costs in the previous year's period. The current year period was also impacted by the inclusion of depletion and depreciation costs associated with the Equatorial Guinea business unit, which was previously accounted for as an equity method investment.

Interest and other financing costs, net.  Interest and other financing costs, net increased $7.2 million primarily a result of an increased outstanding debt balance, the result of the DGE acquisition during the third quarter of 2018.

Derivatives, net.  During the three months ended September 30, 2019 and 2018, we recorded a gain of $27.0 million and a loss of $57.4 million, respectively, on our outstanding hedge positions. The amounts recorded were a result of changes in the forward oil price curve during the respective periods.

Gain on equity method investment, net. During the three months ended September 30, 2018 we recognized a $24.8 million gain on our equity method investment in KTIPI. Effective January 1, 2019, our equity method investment in KTIPI was exchanged for a direct interest in the Ceiba Field and Okume Complex, which was accounted for under the proportionate consolidation method of accounting during the three months ended September 30, 2019.

Other expenses, net.  Other expenses, net increased $24.3 million primarily related to the recovery of disputed charges of $12.9 million related to the arbitration award against Tullow Ghana during 2018 and an $8.7 million indirect tax settlement with tax authorities in Senegal.

Income tax expense (benefit).  For the three months ended September 30, 2019, our overall effective tax rate was impacted by the difference in our 21% U.S. income tax reporting rate and the 35% statutory tax rates applicable to our Ghanaian and Equatorial Guinean operations, non-deductible and non-taxable items associated with our U.S., Ghanaian, and Equatorial Guinean operations, and other losses and expenses, primarily related to exploration operations in tax-exempt jurisdictions or in taxable jurisdictions where we have valuation allowances against our deferred tax assets, and therefore, we do not realize any tax benefit on such losses or expenses.

For the three months ended September 30, 2018, our overall effective tax rate was impacted by non-deductible and non-taxable items associated with our U.S. and Ghanaian operations and other losses and expenses, primarily related to exploration operations in tax-exempt jurisdictions or in taxable jurisdictions where we have valuation allowances against our deferred tax assets, and therefore, we do not realize any tax benefit on such expenses or losses.

45

Nine months ended September 30, 2019 compared to nine months ended September 30, 2018

	Nine Months Ended
	September 30,						Increase
	2019			2018			(Decrease)
	(In thousands)
Revenues and other income:
Oil and gas revenue	$	1,049,759		$	585,220		$	464,539
Gain on sale of assets	—			7,666			(7,666		)
Other income, net	(65		)	(17		)	(48		)
Total revenues and other income	1,049,694			592,869			456,825
Costs and expenses:
Oil and gas production	266,316			151,661			114,655
Facilities insurance modifications, net	(5,174		)	21,812			(26,986		)
Exploration expenses	83,022			246,912			(163,890		)
General and administrative	88,703			65,343			23,360
Depletion, depreciation and amortization	416,186			208,607			207,579
Interest and other financing costs, net	125,565			68,113			57,452
Derivatives, net	35,884			236,107			(200,223		)
Gain on equity method investment, net	—			(59,637		)	59,637
Other expenses, net	11,798			(8,164		)	19,962
Total costs and expenses	1,022,300			930,754			91,546
Income (loss) before income taxes	27,394			(337,885		)	365,279
Income tax expense	47,398			(58,329		)	105,727
Net income (loss)	$	(20,004	)	$	(279,556	)	$	259,552

Oil and gas revenue.  Oil and gas revenue increased by $464.5 million as a result of the inclusion of revenue from our U.S. Gulf of Mexico business unit during the nine months ended September 30, 2019 related to the DGE acquisition, versus 16 days of revenue in the previous year's period. The current year period also benefited from the inclusion of revenue from Equatorial Guinea on a consolidated basis for the nine months ended September 30, 2019, which was previously accounted for as an equity method investment. The revenue increase from higher sales volumes was impacted by lower oil prices during the nine months ended September 30, 2019, compared to the nine months ended September 30, 2018. We sold 17,408 MBoe at an average realized price per barrel equivalent of $60.30 during the nine months ended September 30, 2019 and 8,152 MBoe at an average realized price per barrel equivalent of $71.79 during the nine months ended September 30, 2018.

Oil and gas production.  Oil and gas production costs increased by $114.7 million during the nine months ended September 30, 2019, as compared to the nine months ended September 30, 2018. This is a result of the inclusion of the U.S. Gulf of Mexico business unit, related to the DGE acquisition having a full nine months of oil and gas production costs from our U.S. Gulf of Mexico business unit during the nine months ended September 30, 2019 versus 16 days of costs in the previous year's period. The current year period was also impacted by the inclusion of production costs from Equatorial Guinea on a consolidated basis for the nine months ended September 30, 2019, which was previously accounted for as an equity method investment.

Facilities insurance modifications, net. During the nine months ended September 30, 2019, we incurred $34.8 million of facilities insurance modifications costs associated with the long-term solution to the Jubilee turret bearing issue versus $31.5 million during the nine months ended September 30, 2018. During the nine months ended September 30, 2019 and 2018, these costs were offset by $40.0 million and $9.7 million, respectively, of hull and machinery insurance proceeds.

Exploration expenses.  Exploration expenses decreased by $163.9 million during the nine months ended September 30, 2019, as compared to the nine months ended September 30, 2018. The decrease is primarily a result of unsuccessful well costs recorded in 2018 associated with the write off of $57.7 million related to the Akasa-1 and Wawa-1 exploration wells in Ghana and $57.1 million of unsuccessful well costs associated with our Suriname drilling. Additionally, we incurred approximately $50.0 million related to seismic acquisition costs in our Gulf of Mexico business unit during the nine months ended September 30, 2018.

46

General and administrative.  General and administrative costs increased by $23.4 million during the nine months ended September 30, 2019, as compared with the nine months ended September 30, 2018. This is primarily a result of having a full nine months of G&A costs from our U.S. Gulf of Mexico business unit during the nine months ended September 30, 2019 related to the DGE acquisition, versus 16 days of costs in the previous year's period.

Depletion, depreciation and amortization.  Depletion, depreciation and amortization increased $207.6 million during the nine months ended September 30, 2019, as compared with the nine months ended September 30, 2018. The increase is primarily a result of depletion and depreciation costs associated with the acquired U.S. Gulf of Mexico business unit and the Equatorial Guinea business unit, which was previously accounted for as an equity method investment.

Interest and other financing costs, net.  Interest and other financing costs, net increased $57.5 million primarily a result of an increased outstanding debt balance, the result of the DGE acquisition during the third quarter of 2018, and a $24.8 million loss on extinguishment of debt primarily associated with the refinancing of our senior notes recorded during the second quarter of 2019.

Derivatives, net.  During the nine months ended September 30, 2019 and 2018, we recorded a loss of $35.9 million and a loss of $236.1 million, respectively, on our outstanding hedge positions. The losses recorded were a result of changes in the forward curve of oil prices during the respective periods.

Gain on equity method investment, net. During the nine months ended September 30, 2018 we recognized a $59.6 million gain on our equity method investment in KTIPI. Effective January 1, 2019, our equity method investment in KTIPI was exchanged for a direct interest in the Ceiba Field and Okume Complex, which was accounted for under the proportionate consolidation method of accounting during the nine months ended September 30, 2019.

Other expenses, net.  Other expenses, net increased $20.0 million primarily related to the recovery of disputed charges of $12.9 million related to the arbitration against Tullow Ghana during 2018 and an $8.7 million indirect tax settlement with tax authorities in Senegal.

Income tax expense (benefit).  For the nine months ended September 30, 2019, our overall effective tax rate was impacted by the difference in our 21% U.S. income tax reporting rate and the 35% statutory tax rates applicable to our Ghanaian and Equatorial Guinean operations, non-deductible and non-taxable items associated with our U.S., Ghanaian, and Equatorial Guinean operations, and other losses and expenses, primarily related to exploration operations in tax-exempt jurisdictions or in taxable jurisdictions where we have valuation allowances against our deferred tax assets, and therefore, we do not realize any tax benefit on such losses or expenses.

For the nine months ended September 30, 2018, our overall effective tax rate was impacted by non-deductible and non-taxable items associated with our U.S. and Ghanaian operations and other losses and expenses, primarily related to exploration operations in tax-exempt jurisdictions or in taxable jurisdictions where we have valuation allowances against our deferred tax assets, and therefore, we do not realize any tax benefit on such expenses or losses.

Liquidity and Capital Resources

We are actively engaged in an ongoing process of anticipating and meeting our funding requirements related to our strategy as a full-cycle exploration and production company. We have historically met our funding requirements through cash flows generated from our operating activities and obtained additional funding from issuances of equity and debt, as well as partner carries.

While we are presently in a strong financial position, commodity prices are volatile and could negatively impact our ability to generate sufficient operating cash flows to meet our funding requirements. To partially mitigate this price volatility, we maintain a hedging program. Our investment decisions are based on longer-term commodity prices based on the nature of our projects and development plans. Also, BP has agreed to partially carry our exploration, appraisal and development program in Mauritania and Senegal up to a contractually agreed cap. Current commodity prices, combined with our hedging program, partner carries and our current liquidity position support our dividend and remaining capital program for 2019.

47

Sources and Uses of Cash

The following table presents the sources and uses of our cash and cash equivalents and restricted cash for the nine months ended September 30, 2019 and 2018:

	Nine Months Ended
	September 30,
	2019		2018
	(In thousands)
Sources of cash, cash equivalents and restricted cash:
Net cash provided by operating activities	$	400,276	$	90,247
Net proceeds from issuance of senior notes	641,875		—
Return of investment from KTIPI	—		142,628
Borrowings under long-term debt	175,000		1,000,000
Proceeds on sale of assets	—		13,703
	1,217,151		1,246,578
Uses of cash, cash equivalents and restricted cash:
Oil and gas assets	240,642		149,305
Other property	8,291		3,560
Acquisition of oil and gas properties	—		961,764
Notes receivable from partners	19,565		—
Payments on long-term debt	325,000		175,000
Redemption of senior secured notes	535,338		—
Purchase of treasury stock	1,983		17,695
Dividends	54,447		—
Deferred financing costs	2,443		36,745
	1,187,709		1,344,069
Increase (decrease) in cash, cash equivalents and restricted cash	$	29,442	$	(97,491	)

Net cash provided by operating activities.  Net cash provided by operating activities for the nine months ended September 30, 2019 was $400.3 million compared with net cash provided by operating activities for the nine months ended September 30, 2018 of $90.2 million. The increase in cash provided by operating activities is a result of the inclusion of our U.S. Gulf of Mexico business unit during the nine months ended September 30, 2019 related to the DGE acquisition, which was completed during the third quarter of 2018. It is also the result of the inclusion of operations from Equatorial Guinea on a consolidated basis for the nine months ended September 30, 2019, which was previously accounted for as an equity method investment.

48

The following table presents our net debt and liquidity as of September 30, 2019:

	September 30, 2019
	(In thousands)
Cash and cash equivalents	$	203,646
Restricted cash	11,412
Senior Notes at par	650,000
Borrowings under the Facility	1,500,000
Borrowings under the Corporate Revolver	—
Net debt	$	1,934,942
Availability under the Facility	$	100,000
Availability under the Corporate Revolver	$	400,000
Available borrowings plus cash and cash equivalents	$	703,646

Capital Expenditures and Investments

We expect to incur capital costs as we:

• drill additional wells and execute exploitation activities in Ghana, Equatorial Guinea and in the U.S. Gulf of Mexico;

• execute infrastructure-led exploration efforts in the U.S. Gulf of Mexico and Equatorial Guinea;

• execute appraisal and exploration activities in a number of our exploration license areas; and

• acquire and analyze seismic on existing licenses and purchase seismic over new prospective areas.

We have relied on a number of assumptions in budgeting for our future activities. These include the number of wells we plan to drill, our participating, paying and carried interests in our prospects including disproportionate payment amounts, the costs involved in developing or participating in the development of a prospect, the timing of third‑party projects, the availability of suitable equipment and qualified personnel and our cash flows from operations. We also evaluate potential corporate and asset acquisition opportunities to support and expand our asset portfolio which may impact our budget assumptions. These assumptions are inherently subject to significant business, political, economic, regulatory, environmental and competitive uncertainties, contingencies and risks, all of which are difficult to predict and many of which are beyond our control. We may need to raise additional funds more quickly if market conditions deteriorate, or one or more of our assumptions proves to be incorrect, or if we choose to expand our acquisition, exploration, appraisal, development efforts or any other activity more rapidly than we presently anticipate. We may decide to raise additional funds before we need them if the conditions for raising capital are favorable. We may seek to sell equity or debt securities or obtain additional bank credit facilities. The sale of equity securities could result in dilution to our shareholders. The incurrence of additional indebtedness could result in increased fixed obligations and additional covenants that could restrict our operations.

2019 Capital Program

We estimate we will spend approximately $425 - $475 million of capital, net of carry amounts related to the Mauritania and Senegal transactions with BP, for the year ending December 31, 2019. However, the ultimate amount of capital we will spend may vary or fluctuate materially based on market conditions and the success of our drilling results among other factors. Through September 30, 2019, we have spent approximately $318 million.

49

Significant Sources of Capital

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. The borrowing base calculation includes value related to the Jubilee, TEN, Ceiba and Okume fields. 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 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 September 30, 2019, we have $34.4 million of unamortized issuance costs related to the Facility, which will be amortized over the remaining term of the Facility. The commitments were reduced by $100 million to $1.6 billion following the Senior Notes issuance in April 2019.

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 September 30, 2019, we had no letters of credit issued under the Facility.

We were in compliance with the financial covenants contained in the Facility as of September 30, 2019 (the most recent assessment date). The Facility contains customary cross default provisions.

Corporate Revolver

In August 2018, we amended and restated the Corporate Revolver from a number of financial institutions, 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 September 30, 2019, there were no outstanding borrowings under the Corporate Revolver and the undrawn availability under the Corporate Revolver was $400 million. 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

We had a revolving letter of credit facility agreement (“LC Facility”), which matured in July 2019. As of September 30, 2019, there were six outstanding letters of credit totaling $9.4 million under the LC Facility. 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 require cash collateral. This arrangement contains customary cross default provisions.

7.875% Senior Secured Notes due 2021

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 during the second quarter.

7.125% Senior Notes due 2026

50

In April 2019, the Company issued $650.0 million of 7.125% Senior Notes (the "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.

51

Contractual Obligations

The following table summarizes by period the payments due for our estimated contractual obligations as of September 30, 2019:

	Payments Due By Year(4)
	Total		2019(5)		2020		2021		2022		2023		Thereafter
	(In thousands)
Principal debt repayments(1)	$	2,150,000	$	—	$	—	$	274,800	$	284,200	$	271,600	$	1,319,400
Interest payments on long-term debt(2)	618,914		45,266		127,318		114,764		102,899		86,169		142,498
Operating leases(3)	36,657		483		4,098		4,148		4,199		4,249		19,480

__________________________________

(1) Includes the scheduled principal 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 September 30, 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.

(2) Based on outstanding borrowings as noted in (1) above and the LIBOR yield curves at the reporting date and commitment fees related to the Facility and Corporate Revolver and the interest on the Senior Secured Notes.

(3) Primarily relates to corporate office and foreign office leases.

(4) 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 and seismic obligations, in our petroleum contracts. The Company's liabilities for asset retirement obligations associated with the dismantlement, abandonment and restoration costs of oil and gas properties are not included. See Note 15 — Additional Financial Information for additional information regarding these liabilities.

(5) Represents the period from October 1, 2019 through December 31, 2019.

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.

 The following table presents maturities by expected debt maturity dates, the weighted average interest rates expected to be paid on the Facility given current contractual terms and market conditions, and the debt’s estimated fair value. Weighted-average interest rates are based on implied forward rates in the yield curve at the reporting date. This table does not include amortization of deferred financing costs.

																			Asset
																			(Liability)
																			Fair Value at
	Years Ending December 31,																		September 30,
	2019(3)			2020			2021			2022			2023			Thereafter			2019
	(In thousands, except percentages)
Fixed rate debt:
Senior Secured Notes	$	—		$	—		$	—		$	—		$	—		$	650,000		$	(670,514	)
Fixed interest rate	7.13		%	7.13		%	7.13		%	7.13		%	7.13		%	7.13		%
Variable rate debt:
Facility(1)	$	—		$	—		$	274,800		$	284,200		$	271,600		$	669,400		$	(1,500,000	)
Weighted average interest rate(2)	5.30		%	4.83		%	4.55		%	4.91		%	5.03		%	5.52		%

__________________________________

(1) The amounts included in the table represent principal maturities only. The scheduled maturities of debt are based on the level of borrowings and the available borrowing base as of September 30, 2019. 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.

52

(2) Based on outstanding borrowings as noted in (1) above and the LIBOR yield curves plus applicable margin at the reporting date. Excludes commitment fees related to the Facility and Corporate Revolver.

(3) Represents the period October 1, 2019 through December 31, 2019.

Off-Balance Sheet Arrangements

We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of September 30, 2019, our material off-balance sheet arrangements and transactions include short-term operating leases and undrawn letters of credit. There are no other transactions, arrangements, or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect Kosmos’ liquidity or availability of or requirements for capital resources.

Critical Accounting Policies

We consider accounting policies related to our revenue recognition, exploration and development costs, receivables, income taxes, derivative instruments and hedging activities, estimates of proved oil and natural gas reserves, asset retirement obligations, leases and impairment of long-lived assets as critical accounting policies. The policies include significant estimates made by management using information available at the time the estimates are made. However, these estimates could change materially if different information or assumptions were used. Other than the implementation of the new lease standard discussed in Note 2 — Accounting Policies, there have been no changes to our critical accounting policies which are summarized in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” section in our annual report on Form 10-K, for the year ended December 31, 2018.

Cautionary Note Regarding Forward-looking Statements

This quarterly report on Form 10-Q contains estimates and forward-looking statements, principally in “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Our estimates and forward-looking statements are mainly based on our current expectations and estimates of future events and trends, which affect or may affect our businesses and operations. Although we believe that these estimates and forward-looking statements are based upon reasonable assumptions, they are subject to several risks and uncertainties and are made in light of information currently available to us. Many important factors, in addition to the factors described in our quarterly report on Form 10-Q and our annual report on Form 10-K, may adversely affect our results as indicated in forward-looking statements. You should read this quarterly report on Form 10-Q, the annual report on Form 10-K and the documents that we have filed with the Securities and Exchange Commission completely and with the understanding that our actual future results may be materially different from what we expect. Our estimates and forward-looking statements may be influenced by the following factors, among others:

• our ability to find, acquire or gain access to other discoveries and prospects and to successfully develop and produce from our current discoveries and prospects;

• uncertainties inherent in making estimates of our oil and natural gas data;

• the successful implementation of our and our block partners’ prospect discovery and development and drilling plans;

• projected and targeted capital expenditures and other costs, commitments and revenues;

• termination of or intervention in concessions, rights or authorizations granted to us by the governments of the countries in which we operate (or their respective national oil companies) or any other federal, state or local governments or authorities;

• our dependence on our key management personnel and our ability to attract and retain qualified technical personnel;

• the ability to obtain financing and to comply with the terms under which such financing may be available;

• the volatility of oil, natural gas and NGL prices;

• the availability, cost, function and reliability of developing appropriate infrastructure around and transportation to our discoveries and prospects;

• the availability and cost of drilling rigs, production equipment, supplies, personnel and oilfield services;

• other competitive pressures;

• potential liabilities inherent in oil and natural gas operations, including drilling and production risks and other operational and environmental risks and hazards;

• current and future government regulation of the oil and gas industry or regulation of the investment in or ability to do business with certain countries or regimes;

• cost of compliance with laws and regulations;

• changes in environmental, health and safety or climate change or greenhouse gas (“GHG”) laws and regulations or the implementation, or interpretation, of those laws and regulations;

53

• adverse effects of sovereign boundary disputes in the jurisdictions in which we operate;

• environmental liabilities;

• geological, geophysical and other technical and operations problems, including drilling and oil and gas production and processing;

• military operations, civil unrest, outbreaks of disease, terrorist acts, wars or embargoes;

• the cost and availability of adequate insurance coverage and whether such coverage is enough to sufficiently mitigate potential losses and whether our insurers comply with their obligations under our coverage agreements;

• our vulnerability to severe weather events, including tropical storms and hurricanes in the Gulf of Mexico;

• our ability to meet our obligations under the agreements governing our indebtedness;

• the availability and cost of financing and refinancing our indebtedness;

• the amount of collateral required to be posted from time to time in our hedging transactions, letters of credit, performance bonds and other secured debt;

• the result of any legal proceedings, arbitrations, or investigations we may be subject to or involved in;

• our success in risk management activities, including the use of derivative financial instruments to hedge commodity and interest rate risks; and

• other risk factors discussed in the “Item 1A. Risk Factors” section of this quarterly report on Form 10-Q and our annual report on Form 10-K.

The words “believe,” “may,” “will,” “aim,” “estimate,” “continue,” “anticipate,” “intend,” “expect,” “plan” and similar words are intended to identify estimates and forward-looking statements. Estimates and forward-looking statements speak only as of the date they were made, and, except to the extent required by law, we undertake no obligation to update or to review any estimate and/or forward-looking statement because of new information, future events or other factors. Estimates and forward-looking statements involve risks and uncertainties and are not guarantees of future performance. As a result of the risks and uncertainties described above, the estimates and forward-looking statements discussed in this quarterly report on Form 10-Q might not occur, and our future results and our performance may differ materially from those expressed in these forward-looking statements due to, including, but not limited to, the factors mentioned above. Because of these uncertainties, you should not place undue reliance on these forward-looking statements.

Item 3. Qualitative and Quantitative Disclosures About Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risks” as it relates to our currently anticipated transactions refers to the risk of loss arising from changes in commodity prices and interest rates. These disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage ongoing market risk exposures. We enter into market-risk sensitive instruments for purposes other than to speculate.

We manage market and counterparty credit risk in accordance with our policies. In accordance with these policies and guidelines, our management determines the appropriate timing and extent of derivative transactions. See “Item 8. Financial Statements and Supplementary Data — Note 2 — Accounting Policies, Note 9 — Derivative Financial Instruments and Note 10 — Fair Value Measurements” section of our annual report on Form 10-K for a description of the accounting procedures we follow relative to our derivative financial instruments.

The following table reconciles the changes that occurred in fair values of our open derivative contracts during the nine months ended September 30, 2019:

	Derivative Contracts Assets (Liabilities)
	Commodities
	(In thousands)
Fair value of contracts outstanding as of December 31, 2018	$	30,744
Changes in contract fair value	(34,003		)
Contract maturities	24,701
Fair value of contracts outstanding as of September 30, 2019	$	21,442

54

Commodity Price Risk

The Company’s revenues, earnings, cash flows, capital investments and, ultimately, future rate of growth are highly dependent on the prices we receive for our crude oil, which have historically been very volatile. Substantially all of our oil sales are indexed against Dated Brent, Eugene Island, Heavy Louisiana Sweet and Mars crude.

Commodity Derivative Instruments

We enter into various oil derivative contracts to mitigate our exposure to commodity price risk associated with anticipated future oil production. These contracts currently consist of collars, put options, call options and swaps. In regards to our obligations under our various commodity derivative instruments, if our production does not exceed our existing hedged positions, our exposure to our commodity derivative instruments would increase.

Commodity Price Sensitivity

The following table provides information about our oil derivative financial instruments that were sensitive to changes in oil prices as of September 30, 2019. Volumes and weighted average prices are net of any offsetting derivatives entered into.

				Weighted Average Price per Bbl										Asset (Liability)
				Net Deferred										Fair Value at
				Premium										September 30,
Term	Type of Contract	Index	MBbl	Payable/(Receivable)		Swap		Sold Put		Floor		Ceiling		2019(3)
														(In thousands)
2020:
Oct — Dec	Three-way collars	Dated Brent	2,628	$	1.17	$	—	$	43.81	$	53.33	$	73.57	$	(1,701	)
Oct — Dec	Sold calls(1)	Dated Brent	230	—		—		—		—		80.00		(2,355		)
Oct — Dec	Swaps	NYMEX WTI	265	—		51.61		—		—		—		(563		)
Oct — Dec	Collars	Argus LLS	250	—		—		—		60.00		88.75		1,026
2020:
Jan — Dec	Three-way collars	Dated Brent	6,000	$	0.45	$	—	$	45.00	$	57.50	$	80.18	$	21,019
Jan — Dec	Swaps with sold puts	Dated Brent	2,000	—		60.53		48.75		—		—		3,074
Jan — Dec	Put spread	Dated Brent	2,000	2.59		—		50.00		60.00		—		4,139
Jan — Dec	Sold calls(1)(2)	Dated Brent	8,000	1.17		—		—		—		85.00		(1,940		)
2021:
Jan — Dec	Sold calls(1)	Dated Brent	1,000	$	—	$	—	$	—	$	—	$	75.00	(1,257		)

__________________________________

(1) Represents call option contracts sold to counterparties to enhance other derivative positions.

(2) Deferred premium payable to be paid October 1, 2019 — December 31, 2019.

(3) Fair values are based on the average forward oil prices on September 30, 2019.

In October 2019, we entered into put option contracts for 2.0 MMBbls from January 2020 through December 2020 with a floor price of $57.50 per barrel and a sold put price of $50.00 per barrel. In addition, we sold 3.0 MMBbl of calls from January 2021 through December 2021 with an average strike price of $71.67 per barrel. The contracts are indexed to Dated Brent prices.

At September 30, 2019, our open commodity derivative instruments were in a net asset position of $21.4 million. As of September 30, 2019, a hypothetical 10% price increase in the commodity futures price curves would decrease future pre-tax earnings by approximately $37.6 million. Similarly, a hypothetical 10% price decrease would increase future pre-tax earnings by approximately $35.3 million.

55

Interest Rate Sensitivity

At September 30, 2019, we had indebtedness outstanding under the Facility of $1,500 million, which bore interest at floating rates. The interest rate on this indebtedness as of September 30, 2019 was approximately 5.3%. If LIBOR increased by 10% at this level of floating rate debt, we would pay an additional $3.1 million in interest expense per year. The commitment fees on the undrawn availability under the Facility and the Corporate Revolver are not subject to changes in interest rates.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) was performed under the supervision and with the participation of the Company’s management, including our Chief Executive Officer and Chief Financial Officer. This evaluation considered the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in the SEC reports we file or submit under the Exchange Act is accurate, complete and timely. However, a control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. The design of a control system must reflect the fact that there are resource constraints, and the benefit of controls must be considered relative to their costs. Consequently, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected. Based upon this evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of September 30, 2019, in ensuring that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, including that such information is accumulated and communicated to the Company’s management, including our Chief Executive Officer and our Chief Financial Officer, to allow timely decisions regarding required disclosure.

Evaluation of Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during our most recent fiscal quarter that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings 

There have been no material changes from the information concerning legal proceedings discussed in the “Item 3. Legal Proceedings” section of our annual report on Form 10-K.

Item 1A. Risk Factors

There have been no material changes from the risks discussed in the “Item 1A. Risk Factors” section of our annual report on Form 10-K for the year ended December 31, 2018, other than the following:

Changes in the method of determining London Interbank Offered Rate (“LIBOR”), or the replacement of LIBOR with an alternative reference rate, may adversely affect interest expense related to our outstanding debt.

Changes in the method of determining London Interbank Offered Rate (“LIBOR”), or the replacement of LIBOR with an alternative reference rate, may adversely affect interest expense related to outstanding debt. On July 27, 2017, the Financial Conduct Authority in the United Kingdom announced that it would no longer persuade or compel panel banks to submit the rates required to calculate LIBOR after the end of 2021. The announcement indicates that the continuation of LIBOR on the current basis cannot and will not be guaranteed after 2021. The continued existence of LIBOR after 2021, therefore, remains highly uncertain. While various governmental working groups are pursuing replacement rates, if LIBOR ceases to exist, we may need to renegotiate our Facility and Corporate Revolver and may not be able to do so on terms that are favorable to us.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

56

None.

Item 3.    Defaults Upon Senior Securities

None.

Item 4.    Mine Safety Disclosures

Not applicable.

Item 5.    Other Information.

There have been no material changes required to be reported under this Item that have not previously been disclosed in the annual report on Form 10-K.

Item 6. Exhibits

The information required by this Item 6 is set forth in the Index to Exhibits accompanying this quarterly report on Form 10‑Q.

57

SIGNATURES

Pursuant to the requirements of the Securities Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		Kosmos Energy Ltd.
		(Registrant)
Date	November 4, 2019	/s/ THOMAS P. CHAMBERS
		Thomas P. Chambers
		Senior Vice President and Chief Financial Officer
		(Principal Financial Officer)

58

INDEX OF EXHIBITS

Exhibit Number	Description of Document
10.1	Exploration Right Contract relating to the Northern Cape Ultra Deep Block Offshore South Africa between the Republic of South Africa and OK Energy Limited dated January 10, 2019.
31.1	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document

59

EX-10.1

Ref No: 12/3/274

EXPLORATION RIGHT

Granted in terms of Section 80 of the Mineral and Petroleum Resources Development Act, 2002(Act No. 28 of 2002)

Ref No: 12/3/274

TABLE OF CONTENTS

Clause	Title	Page
	Preamble	4-6
1.	Definitions and Interpretations	6-11
2.	Granting of the Right	11
3.	Exploration Area	11
4.	Exclusive Right to Apply for a Production Right in respect of Discoveries	11-12
5.	Rights and Obligations of the Holder	12
6	Commencement, Duration and Renewal	12-13
7	Exploration Fees	13
8	Technical Advisory Committee	13-15
9.	Cancellation or Suspension of the Exploration Right	15
10.	Relinquishment and Voluntary Abandonment of the Exploration Area	15-16
11.	Rights to Minerals and Petroleum	16
12.	Examination of the Exploration Area	17
13.	Records and Samples	17
14.	Reports	18
15.	Annual Exploration Work Programme and Budget	18-19
16.	Discoveries and Testing	20-22
17.	Manner of Conducting Exploration Operations	22-23
18.	Existing Data	23
19.	Environmental Protection and Financial Provision	24
20.	Social and Labour Matters	24-25
21.	Tax	25
22.	Financial Records and Audits	25
23.	Customs Duties	26

Page 1 of 147

Ref No: 12/3/274

24.	Exchange Control	26
25.	Indemnity and Insurance	26-27
26.	Health and Safety	27
27.	Confidentiality and Public Announcements	27-29
28.	Cession and Sub-contracting	29
29.	Law and Interpretation	30
30.	Obligations of the Grantor	30
31.	State Option	30-31
32.	Vis Major	31-32
33.	Amendments	32
34.	Unitisation	32-33
35.	Special Provisions Relating to Gas Discovery	33-34
36.	Waiver or Lenience	34
37.	Dispute Resolution	34-36
38.	Costs and Value Added Tax	36
39.	Entire agreement	36
40.	Severability	37
41.	Domicilia Citandi et Executandi	37-38
42.	Registration	38-39

ANNEXURE INDEX

Page 2 of 247

Ref No: 12/3/274

Annexure	Annexure Title	Pages
A	List of farms & Sketch Plan for the Exploration Area	40
B	Exploration Work Programme [Inclusive of the Minimum Work Obligations]	41
C	Relinquishment Schedule	42
D	Schedule of Contributions to the Upstream Training Trust	43
E	A List of Available Data Made Available to the Holder	44

Page 3 of 347

Ref No: 12/3/274

PROTOCOL NO: 2537/2019

EXPLORATION RIGHT

GRANTED IN TERMS OF SECTION 80 OF THE MINERAL AND PETROLEUM RESOURCES DEVELOPMENT ACT, NO. 28 OF 2002 READ TOGETHER WITH REGULATION 29 PUBLISHED IN THE GOVERNMENT GAZETTE NO. 26275 ON 23 APRIL 2004, PROMULGATED IN TERMS OF SECTION 107 OF THE ACT

PREAMBLE:

Whereas	Buyelwa Patience Sonjica in her capacity as the Minister of Minerals and Energy on the 14th December 2006 delegated the powers conferred on her in the Act, as defined below, to the Director-General in terms of the provisions of section 3(2)(a) and section 103 of the Act, which delegation (reference no. 12/2/7/1/7) remains of full force and effect.
And	on 1 July 2009 by Proclamation No 44, 2009 the State President of the Republic of South Africa transferred the administration and the powers and functions entrusted to the Minister of Minerals and Energy by the Act including all amendments thereto, to the Minister of Mineral Resources.
And	the Minister has on the 12th day of January 2016 granted the Holder as defined below, an Exploration Right upon the following terms and conditions.

LET IT HEREBY BE KNOWN:

That on this 10th day of January in the year 2019 before me,

HENDRIK MALHERBE OOSTHUIZEN

a Notary Public, duly sworn and admitted, practicing and residing at Cape Town, in the Western Cape Province, Republic of South Africa, and in the presence of the subscribing competent witnesses personally came and appeared:

1.    VILJOEN STORM

In his capacity as the Acting Chief Executive Officer of

SOUTH AFRICAN AGENCY FOR PROMOTION OF PETROLEUM EXPLORATION ANDEXPLOITATION (SOC) LTD,

Registration No.1999/015715/30

he being duly authorized hereto by a Power of Attorney granted to him at Pretoria on 24 November 2015 by the Director General of the Department of Mineral Resources, which Power of Attorney has this day been exhibited to me, the Notary, and remains filed of record in my protocol with the minute thereto, and herein representing:

THE MINISTER OF MINERAL RESOURCES

Page 4 of 447

Ref No: 12/3/274

(hereinafter together with his successors in title referred to as ‘the Minister’), being duly authorised by virtue of the provisions of Section 3(2)(a) and Section 103 of the Mineral and Petroleum Resources Development Act, 2002 (Act No. 28 of 2002) and as such in his capacity representing:

THE REPUBLIC OF SOUTH AFRICA

(hereinafter referred to as “the Grantor”) of the one part, and

2.    OK ENERGY LIMITED

Registration Number 7394765A company incorporated under the laws of England and Wales

herein represented by Paul Barrett he being duly authorized thereto under and by virtue of a Resolution signed on the 7th January 2019, a certified copy of the extract of the Minutes of the Meeting has this day been exhibited to me, the Notary, and now remains filed of record in my Protocol. 

(hereinafter together with its successors in title and assigns referred to as “the Holder”),

all jointly hereinafter referred to as “the Parties”.

AND THE APPEARERS DECLARED THAT

WHEREAS	The State, as Grantor is the custodian of the mineral and petroleum resources of the Republic of South Africa;
AND WHEREAS	The Holder has applied for an Exploration Right in respect of the Exploration area described below;
AND WHEREAS	The Grantor has granted to the Holder this Exploration Right on the terms and conditions set out below.

NOW, THEREFORE, THE GRANTOR HEREBY GRANTS TO THE HOLDER, AND THE HOLDER HEREBY ACCEPTS, THIS EXPLORATION RIGHT SUBJECT TO THE FOLLOWING TERMS AND CONDITIONS:

1. Definitions and Interpretation

1.1. Unless the context indicates otherwise, or as otherwise defined herein, any expression to which a meaning has been assigned in the Act shall bear, when used in this Exploration Right, the same meaning and apply mutatismutandis hereto. In this Exploration Right the following words and expressions shall have the corresponding meanings assigned to them:

1.1.1. ‘the Act’ shall mean the Mineral and Petroleum Resources Development Act, 2002 (Act No. 28 of 2002);

1.1.2. ‘Acquired Data’ shall mean all technical information and data (digital or otherwise) and Samples, directly or indirectly, relating to the Exploration Area that are obtained

Page 5 of 547

Ref No: 12/3/274

or created by the Holder in the course of Exploration Operations, including drilling, appraisal, production, completion, and abandonment reports; tests (including reservoir analysis); well logs; maps; production rates, records and statistics; and geological and geophysical information and interpretations; but excluding, for the avoidance of doubt, any Existing Data;

1.1.3. ‘Affiliate’ shall mean another Person which, directly or indirectly, owns, or is owned by, or is owned by a Person which owns, that first-mentioned Person; ‘owns’ and ‘owned’ in this definition means the beneficial ownership of 50 % (fifty percent) or more of the voting shares or other securities of such person;

1.1.4. ‘Agency’ shall mean the designated agency as defined in the Act, which currently is the South African Agency for Promotion of Petroleum Exploration and Exploitation SOC Ltd, also known as Petroleum Agency SA;

1.1.5. ‘Annual Exploration Work Programme’ shall mean the annual work programme for Exploration Operations, inclusive of the estimated budget of costs and expenses of carrying out the same, that the Holder prepares and is approved by the Grantor in accordance with Clause 15;

1.1.6. ‘Applicable Laws’ shall mean the laws of the Republic of South Africa;

1.1.7. ‘Appraisal Operations’ shall mean any operation, study, activity, or matter, whether taking place within or outside of the Republic of South Africa, to appraise and evaluate the extent and volume of petroleum within a Discovery made by the Holder in the Exploration Area and to determine whether such Discovery could be a Commercial Discovery, including, if and to the extent applicable, all production of petroleum necessary in connection with completion and testing of any appraisal well (including, if necessary, any long-term production test) and all plugging and abandonment of any appraisal well. The terms ‘to Appraise’ or ‘Appraisal’ shall be construed accordingly;

1.1.8. ‘Appraisal Programme’ shall mean the appraisal programme for Appraisal Operations, inclusive of the estimated budget of costs and expenses of carrying out the same, that the Holder prepares and is approved by the Grantor in accordance with Clause 16 3;

1.1.9. ‘Commercial Discovery’ shall mean a Discovery of petroleum within the Exploration Area in such quantities as will permit the economic development thereof, on its own or in combination with other existing Discoveries or as part of a unitised development;

1.1.10. ‘Days’ shall have the meaning ascribed to it in the Act;

Page 6 of 647

Ref No: 12/3/274

1.1.11. ‘Development Plan’ shall mean the development plan for the Exploration Area, as amended from time to time, that the Holder prepares and is approved by the Grantor;

1.1.12. ‘Development Plan Supplement’ shall mean a plan for the further development and production of any additional Commercial Discoveries within the Exploration Area, as amended from time to time, that the Holder prepares and is approved by the Grantor; 

1.1.13. ‘Discovery’ shall mean the discovery by the Holder of a geological feature within the Exploration Area that is determined by the Holder in accordance with Good International Petroleum Industry Practices to be capable of producing petroleum;

1.1.14. ‘Environmental Authorisation’ shall have the meaning ascribed to it in terms of the National Environmental Management Act. 1998 (Act 107 of 1998);

1.1.15. ‘Existing Data’ shall mean all technical information and data provided to the Holder by the Grantor, as set out in Annexure “E” hereto, receipt of which has been acknowledged by the Holder;

1.1.16. ‘Exploration Area’ shall mean the area within the Republic of South Africa described in Clause 3, excluding those portions relinquished or abandoned from time to time in accordance herewith;

1.1.17. ‘Exploration Operations’ shall have the meaning ascribed to it in the Act which for purposes of this Exploration Right shall include Appraisal Operations;

1.1.18. ‘Exploration Work Programme’ shall mean the work programme attached hereto as Annexure B, the Annual Exploration Work Programme and any Appraisal Programme, as it may be amended from time to time, that the Holder prepares and is approved by the Grantor;

1.1.19. ‘First Renewal Period’ shall mean the first renewal of this Exploration Right granted in terms of Section 81 of the Act read together with Regulation 33;

1.1.20. ‘Gas’ shall mean any hydrocarbon which at a temperature of 21 (twenty one) degrees Celsius and a pressure of 1 (one) atmosphere, is in a gaseous phase existing in a natural condition in the earth’s crust, regardless of the nature of the host rock, and includes any gas which has in any manner been returned to such natural condition, and includes condensate of such gas, but does not include hydrocarbon gas obtained by destructive distillation or gas arising from a marsh or other surface deposit;

1.1.21. ‘Good International Petroleum Industry Practices’ shall mean those good, sound and generally accepted prevailing standards, practices, considerations, and

Page 7 of 747

Ref No: 12/3/274

procedures that are applied by reasonable and prudent companies and operators in the international petroleum industry under conditions and circumstances similar to those experienced in the Exploration Area;

1.1.22. ‘Government’ shall mean the government of the Republic of South Africa; 

1.1.23. ‘Granting Date’ shall mean the date on which the granting of this Exploration Right or any renewal thereof (whichever applicable) is communicated to the Holder;

1.1.24. ‘Grantor’ shall have the meaning attributed thereto in the description of the Parties above;

1.1.25. ‘Grantor Group’ shall mean collectively, the Department of Mineral Resources (including the Minister), and the Agency (including the Chief Executive Officer), and the directors, officers, employees, agents, representatives and invitees of each of the aforementioned;

1.1.26. ‘Holder’ shall have the meaning ascribed to it in the preamble and shall include each Holder Party;

1.1.27. ‘Holder Group’ shall mean, collectively, the Holder, each Holder Party, contractors (of any tier) of the Holder used in connection with Exploration Operations hereunder and directors, officers, employees, agents, representatives, and invitees of each of the aforementioned;

1.1.28. ‘Holder Party’ shall mean each Holder and each successor in title;

1.1.29. ‘Income Tax Act’ shall mean the Income Tax Act, 1962 (Act No. 58 of 1962);

1.1.30. ‘Initial Period’ shall mean a period of 36 (thirty six) months commencing from the date of notarial execution;

1.1.31. ‘Minimum Work Obligation’ shall mean the minimum work to be conducted by the Holder in respect of each Sub-period (as defined below) and as specified in the attached Annexure B;

1.1.32. ‘Participating Interest’ shall mean a Holder Party’s undivided share (expressed as a percentage) in all of the rights and obligations of the Holder derived from this Exploration Right;

1.1.33. ‘Person’ shall mean any natural person and any partnership, incorporated or unincorporated joint venture, corporation, limited liability company, trust, estate, organisation or entity, and any branch, division, political sub-division, instrumentality, authority or agency of any government or state;

1.1.34. ‘Petroleum’ shall have the meaning ascribed to it in the Act;

Page 8 of 847

Ref No: 12/3/274

1.1.35. ‘Production Right’ shall have the meaning ascribed to it in Clause 4;

1.1.36. ‘Quarter’ means a three-month period of a year beginning on 1^st January, 1^st April, 1^st July or 1^st October of any year;

1.1.37. ‘Regulations’ shall mean the Regulations promulgated in terms of Section 107 of the Act;

1.1.38. ‘Renewal Period’ shall mean that period of time for which this Exploration Right is renewed in terms of Section 81 of the Act read together with Regulation 33;

1.1.39. ‘Required Data’ shall mean, collectively, all the Acquired Data in its final form generated or recorded and preserved by the Holder in the course of conducting Exploration Operations pursuant to (a) the requirements of the Applicable Laws or (b) a reasonable request by the Grantor or (c) the Agency’s published reporting standards manual;

1.1.40. ‘Samples’ shall mean physical samples of rock, fluid and other materials acquired by the Holder in the course of conducting Exploration Operations for the purpose of preserving and analysing such samples;

1.1.41. ‘Second Renewal Period’ shall mean the second renewal of this Exploration Right granted in terms of Section 81 of the Act read together with Regulation 33;

1.1.42. ‘State’ shall mean the Republic of South Africa;

1.1.43. ‘Sub-period’ shall mean the First Renewal Period and/or the Second Renewal Period and/or the Third Renewal Period;

1.1.44. ‘Third Renewal Period’ shall mean the third renewal of this Exploration Right granted in terms of Section 81 of the Act read together with Regulation 33;

1.1.45. ‘Upstream Training Trust’ shall mean the independent Upstream Training Trust registered under registration number IT 1289/98; and

1.1.46. ‘Year’ shall mean the period of 12 (twelve) calendar months from the date of notarial execution and each subsequent 12 (twelve) month period thereafter. The terms ‘Yearly,’ ‘Annual,’ or ‘Annually’ shall be construed accordingly.

1.2. Interpretation in this Exploration Right

1.2.1. Where the context so requires, in this Exploration Right the words: 

1.2.1.1. importing the masculine gender shall include the feminine and vice versa,

Page 9 of 947

Ref No: 12/3/274

1.2.1.2. ‘hereunder,’ ‘herein,’ ‘hereof and words of similar import are references to this Exploration Right as a whole and not to any particular provision of this Exploration Right, unless expressly provided to the contrary, and

1.2.1.3. ‘include’ and ‘including’ shall mean to be inclusive without limiting the generality of the description preceding such term and are used in an illustrative sense and not a limiting sense.

1.2.2. Headings and sub-headings to clauses and sub-clauses are inserted for convenience only and are not to be taken into consideration in the interpretation or construction of this Exploration Right.

1.2.3. References to any Clause or Annexure are to a Clause or Annexure (as the case may be) of this Exploration Right unless expressly stated to the contrary.

1.2.4. This Exploration Right has been written in English and shall be interpreted and construed in accordance with the English language. All correspondence, communication and documents exchanged between the Grantor and the Holder in connection herewith, whether oral or written, shall be in the English language.

1.2.5. Reference to any statute, statutory provision or regulation shall include a reference to that statute, statutory provision or regulation as amended, extended or re-enacted from time to time.

1.2.6. In the event of any conflict or inconsistency between the provisions of this Exploration Right and the Act, the provisions of the Act shall govern. In the event of any conflict or inconsistency between the provisions of this Exploration Right and any Regulations, the provisions of the Regulations shall govern.

1.2.7. In the event of any conflict between the provisions of the main body of this Exploration Right and its Annexures the provisions of the main body of this Exploration Right shall govern.

2. Granting of the Right

2.1. Subject to the Act, the Regulations and the terms and conditions set forth herein, the Grantor hereby grants to the Holder and the Holder hereby accepts this Exploration Right.

2.2. As of the date of notarial execution of this Exploration Right, the Participating Interest of each Holder Party is as follows:

OK Energy Limited 100% share

Page 10 of 1047

Ref No: 12/3/274

3. Exploration Area

The Exploration Area, shall comprise of 693 003 (six nine three zero zero three) hectares in extent, situated offshore the Northern and Western Cape Provinces of the Republic of South Africa, which Exploration Area is described in detail on the attached plan marked hereto as Annexure “A”.

4. Exclusive Right to Apply for a Production Right in Respect of Discoveries

4.1. Subject to the provisions of Section 83 of the Act read together with Regulation 34, the Holder has the exclusive right to apply for and be granted a Production Right in respect of each Commercial Discovery within the Exploration Area provided that any such application for a Production Right has been lodged prior to the expiry date of this Exploration Right. To the extent permissible in terms of the Applicable Laws in force at the time, the Parties undertake to commence negotiation of the terms of such Product Right one year from the date of notarial execution of the Exploration Right, which terms shall thereafter by included as an Annexure to the Exploration Right by way of an amendment to the Exploration Right in accordance with section 102 of the Act

4.2. Any area falling within the Exploration Area in respect of which a production right has been granted to the Holder shall, as from the date of the grant of such production right, be severed from and no longer form part of the Exploration Area.

4.3. In the case of the severance referred to in 4.2 above, the Holder shall, simultaneous with the granting and or issuing of the new Production Right, submit the necessary amended sketch plan reflecting the new size and extent of the Exploration Area, and the necessary endorsements shall be reflected on the Grantor’s records.

4.4. As a part of its application for a Production Right, the Holder shall propose the area to be included in the Production Right, which area shall be at least sufficient to ensure that it encloses the entire formation in which the Commercial Discovery is located, including any likely extensions thereto and any potential additions to the initial Development Plan. In the event that a Commercial Discovery extends beyond the boundary of the Exploration Area into acreage over which no person has an outstanding application for a technical cooperation permit, exploration right or production right, the Holder shall have the right, to the extent permissible in terms of the Applicable Laws, to apply for a further Production Right to include the full extent of the Commercial Discovery that falls outside the boundary of the Exploration Area.

5. Rights and Obligations of the Holder

Page 11 of 1147

Ref No: 12/3/274

5.1. Without derogating from the Holder’s rights and obligations in terms of this Exploration Right and Section 5 of the Act. the Holder shall have the right to own and dispose of any and all facilities, materials, equipment, supplies and consumables purchased and/or leased by the Holder for the conduct of Exploration Operations.

5.2. Without derogating from the Holder’s other obligations in terms of this Exploration Right, the Holder shall:

5.2.1. diligently conduct Exploration Operations in accordance with the Exploration Work Programme;

5.2.2. comply with the Environmental Authorisation; and

5.2.3. pay all amounts due and payable to the Grantor in terms of the Act, the Regulations, this Exploration Right and the Applicable Laws

5.3. Although the Grantor undertakes to make a reasonable attempt to resolve disputes, the Holder acknowledges that the Grantor cannot guarantee that the Holder will at all times be in a position to exercise within the Exploration Area the rights granted in terms of this Exploration Right, and that in certain instances conflicts may arise with other rights holders and or interested and affected parties within or around the Exploration Area In the event of such conflicts the holder will endeavour to resolve these conflicts with such right holders and or interested parties.

6. Commencement, Duration and Renewal

6.1. This Exploration Right will commence on the Granting Date and, unless abandoned, cancelled, relinquished, suspended, terminated, extended or renewed in accordance herewith, will continue to be in force and effect until the 11 January 2019.

6.2. In line with section 82 (2) of the Act the Holder shall, within 90 (ninety) days from the date of notarial execution, or such extended period as the Minister may authorise, commence Exploration Operations in accordance with the Exploration Work Programme. 

6.3. In terms of section 81, read with regulation 33, of the Act the applicant has the right to, prior the end of the Initial Period or any Renewal Period, apply to the Minister for the renewal of the Exploration Right.

7. Exploration Fees

7.1. The Holder shall pay in terms Section 82(2)(e) of the Act read together with Regulation 76 the prescribed exploration fees inclusive of interest to the Agency as from the commencement date.

Page 12 of 1247

Ref No: 12/3/274

7.2. All amounts due and payable by the Holder in terms of this Exploration Right shall be paid into the Agency’s nominated Bank account, namely:

Bank Name: ABSA

Branch: Parow

Branch Code: 502110

Account name: Petroleum Agency SA

Account number: 405 103 0832

Account type: Current Account

or such other bank account as the Grantor may from time to time notify the Holder, subject to the Holder conducting due diligence to its satisfaction on such other bank account within 30 (thirty) days of such notification.

7.3. Should the Holder fail to pay any amount due and payable hereunder on the due date, the Holder shall be in mora debitoris and shall be liable for and pay interest on such late payment at the rate prescribed in terms of Section 80 of the Public Finance Management Act, 1999 (Act No. 1 of 1999). Interest on outstanding amounts shall be calculated from the due date for payment hereunder to the date of actual payment.

8. Technical Advisory Committee

8.1. The Parties shall by written notice to each other, within 30 (thirty) days from the date of notarial execution, establish a committee (herein referred to as the Technical Advisory Committee) which shall consist of the following members:

8.1.1. a chairman and one other person appointed by the Grantor; and

8.1.2. two persons appointed by the Holder.

8.2. The membership of the Technical Advisory Committee may be enlarged to include one member for each Holder Party. The Grantor may in such instances enlarge its membership of the Technical Advisory Committee to equal that of the Holder. 

8.3. The Grantor and each Holder Party may appoint by written notice to each other, alternate members to act in the place of their representatives. When an alternate member acts in the place of any member he or she shall be deemed to have the powers and shall perform the duties of such member.

8.4. Without prejudice to and without derogating from the rights and obligations of the Holder in terms of this Exploration Right, the Act and the Regulations the functions of the Technical Advisory Committee are as follows:

Page 13 of 1347

Ref No: 12/3/274

8.4.1. to review the progress of all Exploration Operations, to monitor the implementation thereof and to provide the Holder with advice and recommendations with regard thereto;

8.4.2. to review any proposed amendments to the approved Annual Exploration Work Programme submitted by the Holder to the Grantor in terms of Clause 15, to monitor the implementation thereof, and to provide the Holder with advice and recommendations with regard thereto;

8.4.3. to review any Appraisal Programme submitted by the Holder to the Grantor in terms of Clause 16, to monitor the implementation thereof, and to provide the Holder with advice and recommendations with regard thereto;

8.4.4. to review any proposed Development Plan and provide the Holder with advice and recommendations with regard thereto;

8.4.5. to review the accounting of expenditure and the maintenance of operating records and reports kept in connection with Exploration Operations, to monitor the implementation thereof, and to provide the Holder with advice and recommendations with regard thereto; and

8.4.6. to offer advice to the Holder in order to promote the efficient carrying out of Exploration Operations.

8.5. The Technical Advisory Committee shall meet as and when required but not less than once annually unless otherwise agreed between the members in which case, a 30 (thirty) days’ notice must be given by the Party requesting such meeting.

8.6. All meetings shall be held in Cape Town, South Africa or such other place as unanimously agreed to by the members of the Technical Advisory Committee. Except in respect of meetings of the Technical Advisory Committee held in Cape Town, the Holder shall be responsible for all costs and expenses related to attendance by the Grantor and its representatives at such meetings. 

8.7. The Grantor shall propose for the Holder’s input, an Agenda for the meeting which Agenda takes into consideration inter alia the holder’s work programme and other exploration right obligations. The aforesaid Agenda and the copies of all the necessary documentation and presentation materials shall be exchanged between the Parties not less than 7 (seven) days prior to the meeting. The Grantor shall not unreasonably deny any additional agenda items or agenda modifications proposed by the Holder if consistent with the Holder’s work programme obligations.

8.8. Three members of the Technical. Advisory Committee shall form a quorum: Provided that at least one representative of the Grantor and one representative of the Holder are present.

Page 14 of 1447

Ref No: 12/3/274

8.9. Any member of the Technical Advisory Committee shall have the right to bring any expert or advisor to a meeting of the Technical Advisory Committee for the purpose of advising on any matter requiring an expert’s advice.

8.10. The proceedings and processes of the Technical Advisory Committee are without prejudice to the rights and obligations of the Grantor or the Grantor Group or the Holder or the Holder Group and are not binding on the Holder.

9. Cancellation or Suspension of the Exploration Right

9.1. It is recorded that in terms of Section 90 of the Act, the Minister is empowered to cancel or suspend this Exploration Right in the circumstances set out in and in accordance with the provisions of Section 47 of the Act.

9.2. Should this Exploration Right be cancelled or suspended in accordance with Section 90 of the Act, the Holder shall not be absolved from those obligations and liabilities that have accrued up to the date of such cancellation or suspension.

9.3. Any cancellation or suspension of this Exploration Right by the Grantor shall be without prejudice to the Grantor’s other rights under this Exploration Right or the Applicable Laws and the Grantor reserves the right to claim damages, claim specific performance or claim any other alternative relief.

10. Relinquishment and Voluntary Abandonment of the Exploration Area

10.1. The Holder shall relinquish contiguous portions of the Exploration Area as set out in and in accordance with the attached Annexure “C”.

10.2. Subject to Clause 10.4, the Holder may, upon giving the Grantor not less than 180 (one hundred and eighty) days prior written notice, abandon this Exploration Right by relinquishing the entire Exploration Area to the Grantor. 

10.3. Subject to Clause 10.4, the Holder may by giving the Grantor not less than 90 (ninety) days prior written notice relinquish any portion of the Exploration Area. Any portion of the Exploration Area relinquished by the Holder shall comply with the requirements set out in Annexure “C” and shall be accompanied by a sketch plan depicting the area remaining or still covered by the exploration right.

10.4. Any relinquishment in terms of Clauses 10.1 and 10.3 or abandonment in terms of Clause 10.2 shall not absolve the Holder of any cost, liability, obligation or expense incurred by the Holder in respect of this Exploration Right prior to the date of such abandonment or relinquishment and the Holder shall remain liable therefor.

Page 15 of 1547

Ref No: 12/3/274

10.5. From the date that the Holder has abandoned this Exploration Right or has relinquished a portion or portions of the Exploration Area, the Grantor shall be entitled to grant to any other person any of the rights and permits referred to in the Act in, on, or under the portion or portions so abandoned or relinquished.

10.6. Upon abandonment of this Exploration Right, the Holder shall within 3 (three) months furnish the Grantor with a copy of all the Required Data that has not been previously furnished to the Grantor, and all copies of the Existing Data or a certificate to the effect that all such copies have been destroyed.

10.7. Upon relinquishment of any portion of the Exploration Area, the Holder shall within 3 (three) months furnish the Grantor with a copy of all the Required Data that has not been previously furnished to the Grantor in respect of those portions of the Exploration Area that have been so relinquished The Holder shall thereafter be entitled to freely use, distribute or dispose of such Required Data in respect of the Exploration Area so abandoned or relinquished.

10.8. Upon the abandonment of this Exploration Right or any relinquishment, the Holder shall apply for a closure certificate in terms of Section 43 of the Act in respect of the abandoned or relinquished areas.

11. Rights to Minerals and Petroleum

11.1. Except as provided for herein in respect of petroleum, this Exploration Right confers no rights to the Holder in respect of any mineral (as defined in the Act) discovered in the Exploration Area. Should the Holder discover any mineral during Exploration Operations, the Holder shall forthwith report such discovery to the Grantor who shall assume the ownership of the said discovery.

11.2. The Holder may thereafter, subject to any prior third party rights, apply for the right to explore, prospect for, produce and/or mine such mineral. 

12. Examination of the Exploration Area

12.1. It is recorded that in terms of Sections 91 and 92 of the Act, the Minister or any person duly authorised by the Minister may enter upon the Exploration Area and conduct routine inspections and exercise such related powers as set out in the Act.

12.2. Upon request by the Grantor, in the event of Exploration Operations being conducted offshore, the Holder shall provide free transportation during normal business hours between the Holder’s onshore base and the offshore facilities as well as free accommodation on the offshore facilities to the Minister or any person duly authorised by him or her.

13. Records and Samples

Page 16 of 1647

Ref No: 12/3/274

13.1. Without derogating from the Holder’s responsibilities in terms of Section 88 of the Act read together with the Regulations, the Holder shall keep current and accurate records of all Acquired Data acquired during the Exploration Operations. Such Acquired Data shall be kept in such form as is reasonably required and approved by the Grantor.

13.2. Samples shall be taken by the Holder at regular intervals in accordance with the Applicable Laws and Good International Petroleum Industry Practices. The Holder shall, at its own cost, save and correctly label a representative portion of all Samples in such form as reasonably required and approved by the Grantor. A portion of Samples of any petroleum or other minerals of potential value recovered by the Holder during Exploration Operations shall be forwarded promptly to the Grantor at the Holder’s expense. All Samples acquired by the Holder for its own purpose shall be made available for inspection by the Grantor at all reasonable times.

13.3. Prior to the Holder discarding any Samples, the Holder shall obtain the Grantor’s written consent, which consent is to be provided or refused within 30 (thirty) days of the Grantor receiving a request from the Holder. Should the Grantor fail to respond to the Holder within 30 (thirty) days, the Grantor shall be deemed to have provided its consent. Should the Grantor refuse to consent, or otherwise require such Samples, the Holder shall, at its cost, deliver the Samples to the Grantor.

13.4. The Holder may export Existing Data, Acquired Data and Samples for processing or laboratory examination or analysis by the Holder or by third parties or for storage outside of the Republic of South Africa, provided that representative Samples (equivalent in quality) and copies of the Acquired Data (equivalent in quality) have first been delivered to the Grantor and provided further that the Grantor’s prior written approval has been obtained by the Holder. Such approval shall not unreasonably be withheld or refused by the Grantor. 

13.5. The Holder shall deliver to the Grantor, at the Holder’s expense, digital and where appropriate, paper copies of all Acquired Data and representative Samples as soon as they are acquired or prepared. In this respect the Holder shall adhere to the Grantor’s guidelines with regard to the form, substance and format for preparing and storing the Acquired Data and Samples.

14. Reports

14.1. The Holder shall keep the Grantor advised of all material developments taking place during the course of Exploration Operations and shall furnish the Grantor with Required Data and such other reports and information as the Grantor may reasonably require.

14.2. Without derogating from the generality of Clause 14.1 or the Holder’s reporting obligations in terms of Section 88 of the Act, within 21 (twenty one) days from the end of each Quarter and within 60 (sixty) days from the end of each Year, the Holder shall submit to the Grantor a written report reflecting, for the relevant Quarter or Year, respectively, the progress of Exploration Operations, including the summary of:

Page 17 of 1747

Ref No: 12/3/274

14.2.1. the numbers of local persons (classified by race and gender) and expatriate persons employed;

14.2.2. the work done and expenditure on Exploration Operations;

14.2.3. the site and depth of every well drilled or being drilled;

14.2.4. the formations penetrated and particulars regarding any occurrence of petroleum and/or any mineral of potential value encountered; and

14.2.5. a statement of compliance with the Environmental Authorisation.

14.3. The Grantor and Holder shall each own the Required Data in their possession, whether original or a copy, and after the termination, cancellation or abandonment of this Exploration Right, each Party may freely use, sell, distribute, trade, license or otherwise disclose or dispose of such data.

14.4. None of the terms of this Exploration Right shall be construed as requiring the Holder to disclose any of its or its Affiliates’ proprietary technology or information or data licensed by the Holder or its Affiliates under obligations of confidentiality.

14.5. Within 3 (three) months from the termination and/or cancellation and/or abandonment of this Exploration Right, the Holder shall furnish the Grantor with a copy of all the Acquired Data not already in the possession of the Grantor and shall return all the Existing Data to the Grantor. 

15. Annual Exploration Work Programme and Budget

15.1. Not later than 60 (sixty) days from the date of notarial execution, the Holder shall submit and present to the Grantor for approval an Annual Exploration Work Programme for the current Year. Thereafter, at least 90 (ninety) days prior to the commencement of each succeeding Year, the Holder shall submit and present to the Grantor for review and approval its proposed Annual Exploration Work Programme for the next Year or part thereof, as the case may be, in accordance with this Clause and such approval shall not be unreasonably withheld or delayed.

15.2. The proposed Annual Exploration Work Programme shall set forth the Exploration Operations, inclusive of the Minimum Work Obligations, to be carried out during the next Year or part thereof, as the case may be, together with a budget of the expected cost thereof. The Annual Exploration Work Programme shall be consistent with and be part and parcel of the Exploration Work Programme attached hereto as Annexure “B”.

15.3. Within 30 (thirty) days from receipt of the proposed Annual Exploration Work Programme, the Grantor shall either, notify the Holder in writing of its approval of the proposed Annual

Page 18 of 1847

Ref No: 12/3/274

Exploration Work Programme or, reject the same and propose amendments thereto specifying the reasons for such amendments.

15.4. Should the Grantor fail to respond with regard to the proposed Annual Exploration Work Programme within 30 (thirty) days from its receipt thereof, the proposed Annual Exploration Work Programme shall be deemed approved by the Grantor.

15.5. The Grantor may, within 10 (ten) days from its receipt of the proposed Annual Exploration Work Programme, request the Holder to supply such further information relating to the proposed Annual Exploration Work Programme as may be reasonably required by the Grantor for its review and approval thereof. The Holder, to the extent reasonably possible and practical, shall comply in writing with such request within 10 (ten) days from the date of receipt of such request from the Grantor.

15.6. If the Grantor proposes any amendments to the proposed Annual Exploration Work Programme as described above, the Parties shall meet within 15 (fifteen) days from the date on which the proposed amendments are notified to the Holder to discuss the proposed amendments The proposed amendments to the Annual Exploration Work Programme shall be consistent with the Exploration Work Programme.

15.7. Following review and consideration of any amendments proposed by the Grantor, the Holder shall within 15 (fifteen) days from the meeting required in terms of Clause 15.6 re-submit to the Grantor for approval a revised Annual Exploration Work Programme, and shall give effect to all amendments to the proposed Annual Exploration Work Programme reasonably requested by the Grantor. 

15.8. Should any amendments to the Exploration Work Programme be required, such shall be subject to the provisions of Section 102 of the Act which requires the approval of the Minister.

15.9. Any dispute which cannot be resolved between the Parties with regard to the Annual Exploration Work Programme shall be resolved in accordance with Clause 37.

16. Discoveries and Testing

16.1. If a Discovery is made by the Holder in the Exploration Area, the Holder shall:

16.1.1. promptly inform the Grantor by written notice of the fact that such Discovery has been made;

16.1.2. cause tests to be made on such Discovery within a reasonable period of time consistent with Good International Petroleum Industry Practices in order to determine whether such Discovery is or could be a Commercial Discovery and is worthy of appraisal. Prior to testing each Discovery, the Holder shall give written notice to the Grantor of the tests the Holder intends to conduct and the Grantor shall

Page 19 of 1947

Ref No: 12/3/274

have the right to witness such tests. If such tests are being conducted offshore, then the Holder shall, free of charge, provide access, transportation to and from the offshore facilities, including reasonable accommodation facilities on the installation, for not more than 4 (four) of the Grantor’s representatives who will witness the tests; and

16.1.3. within 120 (one hundred and twenty) days from having completed and received the results of tests under Clause 16.1.2, furnish the Grantor with a copy of the test results report containing a summary of the Holder’s interpretation of such tests and Holder’s conclusion as to whether or not such Discovery could be a Commercial Discovery and is worthy of appraisal (the Discovery Report’).

16.2. All tests and measurements conducted by the Holder for the purpose of establishing the potential existence of a Commercial Discovery shall be carried out in accordance with Good International Petroleum Industry Practices.

16.3. If the Holder considers, after providing the Grantor with the Discovery Report that the Discovery could be commercial, then the Holder shall forthwith take such reasonable steps to appraise the Discovery and submit a proposed Appraisal Programme to the Grantor for its approval.

16.4. Within 30 (thirty) days from receipt of the proposed Appraisal Programme, the Grantor shall either notify the Holder in writing of its approval of the proposed Appraisal Programme or reject the same and propose amendments thereto specifying the reasons for such amendments.

16.5. Should the Grantor fail to respond to the proposed Appraisal Programme within 30 (thirty) days from its receipt thereof, the proposed Appraisal Programme shall be deemed approved by the Grantor.

16.6. The Grantor may, within 10 (ten) days from its receipt of the proposed Appraisal Programme, request the Holder to supply such further information relating to the proposed Appraisal Programme as may be reasonably required by the Grantor for its review and approval thereof. The Holder, to the extent reasonably possible and practical, shall comply in writing with such request within 10 (ten) days from the date of receipt of such request from the Grantor.

16.7. If the Grantor proposes any amendments to the proposed Appraisal Programme as described above, the Parties shall meet within 15 (fifteen) days from the date on which the proposed amendments are notified to the Holder to discuss the proposed amendments. The proposed amendments to the Appraisal Programme shall be consistent with the objectives of appraising the discovery.

16.8. Following review and consideration of any amendments proposed by the Grantor, the Holder shall within 15 (fifteen) days from the meeting required in terms of Clause 16.7, re-submit to

Page 20 of 2047

Ref No: 12/3/274

the Grantor for approval a revised Appraisal Programme to give effect to all amendments to the proposed Appraisal Programme reasonably requested by the Grantor.

16.9. Any dispute which cannot otherwise be resolved between the Parties with regard to the Appraisal Programme shall be resolved between the Parties in accordance with Clause 37.

16.10. In the event that operational imperatives (including the immediate availability of a seismic vessel or drilling rig) require such approval to the Appraisal Programme in a shorter timeframe than specified in Clauses 16 4 to 16.8, then the Parties shall use all of their reasonable commercial efforts to complete the approval process in accordance with the aforesaid procedures within a shorter timeframe.

16.11. Within 180 (one hundred eighty) days from the completion of such Appraisal Operations, or such further period as agreed between the Parties in writing, the Holder shall deliver to the Grantor (a) a full report containing particulars of the results of such Appraisal Operations, including particulars and preliminary estimates relating to the location and depth of petroleum bearing structures, the composition of petroleum, the estimated recoverable reserves of petroleum, and the estimated daily production potential of petroleum, (b) a declaration by the Holder as to whether or not the Discovery is a Commercial Discovery, and (c) an election by the Holder as to whether or not the Holder intends to develop such Discovery (the ‘Appraisal Report’).

16.12. If the Holder notifies the Grantor in the Appraisal Report that the Discovery is a Commercial Discovery, then within 365 (three hundred and sixty-five) days from the date of receipt of the Appraisal Report by the Grantor, the Holder shall submit a proposed Development Plan for such Discovery to the Grantor for its approval.

16.13. Within 60 (sixty) days from receipt of the proposed Development Plan, the Grantor shall either notify the Holder in writing of its approval of the proposed Development Plan or reject the same and propose amendments thereto specifying the reasons for such amendments

16.14. Should the Grantor fail to so act on the proposed Development Plan within 60 (sixty) days from its receipt thereof, the proposed Development Plan shall be deemed approved by the Grantor.

16.15. The Grantor may, within 20 (twenty) days from its receipt of the proposed Development Plan, request the Holder to supply such further information relating to the proposed Development Plan as may be reasonably required by the Grantor for review and approval thereof. The Holder, to the extent reasonably possible and practical, shall comply in writing with such request within 20 (twenty) days from the date of receipt of such request from the Grantor.

16.16. If the Grantor proposes any amendments to the proposed Development Plan as described above, the Parties shall meet within 30 (thirty) days from the date on which the proposed amendments are notified to the Holder to discuss the proposed amendments.

Page 21 of 2147

Ref No: 12/3/274

16.17. Following review and consideration of any amendments proposed by the Grantor, the Holder shall within 30 (thirty) days from the meeting required in terms of Clause 16 16 (or such longer period as agreed between the Parties), re-submit to the Grantor for approval a revised Development Plan to give effect to all amendments to the proposed Development Plan reasonably requested by the Grantor.

16.18. Should any amendments to the Exploration Work Programme be required, such shall be subject to the provisions of Section 102 of the Act which requires the approval of the Minister.

16.19. Any dispute which cannot otherwise be resolved between the Parties with regard to the Development Plan shall be resolved in accordance with Clause 37.

17. Manner of Conducting Exploration Operations

17.1. Without derogating from the provisions of the Applicable Laws and Environmental Authorisation, the Holder shall:

17.1.1. execute all Exploration Operations in a proper and workmanlike manner in accordance with Good International Petroleum Industry Practices and, without prejudice to the generality of the foregoing, the Holder shall take all reasonable and practical steps in order to prevent: 

17.1.1.1. the escape or waste of petroleum discovered in the Exploration Area:

17.1.1.2. damage to petroleum-bearing strata;

17.1.1.3. the entrance of uncontrolled water through wells to petroleum-bearing strata;

17.1.1.4. the escape of petroleum into any waters or aquifer in the vicinity of the Exploration Area; and

17.1.1.5. pollution of the terrestrial or marine environment.

17.1.2. promptly inform the Grantor and all other relevant Government departments of the occurrence of any event described in Clauses 17.1.1 to 17.1.5 inclusive;

17.1.3. take all actions required under the Environmental Authorisation and all Applicable Laws with respect to any of the incidents referred to Clauses 17.1.1 to 17.1.5 inclusive;

17.1.4. promptly notify, upon the completion of any operation or activity within the Exploration Area, the Grantor and all relevant Government departments of any obstruction, including the location, nature and extent thereof, that remains in the Exploration Area;

Page 22 of 2247

Ref No: 12/3/274

17.1.5. not flare any petroleum without the Grantor’s prior written approval; and

17.1.6. promptly give notices to relevant Government departments, including interested and affected parties, with regard to all Exploration Operations which may be reasonably expected to interfere with the rights of other users of the Exploration Area and shall take all reasonable steps to minimise interference with the rights of other users.

18. Existing Data

18.1. It is recorded that, at the date of notarial execution of this Exploration Right, no Existing Data has been made available to the Holder.

18.2. Any Existing Data or information relating to the Exploration Area that the Grantor has made available or which the Grantor acquires independent of the Holder will be made available for inspection, copying and use by the Holder; provided that the Holder shall pay the Grantor for the costs incurred in copying and preparing such data or information. Should such further data or information be provided to the Holder, such data and information shall be deemed to form part of the Existing Data and Annexure “E” will be amended accordingly. 

18.3. Upon terms and conditions to be agreed, the Grantor may assist the Holder in resolving technical problems relating to the Existing Data. Such assistance shall not include interpretation of the Existing Data.

18.4. Ownership in all Existing Data vests in the Grantor and is of considerable commercial value to the Grantor. On expiry, cancellation, termination or abandonment of this Exploration Right or relinquishment of the exploration area, all Existing Data in the Holder’s possession, shall forthwith, at the Holder’s cost, be returned to the Grantor. Alternatively the Holder shall submit to the Grantor a certificate to the effect that all such copies have been destroyed

18.5. While every effort has been made to verify the quality and accuracy of the Existing Data, the Grantor Group shall not be liable for any error or inaccuracy contained within the Existing Data or any damages of whatsoever nature suffered by the Holder arising from any such error or inaccuracy in the Existing Data.

19. Environmental Protection and Financial Provision

19.1. The Holder shall conduct all Exploration Operations in accordance with the approved Environmental Authorisation, record of decisions and addendums thereto and in a manner that facilitates the protection and conservation of the natural resources of the Republic of South Africa and of the environment in general.

19.2. The financial provision made available by the applicant herein in terms of the Holder Financial Guarantee satisfies the requirements as required by Section 24P of the National

Page 23 of 2347

Ref No: 12/3/274

Environmental Management Act, 107 of 1998 and must annually be assessed and if necessary adjusted to the satisfaction of the Minister.

20. Social and Labour Matters

20.1. Without derogating from the Holder’s responsibilities in terms of the Applicable Laws including Section 2(d) and Section 2(f) of the Act, the Holder undertakes:

20.1.1. within two (2) years from Execution Date, to find a suitable additional holder who is a Historically Disadvantaged South African, and that is technically, legally and financially qualified to hold a Participating Interest. Such additional holder shall be entitled to receive a Participating Interest up to but not greater than 10% (ten per cent), and shall acquire any such interest at a fair market value price. The Historically Disadvantaged South African, upon taking up such Participating Interest, shall become a party to the relevant joint operating agreement and shall be responsible for its Participating Interest share of the Holder’s financial and other obligations hereunder. The applicable joint operating agreement may, subject to the Grantor approving the inclusion of the relevant provision, require that a Historically Disadvantaged South African may only transfer its Participating Interest to another Historically Disadvantaged South African. Notwithstanding the provisions hereof, if the Holder demonstrates that, despite making a sincere attempt to do so, the Holder is unable to comply with the requirement to find a suitable HDSA partner, the Holder shall be permitted to make an application in terms of section 102 of the Act to extend the time period in which the Holder is required to find a suitable HDSA partner by a further two (2) years. Should the Holder make an application for amendment in terms of section 102 as contemplated in this clause, notwithstanding the failure of the Holder to comply with the provisions of this clause 20.1.1., the Holder shall not be in breach of its obligations under this Exploration Right unless and until such time as the section 102 application has been refused.

20.1.2. to employ Historically Disadvantaged South Africans having appropriate qualifications and experience, and or alternatively implement a programme for the future recruitment of such, taking into account the Holder’s operational requirements under this Exploration Right;

20.1.3. to implement programmes for the training and skills development of Historically Disadvantaged South Africans;

20.1.4. to give preference, in procuring for purposes of use in the exploration operations, the equipment, machinery, materials, instruments, supplies and accessories (all referred to collectively as ‘Goods’) manufactured or produced by Historically Disadvantaged South Africans, provided that such Goods are competitive with like

Page 24 of 2447

Ref No: 12/3/274

goods manufactured or produced or available outside the Republic of South Africa in respect of cost, quantity and quality and that such Goods can be made available at the time when and the place where required by the Holder;

20.1.5. to use contractors and/or sub-contractors who are Historically Disadvantaged South Africans and whose services and standards are competitive with those available outside the Republic of South Africa in terms of price, quality, expertise, and: Provided further that such services can be performed at the place and within the time required by the Holder; and

20.1.6. to pay the amounts set out and specified in the attached Annexure “D” to the Upstream Training Trust, to be used by the Trust for the training, education, and obtaining of practical experience for Historically Disadvantaged South Africans and other South Africans in the manner determined by the trustees.

20.2. The Holder shall propose a field training programme for graduates who have the appropriate qualifications, to be approved by the Agency, which shall include, but not be limited to the following aspects of oil and gas exploration and production:

(i)    Geophysical and/or geological data acquisition, processing and interpretation;

(ii)    Exploration methods;

(iii)    Drilling and well completions; and

(iv)    Field development and production.

21. Tax

21.1. The Holder’s tax obligations and benefits shall be as provided for in the Income Tax Act and other Applicable Laws of the Republic of South Africa.

21.2. Except to the extent exempted or as directed otherwise, the Holder shall for the duration of this Exploration Right be liable for income tax payments to the State on the annual taxable income derived by it from the sale of Petroleum (referred to in the Income Tax Act as “natural oil”) or any other product of Exploration Operations in accordance with the provisions of the Income Tax Act, including any amendments and regulations issued pursuant thereto.

22. Financial Records and Audits

22.1. Without derogating from the Holder’s responsibilities under the Applicable Laws, the Holder shall keep in the Republic of South Africa financial records and accounts of all transactions pertaining to this Exploration Right, in accordance with generally accepted accounting practices as applicable in the Republic of South Africa.

Page 25 of 2547

Ref No: 12/3/274

22.2. At the Grantor’s request, such financial records and accounts or copies thereof shall be promptly provided to the Grantor. The Grantor or its duly appointed representative shall, at Grantor’s own cost, have the right to audit the Holder’s financial records and accounts relating to transactions for any year within 3 (three) years after the close of such year. The Holder’s financial records and accounts shall be conclusively presumed true and correct unless the Grantor takes written exception to specific costs within the 3 (three) year period.

23. Customs duties

Without derogating from the provisions of Clause 29.1, and except to the extent exempted or as directed otherwise, in respect of all goods imported into the Republic of South Africa for purposes of conducting Exploration Operations, the Holder shall comply with the provisions of the Customs and Excise Act, 1964 (Act No. 91 of 1964), including any regulations issued pursuant thereto.

24. Exchange Control

Without derogating from the provisions of Clause 29.1 and except to the extent exempted or as directed otherwise, the Holder undertakes to comply with the provisions of the Currency and Exchanges Act, 1933 (Act No. 9 of 1933), including any regulations issued pursuant thereto.

25. Indemnity and insurance

25.1. The Holder shall for the duration of this Exploration Right take all the necessary and reasonable steps to conduct the Exploration Operations in a manner that safeguards and protects persons from injury or death and prevents damage or destruction of property and the environment.

25.2. The Holder hereby undertakes to defend, hold harmless and indemnify the Grantor Group from and against any and all claims, costs, charges, liabilities and expenses, including reasonable legal costs (hereinafter referred to as ‘Claims’), that may be instituted against or suffered by any member of the Grantor Group as a result of injury or death to any person or damage or destruction to any property and/or the environment arising from the negligent and/or unlawful acts and/or omissions of the Holder Group.

25.3. Notwithstanding the foregoing, under no circumstances shall the Holder, or their Affiliates be liable to the Grantor Group or any third party, for consequential or indirect damages, losses, expenses or liabilities, loss of profit, loss of production, reservoir or formation damage or other losses whether or not similar to the foregoing and howsoever arising.

25.4. The Holder shall within 10 (ten) days from the date of notarial execution obtain and maintain sufficient insurance during the term of this Exploration Right to address the risks related to

Page 26 of 2647

Ref No: 12/3/274

Exploration Operations and support the indemnities given by the Holder under this Exploration Right. Without derogating from the Holder’s responsibilities, the Holder, with the prior written approval of the Grantor, may implement a policy of self-insurance in respect of certain risks related to Exploration Operations. Without derogating from the generality of the foregoing such insurance shall specifically provide for:

25.4.1. all risks in respect of any property or equipment used in connection with Exploration Operations;

25.4.2. pollution liability;

25.4.3. third-party liability and public liability:

25.4.4. removal of wrecks and cleaning-up operations pursuant to an accident in the course of or as a result of Exploration Operations; 

25.4.5. the Holder’s liability to its contractors, employees, consultants and agents engaged in Exploration Operations; and

25.4.6. any other risk of whatever nature as is customary to insure against in the international petroleum industry or in accordance with the Good International Petroleum Industry Practices.

25.5. Without derogating from the Holder’s responsibilities in terms of the Applicable Laws or this Exploration Right, the amounts, type and terms of the insurance referred to in Clause 25.4 above shall be determined in consultation with the Grantor.

25.6. The obligations of the Holder Parties under this Exploration Right, including any obligations and liability under this Clause 25 and under Clause 21 shall be several and not joint and several. Each Holder Party shall be liable for their respective share of all such obligations and liabilities based on their respective Participating Interest.

25.7. Subject to the Applicable Laws, the Grantor hereby undertakes to defend, hold harmless and indemnify the Holder Group from and against any and all Claims, that may be instituted against or suffered by any member of the Holder Group as a result of injury or death to any person or damage or destruction to any property and/or the environment arising from the negligent and/or unlawful refusal by the Grantor to permit the Holder to adequately respond to the situation in question.

26. Health and Safety

26.1. The Holder undertakes while conducting Exploration Operations to comply with the Applicable Laws in respect of all health and safety matters; and

Page 27 of 2747

Ref No: 12/3/274

26.2. Where any emergency or incident arising from Exploration Operations causes or has the potential to cause death and/or injury to persons or damage to and/or destruction of property and/or the environment, the Holder shall in consultation with the responsible Government departments take such action as may be prescribed under the Applicable Laws or where not prescribed take such prudent and necessary action in accordance with the Good International Petroleum Industry Practices.

27. Confidentiality and Public Announcements

27.1. The Acquired Data and the Existing Data together with all programmes, tests, analyses, results, books, statements, records, returns, plans, information and correspondence between the Parties which the Holder is or may from time to time be required to furnish under the provisions of this Exploration Right (hereinafter collectively referred to as ‘Confidential Information’) shall be treated as confidential by the Holder and shall not be disclosed by the Holder to any person without the prior written consent of the Grantor, except that the Grantors consent shall not be required in the following circumstances:

27.1.1. where the Holder is required by law, regulation, decree, rule or order applicable to the Holder or its Affiliates to disclose such Confidential Information;

27.1.2. where the Holder discloses Confidential Information to any Affiliate of any Holder Party: Provided that such Holder Party informs its Affiliates of the confidential nature of information so disclosed and guarantees the adherence of such Affiliates to the confidentiality restrictions as set out in this Clause;

27.1.3. to the extent that such Confidential Information has to be produced at legal or arbitral proceedings or because an order from a court or arbitral panel of competent jurisdiction has compelled the production of such Confidential Information;

27.1.4. where the Holder discloses Confidential information to prospective or actual contractors, consultants, advisors, and attorneys employed by any Holder Party or its Affiliates where disclosure of such Confidential Information is essential to such person’s services for such Holder Party: Provided that, prior to disclosure, such contractor, consultant, advisor, lender, and attorney provides the Holder Party with a written undertaking of confidentiality that is not less restrictive than the confidentiality restrictions set out in this Clause, provided that in the case of an attorney, compliance with professional obligations of confidence shall be sufficient to represent compliance with this clause 27.1.4;

27.1.5. where the Holder discloses Confidential Information to a bank or other financial institution to the extent appropriate to Holder arranging for funding: Provided that, prior to disclosure, such person provides the Holder Party with a written undertaking

Page 28 of 2847

Ref No: 12/3/274

of confidentiality that is not less restrictive than the confidentiality restrictions set out in this Clause;

27.1.6. to the extent that such Confidential Information must be disclosed pursuant to any rules or requirements of any recognised stock exchange on which the securities of any Holder Party or its Affiliates are or are to be listed;

27.1.7. where the Holder discloses Confidential Information to a bona fide prospective assignee or assignees to whom the Holder’s or any of the Holder Party’s rights and obligations under this Exploration Right are proposed to be assigned;

27.1.8. to the extent that any Confidential Information, through no fault of the Holder, has become or becomes part of public domain; or

27.1.9. where the Holder discloses Confidential Information as part of an exchange with third parties for the geological, geophysical, geochemical and any other technical or scientific data, reports and information (either raw, processed or interpreted) pertaining to their petroleum operations in respect of other acreage within the Republic and subject to their execution of suitable confidentiality arrangements. In this event the Grantor shall be apprised of the extent of the proposed exchange.

27.2. Except as may be required by laws, rules, regulations or decrees (including that of a stock exchange) applicable to the Holder or its Affiliates, the Holder shall make no public announcement with regard to this Exploration Right or any matter related thereto, unless the Holder has furnished the Grantor with a copy of the intended public announcement and the Grantor has given its prior written approval, which approval shall not be unreasonably withheld or delayed.

27.3. If the Grantor desires to issue any press release, media statement, or interview on any petroleum Discovery, estimated petroleum reserves, and/or any well drilling operations, tests, and/or results relating to the Exploration Operations hereunder, the Grantor shall give written notice thereof to the Holder at least three (3) days in advance to enable the Holder to comply with disclosure rules and requirements imposed on any Holder Party or its Affiliates by the laws, regulations or rules of the relevant countries in which such Holder Party is incorporated or doing business or in which the securities of such Holder Party or its Affiliates are or are to be listed or traded.

27.4. When a public announcement or statement becomes required by law or necessary or desirable because of impending danger to or loss of life, damage to property or pollution as a result of Operations, either Party is authorised to issue and make such announcement or statement without prior notice or prior approval of the other Party where such prior notice and approval is impractical. In such a case the Party making the announcement or statement shall promptly furnish the other Party with a copy of such announcement or statement.

Page 29 of 2947

Ref No: 12/3/274

28. Cession and Sub-contracting

28.1. It is recorded that this Exploration Right may not be ceded, transferred, let, sub-let, assigned, alienated or otherwise disposed of without the written consent of the Minister in terms of Section 11 of the Act.

28.2. The Holder may from time to time appoint one or more independent sub-contractors to carry out any portion of the Annual Exploration Work Programme and/or Exploration Work Programme, provided that the Holder shall always remain liable to the Grantor for the compliance with and observance of its obligations in terms of this Exploration Right.

29. Law and Interpretation

29.1. The Holder shall comply with all Applicable Laws.

29.2. Without derogating from the provisions of Section 4 of the Act, this Exploration Right shall be governed, construed and interpreted in accordance with the laws of the Republic of South Africa.

29.3. It is recorded that the Grantor and the Holder are not partners nor is it the intention of the Parties to create a partnership and that Exploration Operations to be carried out in terms of this Exploration Right are at the sole cost, risk and expense of the Holder.

30. Obligations of the Grantor

30.1. If, at any time or from time to time from the should be any change enacted or prescribed to any national legislation and/or regulations affecting petroleum exploration or production (“legislative changes”) which in any way materially limits and/or directly or indirectly adversely affects any rights hereby granted to the Holder, then the Parties shall consult with each other and conduct negotiations in the utmost good faith to agree on an equitable arrangement to take account of the impact of such changes, and failing agreement either party shall be entitled to refer the matter to arbitration as provided for herein.

30.2. Terms relating to fiscal stability, will be established through contracts between the Holder and the Minister of Finance as provided for in the Income Tax Act and the Mineral and Petroleum Resources Royalty (Act No. 28 of 2008).

31. State Option

31.1. Subject always to the obligations of the Grantor contained in Clause 30, the State has the option, within 90 (ninety) days from the date of notarial execution of a Production Right, or in the event that the Holder exercises its option under clause 35.1. within 90 (ninety) Days after the expiry of the Gas Market Development Period, to acquire a percentage of the

Page 30 of 3047

Ref No: 12/3/274

Participating Interest (“State Option”) in accordance with the provisions of the Applicable Laws prevailing at the time of the granting of a Production Right governing State Option requirements.

31.2. Should the State elect to exercise such State Option it must notify the Holder in writing, within 90 (ninety) days of notarial execution of a Production Right or in the event the Holder exercises its option under Clause 35.1.1, within 90 (ninety) Days after the expiry of the Gas Market Development Period:

31.2.1. that it has elected to exercise the State Option: and 

31.2.2. of the percentage of the Participating Interest, up to a maximum allowed in accordance with the provisions of the Applicable Laws prevailing at the time of the granting of a Production Right governing State Option requirements, that it has elected to acquire

31.3. Upon the exercise of the State Option in the manner contemplated in Clause 31.2, the State shall become a member of the Holder Group to the extent of its Participating Interest and the State shall also become a party to any joint operating agreement relating to the Production Right. The State shall pay its Participating Interest share of all costs and expenses in relation to the approved production work programme in respect of the production area, excluding any costs and expenses related to any previous and/or further Exploration or Appraisal Operations conducted within the production area.

31.4. The State shall have the right at any time, on giving written notice to the Holder, to assign all or any part of its Participating Interest to any technically and- financially competent third party. Such assignment by the State will not require the consent of the Holder or any Holder Party. The assignment shall only become effective after the assignee consents to and executes the joint operating agreement applicable to this Exploration Right and/or any Production Right. The terms of such joint operating agreement shall neither limit the State in the exercise of any of its rights and obligations as Grantor nor impose additional obligations on the State in its capacity as Grantor merely because the State is also member of the Holder Group.

31.5. Notwithstanding the foregoing provisions of this Clause 31, if the Holder has divested part of its Participating Interest prior to the exercise by the State of the State Option, then the percentage Participating Interest to be acquired by the State under the State Option shall be divided pro-rata among all of the Holder(s) of a Participating Interest and the foregoing provisions of this Clause 31 shall apply pari passu with respect thereto.

32. Vis Major

Page 31 of 3147

Ref No: 12/3/274

32.1. Any act, cause, thing or event outside the control of the Parties, including acts of God, war, insurrection, civil commotion, blockade, strikes, flood, storm, lightning, fire or earthquake which prevents any of the Parties from fulfilling its obligations under this Exploration Right shall be regarded as a vis major event and any such failure on the part of any of the Parties as a consequence of the vis major event shall not constitute a breach hereof.

32.2. Financial inability, ordinary hardship and inconvenience on the part of the Holder, howsoever caused or arising, shall not be regarded as a vis major event.

32.3. If the Holder by reason of a vis major event as contemplated in Clause 32.1 is prevented from fulfilling its obligations or enjoying its rights under this Exploration Right, the Holder shall in writing promptly notify the Grantor thereof and the Holder shall take all reasonable steps to investigate and remove the cause thereof. The Holder shall promptly notify the Grantor in writing as soon as the vis major event ends and the Holder shall as soon as is reasonably practicable thereafter resume the Exploration Work Programme.

32.4. Upon the Holder notifying the Grantor of the end of the vis major, the duration of this Exploration Right shall automatically be extended for the equivalent period of time that the Holder was prevented from fulfilling its obligations or enjoying its rights under this Exploration Right by reason of such vis major. The Holder’s notice of the end of the vis major must declare the Holder’s intention to resume the Exploration Work Programme and state the length of the extension time. Such extension period shall be calculated from the date that the Holder first notified the Grantor in writing of the vis major event until the date that the vis major event has ended.

32.5. In the event of the automatic extension envisaged in clause 32.4 above, the Holder shall present the original copy of this Exploration Right for an endorsement reflecting such extension and the Grantor shall make the same endorsement on the office copy.

33. Amendments

33.1. It is recorded that in terms of Section 102 of the Act, this Exploration Right may not be amended or varied without the written consent of the Director General (being the delegate of the Minister).

33.2. The aforesaid amendment or variation shall be in writing and effective once the aforesaid consent has been given.

34. Unitisation

34.1. In the event that the rights held by the holders under two or more exploration rights and/or mining leases and/or production rights and/or prospecting leases or sub-leases extend over different areas which geologically form part of the same petroleum-bearing area within the

Page 32 of 3247

Ref No: 12/3/274

Republic of South Africa, the Grantor may by notice in writing require the holders of such rights to prepare a proposal for the production of that petroleum-bearing area as a unit. Such proposal shall be submitted to the Grantor within the period specified in the said notice which shall not be less than 180 (one hundred and eighty) days.

34.2. The unitisation proposal referred to in Clause 34.1 shall maximise the exploration and/or production for the benefit of all holders of interests in the unitised area.

34.3. The Grantor may, if no unitisation proposal is submitted, or if the Grantor is not satisfied with the unitisation proposal submitted in terms of Clause 34.2, the matter shall be referred to [a committee of up to three independent experts selected by the Grantor, the Holder and the holders of any other rights subject to a unitization proposal in accordance with this clause 34.

34.4. The parties shall submit materials to the independent Expert within 30 (thirty) days of appointment and the Expert shall render a decision within 90 (ninety) days of appointment based on the following principles:

34.4.1. all relevant technical data and production experience should be used in any equity determination/redetermination;

34.4.2. the equity determination/redetermination process should require an initial tract participation, one equity determination and at least one equity redetermination, subject to the unanimous agreement of the unit participants not to pursue a scheduled redetermination; and

34.4.3. equity parameters should be developed on a fair and equitable basis, consistent with sound engineering, technical, and economic principles and Good International Petroleum Industry Practices.

34.5. The decision of the independent Expert shall be binding on the parties.

35. Special Provisions Relating to Gas Discovery

35.1. If the Holder discovers petroleum, the economic development of which the Holder believes can only be accomplished if Gas produced as the primary or secondary product is sold commercially, then the Holder shall have the option, exercisable upon written notice to the Grantor at the time that the Holder makes an application to the Grantor for a production right, to have the production right suspended for a period of up to 5 (five) years (hereinafter referred to as the “Gas Market Development Period”) commencing from the date of notarial execution of the Production Right during which period the Holder shall conduct studies to determine whether the Gas can be commercially produced. In such circumstances, the Development

Page 33 of 3347

Ref No: 12/3/274

Plan and proposed production programme submitted in support of the application for the Production Right shall be deemed to be preliminary

35.2. Not less than 90 (ninety) days prior to the expiry of the Gas Market Development Period the Holder shall advise the Grantor in writing either that:

35.2.1. the Gas can be commercially developed and produced, in which case the Holder shall proceed with implementation of the Development Plan and proposed production programme, duly amended if necessary; or

35.2.2. the Gas cannot be commercially developed and produced, in which case the Holder shall be deemed to have abandoned the Production Right with effect from 90 (ninety) days after Grantor has been; and 

35.2.3. failure to give notice in the timely manner shall be construed as notice that the Gas cannot be developed and produced commercially.

35.3. The grant of any extension to the Gas Market Development Period shall be at the sole discretion of Grantor.

35.4. The activities envisaged to be relevant during a Gas Market Development Period do not include Exploration Operations.

36. Waiver or Lenience

Any failure by either the Grantor or the Holder to exercise any of the rights that they have whether in terms of this Exploration Right, the Act or the Regulations, or any lenience granted by them In terms thereof shall not constitute a waiver of such rights or a variation to the terms and conditions of this Exploration Right.

37. Dispute Resolution

37.1. Should any difference or dispute arise between the Parties to this Exploration Right concerning;

37.1.1. the conclusion, interpretation, application and execution of this Exploration Right;

37.1.2. the authority of any signatory to the Exploration Right to conclude the Exploration Right on behalf of the party that he or she purports to represent;

37.1.3. any alleged breach or repudiation of the Exploration Right;

37.1.4. whether the Exploration Right is void or voidable at the instance of any Party;

37.1.5. any rectification of the Exploration Right, and/or;

Page 34 of 3447

Ref No: 12/3/274

37.1.6. any other matter arising from this Exploration Right,

(each, a “Dispute”), then either Party shall be entitled to deliver to the other a written notice recording the existence and, in brief, the nature of the Dispute (“the Dispute Notice”). The Dispute shall be deemed to have arisen on the date when a Dispute Notice is delivered to either Party. The Parties shall make every reasonable effort to resolve the Dispute on its merits by negotiation in good faith and shall, for that purpose, attend at least one meeting with each other. Such negotiations shall take place within 21 (twenty one) days of the Dispute arising, unless the Parties otherwise agree in writing, and shall endure for no longer than 7 (seven) days from the date of commencement thereof or such extended period as the Parties may agree in writing. 

37.2. If the Parties are unable to resolve the Dispute despite compliance with Clause 37.1, then the Dispute may at the instance of either Party be referred to and fully, finally and exclusively settled by arbitration, in terms of the provisions hereof.

37.3. The proceedings, records and the award of the arbitration shall be in the English language. The venue for and seat of the arbitration shall be Cape Town, Republic of South Africa or such other place in the Republic of South Africa as may be agreed between the Parties. The Parties hereby waive irrevocably their right to institute any form of appeal, review or recourse to any court of competent jurisdiction insofar as such waiver may be validly made.

37.4. Notwithstanding the referral of such Dispute to arbitration, the Parties shall, to the extent possible, proceed with the carrying out of their respective obligations under this Exploration Right, unless such obligations are directly in dispute, provided that the foregoing undertaking shall be without prejudice to other rights and remedies available to either Party at law or in equity.

37.5. The provisions of this Clause 37 shall survive the termination of this Exploration Right.

37.6. The arbitration shall commence by a written notice (“the Arbitration Notice”) to that effect delivered by the Party demanding the arbitration (“the Plaintiff) to the other (“the Respondent”). No Arbitration Notice shall be delivered after the lapse of 90 (ninety) days after the terminations of any negotiations set out in Clause 37.1 above. Any Dispute, if not resolved and not thereafter made subject to arbitration, may at any time be raised again, commencing with the procedure set out in Clause 37.1 above. In the Arbitration Notice, the Plaintiff shall set out,

37.6.1. a short summary of the nature of the Dispute;

37.6.2. the relief claimed by the Plaintiff;

Page 35 of 3547

Ref No: 12/3/274

37.6.3. the identity and curriculum vitae of an independent arbitrator proposed by the Plaintiff.

37.7. Within 21 (twenty one) days after delivery of the Arbitration Notice, the Respondent shall deliver a written reply to the Plaintiff setting out the identity and particulars of an independent arbitrator proposed by it. If the Respondent shall not deliver such reply, the Plaintiff shall nevertheless be entitled to proceed with the arbitration as set out herein.

37.8. There shall be 3 (three) arbitrators, appointed as set out herein, and all decisions, rulings and/or awards of the arbitrators shall be by majority decision amongst them. No person who has any pecuniary or any other interest, directly or indirectly, in either of the Parties, shall serve as arbitrator.

37.9. The third arbitrator (or the second and third arbitrators if the Respondent shall not have delivered a reply as provided for in Clause 37.7), shall be appointed by the Secretariat of the ICC International Court of Arbitration (or its successor in title).

37.10. The arbitrators shall determine the practical measures necessary to conduct the arbitration and shall issue directives in that regard to the Parties and/or their representatives, from time to time, as may be required. The arbitrators shall be entitled to award costs against any party on any scale as otherwise provided for in the Rules of the High Court of the Republic of South Africa and shall, in the case of any disagreement between the Parties about the amount of such costs, be entitled to retain the services of an independent legal costs consultant to determine the amount of any such costs. The costs, fees and charges of the arbitrators shall be borne by the Parties in equal proportion and shall be payable by them on presentation of invoices in that regard. Any order as to costs which may be made by the arbitrators shall operate as between the Parties only and shall not affect their obligation to the arbitrators as set out herein.

37.11. Save as set out above and as may be otherwise agreed between the parties, the proceedings shall be conducted subject to and in accordance with the rules of the Arbitration Foundation of Southern Africa (“AFSA”).

38. Costs and Value Added Tax

38.1. All taxes, levies, stamp duties, transfer costs, transfer duties and registration costs arising directly or indirectly out of or related to this Exploration Right shall be for the account of and promptly paid by the Holder.

38.2. All amounts due and payable by the Holder in terms of this Exploration Right, the Act and Regulations are exclusive of statutory value added tax. Statutory value added tax at the prevailing rate in accordance with the Value Added Tax Act (Act No. 89 of 1991), except as

Page 36 of 3647

Ref No: 12/3/274

provided for by the terms of that Act, shall be added to all applicable amounts due and payable by the Holder.

39. Entire Agreement

Subject to the Act, the Regulations, Applicable Laws, this Exploration Right and the Annexures attached hereto (those Annexures being and forming an integral part of this Exploration Right) contain the entire and sole agreement between the parties and supersede all prior negotiations, representations, understandings, agreements and communications of whatsoever nature between the Parties with respect to such Exploration Area, whether oral or written, express or implied. 

40. Severability

Any provision within this Exploration Right which is not enforceable or which contravenes the Applicable Laws of the Republic of South Africa shall be severed from this Exploration Right and be of no force or effect without prejudice to the other provisions of this Exploration Right which shall remain in force and effect

41. Domicilia Citandi et Executandi

41.1. All notices, requests and reports provided for herein shall be in writing and shall be delivered either by hand to an authorised representative of the receiving Party, or sent by courier or telefax to the addresses below in the Republic of South Africa: Provided that if given by telefax a copy thereof shall then be sent immediately by prepaid registered mail:

If to the Grantor:

Minister of Mineral Resources

Physical address:	Postal address:
Trevenna Campus Cnr Meintjes & Schoeman Streets PRETORIA 0001 Tel number +27 (0)12 444 3000	Private Bag X59 ARCADIA PRETORIA 0007 Fax number: +27 (0)12 444 3145

And copy to the Agency:

South African Agency for the Promotion of Petroleum Exploration and Exploitation (Proprietary) Limited

Attention: Chief Executive Officer

Page 37 of 3747

Ref No: 12/3/274

Physical address:	Postal address:
7 Mispel Street BELLVILLE 7530 Western Cape Tel number +27 (0)21 938 3500	P. O. Box 5111 TYGERVALLEY 7536 Fax number: +27 (0)21 938 3553

If to the Holder:

Physical address:	Postal address:
151 Kingston Road Oxford, OX2, 6RP United Kingdom Tel number +44 01865516910	151 Kingston Road Oxford, OX2, 6RP United Kingdom

41.2. Each Party, including the Agency, may change its address to a different address in the Republic: Provided that it gives the other Parties at least 15 (fifteen) days prior notice.

41.3. All notices, requests and reports sent by prepaid registered post shall be deemed received by addressee within five (5) days of dispatch and all notices, requests and reports sent by telefax during ordinary business hours shall be deemed to have been received within 12 (twelve) hours of transmission or if transmitted outside ordinary business hours, then on the next business day. Those delivered by hand or sent by courier shall be deemed to have been received at the time of actual delivery.

41.4. Each Party also chooses the physical address specified above as its domicilium citandi et executandi for all purposes under this Exploration Right, including service of process.

42. Registration

It is recorded that in terms of Section 82 of the Act, the Holder must lodge this Exploration Right for registration at the Mineral and Petroleum Titles Registration Office within 60 (sixty) days from the notarial execution and, in the event of each renewal of this Exploration Right, within 60 (sixty) days of such renewal.

Page 38 of 3847

Ref No: 12/3/274

Thus done and signed at Bellville on 10^th JANUARY 2019 in the presence of the undersigned witnesses:

AS WITNESS:

1.	/s/
		/s/ Viljoen Störm
		For and on behalf of the Grantor: South African Agency for Promotion of Petroleum Exploration and Exploitation (SOC) Ltd
2.	/s/
		/s/Paul Barrett
		For and on behalf of the Holder: OK Energy Limited
			Quod Attestor
		/s/ Hendrik Malherbe Oosthuizen
		Notary Public
		Seal:HENDRIK MALHERBE OOSTHUIZEN Notary PublicWESTERN CAPE

Page 39 of 3947

Ref No: 12/3/274

Annexure A
Sketch Plan for the Exploration Area

Page 40 of 4047

Ref No: 12/3/274

Annexure B
Exploration Work Programme

Page 41 of 4147

Appendices for Northern Cape Ultra Deep Exploration Right Application

B.    Exploration Right Work Programme

Minimum proposed work programme is:

1.    Acquire 500 Line Km new 2D In-fill Data

2.    Purchase 800 Line Km Multi-Client Seismic

3.    Integrate new seismic into Kingdom Project

4.    Seismic Interpretation and Update Structural Maps

5.    Update Basin Model

6.    Generate Prospect Maps

Contingent Work Programme is:

1.    Acquire 1000 km2 3D seismic

2.    Multi-Beam Bathymetry

3.    Boat or Airborne acquired Full Tensor Gravity

4.    Seafloor Sampling for Geochemical Analysis

2014

2015

2016

1st Qtr

2nd Qtr

3rd Qtr

4th Qtr

1st Qtr

2nd Qtr

3rd Qtr

4th Qtr

1st Qtr

2nd Qtr

3rd Qtr

4th Qtr

Seismic

Purchase 700 Line km 2D multi-client seismic

Acquire 500 Line km 2D in-fill seismic

Satellite Seep Studies

1000 sq km 3D seismic

Multi-Beam Bathymetry

Boat or Airborne Acquired Full Tensor Gravity

Seafloor Sampling

G&G

Integrate new seismic into Kingdom Project

Seismic Interpretation and Update Structural Maps

Update Basin Model

Generate Prospect Maps

Engineering

Economic modeling

Environmental Assessment

Environ. Assess, for Exploration Programme

G&A

Travel

Legal

Forward Programme

Decision on forward programme

Firm

Contingent

Phase 1 Exploration Work Programme Costs Northern Cape Ultra Deep
Work Programme	Cost Category	Est. costs- USD	Total-USD
Seismic, Geochemical, Gravity, Bathymetry
Purchase c. 800 Line km 2D seismic	Purchase	360 000
Acquire 500 Line km 2D in-fill seismic	Purchase	275 000
1000 sq km 3D seismic	Contingent
Multi-Beam Bathymetry	Contingent
Boat or Airborne Acquired Full Tensor Gravity	Contingent
Seafloor Sampling	Contingent
Total Seismic cost			635 000
G&G
Integrate new seismic into Kingdom Project	Labour	20 000
Seismic Interpretation and Update Structural Maps	Labour	40 000
Update Basin Model	Labour	50 000
Generate Prospect Maps	Labour	40 000
Total G&G costs			150 000
Engineering
Economic modeling	consultants	40 000
Total Engineering cost
			40 000
Environmental Assessment
Environ. Assess, for Exploration Programme	consultants	100 000
Total Environmental Assessment			100 000
Travel
S. Africa	travel	30 000
Total Travel			30 000
Legal
Licence, JOA, Ministry and Mining Code	consultants	80 000
Total Legal			80 000
Total Exploration Work Programme Costs			1 035 000

Ref No: 12/3/274

Annexure CRelinquishment Schedule

At the end of ...	% of the original extent of the Exploration Area
The Initial Period	Not less than 15%
The First Renewal Period	Not less than 15%
The Second Renewal Period	Not less than 15%

Page 45 of 4547

Ref No: 12/3/274

Annexure DSchedule of contributions to the Upstream Training Trust

On granting and each subsequent renewal 100 000

Page 46 of 4647

Ref No: 12/3/274

Annexure EExisting Data made available to the Holder

Page 47 of 4747

EX-31.1

Exhibit 31.1

Certification of Chief Executive Officer

I, Andrew G. Inglis, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Kosmos Energy Ltd.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 4, 2019	/s/ ANDREW G. INGLIS
	Andrew G. Inglis
	Chairman of the Board of Directors and Chief Executive Officer
	(Principal Executive Officer)

EX-31.2

Exhibit 31.2

Certification of Chief Financial Officer

I, Thomas P. Chambers, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Kosmos Energy Ltd.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 4, 2019	/s/ THOMAS P. CHAMBERS
	Thomas P. Chambers
	Senior Vice President and Chief Financial Officer
	(Principal Financial Officer)

EX-32.1

Exhibit 32.1

Certification of Chief Executive Officer

Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the accompanying quarterly report of Kosmos Energy Ltd. (the “Company”) on Form 10-Q for the quarter ended September 30, 2019, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Andrew G. Inglis, Chairman of the Board of Directors and Chief Executive Officer of the Company, hereby certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: November 4, 2019	/s/ ANDREW G. INGLIS
	Andrew G. Inglis
	Chairman of the Board of Directors and Chief Executive Officer
	(Principal Executive Officer)

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

Certification of Chief Financial Officer

Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the accompanying quarterly report of Kosmos Energy Ltd. (the “Company”) on Form 10-Q for the quarter ended September 30, 2019, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Thomas P. Chambers, Senior Vice President and Chief Financial Officer of the Company, hereby certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: November 4, 2019	/s/ THOMAS P. CHAMBERS
	Thomas P. Chambers
	Senior Vice President and Chief Financial Officer
	(Principal Financial Officer)

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

XML

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Sep. 30, 2019	Dec. 31, 2018
Statement of Financial Position [Abstract]
Deferred financing costs, accumulated amortization	$ 14,027	$ 12,065
Preference shares, par value (in dollars per share)	$ 0.01	$ 0.01
Preference shares, authorized shares (in shares)	200,000,000	200,000,000
Preference shares, issued shares (in shares)	0	0
Common shares, par value (in dollars per share)	$ 0.01	$ 0.01
Common shares, authorized shares (in shares)	2,000,000,000	2,000,000,000
Common shares, issued shares (in shares)	445,757,319	442,914,675
Treasury stock shares (in shares)	44,263,269	44,263,269

XML

Accounting Policies (Tables)

9 Months Ended

Sep. 30, 2019

Accounting Policies [Abstract]

Schedule of cash and cash equivalents

	September 30, 2019		December 31, 2018
	(In thousands)
Cash and cash equivalents	$	203,646	$	173,515
Restricted cash - current	7,745		4,527
Restricted cash - long-term	3,667		7,574
Total cash, cash equivalents and restricted cash shown in the consolidated statements of cash flows	$	215,058	$	185,616

Schedule of oil and gas revenue

Oil and gas revenue is composed of the following:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
	(In thousands)
Revenues from contract with customer - Equatorial Guinea	$	54,894	$	—	$	207,173	$	—
Revenues from contract with customer - Ghana	173,613		215,581		502,413		557,459
Revenues from contract with customers - U.S. Gulf of Mexico	123,861		24,177		338,292		24,177
Provisional oil sales contracts	4,668		3,075		1,881		3,584
Oil and gas revenue	$	357,036	$	242,833	$	1,049,759	$	585,220

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018
Operating activities
Net loss	$ (20,004)	$ (279,556)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation and amortization	423,160	215,676
Deferred income taxes	(69,840)	(84,095)
Unsuccessful well costs and leasehold impairments	7,361	114,948
Change in fair value of derivatives	34,003	232,057
Cash settlements on derivatives, net (including $(27.0) million and $(107.3) million on commodity hedges during 2019 and 2018)	(24,701)	(102,705)
Equity-based compensation	27,382	25,975
Gain on sale of assets	0	(7,666)
Loss on extinguishment of debt	24,794	4,324
Distributions in excess of equity in earnings	0	5,235
Other	9,600	1,237
Changes in assets and liabilities:
Decrease in receivables	12,886	59,318
(Increase) decrease in inventories	(51,943)	3,978
(Increase) decrease in prepaid expenses and other	23,512	(9,732)
Decrease in accounts payable	(61,909)	(15,178)
Increase (decrease) in accrued liabilities	65,975	(73,569)
Net cash provided by operating activities	400,276	90,247
Investing activities
Oil and gas assets	(240,642)	(149,305)
Other property	(8,291)	(3,560)
Acquisition of oil and gas properties, net of cash acquired	0	(961,764)
Return of investment from KTIPI	0	142,628
Proceeds on sale of assets	0	13,703
Notes receivable from partners	(19,565)	0
Net cash used in investing activities	(268,498)	(958,298)
Financing activities
Borrowings under long-term debt	175,000	1,000,000
Payments on long-term debt	(325,000)	(175,000)
Net proceeds from issuance of senior notes	641,875	0
Redemption of senior secured notes	(535,338)	0
Purchase of treasury stock / tax withholdings	(1,983)	(17,695)
Dividends	(54,447)	0
Deferred financing costs	(2,443)	(36,745)
Net cash provided by (used in) financing activities	(102,336)	770,560
Net increase (decrease) in cash, cash equivalents and restricted cash	29,442	(97,491)
Cash, cash equivalents and restricted cash at beginning of period	185,616	304,986
Cash, cash equivalents and restricted cash at end of period	215,058	207,495
Cash paid for:
Interest, net of capitalized interest	78,691	86,981
Income taxes	27,768	25,601
Non-cash activity:
Common stock issued for acquisition of oil and gas properties	$ 0	$ 307,944

XML

Commitments and Contingencies

9 Months Ended

Sep. 30, 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.

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 one year to ten years. Certain lease agreements contain provisions for future rent increases.

The components of lease cost for the three months and nine months ended September 30, 2019 are as follows:

	Three months ended September 30, 2019		Nine Months Ended September 30, 2019
	(In thousands)
Operating lease cost	$	1,279	$	4,288
Short-term lease cost	960		1,547
Total lease cost	$	2,239	$	5,835

Other information related to operating leases at September 30, 2019, is as follows:

	September 30, 2019
(In thousands, except lease term and discount rate)
Balance sheet classifications
Other assets (right-of-use assets)	$	20,436
Accrued liabilities (current maturities of leases)	1,294
Other long-term liabilities (non-current maturities of leases)	22,480
Weighted average remaining lease term	9.1 years
Weighted average discount rate	9.8		%

The table below presents supplemental cash flow information related to leases during the nine months ended September 30, 2019:

	Nine Months Ended September 30, 2019
	(In thousands)
Operating cash flows for operating leases	$	3,077

Future minimum rental commitments under our leases at September 30, 2019, are as follows:

	Operating Leases(1)
	(In thousands)
2019(2)	$	483
2020	4,098
2021	4,148
2022	4,199
2023	4,249
Thereafter	19,480
Total undiscounted lease payments	$	36,657
Less: Imputed interest	(12,883		)
Total lease liabilities	$	23,774

__________________________________

(1) Does not include purchase commitments for jointly owned fields and facilities where we are not the operator and excludes commitments for exploration activities, including well commitments, in our petroleum contracts.

(2) Represents payments for the period from October 1, 2019 through December 31, 2019.

Performance Obligations

As of September 30, 2019 and December 31, 2018, the Company had performance bonds totaling $208.7 million and $200.9 million, respectively, for our supplemental bonding requirements stipulated by the 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 our U.S. Gulf of Mexico fields. As of September 30, 2019 and December 31, 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 November 1, 2019, we declared our quarterly cash dividend of $0.0452 per common share for the fourth quarter payable on December 23, 2019 to stockholders of record as of December 2, 2019.

XML

Commitments and Contingencies - Leases (Details) $ in Thousands	3 Months Ended	9 Months Ended
	Sep. 30, 2019 USD ($)	Sep. 30, 2019 USD ($)
Lease, Cost [Abstract]
Operating lease cost	$ 1,279	$ 4,288
Short-term lease cost	960	1,547
Total lease cost	2,239	5,835
Balance sheet classifications
Other assets (right-of-use assets)	20,436	20,436
Accrued liabilities (current maturities of leases)	1,294	1,294
Other long-term liabilities (non-current maturities of leases)	$ 22,480	$ 22,480
Weighted average remaining lease term	9 years 1 month 6 days	9 years 1 month 6 days
Weighted average discount rate	9.80%	9.80%
Operating cash flows for operating leases		$ 3,077
Lessee, Operating Lease, Liability, Payment, Due [Abstract]
2019	$ 483	483
2020	4,098	4,098
2021	4,148	4,148
2022	4,199	4,199
2023	4,249	4,249
Thereafter	19,480	19,480
Total undiscounted lease payments	36,657	36,657
Less: Imputed interest	(12,883)	(12,883)
Total lease liabilities	$ 23,774	$ 23,774
Minimum
Lessee, Lease, Description [Line Items]
Operating lease, initial term	1 year	1 year
Maximum
Lessee, Lease, Description [Line Items]
Operating lease, initial term	10 years	10 years

XML

Equity-based Compensation - Schedule of awards (Details) - LTIP shares in Thousands	9 Months Ended
	Sep. 30, 2019 $ / shares shares
Service Vesting Restricted Stock Units
Outstanding unvested awards activity
Outstanding at the beginning of the period (in shares) | shares	4,115
Granted (in shares) | shares	3,096
Forfeited (in shares) | shares	(134)
Vested (in shares) | shares	(1,999)
Outstanding at the end of the period (in shares) | shares	5,078
Weighted-Average Grant-Date Fair Value
Outstanding at beginning of the period (in dollars per share)	$ 6.42
Granted (in dollars per share)	4.96
Forfeited (in dollars per share)	6.11
Vested (in dollars per share)	5.92
Outstanding at the end of the period (in dollars per share)	$ 5.73
Market/Service Vesting Restricted Stock Units
Outstanding unvested awards activity
Outstanding at the beginning of the period (in shares) | shares	6,716
Granted (in shares) | shares	3,160
Forfeited (in shares) | shares	(295)
Vested (in shares) | shares	(1,300)
Outstanding at the end of the period (in shares) | shares	8,281
Weighted-Average Grant-Date Fair Value
Outstanding at beginning of the period (in dollars per share)	$ 9.02
Granted (in dollars per share)	6.02
Forfeited (in dollars per share)	9.87
Vested (in dollars per share)	6.32
Outstanding at the end of the period (in dollars per share)	8.39
Minimum | Market/Service Vesting Restricted Stock Units
Weighted-Average Grant-Date Fair Value
Granted (in dollars per share)	$ 4.83
Vesting percentage of the awards granted	0.00%
Maximum | Market/Service Vesting Restricted Stock Units
Weighted-Average Grant-Date Fair Value
Granted (in dollars per share)	$ 12.96
Vesting percentage of the awards granted	200.00%

XML

Derivative Financial Instruments - Derivatives instrument and gain/loss from derivatives (Details) - USD ($)	Sep. 30, 2019	Dec. 31, 2018
Derivative instruments, Balance Sheet Location
Derivatives assets—current	$ 22,067,000	$ 38,785,000
Derivatives assets—long-term	10,535,000	14,312,000
Derivatives liabilities—current	(8,461,000)	(12,172,000)
Derivatives liabilities—long-term	(2,699,000)	(10,181,000)
Derivatives not designated as hedging instruments:
Derivative instruments, Balance Sheet Location
Total derivatives not designated as hedging instruments	21,442,000	30,744,000
Derivatives not designated as hedging instruments: | Commodity
Derivative instruments, Balance Sheet Location
Derivatives assets—current	22,067,000	38,785,000
Derivatives assets—long-term	10,535,000	14,312,000
Derivatives liabilities—current	(8,461,000)	(12,172,000)
Derivatives liabilities—long-term	(2,699,000)	(10,181,000)
Net deferred premiums payable related to commodity derivative contracts - current assets	4,100,000	1,600,000
Net deferred premiums payable related to commodity derivative contracts - non-current assets	2,600,000	1,300,000
Net deferred premiums payable related to commodity derivative contracts - current liabilities	6,500,000	18,000,000.0
Net deferred premiums payable related to commodity derivative contracts - non-current liabilities	0	500,000
Oil and gas revenue | Derivatives not designated as hedging instruments: | Commodity
Derivative instruments, Balance Sheet Location
Derivatives assets—current	$ 0	$ 400,000

XML

Joint Interest Billings, Related Party Receivables and Notes Receivables (Details) $ in Thousands	1 Months Ended	12 Months Ended
	Feb. 28, 2019 USD ($) Agreement	Dec. 31, 2014	Sep. 30, 2019 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017
Joint interest billings
Joint interest billings, net			$ 54,409	$ 64,572
Long-term receivables			36,957	19,002
Related party receivable			0	$ 5,580
Kosmos-Trident International Petroleum Inc.
Joint interest billings
Ownership percentage					50.00%
Trident | Kosmos-Trident International Petroleum Inc.
Joint interest billings
Ownership percentage				50.00%
TEN Discoveries | GNPC
Joint interest billings
Joint interest billings, net			14,000	$ 14,000
Long-term receivables			17,200	14,000
TEN Discoveries | GNPC
Joint interest billings
GNPC's paying interest		5.00%
Kosmos-Trident International Petroleum Inc.
Joint interest billings
Related party receivable				$ 5,600
Carry Advance Agreements | National Oil Companies Of Mauritania And Senegal
Joint interest billings
Long-term receivables			$ 19,800
Number of agreements | Agreement	2
Share of development costs to be financed, up to	$ 239,700

XML

Equity Method Investments - Narrative (Details)	Jan. 01, 2019	Dec. 31, 2018	Dec. 31, 2017
Kosmos-Trident International Petroleum Inc.
Schedule of Equity Method Investments [Line Items]
Ownership percentage			50.00%
Basis presented		100.00%
Ceiba Field And Okume Complex Acquisition
Schedule of Equity Method Investments [Line Items]
Direct ownership percentage	40.375%

XML

Business Segment Information - Consolidated Capital Expenditures (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Segment Reporting [Abstract]
Oil and gas assets			$ 240,642	$ 149,305
Other property			8,291	3,560
Changes in capital accruals			11,083	13,965
Exploration expense, excluding unsuccessful well costs			75,661	131,964
Capitalized interest			(21,330)	(21,209)
Proceeds on sale of assets			0	(13,703)
Other			3,959	111
Consolidated capital expenditures	$ (107,393)	$ (109,191)	$ (318,306)	$ (263,993)

XML

Debt - Maturities (Details) - USD ($) $ in Thousands	Sep. 30, 2019	Dec. 31, 2018
Scheduled maturities of debt during the five year period and thereafter
Total	$ 2,150,000	$ 2,175,000
2019	0
2020	0
2021	274,800
2022	284,200
2023	271,600
Thereafter	1,319,400
Senior Notes | 7.125% Senior Notes due 2026
Scheduled maturities of debt during the five year period and thereafter
Total	$ 650,000	$ 0

XML

Debt - Corporate Revolver (Details) - USD ($)	1 Months Ended
	Aug. 31, 2018	Sep. 30, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Net deferred financing costs		$ 6,975,000	$ 8,937,000
Corporate Revolver | Revolving Credit Facility
Debt Instrument [Line Items]
Maximum borrowing capacity	$ 400,000,000.0
Change in basis points	1.00%
Applicable margin	5.00%
Commitment fee percentage	30.00%
Undrawn availability		400,000,000.0
Net deferred financing costs		$ 7,000,000.0

XML

Equity-based Compensation (Tables)

9 Months Ended

Sep. 30, 2019

Share-based Payment Arrangement [Abstract]

Schedule of plan activity

The following table reflects the outstanding restricted stock units as of September 30, 2019:

			Weighted-		Market / Service		Weighted-
	Service Vesting		Average		Vesting		Average
	Restricted Stock		Grant-Date		Restricted Stock		Grant-Date
	Units		Fair Value		Units		Fair Value
	(In thousands)				(In thousands)
Outstanding at December 31, 2018	4,115		$	6.42	6,716		$	9.02
Granted(1)	3,096		4.96		3,160		6.02
Forfeited(1)	(134	)	6.11		(295	)	9.87
Vested	(1,999	)	5.92		(1,300	)	6.32
Outstanding at September 30, 2019	5,078		5.73		8,281		8.39

__________________________________

(1) The restricted stock units with a combination of market and service vesting criteria may vest between 0% and 200% of the originally granted units depending upon market performance conditions. Awards vesting over or under target shares of 100% results in additional shares granted or forfeited, respectively, in the period the market vesting criteria is determined.

XML

Additional Financial Information (Tables)

9 Months Ended

Sep. 30, 2019

Additional Financial Information

Schedule of accrued liabilities

Accrued liabilities consisted of the following:

	September 30, 2019		December 31, 2018
	(In thousands)
Accrued liabilities:
Exploration, development and production	$	114,833	$	92,613
Revenue payable	33,721		24,379
Current asset retirement obligations	5,844		6,617
Operating leases	1,294		—
General and administrative expenses	31,913		39,373
Interest	27,913		18,152
Income taxes	69,938		8,958
Taxes other than income	2,060		4,613
Derivatives	2,975		441
Other	1,928		450
	$	292,419	$	195,596

Schedule of changes in asset retirement obligations

The following table summarizes the changes in the Company's asset retirement obligations:

	September 30, 2019
	(In thousands)
Asset retirement obligations:
Beginning asset retirement obligations	$	151,953
Additions associated with Equatorial Guinea - Ceiba Field and Okume Complex	114,395
Liabilities incurred during period	9,706
Liabilities settled during period	(4,384		)
Revisions in estimated retirement obligations	905
Accretion expense	17,795
Ending asset retirement obligations	$	290,370

Schedule of other expenses, net incurred

Other expenses, net incurred during the period is comprised of the following:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019		2018
	(In thousands)
(Gain) loss on disposal of inventory	$	1,232		$	(2	)	$	1,419	$	(26	)
(Gain) loss on ARO liability settlements	(746		)	—			1,167		—
Disputed charges and related costs, net of recoveries	1,677			(12,682		)	1,663		(9,721		)
Other, net	9,309			(123		)	7,549		1,583
Other expenses, net	$	11,472		$	(12,807	)	$	11,798	$	(8,164	)

XML

Fair Value Measurements

9 Months Ended

Sep. 30, 2019

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Measurements

In accordance with ASC Topic 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 September 30, 2019 and December 31, 2018, for each fair value hierarchy level:

	Fair Value Measurements Using:
	Quoted Prices in
	Active Markets for		Significant Other			Significant
	Identical Assets		Observable Inputs			Unobservable Inputs
	(Level 1)		(Level 2)			(Level 3)		Total
	(In thousands)
September 30, 2019
Assets:
Commodity derivatives	$	—	$	32,602		$	—	$	32,602
Liabilities:
Commodity derivatives	—		(11,160		)	—		(11,160		)
Total	$	—	$	21,442		$	—	$	21,442
December 31, 2018
Assets:
Commodity derivatives	$	—	$	53,097		$	—	$	53,097
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 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 provisional oil sales derivatives 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 September 30, 2019 and December 31, 2018:

	September 30, 2019				December 31, 2018
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In thousands)
Senior Notes	$	642,318	$	670,514	$	—	$	—
Senior Secured Notes	—		—		511,873		525,026
Corporate Revolver	—		—		325,000		325,000
Facility	1,500,000		1,500,000		1,325,000		1,325,000
Total	$	2,142,318	$	2,170,514	$	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 and Senior Secured 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.

XML

Suspended Well Costs

9 Months Ended

Sep. 30, 2019

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Suspended Well Costs

Suspended Well Costs

The following table reflects the Company’s capitalized exploratory well costs on drilled wells as of and during the nine months ended September 30, 2019. The table excludes $1.4 million in costs that were capitalized and subsequently expensed during the same period.

	September 30, 2019
	(In thousands)
Beginning balance	$	367,665
Additions to capitalized exploratory well costs pending the determination of proved reserves	55,244
Reclassification due to determination of proved reserves	(10,711		)
Capitalized exploratory well costs charged to expense	—
Ending balance	$	412,198

The following table provides an 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:

	September 30, 2019		December 31, 2018
	(In thousands, except well counts)
Exploratory well costs capitalized for a period of one year or less	$	—	$	—
Exploratory well costs capitalized for a period of one to two years	77,995		299,253
Exploratory well costs capitalized for a period of three years or greater	334,203		68,412
Ending balance	$	412,198	$	367,665
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year	3		3

As of September 30, 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, the Bir Allah 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.

Bir Allah 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 to 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.

Yakaar and Teranga Discoveries — In May 2016, we completed the Teranga-1 exploration well in the Cayar Offshore Profond block offshore Senegal, which encountered hydrocarbon pay. In June 2017, we completed the Yakaar-1 exploration well in the Cayar Offshore Profond block offshore Senegal, which encountered hydrocarbon pay. In November 2017, an integrated Yakaar-Teranga appraisal plan was submitted to the government of Senegal. In September 2019, we completed the Yakaar-2 appraisal well which encountered hydrocarbon pay. The Yakaar-2 well was drilled approximately nine kilometers from the Yakaar-1 exploration well. Following additional evaluation, a decision regarding commerciality is expected to be made.

XML

Accounting Policies

9 Months Ended

Sep. 30, 2019

Accounting Policies [Abstract]

Accounting Policies

Accounting Policies

General

The interim consolidated financial statements included in this report are unaudited and, in the opinion of management, include all adjustments of a normal recurring nature necessary for a fair presentation of the results for the interim periods. The results of the interim periods shown in this report are not necessarily indicative of the final results to be expected for the full year. The consolidated financial statements were prepared in accordance with the requirements of the Securities and Exchange Commission (“SEC”) for interim reporting. As permitted under those rules, certain notes or other financial information that are normally required by Generally Accepted Accounting Principles in the United States of America (“GAAP”) have been condensed or omitted from these interim consolidated financial statements. These consolidated financial statements and the accompanying notes should be read in conjunction with our audited consolidated financial statements for the year ended December 31, 2018, included in our annual report on Form 10-K.

Reclassifications

Certain prior period amounts have been reclassified to conform with the current presentation. Such reclassifications had no significant impact on our reported net income (loss), current assets, total assets, current liabilities, total liabilities, stockholders’ equity or cash flows. Additionally, as a result of our outstanding shares in KTIPI being transferred for an undivided interest in the Ceiba Field and Okume Complex (effective January 1, 2019), our previously reported equity method investment in KTIPI has been allocated to the respective assets and liabilities on a relative fair value basis. See Note 7 — Equity Method Investments for additional information. 

Cash, Cash Equivalents and Restricted Cash 

	September 30, 2019		December 31, 2018
	(In thousands)
Cash and cash equivalents	$	203,646	$	173,515
Restricted cash - current	7,745		4,527
Restricted cash - long-term	3,667		7,574
Total cash, cash equivalents and restricted cash shown in the consolidated statements of cash flows	$	215,058	$	185,616

Cash and cash equivalents include 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 respective 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.

Inventories

Inventories consisted of $123.6 million and $83.4 million of materials and supplies and $16.6 million and $1.4 million of hydrocarbons as of September 30, 2019 and December 31, 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.

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.

Revenue Recognition

We recognize revenues on the volumes 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 September 30, 2019 and December 31, 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:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
	(In thousands)
Revenues from contract with customer - Equatorial Guinea	$	54,894	$	—	$	207,173	$	—
Revenues from contract with customer - Ghana	173,613		215,581		502,413		557,459
Revenues from contract with customers - U.S. Gulf of Mexico	123,861		24,177		338,292		24,177
Provisional oil sales contracts	4,668		3,075		1,881		3,584
Oil and gas revenue	$	357,036	$	242,833	$	1,049,759	$	585,220

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 three months ended September 30, 2019 and 2018, revenue from Phillips 66 Company made up approximately 21% and 6%, respectively, and revenue from Shell Trading (US) Company made up approximately11% and 3%, respectively, of our total consolidated revenue and was included in our U.S. Gulf of Mexico segment. For the nine months ended September 30, 2019 and 2018, revenue from Phillips 66 Company made up approximately 22% and 3%, respectively, and revenue from Shell Trading (US) Company made up approximately 9% and 1%, respectively, of our total consolidated revenue and was included in our U.S. Gulf of Mexico segment.

Recent Accounting Standards

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 are evaluating its potential impact.

XML

Business Segment Information (Details) $ in Thousands	3 Months Ended						9 Months Ended
	Sep. 30, 2019 USD ($)	Jun. 30, 2019 USD ($)	Mar. 31, 2019 USD ($)	Sep. 30, 2018 USD ($)	Jun. 30, 2018 USD ($)	Mar. 31, 2018 USD ($)	Sep. 30, 2019 USD ($) segment	Sep. 30, 2018 USD ($)	Dec. 31, 2018 USD ($)
Segment Reporting Information [Line Items]
Number of reportable segments | segment							4
Oil and gas revenue	$ 357,036			$ 242,833			$ 1,049,759	$ 585,220
Gain on sale of assets	0			7,666			0	7,666
Other income, net	(66)			(280)			(65)	(17)
Total revenues and other income	356,970			250,219			1,049,694	592,869
Oil and gas production	95,540			55,078			266,316	151,661
Facilities insurance modifications, net	12,569			12,334			(5,174)	21,812
Exploration expenses	22,773			148,238			83,022	246,912
General and administrative	24,723			25,963			88,703	65,343
Depletion, depreciation and amortization	146,653			80,041			416,186	208,607
Interest and other financing costs, net	30,721			23,549			125,565	68,113
Derivatives, net	(27,016)			57,357			35,884	236,107
Gain on equity method investments, net	0			(24,841)			0	(59,637)
Other expenses, net	11,472			(12,807)			11,798	(8,164)
Total costs and expenses	317,435			364,912			1,022,300	930,754
Income (loss) before income taxes	39,535			(114,693)			27,394	(337,885)
Income tax expense (benefit)	23,470			11,364			47,398	(58,329)
Net income (loss)	16,065	$ 16,837	$ (52,906)	(126,057)	$ (103,273)	$ (50,226)	(20,004)	(279,556)
Consolidated capital expenditures	107,393			109,191			318,306	263,993
Property and equipment, net	3,799,036			3,509,537			3,799,036	3,509,537	$ 3,459,701
Total assets	4,468,259			4,329,464			4,468,259	4,329,464	$ 4,088,189
Corporate & Other
Segment Reporting Information [Line Items]
Oil and gas revenue	0			0			0	0
Gain on sale of assets				0				0
Other income, net	5,706			78,166			97,594	315,771
Total revenues and other income	5,706			78,166			97,594	315,771
Oil and gas production	0			1,331			0	3,334
Facilities insurance modifications, net	0			0			0	0
Exploration expenses	8,369			22,457			32,174	98,392
General and administrative	38,897			42,072			127,416	122,558
Depletion, depreciation and amortization	913			1,037			2,941	3,111
Interest and other financing costs, net	17,304			7,704			77,782	24,735
Derivatives, net	(25,271)			47,275			7,116	226,025
Gain on equity method investments, net				0				0
Other expenses, net	1,253			846			1,304	2,695
Total costs and expenses	41,465			122,722			248,733	480,850
Income (loss) before income taxes	(35,759)			(44,556)			(151,139)	(165,079)
Income tax expense (benefit)	3,833			1,826			(15,466)	3,143
Net income (loss)	(39,592)			(46,382)			(135,673)	(168,222)
Consolidated capital expenditures	13,127			17,970			41,177	102,651
Property and equipment, net	43,281			34,551			43,281	34,551
Total assets	12,078,321			10,660,832			12,078,321	10,660,832
Eliminations
Segment Reporting Information [Line Items]
Oil and gas revenue	0			(107,704)			0	(300,079)
Gain on sale of assets				0				0
Other income, net	(5,973)			(78,129)			(98,120)	(315,793)
Total revenues and other income	(5,973)			(185,833)			(98,120)	(615,872)
Oil and gas production	0			(20,167)			0	(57,683)
Facilities insurance modifications, net	0			0			0	0
Exploration expenses	0			0			0	0
General and administrative	(29,459)			(29,078)			(85,653)	(84,288)
Depletion, depreciation and amortization	0			(37,291)			0	(115,862)
Interest and other financing costs, net	(1,784)			(1,784)			(5,351)	(5,351)
Derivatives, net	0			0			0	0
Gain on equity method investments, net				(24,841)				(59,637)
Other expenses, net	25,270			(47,274)			(7,116)	(226,027)
Total costs and expenses	(5,973)			(160,435)			(98,120)	(548,848)
Income (loss) before income taxes	0			(25,398)			0	(67,024)
Income tax expense (benefit)	0			(25,398)			0	(67,024)
Net income (loss)	0			0			0	0
Consolidated capital expenditures	0			0			0	0
Property and equipment, net	0			0			0	0
Total assets	(13,821,741)			(12,489,869)			(13,821,741)	(12,489,869)
Ghana | Operating Segments
Segment Reporting Information [Line Items]
Oil and gas revenue	177,797			218,656			502,800	561,043
Gain on sale of assets				0				0
Other income, net	1			0			2	(17)
Total revenues and other income	177,798			218,656			502,802	561,026
Oil and gas production	42,017			49,280			117,027	143,860
Facilities insurance modifications, net	12,569			12,334			(5,174)	21,812
Exploration expenses	82			57,818			189	58,076
General and administrative	3,886			5,786			15,844	15,651
Depletion, depreciation and amortization	73,347			70,799			204,108	197,260
Interest and other financing costs, net	16,821			21,989			56,500	65,357
Derivatives, net	0			0			0	0
Gain on equity method investments, net				0				0
Other expenses, net	(25,357)			34,610			6,761	216,319
Total costs and expenses	123,365			252,616			395,255	718,335
Income (loss) before income taxes	54,433			(33,960)			107,547	(157,309)
Income tax expense (benefit)	10,585			21,862			30,285	(49,148)
Net income (loss)	43,848			(55,822)			77,262	(108,161)
Consolidated capital expenditures	28,398			32,501			96,861	71,330
Property and equipment, net	1,603,170			1,727,595			1,603,170	1,727,595
Total assets	1,844,328			2,073,825			1,844,328	2,073,825
Equatorial Guinea | Operating Segments
Segment Reporting Information [Line Items]
Oil and gas revenue	55,378			107,704			208,667	300,079
Gain on sale of assets				7,666				7,666
Other income, net	0			(317)			0	22
Total revenues and other income	55,378			115,053			208,667	307,767
Oil and gas production	21,369			20,167			60,645	57,683
Facilities insurance modifications, net	0			0			0	0
Exploration expenses	2,437			16,584			8,080	33,665
General and administrative	1,719			1,761			5,303	3,768
Depletion, depreciation and amortization	16,019			37,291			55,323	115,862
Interest and other financing costs, net	0			(4)			0	(9)
Derivatives, net	0			0			0	0
Gain on equity method investments, net				0				0
Other expenses, net	615			(976)			(1,629)	(1,138)
Total costs and expenses	42,159			74,823			127,722	209,831
Income (loss) before income taxes	13,219			40,230			80,945	97,936
Income tax expense (benefit)	6,110			25,398			33,403	67,024
Net income (loss)	7,109			14,832			47,542	30,912
Consolidated capital expenditures	15,397			2,913			36,448	27,891
Property and equipment, net	460,044			3,801			460,044	3,801
Total assets	489,564			145,823			489,564	145,823
Mauritania And Senegal | Operating Segments
Segment Reporting Information [Line Items]
Oil and gas revenue	0			0			0	0
Gain on sale of assets				0				0
Other income, net	0			0			0	0
Total revenues and other income	0			0			0	0
Oil and gas production	0			0			0	0
Facilities insurance modifications, net	0			0			0	0
Exploration expenses	1,260			1,203			9,745	6,603
General and administrative	2,678			1,396			6,505	3,628
Depletion, depreciation and amortization	15			15			46	46
Interest and other financing costs, net	(6,703)			(6,441)			(20,020)	(18,704)
Derivatives, net	0			0			0	0
Gain on equity method investments, net				0				0
Other expenses, net	9,141			(13)			9,783	(13)
Total costs and expenses	6,391			(3,840)			6,059	(8,440)
Income (loss) before income taxes	(6,391)			3,840			(6,059)	8,440
Income tax expense (benefit)	0			0			0	0
Net income (loss)	(6,391)			3,840			(6,059)	8,440
Consolidated capital expenditures	842			3,319			7,132	9,633
Property and equipment, net	428,596			403,111			428,596	403,111
Total assets	568,743			465,352			568,743	465,352
U.S. Gulf of Mexico | Operating Segments
Segment Reporting Information [Line Items]
Oil and gas revenue	123,861			24,177			338,292	24,177
Gain on sale of assets				0				0
Other income, net	200			0			459	0
Total revenues and other income	124,061			24,177			338,751	24,177
Oil and gas production	32,154			4,467			88,644	4,467
Facilities insurance modifications, net	0			0			0	0
Exploration expenses	10,625			50,176			32,834	50,176
General and administrative	7,002			4,026			19,288	4,026
Depletion, depreciation and amortization	56,359			8,190			153,768	8,190
Interest and other financing costs, net	5,083			2,085			16,654	2,085
Derivatives, net	(1,745)			10,082			28,768	10,082
Gain on equity method investments, net				0				0
Other expenses, net	550			0			2,695	0
Total costs and expenses	110,028			79,026			342,651	79,026
Income (loss) before income taxes	14,033			(54,849)			(3,900)	(54,849)
Income tax expense (benefit)	2,942			(12,324)			(824)	(12,324)
Net income (loss)	11,091			(42,525)			(3,076)	(42,525)
Consolidated capital expenditures	49,629			52,488			136,688	52,488
Property and equipment, net	1,263,945			1,340,479			1,263,945	1,340,479
Total assets	$ 3,309,044			$ 3,473,501			$ 3,309,044	$ 3,473,501

XML

Debt - Interest and other financing costs, net (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Debt Disclosure [Abstract]
Interest expense	$ 34,944	$ 27,317	$ 111,566	$ 77,121
Amortization—deferred financing costs	2,285	2,346	6,974	7,069
Loss on extinguishment of debt	0	268	24,794	4,324
Capitalized interest	(7,077)	(7,097)	(21,330)	(21,209)
Deferred interest	290	(194)	1,559	(1,284)
Interest income	(972)	(788)	(2,215)	(2,579)
Other, net	1,251	1,697	4,217	4,671
Interest and other financing costs, net	$ 30,721	$ 23,549	$ 125,565	$ 68,113

XML

Debt - Revolving Letter of Credit Facility (Details) $ in Millions	Sep. 30, 2019 USD ($) letter_of_credit
Revolving Letter of Credit Facility
Debt Instrument [Line Items]
Number of letters of credit | letter_of_credit	6
Amount outstanding | $	$ 9.4
Letter of Credit Arrangement
Debt Instrument [Line Items]
Number of letters of credit | letter_of_credit	2
Amount outstanding | $	$ 20.4

XML

Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 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 September 30, 2019 and December 31, 2018, for each fair value hierarchy level:

	Fair Value Measurements Using:
	Quoted Prices in
	Active Markets for		Significant Other			Significant
	Identical Assets		Observable Inputs			Unobservable Inputs
	(Level 1)		(Level 2)			(Level 3)		Total
	(In thousands)
September 30, 2019
Assets:
Commodity derivatives	$	—	$	32,602		$	—	$	32,602
Liabilities:
Commodity derivatives	—		(11,160		)	—		(11,160		)
Total	$	—	$	21,442		$	—	$	21,442
December 31, 2018
Assets:
Commodity derivatives	$	—	$	53,097		$	—	$	53,097
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 September 30, 2019 and December 31, 2018:

	September 30, 2019				December 31, 2018
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In thousands)
Senior Notes	$	642,318	$	670,514	$	—	$	—
Senior Secured Notes	—		—		511,873		525,026
Corporate Revolver	—		—		325,000		325,000
Facility	1,500,000		1,500,000		1,325,000		1,325,000
Total	$	2,142,318	$	2,170,514	$	2,161,873	$	2,175,026

XML

Commitments and Contingencies (Tables)

9 Months Ended

Sep. 30, 2019

Commitments and Contingencies Disclosure [Abstract]

Schedule of Components of Lease Costs and Cash Flow Information

The table below presents supplemental cash flow information related to leases during the nine months ended September 30, 2019:

	Nine Months Ended September 30, 2019
	(In thousands)
Operating cash flows for operating leases	$	3,077

The components of lease cost for the three months and nine months ended September 30, 2019 are as follows:

	Three months ended September 30, 2019		Nine Months Ended September 30, 2019
	(In thousands)
Operating lease cost	$	1,279	$	4,288
Short-term lease cost	960		1,547
Total lease cost	$	2,239	$	5,835

Schedule of Other Information on Leases

Other information related to operating leases at September 30, 2019, is as follows:

	September 30, 2019
(In thousands, except lease term and discount rate)
Balance sheet classifications
Other assets (right-of-use assets)	$	20,436
Accrued liabilities (current maturities of leases)	1,294
Other long-term liabilities (non-current maturities of leases)	22,480
Weighted average remaining lease term	9.1 years
Weighted average discount rate	9.8		%

Schedule of Future Minimum Rental Commitments

Future minimum rental commitments under our leases at September 30, 2019, are as follows:

	Operating Leases(1)
	(In thousands)
2019(2)	$	483
2020	4,098
2021	4,148
2022	4,199
2023	4,249
Thereafter	19,480
Total undiscounted lease payments	$	36,657
Less: Imputed interest	(12,883		)
Total lease liabilities	$	23,774

__________________________________

(1) Does not include purchase commitments for jointly owned fields and facilities where we are not the operator and excludes commitments for exploration activities, including well commitments, in our petroleum contracts.

(2) Represents payments for the period from October 1, 2019 through December 31, 2019.

XML

Equity Method Investments

9 Months Ended

Sep. 30, 2019

Equity Method Investments and Joint Ventures [Abstract]

Equity Method Investments

Equity Method Investments

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 stockholders' equity
Total current liabilities	$	226,311
Total long-term liabilities	536,178
Shareholders' equity:
Total shareholders' equity	(340,891		)
Total liabilities and shareholders' equity	$	421,598

	Three Months Ended September 30, 2018			Nine Months Ended September 30, 2018
	(In thousands)
Revenues and other income:
Oil and gas revenue	$	215,408		$	600,158
Other income	(72		)	44
Total revenues and other income	215,336			600,202
Costs and expenses:
Oil and gas production	40,334			115,366
Depletion, depreciation and amortization	33,044			108,996
Other expenses, net	(58		)	(211		)
Total costs and expenses	73,320			224,151
Income before income taxes	142,016			376,051
Income tax expense	50,796			134,047
Net income	$	91,220		$	242,004
Kosmos' share of net income	$	45,610		$	121,002
Basis difference amortization(1)	20,769			61,365
Equity in earnings - KTIPI	$	24,841		$	59,637

______________________________________

(1) The basis difference, which was associated with oil and gas properties and subject to amortization, has been allocated to the Ceiba Field and Okume Complex. We amortized the basis difference using the unit-of-production method.

With an effective date of January 1, 2019, our outstanding shares in KTIPI were transferred to Trident in exchange for a 40.375% undivided participating 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

XML

Acquisitions and Divestitures

9 Months Ended

Sep. 30, 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 customary governmental approvals. Upon approval, we will hold an 85% participating interest and will 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.

During the first quarter of 2019, Kosmos farmed-in to 18 BP-owned blocks in the Garden Banks area of the deepwater U.S. Gulf of Mexico. In addition, Kosmos can earn an interest in three BP blocks in other areas of the deepwater U.S. Gulf of Mexico. Kosmos is the designated operator.

During the first quarter of 2019, Kosmos executed a farm-in agreement with Chevron covering the right to earn an interest in a deepwater block in the U.S. Gulf of Mexico. Kosmos has been designated operator.

During the first quarter of 2019, Kosmos participated in the U.S. Gulf of Mexico Federal Lease Sale 252 and was awarded nine deepwater blocks. During the third quarter of 2019, Kosmos participated in the U.S. Gulf of Mexico Federal Lease Sale 253 and was awarded four deepwater blocks.

In March 2019, we completed an agreement to acquire Ophir's 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 May 2019, we entered into 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, subject to customary governmental approvals, resulting in our participating interests in Blocks 6 and 11 being 25% and 35%, respectively.

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.

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 and BP. We have a 35% participating interest in the blocks and the operator, BP, holds a 50% participating interest. The national petroleum agency, 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 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 future 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 August 2018, we closed a farm-out agreement with Trident, whereby they acquired a 40% participating interest in blocks EG-21, S, and W, offshore Equatorial Guinea, resulting in a $7.7 million gain. After giving effect to the farm-out agreement, we hold a 40% participating interest and are the operator in all three blocks. The Equatorial Guinean national oil company, GEPetrol, has a 20% carried participating interest during the exploration period. Should a commercial discovery be made, GEPetrol's 20% carried participating 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, which was completed in 2018.

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. The DGE acquisition was accounted for as an asset acquisition.

In October 2018, Kosmos entered into a strategic exploration alliance with 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. 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.

XML

Equity-based Compensation

9 Months Ended

Sep. 30, 2019

Share-based Payment Arrangement [Abstract]

Equity-based Compensation

Equity-based Compensation

Restricted Stock Units

We record equity-based compensation expense equal to the fair value of share-based payments over the vesting periods of the Long Term Incentive Plan (“LTIP”) awards. We recorded compensation expense from awards granted under our LTIP of $9.5 million and $8.9 million during the three months ended September 30, 2019 and 2018, respectively, and $27.4 million and $26.0 million during the nine months ended September 30, 2019 and 2018, respectively. The total tax benefit for the three months ended was $3.1 million and $1.6 million, respectively, and $5.9 million and $5.0 million during the nine months ended September 30, 2019 and 2018, respectively. Additionally, we recorded a net tax shortfall (windfall) related to equity-based compensation of nil and $0.1 million for the three months ended September 30, 2019 and 2018, respectively, and $1.2 million and $(0.3) million during the nine months ended September 30, 2019 and 2018, respectively. The fair value of awards vested during the three months ended September 30, 2019 and 2018 was approximately $0.7 million and $1.1 million, respectively, and $14.7 million and $83.1 million during the nine months ended September 30, 2019 and 2018, respectively. The Company granted restricted stock units with service vesting criteria and a combination of market and service vesting criteria under the LTIP. Substantially all these grants vest over three years. Upon vesting, restricted stock units become issued and outstanding stock.

The following table reflects the outstanding restricted stock units as of September 30, 2019:

			Weighted-		Market / Service		Weighted-
	Service Vesting		Average		Vesting		Average
	Restricted Stock		Grant-Date		Restricted Stock		Grant-Date
	Units		Fair Value		Units		Fair Value
	(In thousands)				(In thousands)
Outstanding at December 31, 2018	4,115		$	6.42	6,716		$	9.02
Granted(1)	3,096		4.96		3,160		6.02
Forfeited(1)	(134	)	6.11		(295	)	9.87
Vested	(1,999	)	5.92		(1,300	)	6.32
Outstanding at September 30, 2019	5,078		5.73		8,281		8.39

__________________________________

(1) The restricted stock units with a combination of market and service vesting criteria may vest between 0% and 200% of the originally granted units depending upon market performance conditions. Awards vesting over or under target shares of 100% results in additional shares granted or forfeited, respectively, in the period the market vesting criteria is determined.

As of September 30, 2019, total equity-based compensation to be recognized on unvested restricted stock units is $38.3 million over a weighted average period of 1.97 years. In March 2018, the board of directors approved an amendment to the LTIP to add 11.0 million shares to the plan, which was approved by our stockholders at the Annual General Meeting in June 2018. The LTIP provides for the issuance of 50.5 million shares pursuant to awards under the plan. At September 30, 2019, the Company had approximately 9.8 million shares that remain available for issuance under the LTIP.

For restricted stock units with a combination of market and service vesting criteria, the number of common shares to be issued is determined by comparing the Company’s total shareholder return with the total shareholder return of a predetermined group of peer companies over the performance period and can vest in up to 200% of the awards granted. The grant date fair value ranged from $4.83 to $12.96 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 and ranged from 0.8% to 2.5%.

XML

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Sep. 30, 2019	Dec. 31, 2018
Current assets:
Cash and cash equivalents	$ 203,646	$ 173,515
Restricted cash	7,745	4,527
Receivables:
Joint interest billings, net	54,409	64,572
Oil sales	54,612	48,164
Related party	0	5,580
Other	20,016	21,690
Inventories	140,218	84,827
Prepaid expenses and other	47,315	68,040
Derivatives	22,067	38,785
Total current assets	550,028	509,700
Property and equipment:
Oil and gas properties, net	3,780,989	3,444,864
Other property, net	18,047	14,837
Property and equipment, net	3,799,036	3,459,701
Other assets:
Equity method investment	0	51,896
Restricted cash	3,667	7,574
Long-term receivables	36,957	19,002
Deferred financing costs, net of accumulated amortization of $14,027 and $12,065 at September 30, 2019 and December 31, 2018, respectively	6,975	8,937
Deferred tax assets	37,838	14,004
Derivatives	10,535	14,312
Other	23,223	3,063
Total assets	4,468,259	4,088,189
Current liabilities:
Accounts payable	171,495	176,540
Accrued liabilities	292,419	195,596
Derivatives	8,461	12,172
Total current liabilities	472,375	384,308
Long-term liabilities:
Long-term debt, net	2,106,202	2,120,547
Derivatives	2,699	10,181
Asset retirement obligations	284,526	145,336
Deferred tax liabilities	678,808	477,179
Other long-term liabilities	32,619	9,160
Total long-term liabilities	3,104,854	2,762,403
Stockholders’ equity:
Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at September 30, 2019 and December 31, 2018	0	0
Common stock, $0.01 par value; 2,000,000,000 authorized shares; 445,757,319 and 442,914,675 issued at September 30, 2019 and December 31, 2018, respectively	4,458	4,429
Additional paid-in capital	2,310,776	2,341,249
Accumulated deficit	(1,187,197)	(1,167,193)
Treasury stock, at cost, 44,263,269 and 44,263,269 shares at September 30, 2019 and December 31, 2018, respectively	(237,007)	(237,007)
Total stockholders’ equity	891,030	941,478
Total liabilities and stockholders’ equity	$ 4,468,259	$ 4,088,189

XML

Property and Equipment (Tables)

9 Months Ended

Sep. 30, 2019

Property, Plant and Equipment [Abstract]

Schedule of property and equipment

Property and equipment is stated at cost and consisted of the following:

	September 30, 2019			December 31, 2018
	(In thousands)
Oil and gas properties:
Proved properties	$	4,827,304		$	4,236,489
Unproved properties	898,855			759,472
Total oil and gas properties	5,726,159			4,995,961
Accumulated depletion	(1,945,170		)	(1,551,097		)
Oil and gas properties, net	3,780,989			3,444,864
Other property	59,515			51,987
Accumulated depreciation	(41,468		)	(37,150		)
Other property, net	18,047			14,837
Property and equipment, net	$	3,799,036		$	3,459,701

XML

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (Parenthetical) - $ / shares	3 Months Ended				9 Months Ended
	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Statement of Stockholders' Equity [Abstract]
Dividends declared per common stock (in dollars per share)	$ 0.0452	$ 0.0452	$ 0.0452	$ 0	$ 0.1356	$ 0

XML

Additional Financial Information

9 Months Ended

Sep. 30, 2019

Additional Financial Information

Additional Financial Information

Additional Financial Information

Accrued Liabilities

Accrued liabilities consisted of the following:

	September 30, 2019		December 31, 2018
	(In thousands)
Accrued liabilities:
Exploration, development and production	$	114,833	$	92,613
Revenue payable	33,721		24,379
Current asset retirement obligations	5,844		6,617
Operating leases	1,294		—
General and administrative expenses	31,913		39,373
Interest	27,913		18,152
Income taxes	69,938		8,958
Taxes other than income	2,060		4,613
Derivatives	2,975		441
Other	1,928		450
	$	292,419	$	195,596

Asset Retirement Obligations

The following table summarizes the changes in the Company's asset retirement obligations:

	September 30, 2019
	(In thousands)
Asset retirement obligations:
Beginning asset retirement obligations	$	151,953
Additions associated with Equatorial Guinea - Ceiba Field and Okume Complex	114,395
Liabilities incurred during period	9,706
Liabilities settled during period	(4,384		)
Revisions in estimated retirement obligations	905
Accretion expense	17,795
Ending asset retirement obligations	$	290,370

With an effective date 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 going forward is accounted for under the proportionate consolidation method of accounting, which includes additions to our asset retirement obligations.

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 related insurance reimbursements. During the three months ended September 30, 2019 and 2018, we incurred approximately $12.6 million and $12.3 million, respectively in expenditures with no offsetting insurance recoveries. During the nine months ended September 30, 2019 and 2018, we incurred approximately $34.8 million and $31.5 million, respectively in expenditures offset by approximately $40.0 million and $9.7 million, respectively in insurance recoveries.

Other Expenses, Net

Other expenses, net incurred during the period is comprised of the following:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019		2018
	(In thousands)
(Gain) loss on disposal of inventory	$	1,232		$	(2	)	$	1,419	$	(26	)
(Gain) loss on ARO liability settlements	(746		)	—			1,167		—
Disputed charges and related costs, net of recoveries	1,677			(12,682		)	1,663		(9,721		)
Other, net	9,309			(123		)	7,549		1,583
Other expenses, net	$	11,472		$	(12,807	)	$	11,798	$	(8,164	)

The disputed charges and related costs, net of recoveries arise from the final award issued by the International Chamber of Commerce ("ICC") in favor of Kosmos in its arbitration against Tullow Ghana Limited, related to expenditures arising from Tullow's contract with Seadrill for use of the West Leo drilling rig. Other, net is primarily related to an $8.7 million indirect tax settlement with tax authorities in Senegal.

XML

Income Taxes (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Income Taxes
Effective tax rate (as a percent)	59.00%	10.00%	173.00%	17.00%
Income (loss) before income taxes	$ 39,535	$ (114,693)	$ 27,394	$ (337,885)
Uncertain tax positions	0		0
United States
Income Taxes
Income (loss) before income taxes	3,464	(53,136)	(70,776)	(49,967)
Bermuda
Income Taxes
Income (loss) before income taxes	0	(15,513)	$ 0	(47,474)
Foreign—other
Income Taxes
Effective tax rate (as a percent)			0.00%
Statutory tax rate (as a percent)			0.00%
Income (loss) before income taxes	$ 36,071	$ (46,044)	$ 98,170	$ (240,444)

XML

Derivative Financial Instruments - Schedule of derivative instruments by location of gain/(loss) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Derivative instruments, Location of Gain/(Loss)
Amount of Gain/(Loss)	$ 31,683	$ (54,267)	$ (34,003)	$ (232,057)
Commodity | Oil and gas revenue
Derivative instruments, Location of Gain/(Loss)
Amount of Gain/(Loss)	4,667	3,075	1,881	3,584
Commodity | Derivatives, net
Derivative instruments, Location of Gain/(Loss)
Amount of Gain/(Loss)	27,016	(57,357)	(35,884)	(236,107)
Interest rate | Interest expense
Derivative instruments, Location of Gain/(Loss)
Amount of Gain/(Loss)	$ 0	$ 15	$ 0	$ 466

XML

Additional Financial Information (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2018
Accrued liabilities:
Exploration, development and production	$ 114,833		$ 114,833		$ 92,613
Revenue payable	33,721		33,721		24,379
Current asset retirement obligations	5,844		5,844		6,617
Operating leases	1,294		1,294
General and administrative expenses	31,913		31,913		39,373
Interest	27,913		27,913		18,152
Income taxes	69,938		69,938		8,958
Taxes other than income	2,060		2,060		4,613
Derivatives	2,975		2,975		441
Other	1,928		1,928		450
Accrued liabilities	292,419		292,419		$ 195,596
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning asset retirement obligations	290,370		290,370
Additions associated with Equatorial Guinea - Ceiba Field and Okume Complex			114,395
Liabilities incurred during period			9,706
Liabilities settled during period			(4,384)
Revisions in estimated retirement obligations			905
Accretion expense			17,795
Ending asset retirement obligations			151,953
Facilities insurance modifications, expenditures	12,600	$ 12,300	34,800	$ 31,500
Facilities insurance modifications, insurance recoveries			40,000	9,700
Other Expenses, Net
(Gain) loss on disposal of inventory	1,232	(2)	1,419	(26)
(Gain) loss on ARO liability settlements	(746)	0	1,167	0
Disputed charges and related costs, net of recoveries	1,677	(12,682)	1,663	(9,721)
Other, net	9,309	(123)	7,549	1,583
Other expenses, net	$ 11,472	(12,807)	$ 11,798	$ (8,164)
Payment of tax settlements		$ 8,700

XML

Acquisitions and Divestitures (Details) $ in Thousands	1 Months Ended								3 Months Ended			9 Months Ended
	Sep. 30, 2019 km² meter	May 31, 2019	Mar. 31, 2019 km²	Oct. 31, 2018 company	Sep. 30, 2018 USD ($)	Aug. 31, 2018 USD ($) km² sub_period block	Jun. 30, 2018 km²	Mar. 31, 2018 km² block	Sep. 30, 2019 USD ($) km² meter block	Mar. 31, 2019 km² sub_period block	Sep. 30, 2018 USD ($)	Sep. 30, 2019 USD ($) km² meter	Sep. 30, 2018 USD ($)
Acquisitions and Divestitures
Gain on sale of assets | $									$ 0		$ 7,666	$ 0	$ 7,666
Number of companies in alliance | company				2
Deep Gulf Energy, LP
Acquisitions and Divestitures
Total purchase price | $					$ 1,275,000
Cash consideration | $					952,600
Transaction related costs | $					14,900
Deep Gulf Energy, LP | Common Shares
Acquisitions and Divestitures
Equity consideration | $					$ 307,900
Marine XXI Block | Petroleum Agreement
Acquisitions and Divestitures
Participating interests										85.00%
Area of petroleum exploration			2,350							2,350
Exploration period										4 years
3D seismic requirements										2,200
Number of sub-periods | sub_period										2
First sub exploration period										3 years
Marine XXI Block | Petroleum Agreement | SNPC
Acquisitions and Divestitures
Carried participating interest percentage			15.00%							15.00%
Percentage converted from carried to participating			15.00%							15.00%
U.S. Gulf Of Mexico Garden Banks Blocks | Farm-in agreement
Acquisitions and Divestitures
Number of blocks | block										18
U.S. Gulf Of Mexico Blocks | Farm-in agreement
Acquisitions and Divestitures
Number of blocks | block										3
U.S. Gulf Of Mexico Lease Sale 252 Blocks
Acquisitions and Divestitures
Number of blocks | block										9
U.S. Gulf Of Mexico Lease Sale 253 Blocks
Acquisitions and Divestitures
Number of blocks | block									4
Northern Cape Ultra Deep Block | Farm-in agreement
Acquisitions and Divestitures
Area of petroleum exploration	6,930								6,930			6,930
Exploration period	2 years
Participation interest acquired	45.00%
Northern Cape Ultra Deep Block | Farm-in agreement | Minimum
Acquisitions and Divestitures
Water depths | meter	2,500								2,500			2,500
Northern Cape Ultra Deep Block | Farm-in agreement | Maximum
Acquisitions and Divestitures
Water depths | meter	3,100								3,100			3,100
Block 6
Acquisitions and Divestitures
Participating interests												25.00%
Block 6 | Farm out agreement | Shell Sao Tome and Principe B.V.
Acquisitions and Divestitures
Participation interest acquired		20.00%
Block 11
Acquisitions and Divestitures
Participating interests												35.00%
Block 11 | Farm out agreement | Shell Sao Tome and Principe B.V.
Acquisitions and Divestitures
Participating interests		30.00%
Blocks 10 and 13 | Petroleum Agreement
Acquisitions and Divestitures
Participating interests								35.00%
Area of petroleum exploration								13,600
Exploration period								4 years
3D seismic requirements								13,500
First sub exploration period								4 years
Number of blocks | block								2
Blocks 10 and 13 | Petroleum Agreement | BP
Acquisitions and Divestitures
Participating interests								50.00%
Blocks 10 and 13 | Petroleum Agreement | ANP STP
Acquisitions and Divestitures
Carried participating interest percentage								15.00%
Block EG-24 | Farm-in agreement
Acquisitions and Divestitures
Area of petroleum exploration							3,500
Exploration period							3 years
3D seismic requirements							3,000
First sub exploration period							4 years
Participation interest acquired			80.00%				40.00%
Block EG-24 | Farm-in agreement | GEPetrol
Acquisitions and Divestitures
Carried participating interest percentage			20.00%							20.00%
Percentage converted from carried to participating			20.00%							20.00%
Blocks EG-21, S and W | Petroleum Agreement
Acquisitions and Divestitures
Area of petroleum exploration						6,000
Exploration period						5 years
3D seismic requirements						6,000
Number of sub-periods | sub_period						2
First sub exploration period						3 years
Number of blocks | block						3
Second sub exploration period						2 years
Blocks EG-21, S and W | Petroleum Agreement | GEPetrol
Acquisitions and Divestitures
Carried participating interest percentage						20.00%
Percentage converted from carried to participating						20.00%
Blocks EG-21, S and W | Farm out agreement
Acquisitions and Divestitures
Participating interests						40.00%
Gain on sale of assets | $						$ 7,700
Blocks EG-21, S and W | Farm out agreement | Trident
Acquisitions and Divestitures
Participation interest acquired						40.00%

XML

Suspended Well Costs - Narrative (Details)	May 31, 2015 project
Greater Tortue Discovery
Capitalized Contract Cost [Line Items]
Number of additional appraisal wells drilled	3

XML

Derivative Financial Instruments - Narrative (Details) - Dated Brent	1 Months Ended	9 Months Ended
	Oct. 31, 2019 $ / bbl MBbls	Sep. 30, 2019 $ / bbl MBbls
Put Option | Term January 2020 To December 2020
Derivative Financial Instruments
Volume (mbbls) | MBbls		2,000
Floor (usd per bbl)		60.00
Sold Put (usd per bbl)		50.00
Ceiling (usd per bbl)		0
Sold calls | Term January 2020 To December 2020
Derivative Financial Instruments
Volume (mbbls) | MBbls		8,000
Floor (usd per bbl)		0
Sold Put (usd per bbl)		0
Ceiling (usd per bbl)		85.00
Sold calls | Term January 2021 To December 2021
Derivative Financial Instruments
Volume (mbbls) | MBbls		1,000
Floor (usd per bbl)		0
Sold Put (usd per bbl)		0
Ceiling (usd per bbl)		75.00
Subsequent Event | Put Option | Term January 2020 To December 2020
Derivative Financial Instruments
Volume (mbbls) | MBbls	2,000.0
Floor (usd per bbl)	57.50
Sold Put (usd per bbl)	50.00
Subsequent Event | Sold calls | Term January 2021 To December 2021
Derivative Financial Instruments
Volume (mbbls) | MBbls	3,000.0
Ceiling (usd per bbl)	71.67

XML

Debt - 7.125% Senior Notes due 2026 (Details) - Senior Notes - 7.125% Senior Notes due 2026	1 Months Ended
	Apr. 30, 2019 USD ($)
Debt Instrument [Line Items]
Interest rate	7.125%
Senior notes offering face amount	$ 650,000,000.0
Net proceeds from debt	$ 640,000,000.0
Redemption price percentage following change of control	101.00%
Redemption price percentage following sell of certain assets	100.00%
Any time prior to April 4, 2022
Debt Instrument [Line Items]
Maximum percentage of principal amount available to be redeemed with proceeds from equity offerings	40.00%
Debt Instrument Redemption Price Percentage With Proceeds From Equity Offerings	107.10%
Any time prior to April 4, 2022 with make-whole premium
Debt Instrument [Line Items]
Redemption price, as percent of the principal amount	100.00%
On or after April 4, 2022, but before April 4, 2023
Debt Instrument [Line Items]
Redemption price, as percent of the principal amount	103.60%
On or after April 4, 2023, but before April 4, 2024
Debt Instrument [Line Items]
Redemption price, as percent of the principal amount	101.80%
On or after April 4, 2024 and thereafter
Debt Instrument [Line Items]
Redemption price, as percent of the principal amount	100.00%

XML

Debt - Facility (Details) - USD ($)	1 Months Ended		3 Months Ended		9 Months Ended
	Apr. 30, 2019	Feb. 28, 2018	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018	Mar. 31, 2019
Debt Instrument [Line Items]
Loss on extinguishment of debt			$ 0	$ 268,000	$ 24,794,000	$ 4,324,000
The Facility | Revolving Credit Facility
Debt Instrument [Line Items]
Total commitment	$ 1,600,000,000	$ 1,500,000,000					$ 1,700,000,000
Additional commitments		500,000,000
Loss on extinguishment of debt		$ 4,100,000
Net deferred financing costs			34,400,000		34,400,000
Undrawn availability			100,000,000.0		100,000,000.0
Commitment reduction	$ 100,000,000.0
Availability period of revolving-credit		1 month
Amount outstanding under letters of credit			$ 0		$ 0

XML

Derivative Financial Instruments

9 Months Ended

Sep. 30, 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 September 30, 2019. Volumes and weighted average prices are net of any offsetting derivative contracts entered into.

				Weighted Average Price per Bbl
				Net Deferred
				Premium
Term	Type of Contract	Index	MBbl	Payable/(Receivable)		Swap		Sold Put		Floor		Ceiling
2019:
Oct — Dec	Three-way collars	Dated Brent	2,628	$	1.17	$	—	$	43.81	$	53.33	$	73.57
Oct — Dec	Sold calls(1)	Dated Brent	230	—		—		—		—		80.00
Oct — Dec	Swaps	NYMEX WTI	265	—		51.61		—		—		—
Oct — Dec	Collars	Argus LLS	250	—		—		—		60.00		88.75
2020:
Jan — Dec	Three-way collars	Dated Brent	6,000	$	0.45	$	—	$	45.00	$	57.50	$	80.18
Jan — Dec	Swaps with sold puts	Dated Brent	2,000	—		60.53		48.75		—		—
Jan — Dec	Put spread	Dated Brent	2,000	2.59		—		50.00		60.00		—
Jan — Dec	Sold calls(1)(2)	Dated Brent	8,000	1.17		—		—		—		85.00
2021:
Jan — Dec	Sold calls(1)	Dated Brent	1,000	$	—	$	—	$	—	$	—	$	75.00

__________________________________

(1) Represents call option contracts sold to counterparties to enhance other derivative positions.

(2) Deferred premium payable to be paid October 1, 2019 — December 31, 2019.

In October 2019, we entered into put option contracts for 2.0 MMBbls from January 2020 through December 2020 with a floor price of $57.50 per barrel and a sold put price of $50.00 per barrel. In addition, we sold 3.0 MMBbl of calls from January 2021 through December 2021 with an average strike price of $71.67 per barrel. The contracts are indexed to Dated Brent prices.

The following tables disclose the Company’s derivative instruments as of September 30, 2019 and December 31, 2018, and gain/(loss) from derivatives during the three and nine months ended September 30, 2019 and 2018, respectively:

		Estimated Fair Value
		Asset (Liability)
Type of Contract	Balance Sheet Location	September 30, 2019			December 31, 2018
		(In thousands)
Derivatives not designated as hedging instruments:
Derivative assets:
Commodity(1)	Derivatives assets—current	$	22,067		$	38,785
Commodity(2)	Derivatives assets—long-term	10,535			14,312
Derivative liabilities:
Commodity(3)	Derivatives liabilities—current	(8,461		)	(12,172		)
Commodity(4)	Derivatives liabilities—long-term	(2,699		)	(10,181		)
Total derivatives not designated as hedging instruments		$	21,442		$	30,744

__________________________________

(1) Includes zero and $0.4 million as of September 30, 2019 and December 31, 2018, respectively which represents our provisional oil sales contract. Also, includes net deferred premiums payable of $4.1 million and $1.6 million related to commodity derivative contracts as of September 30, 2019 and December 31, 2018, respectively.

(2) Includes net deferred premiums payable of $2.6 million and $1.3 million related to commodity derivative contracts as of September 30, 2019 and December 31, 2018, respectively.

(3) Includes net deferred premiums payable of $6.5 million and $18.0 million related to commodity derivative contracts as of September 30, 2019 and December 31, 2018, respectively.

(4) Includes net deferred premiums payable of zero and $0.5 million related to commodity derivative contracts as of September 30, 2019 and December 31, 2018, respectively.

		Amount of Gain/(Loss)					Amount of Gain/(Loss)
		Three Months Ended					Nine Months Ended
		September 30,					September 30,
Type of Contract	Location of Gain/(Loss)	2019		2018			2019			2018
		(In thousands)
Derivatives not designated as hedging instruments:
Commodity(1)	Oil and gas revenue	$	4,667	$	3,075		$	1,881		$	3,584
Commodity	Derivatives, net	27,016		(57,357		)	(35,884		)	(236,107		)
Interest rate	Interest expense	—		15			—			466
Total derivatives not designated as hedging instruments		$	31,683	$	(54,267	)	$	(34,003	)	$	(232,057	)

__________________________________

(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 September 30, 2019 and December 31, 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.

XML

Property and Equipment

9 Months Ended

Sep. 30, 2019

Property, Plant and Equipment [Abstract]

Property and Equipment

Property and Equipment

Property and equipment is stated at cost and consisted of the following:

	September 30, 2019			December 31, 2018
	(In thousands)
Oil and gas properties:
Proved properties	$	4,827,304		$	4,236,489
Unproved properties	898,855			759,472
Total oil and gas properties	5,726,159			4,995,961
Accumulated depletion	(1,945,170		)	(1,551,097		)
Oil and gas properties, net	3,780,989			3,444,864
Other property	59,515			51,987
Accumulated depreciation	(41,468		)	(37,150		)
Other property, net	18,047			14,837
Property and equipment, net	$	3,799,036		$	3,459,701

We recorded depletion expense of $139.1 million and $76.8 million for the three months ended September 30, 2019 and 2018, respectively, and $394.1 million and $199.7 million for the nine months ended September 30, 2019 and 2018, 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.

XML

Debt (Tables)

9 Months Ended

Sep. 30, 2019

Debt Disclosure [Abstract]

Schedule of debt

	September 30, 2019			December 31, 2018
	(In thousands)
Outstanding debt principal balances:
Facility	$	1,500,000		$	1,325,000
Corporate Revolver	—			325,000
Senior Notes	650,000			—
Senior Secured Notes	—			525,000
Total	2,150,000			2,175,000
Unamortized deferred financing costs and discounts(1)	(43,798		)	(54,453		)
Long-term debt, net	$	2,106,202		$	2,120,547

__________________________________

(1)

Includes $34.4 million and $40.5 million of unamortized deferred financing costs related to the Facility as of September 30, 2019 and December 31, 2018, respectively; $9.4 million of unamortized deferred financing costs and discounts related to the Senior Notes as of September 30, 2019; and $14.0 million of unamortized deferred financing costs and discounts related to the Senior Secured Notes as of December 31, 2018, respectively.

Schedule of redemption prices (expressed as percentages of principal amount) of all or a part of the Senior Notes

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	%

Schedule of estimated repayments of debt

At September 30, 2019, the estimated repayments of debt during the five fiscal year periods and thereafter are as follows:

	Payments Due by Year
	Total		2019(2)		2020		2021		2022		2023		Thereafter
	(In thousands)
Principal debt repayments(1)	$	2,150,000	$	—	$	—	$	274,800	$	284,200	$	271,600	$	1,319,400

__________________________________

(1) Includes the scheduled principal 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 September 30, 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.

(2)

Represents payments for the period October 1, 2019 through December 31, 2019.

Schedule of interest and other financing costs, net

Interest and other financing costs, net incurred during the periods is comprised of the following:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
	(In thousands)
Interest expense	$	34,944		$	27,317		$	111,566		$	77,121
Amortization—deferred financing costs	2,285			2,346			6,974			7,069
Loss on extinguishment of debt	—			268			24,794			4,324
Capitalized interest	(7,077		)	(7,097		)	(21,330		)	(21,209		)
Deferred interest	290			(194		)	1,559			(1,284		)
Interest income	(972		)	(788		)	(2,215		)	(2,579		)
Other, net	1,251			1,697			4,217			4,671
Interest and other financing costs, net	$	30,721		$	23,549		$	125,565		$	68,113

XML

Income Taxes (Tables)

9 Months Ended

Sep. 30, 2019

Income Tax Disclosure [Abstract]

Schedule of components of income (loss) before income taxes

Income (loss) before income taxes is composed of the following:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2019		2018			2019			2018
	(In thousands)
United States	$	3,464	$	(53,136	)	$	(70,776	)	$	(49,967	)
Bermuda	—		(15,513		)	—			(47,474		)
Foreign—other	36,071		(46,044		)	98,170			(240,444		)
Income (loss) before income taxes	$	39,535	$	(114,693	)	$	27,394		$	(337,885	)

XML

Business Segment Information (Tables)

9 Months Ended

Sep. 30, 2019

Segment Reporting [Abstract]

Schedule of business segment information

Financial information for each area is presented below:

	Ghana			Equatorial Guinea		Mauritania/Senegal			U.S. Gulf of Mexico			Corporate & Other			Eliminations			Total
	(In thousands)
Three months ended September 30, 2019
Revenues and other income:
Oil and gas revenue	$	177,797		$	55,378	$	—		$	123,861		$	—		$	—		$	357,036
Other income, net	1			—		—			200			5,706			(5,973		)	(66		)
Total revenues and other income	177,798			55,378		—			124,061			5,706			(5,973		)	356,970
Costs and expenses:
Oil and gas production	42,017			21,369		—			32,154			—			—			95,540
Facilities insurance modifications, net	12,569			—		—			—			—			—			12,569
Exploration expenses	82			2,437		1,260			10,625			8,369			—			22,773
General and administrative	3,886			1,719		2,678			7,002			38,897			(29,459		)	24,723
Depletion, depreciation and amortization	73,347			16,019		15			56,359			913			—			146,653
Interest and other financing costs, net(1)	16,821			—		(6,703		)	5,083			17,304			(1,784		)	30,721
Derivatives, net	—			—		—			(1,745		)	(25,271		)	—			(27,016		)
Other expenses, net	(25,357		)	615		9,141			550			1,253			25,270			11,472
Total costs and expenses	123,365			42,159		6,391			110,028			41,465			(5,973		)	317,435
Income (loss) before income taxes	54,433			13,219		(6,391		)	14,033			(35,759		)	—			39,535
Income tax expense (benefit)	10,585			6,110		—			2,942			3,833			—			23,470
Net income (loss)	$	43,848		$	7,109	$	(6,391	)	$	11,091		$	(39,592	)	$	—		$	16,065
Consolidated capital expenditures	$	28,398		$	15,397	$	842		$	49,629		$	13,127		$	—		$	107,393

	Ghana			Equatorial Guinea			Mauritania/Senegal			U.S. Gulf of Mexico			Corporate & Other			Eliminations			Total
	(In thousands)
Nine months ended September 30, 2019
Revenues and other income:
Oil and gas revenue	$	502,800		$	208,667		$	—		$	338,292		$	—		$	—		$	1,049,759
Other income, net	2			—			—			459			97,594			(98,120		)	(65		)
Total revenues and other income	502,802			208,667			—			338,751			97,594			(98,120		)	1,049,694
Costs and expenses:													—
Oil and gas production	117,027			60,645			—			88,644			—			—			266,316
Facilities insurance modifications, net	(5,174		)	—			—			—			—			—			(5,174		)
Exploration expenses	189			8,080			9,745			32,834			32,174			—			83,022
General and administrative	15,844			5,303			6,505			19,288			127,416			(85,653		)	88,703
Depletion, depreciation and amortization	204,108			55,323			46			153,768			2,941			—			416,186
Interest and other financing costs, net(1)	56,500			—			(20,020		)	16,654			77,782			(5,351		)	125,565
Derivatives, net	—			—			—			28,768			7,116			—			35,884
Other expenses, net	6,761			(1,629		)	9,783			2,695			1,304			(7,116		)	11,798
Total costs and expenses	395,255			127,722			6,059			342,651			248,733			(98,120		)	1,022,300
Income (loss) before income taxes	107,547			80,945			(6,059		)	(3,900		)	(151,139		)	—			27,394
Income tax expense (benefit)	30,285			33,403			—			(824		)	(15,466		)	—			47,398
Net income (loss)	$	77,262		$	47,542		$	(6,059	)	$	(3,076	)	$	(135,673	)	$	—		$	(20,004	)
Consolidated capital expenditures	$	96,861		$	36,448		$	7,132		$	136,688		$	41,177		$	—		$	318,306
As of September 30, 2019
Property and equipment, net	$	1,603,170		$	460,044		$	428,596		$	1,263,945		$	43,281		$	—		$	3,799,036
Total assets	$	1,844,328		$	489,564		$	568,743		$	3,309,044		$	12,078,321		$	(13,821,741	)	$	4,468,259

______________________________________

(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)
Three months ended September 30, 2018
Revenues and other income:
Oil and gas revenue	$	218,656		$	107,704		$	—		$	24,177		$	—		$	(107,704	)	$	242,833
Gain on sale of assets	—			7,666			—			—			—			—			7,666
Other income, net	—			(317		)	—			—			78,166			(78,129		)	(280		)
Total revenues and other income	218,656			115,053			—			24,177			78,166			(185,833		)	250,219
Costs and expenses:
Oil and gas production	49,280			20,167			—			4,467			1,331			(20,167		)	55,078
Facilities insurance modifications, net	12,334			—			—			—			—			—			12,334
Exploration expenses	57,818			16,584			1,203			50,176			22,457			—			148,238
General and administrative	5,786			1,761			1,396			4,026			42,072			(29,078		)	25,963
Depletion, depreciation and amortization	70,799			37,291			15			8,190			1,037			(37,291		)	80,041
Interest and other financing costs, net(4)	21,989			(4		)	(6,441		)	2,085			7,704			(1,784		)	23,549
Derivatives, net	—			—			—			10,082			47,275			—			57,357
(Gain) loss on equity method investments, net	—			—			—			—			—			(24,841		)	(24,841		)
Other expenses, net	34,610			(976		)	(13		)	—			846			(47,274		)	(12,807		)
Total costs and expenses	252,616			74,823			(3,840		)	79,026			122,722			(160,435		)	364,912
Income (loss) before income taxes	(33,960		)	40,230			3,840			(54,849		)	(44,556		)	(25,398		)	(114,693		)
Income tax expense (benefit)	21,862			25,398			—			(12,324		)	1,826			(25,398		)	11,364
Net income (loss)	$	(55,822	)	$	14,832		$	3,840		$	(42,525	)	$	(46,382	)	$	—		$	(126,057	)
Consolidated capital expenditures	$	32,501		$	2,913		$	3,319		$	52,488		$	17,970		$	—		$	109,191

	Ghana			Equatorial Guinea(1)			Mauritania/Senegal			U.S. Gulf of Mexico(2)			Corporate & Other			Eliminations(3)			Total
	(In thousands)
Nine months ended September 30, 2018
Revenues and other income:
Oil and gas revenue	$	561,043		$	300,079		$	—		$	24,177		$	—		$	(300,079	)	$	585,220
Gain on sale of assets	—			7,666			—			—			—			—			7,666
Other income, net	(17		)	22			—			—			315,771			(315,793		)	(17		)
Total revenues and other income	561,026			307,767			—			24,177			315,771			(615,872		)	592,869
Costs and expenses:
Oil and gas production	143,860			57,683			—			4,467			3,334			(57,683		)	151,661
Facilities insurance modifications, net	21,812			—			—			—			—			—			21,812
Exploration expenses	58,076			33,665			6,603			50,176			98,392			—			246,912
General and administrative	15,651			3,768			3,628			4,026			122,558			(84,288		)	65,343
Depletion, depreciation and amortization	197,260			115,862			46			8,190			3,111			(115,862		)	208,607
Interest and other financing costs, net(4)	65,357			(9		)	(18,704		)	2,085			24,735			(5,351		)	68,113
Derivatives, net	—			—			—			10,082			226,025			—			236,107
(Gain) loss on equity method investments, net	—			—			—			—			—			(59,637		)	(59,637		)
Other expenses, net	216,319			(1,138		)	(13		)	—			2,695			(226,027		)	(8,164		)
Total costs and expenses	718,335			209,831			(8,440		)	79,026			480,850			(548,848		)	930,754
Income (loss) before income taxes	(157,309		)	97,936			8,440			(54,849		)	(165,079		)	(67,024		)	(337,885		)
Income tax expense (benefit)	(49,148		)	67,024			—			(12,324		)	3,143			(67,024		)	(58,329		)
Net income (loss)	$	(108,161	)	$	30,912		$	8,440		$	(42,525	)	$	(168,222	)	$	—		$	(279,556	)
Consolidated capital expenditures	$	71,330		$	27,891		$	9,633		$	52,488		$	102,651		$	—		$	263,993
As of September 30, 2018
Property and equipment, net	$	1,727,595		$	3,801		$	403,111		$	1,340,479		$	34,551		$	—		$	3,509,537
Total assets	$	2,073,825		$	145,823		$	465,352		$	3,473,501		$	10,660,832		$	(12,489,869	)	$	4,329,464

______________________________________

(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 three and nine months ended September 30, 2018, except for capital expenditures. See Note 7 - Equity Method Investments for additional information regarding our equity method investments.

(2) No activity prior to 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.

	Nine Months Ended September 30,
	2019			2018
	(In thousands)
Consolidated capital expenditures:
Consolidated Statements of Cash Flows - Investing activities:
Oil and gas assets	$	240,642		$	149,305
Other property	8,291			3,560
Adjustments:
Changes in capital accruals	11,083			13,965
Exploration expense, excluding unsuccessful well costs(1)	75,661			131,964
Capitalized interest	(21,330		)	(21,209		)
Proceeds on sale of assets	—			(13,703		)
Other	3,959			111
Total consolidated capital expenditures	$	318,306		$	263,993

______________________________________

(1)

Unsuccessful well costs are included in oil and gas assets when incurred.

XML

Equity Method Investments (Tables)

9 Months Ended

Sep. 30, 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 stockholders' equity
Total current liabilities	$	226,311
Total long-term liabilities	536,178
Shareholders' equity:
Total shareholders' equity	(340,891		)
Total liabilities and shareholders' equity	$	421,598

	Three Months Ended September 30, 2018			Nine Months Ended September 30, 2018
	(In thousands)
Revenues and other income:
Oil and gas revenue	$	215,408		$	600,158
Other income	(72		)	44
Total revenues and other income	215,336			600,202
Costs and expenses:
Oil and gas production	40,334			115,366
Depletion, depreciation and amortization	33,044			108,996
Other expenses, net	(58		)	(211		)
Total costs and expenses	73,320			224,151
Income before income taxes	142,016			376,051
Income tax expense	50,796			134,047
Net income	$	91,220		$	242,004
Kosmos' share of net income	$	45,610		$	121,002
Basis difference amortization(1)	20,769			61,365
Equity in earnings - KTIPI	$	24,841		$	59,637

______________________________________

(1)

The basis difference, which was associated with oil and gas properties and subject to amortization, has been allocated to the Ceiba Field and Okume Complex. We amortized the basis difference using the unit-of-production method.

Schedule of asset acquisition

	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

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018
Statement of Cash Flows [Abstract]
Cash settlements on derivatives, net (commodity hedges)	$ (27.0)	$ (107.3)

XML

Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2019

Accounting Policies [Abstract]

General

General

The interim consolidated financial statements included in this report are unaudited and, in the opinion of management, include all adjustments of a normal recurring nature necessary for a fair presentation of the results for the interim periods. The results of the interim periods shown in this report are not necessarily indicative of the final results to be expected for the full year. The consolidated financial statements were prepared in accordance with the requirements of the Securities and Exchange Commission (“SEC”) for interim reporting. As permitted under those rules, certain notes or other financial information that are normally required by Generally Accepted Accounting Principles in the United States of America (“GAAP”) have been condensed or omitted from these interim consolidated financial statements. These consolidated financial statements and the accompanying notes should be read in conjunction with our audited consolidated financial statements for the year ended December 31, 2018, included in our annual report on Form 10-K.

Reclassifications

Reclassifications

Certain prior period amounts have been reclassified to conform with the current presentation. Such reclassifications had no significant impact on our reported net income (loss), current assets, total assets, current liabilities, total liabilities, stockholders’ equity or cash flows. Additionally, as a result of our outstanding shares in KTIPI being transferred for an undivided interest in the Ceiba Field and Okume Complex (effective January 1, 2019), our previously reported equity method investment in KTIPI has been allocated to the respective assets and liabilities on a relative fair value basis. See Note 7 — Equity Method Investments for additional information. 

Cash, Cash Equivalents and Restricted Cash

Cash and cash equivalents include 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 respective 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.

Cash, Cash Equivalents and Restricted Cash

Inventories

Inventories

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.

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.

Revenue Recognition

Revenue Recognition

We recognize revenues on the volumes 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.

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.

Concentration of Credit Risk

Concentration of Credit Risk

Our revenue can be materially affected by current economic conditions and the price of oil. However, based on the current demand for crude oil and the fact that alternative purchasers are readily available, we believe that the loss of our marketing agent and/or any of the purchasers identified by our marketing agent would not have a long‑term material adverse effect on our financial position or results of international operations. For our U.S. Gulf of Mexico operations, crude oil and natural gas are transported to customers using third-party pipelines.

Recent Accounting Standards

Recent Accounting Standards

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 are evaluating its potential impact.

XML

Net Income (Loss) Per Share

9 Months Ended

Sep. 30, 2019

Earnings Per Share [Abstract]

Net Income (Loss) Per Share

Net Income (Loss) Per Share

The following table is a 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:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2019		2018			2019			2018
	(In thousands, except per share data)
Numerator:
Net income (loss) allocable to common stockholders	$	16,065	$	(126,057	)	$	(20,004	)	$	(279,556	)
Denominator:
Weighted average number of shares outstanding:
Basic	401,466		404,536			401,319			399,026
Restricted stock units(1)	9,526		—			—			—
Diluted	410,992		404,536			401,319			399,026
Net income (loss) per share:
Basic	$	0.04	$	(0.31	)	$	(0.05	)	$	(0.70	)
Diluted	$	0.04	$	(0.31	)	$	(0.05	)	$	(0.70	)

__________________________________

(1)

We excluded outstanding restricted stock awards and units of 0.7 million and 13.1 million for the three months ended September 30, 2019 and 2018, respectively, and 15.4 million and 14.5 million for the nine months ended September 30, 2019 and 2018, respectively, from the computations of diluted net income (loss) per share because the effect would have been anti-dilutive.

XML

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	3 Months Ended						9 Months Ended
	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Sep. 30, 2019	Sep. 30, 2018
Revenues and other income:
Oil and gas revenue	$ 357,036			$ 242,833			$ 1,049,759	$ 585,220
Gain on sale of assets	0			7,666			0	7,666
Other income, net	(66)			(280)			(65)	(17)
Total revenues and other income	356,970			250,219			1,049,694	592,869
Costs and expenses:
Oil and gas production	95,540			55,078			266,316	151,661
Facilities insurance modifications, net	12,569			12,334			(5,174)	21,812
Exploration expenses	22,773			148,238			83,022	246,912
General and administrative	24,723			25,963			88,703	65,343
Depletion, depreciation and amortization	146,653			80,041			416,186	208,607
Interest and other financing costs, net	30,721			23,549			125,565	68,113
Derivatives, net	(27,016)			57,357			35,884	236,107
Gain on equity method investments, net	0			(24,841)			0	(59,637)
Other expenses, net	11,472			(12,807)			11,798	(8,164)
Total costs and expenses	317,435			364,912			1,022,300	930,754
Income (loss) before income taxes	39,535			(114,693)			27,394	(337,885)
Income tax expense (benefit)	23,470			11,364			47,398	(58,329)
Net income (loss)	$ 16,065	$ 16,837	$ (52,906)	$ (126,057)	$ (103,273)	$ (50,226)	$ (20,004)	$ (279,556)
Net income (loss) per share:
Basic (in dollars per share)	$ 0.04			$ (0.31)			$ (0.05)	$ (0.70)
Diluted (in dollars per share)	$ 0.04			$ (0.31)			$ (0.05)	$ (0.70)
Weighted average number of shares used to compute net income (loss) per share:
Basic (in shares)	401,466			404,536			401,319	399,026
Diluted (in shares)	410,992			404,536			401,319	399,026
Dividends declared per common stock (in dollars per share)	$ 0.0452	$ 0.0452	$ 0.0452	$ 0			$ 0.1356	$ 0

XML

Accounting Policies (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018	Jan. 01, 2019	Dec. 31, 2018	Dec. 31, 2017
Cash, Cash Equivalents and Restricted Cash
Cash and cash equivalents	$ 203,646		$ 203,646			$ 173,515
Restricted cash - current	7,745		7,745			4,527
Restricted cash - long-term	3,667		3,667			7,574
Total cash, cash equivalents and restricted cash shown in the consolidated statements of cash flows	215,058	$ 207,495	215,058	$ 207,495		185,616	$ 304,986
Inventories
Materials and supplies inventory	123,600		123,600			83,400
Hydrocarbons inventory	16,600		16,600			$ 1,400
Leases
Other assets (right-of-use assets)	20,436		20,436
Total lease liabilities	$ 23,774		$ 23,774
Accounting Standards Update 2016-02
Leases
Other assets (right-of-use assets)					$ 21,700
Total lease liabilities					$ 21,700
Phillips 66 Company | Sales Revenue, Net | Customer Concentration Risk
Risks and Uncertainties
Concentration risk, percentage	21.00%	6.00%	22.00%	3.00%
Shell Trading (US) Company | Sales Revenue, Net | Customer Concentration Risk
Risks and Uncertainties
Concentration risk, percentage	11.00%	3.00%	9.00%	1.00%

XML

Property and Equipment (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2018
Oil and gas properties:
Proved properties	$ 4,827,304		$ 4,827,304		$ 4,236,489
Unproved properties	898,855		898,855		759,472
Total oil and gas properties	5,726,159		5,726,159		4,995,961
Accumulated depletion	(1,945,170)		(1,945,170)		(1,551,097)
Oil and gas properties, net	3,780,989		3,780,989		3,444,864
Other property	59,515		59,515		51,987
Accumulated depreciation	(41,468)		(41,468)		(37,150)
Other property, net	18,047		18,047		14,837
Property and equipment, net	3,799,036	$ 3,509,537	3,799,036	$ 3,509,537	$ 3,459,701
Depletion expense	$ 139,100	$ 76,800	$ 394,100	$ 199,700

XML

Equity Method Investments - Summary of Financial Information (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2018
Costs and expenses:
Equity in earnings - KTIPI	$ 0	$ 24,841	$ 0	$ 59,637
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 stockholders' equity
Total current liabilities					226,311
Total long-term liabilities					536,178
Shareholders' equity:
Total shareholders' equity					(340,891)
Total liabilities and shareholders' equity					$ 421,598
Revenues and other income:
Oil and gas revenue		215,408		600,158
Other income		(72)		44
Total revenues and other income		215,336		600,202
Costs and expenses:
Oil and gas production		40,334		115,366
Depletion, depreciation and amortization		33,044		108,996
Other expenses, net		(58)		(211)
Total costs and expenses		73,320		224,151
Income before income taxes		142,016		376,051
Income tax expense		50,796		134,047
Net income		91,220		242,004
Kosmos' share of net income		45,610		121,002
Basis difference amortization		20,769		61,365
Equity in earnings - KTIPI		$ 24,841		$ 59,637

XML

Commitments and Contingencies (Details)		3 Months Ended				9 Months Ended
	Nov. 01, 2019 $ / shares	Sep. 30, 2019 USD ($) $ / shares	Jun. 30, 2019 $ / shares	Mar. 31, 2019 $ / shares	Sep. 30, 2018 $ / shares	Sep. 30, 2019 USD ($) km² meter exploration_well $ / shares	Sep. 30, 2018 $ / shares	Dec. 31, 2018 USD ($)
Commitments and contingencies
Dividends declared per common stock (in dollars per share) | $ / shares		$ 0.0452	$ 0.0452	$ 0.0452	$ 0	$ 0.1356	$ 0
SAO TOME AND PRINCIPE AND NAMIBIA
Commitments and contingencies
Number of exploration wells | exploration_well						1
Sao Tome and Principe
Commitments and contingencies
3D seismic requirements | 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
Surety Bond | Gulf of Mexico
Commitments and contingencies
Cash collateral | $		$ 0				$ 0		$ 600,000
Bureau Of Ocean Energy Management | Surety Bond | Gulf of Mexico
Commitments and contingencies
Required performance bonds | $		208,700,000				208,700,000		200,900,000
Third Party | Surety Bond | Gulf of Mexico
Commitments and contingencies
Required performance bonds | $		$ 3,700,000				$ 3,700,000		$ 3,700,000
Subsequent Event
Commitments and contingencies
Dividends declared per common stock (in dollars per share) | $ / shares	$ 0.0452

XML

Equity-based Compensation - Additional Information (Details) - LTIP - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	3 Months Ended		9 Months Ended
	Mar. 31, 2018	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense recognized		$ 9.5	$ 8.9	$ 27.4	$ 26.0
Tax benefit		3.1	1.6	5.9	5.0
Net tax shortfall (windfall) related to equity-based compensation		0.0	0.1	1.2	(0.3)
Fair value of awards vested		$ 0.7	$ 1.1	$ 14.7	$ 83.1
Vesting period				3 years
Number of additional shares authorized (in shares)	11,000,000.0
Number of shares authorized (in shares)		50,500,000		50,500,000
Number of shares remaining available for grant (in shares)		9,800,000		9,800,000
Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense not yet recognized		$ 38.3		$ 38.3
Weighted average period over which compensation expense is to be recognized				1 year 11 months 19 days
Market/Service Vesting Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Grant date fair value of awards granted (in dollars per share)				$ 6.02
Market/Service Vesting Restricted Stock Units | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage of the awards granted (up to)				0.00%
Grant date fair value of awards granted (in dollars per share)				$ 4.83
Expected volatility				44.00%
Risk-free interest rate				0.80%
Market/Service Vesting Restricted Stock Units | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage of the awards granted (up to)				200.00%
Grant date fair value of awards granted (in dollars per share)				$ 12.96
Expected volatility				52.00%
Risk-free interest rate				2.50%

XML

Business Segment Information

9 Months Ended

Sep. 30, 2019

Segment Reporting [Abstract]

Business Segment Information

Business Segment Information

Kosmos is engaged in a single line of business, which is the exploration, development and production of oil and gas. At September 30, 2019, substantially all of our long-lived assets and all of our product sales are related to operations in four geographic reporting segments: Ghana, Equatorial Guinea, Mauritania/Senegal and the U.S. Gulf of Mexico. In addition, we have exploration activities in other countries in the Atlantic Margins. 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)
Three months ended September 30, 2019
Revenues and other income:
Oil and gas revenue	$	177,797		$	55,378	$	—		$	123,861		$	—		$	—		$	357,036
Other income, net	1			—		—			200			5,706			(5,973		)	(66		)
Total revenues and other income	177,798			55,378		—			124,061			5,706			(5,973		)	356,970
Costs and expenses:
Oil and gas production	42,017			21,369		—			32,154			—			—			95,540
Facilities insurance modifications, net	12,569			—		—			—			—			—			12,569
Exploration expenses	82			2,437		1,260			10,625			8,369			—			22,773
General and administrative	3,886			1,719		2,678			7,002			38,897			(29,459		)	24,723
Depletion, depreciation and amortization	73,347			16,019		15			56,359			913			—			146,653
Interest and other financing costs, net(1)	16,821			—		(6,703		)	5,083			17,304			(1,784		)	30,721
Derivatives, net	—			—		—			(1,745		)	(25,271		)	—			(27,016		)
Other expenses, net	(25,357		)	615		9,141			550			1,253			25,270			11,472
Total costs and expenses	123,365			42,159		6,391			110,028			41,465			(5,973		)	317,435
Income (loss) before income taxes	54,433			13,219		(6,391		)	14,033			(35,759		)	—			39,535
Income tax expense (benefit)	10,585			6,110		—			2,942			3,833			—			23,470
Net income (loss)	$	43,848		$	7,109	$	(6,391	)	$	11,091		$	(39,592	)	$	—		$	16,065
Consolidated capital expenditures	$	28,398		$	15,397	$	842		$	49,629		$	13,127		$	—		$	107,393

	Ghana			Equatorial Guinea			Mauritania/Senegal			U.S. Gulf of Mexico			Corporate & Other			Eliminations			Total
	(In thousands)
Nine months ended September 30, 2019
Revenues and other income:
Oil and gas revenue	$	502,800		$	208,667		$	—		$	338,292		$	—		$	—		$	1,049,759
Other income, net	2			—			—			459			97,594			(98,120		)	(65		)
Total revenues and other income	502,802			208,667			—			338,751			97,594			(98,120		)	1,049,694
Costs and expenses:													—
Oil and gas production	117,027			60,645			—			88,644			—			—			266,316
Facilities insurance modifications, net	(5,174		)	—			—			—			—			—			(5,174		)
Exploration expenses	189			8,080			9,745			32,834			32,174			—			83,022
General and administrative	15,844			5,303			6,505			19,288			127,416			(85,653		)	88,703
Depletion, depreciation and amortization	204,108			55,323			46			153,768			2,941			—			416,186
Interest and other financing costs, net(1)	56,500			—			(20,020		)	16,654			77,782			(5,351		)	125,565
Derivatives, net	—			—			—			28,768			7,116			—			35,884
Other expenses, net	6,761			(1,629		)	9,783			2,695			1,304			(7,116		)	11,798
Total costs and expenses	395,255			127,722			6,059			342,651			248,733			(98,120		)	1,022,300
Income (loss) before income taxes	107,547			80,945			(6,059		)	(3,900		)	(151,139		)	—			27,394
Income tax expense (benefit)	30,285			33,403			—			(824		)	(15,466		)	—			47,398
Net income (loss)	$	77,262		$	47,542		$	(6,059	)	$	(3,076	)	$	(135,673	)	$	—		$	(20,004	)
Consolidated capital expenditures	$	96,861		$	36,448		$	7,132		$	136,688		$	41,177		$	—		$	318,306
As of September 30, 2019
Property and equipment, net	$	1,603,170		$	460,044		$	428,596		$	1,263,945		$	43,281		$	—		$	3,799,036
Total assets	$	1,844,328		$	489,564		$	568,743		$	3,309,044		$	12,078,321		$	(13,821,741	)	$	4,468,259

______________________________________

(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)
Three months ended September 30, 2018
Revenues and other income:
Oil and gas revenue	$	218,656		$	107,704		$	—		$	24,177		$	—		$	(107,704	)	$	242,833
Gain on sale of assets	—			7,666			—			—			—			—			7,666
Other income, net	—			(317		)	—			—			78,166			(78,129		)	(280		)
Total revenues and other income	218,656			115,053			—			24,177			78,166			(185,833		)	250,219
Costs and expenses:
Oil and gas production	49,280			20,167			—			4,467			1,331			(20,167		)	55,078
Facilities insurance modifications, net	12,334			—			—			—			—			—			12,334
Exploration expenses	57,818			16,584			1,203			50,176			22,457			—			148,238
General and administrative	5,786			1,761			1,396			4,026			42,072			(29,078		)	25,963
Depletion, depreciation and amortization	70,799			37,291			15			8,190			1,037			(37,291		)	80,041
Interest and other financing costs, net(4)	21,989			(4		)	(6,441		)	2,085			7,704			(1,784		)	23,549
Derivatives, net	—			—			—			10,082			47,275			—			57,357
(Gain) loss on equity method investments, net	—			—			—			—			—			(24,841		)	(24,841		)
Other expenses, net	34,610			(976		)	(13		)	—			846			(47,274		)	(12,807		)
Total costs and expenses	252,616			74,823			(3,840		)	79,026			122,722			(160,435		)	364,912
Income (loss) before income taxes	(33,960		)	40,230			3,840			(54,849		)	(44,556		)	(25,398		)	(114,693		)
Income tax expense (benefit)	21,862			25,398			—			(12,324		)	1,826			(25,398		)	11,364
Net income (loss)	$	(55,822	)	$	14,832		$	3,840		$	(42,525	)	$	(46,382	)	$	—		$	(126,057	)
Consolidated capital expenditures	$	32,501		$	2,913		$	3,319		$	52,488		$	17,970		$	—		$	109,191

	Ghana			Equatorial Guinea(1)			Mauritania/Senegal			U.S. Gulf of Mexico(2)			Corporate & Other			Eliminations(3)			Total
	(In thousands)
Nine months ended September 30, 2018
Revenues and other income:
Oil and gas revenue	$	561,043		$	300,079		$	—		$	24,177		$	—		$	(300,079	)	$	585,220
Gain on sale of assets	—			7,666			—			—			—			—			7,666
Other income, net	(17		)	22			—			—			315,771			(315,793		)	(17		)
Total revenues and other income	561,026			307,767			—			24,177			315,771			(615,872		)	592,869
Costs and expenses:
Oil and gas production	143,860			57,683			—			4,467			3,334			(57,683		)	151,661
Facilities insurance modifications, net	21,812			—			—			—			—			—			21,812
Exploration expenses	58,076			33,665			6,603			50,176			98,392			—			246,912
General and administrative	15,651			3,768			3,628			4,026			122,558			(84,288		)	65,343
Depletion, depreciation and amortization	197,260			115,862			46			8,190			3,111			(115,862		)	208,607
Interest and other financing costs, net(4)	65,357			(9		)	(18,704		)	2,085			24,735			(5,351		)	68,113
Derivatives, net	—			—			—			10,082			226,025			—			236,107
(Gain) loss on equity method investments, net	—			—			—			—			—			(59,637		)	(59,637		)
Other expenses, net	216,319			(1,138		)	(13		)	—			2,695			(226,027		)	(8,164		)
Total costs and expenses	718,335			209,831			(8,440		)	79,026			480,850			(548,848		)	930,754
Income (loss) before income taxes	(157,309		)	97,936			8,440			(54,849		)	(165,079		)	(67,024		)	(337,885		)
Income tax expense (benefit)	(49,148		)	67,024			—			(12,324		)	3,143			(67,024		)	(58,329		)
Net income (loss)	$	(108,161	)	$	30,912		$	8,440		$	(42,525	)	$	(168,222	)	$	—		$	(279,556	)
Consolidated capital expenditures	$	71,330		$	27,891		$	9,633		$	52,488		$	102,651		$	—		$	263,993
As of September 30, 2018
Property and equipment, net	$	1,727,595		$	3,801		$	403,111		$	1,340,479		$	34,551		$	—		$	3,509,537
Total assets	$	2,073,825		$	145,823		$	465,352		$	3,473,501		$	10,660,832		$	(12,489,869	)	$	4,329,464

______________________________________

(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 three and nine months ended September 30, 2018, except for capital expenditures. See Note 7 - Equity Method Investments for additional information regarding our equity method investments.

(2) No activity prior to 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.

	Nine Months Ended September 30,
	2019			2018
	(In thousands)
Consolidated capital expenditures:
Consolidated Statements of Cash Flows - Investing activities:
Oil and gas assets	$	240,642		$	149,305
Other property	8,291			3,560
Adjustments:
Changes in capital accruals	11,083			13,965
Exploration expense, excluding unsuccessful well costs(1)	75,661			131,964
Capitalized interest	(21,330		)	(21,209		)
Proceeds on sale of assets	—			(13,703		)
Other	3,959			111
Total consolidated capital expenditures	$	318,306		$	263,993

______________________________________

(1)

Unsuccessful well costs are included in oil and gas assets when incurred.

XML

Cover - shares	9 Months Ended
	Sep. 30, 2019	Nov. 01, 2019
Cover page.
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Sep. 30, 2019
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
Title of 12(b) Security	Common Stock $0.01 par value
Trading Symbol	KOS
Security Exchange Name	NYSE
City Area Code	214
Local Phone Number	445 9600
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 Common Stock, Shares Outstanding		401,516,098
Entity Central Index Key	0001509991
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q3
Amendment Flag	false
Current Fiscal Year End Date	--12-31

XML

Income Taxes

9 Months Ended

Sep. 30, 2019

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

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. We evaluate our estimated annual effective income tax rate each quarter, based on current and forecasted business results and enacted tax laws, and apply this tax rate to our ordinary income or loss to calculate our estimated tax expense or benefit. The Company excludes zero tax rate and tax-exempt jurisdictions from our evaluation of the estimated annual effective income tax rate. The tax effect of discrete items are recognized in the period in which they occur at the applicable statutory tax rate. The company was not subject to taxation at the parent company level for the three and nine months ended September 30, 2018.

For 2019, the income tax provision consists of United States, Ghanaian, and Equatorial Guinean income taxes, and Texas margin taxes. For 2018, results from operations in Equatorial Guinea were reported net of tax, as Gain on equity method investments, net in our consolidated statement of operations, and were not included in our 2018 income tax provision. 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.

Income (loss) before income taxes is composed of the following:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2019		2018			2019			2018
	(In thousands)
United States	$	3,464	$	(53,136	)	$	(70,776	)	$	(49,967	)
Bermuda	—		(15,513		)	—			(47,474		)
Foreign—other	36,071		(46,044		)	98,170			(240,444		)
Income (loss) before income taxes	$	39,535	$	(114,693	)	$	27,394		$	(337,885	)

For the three months ended, September 30, 2019, and 2018, our effective tax rate was 59% and 10%, respectively. For the nine months ended, September 30, 2019, and 2018, our effective tax rate was 173% and 17%, respectively.

For the three and nine months ended September 30, 2019, our overall effective tax rate was impacted by the difference in our 21% U.S. income tax reporting rate and the 35% statutory tax rates applicable to our Ghanaian and Equatorial Guinean operations, non-deductible and non-taxable items associated with our U.S., Ghanaian, and Equatorial Guinean operations, and other losses and expenses, primarily related to exploration operations in tax-exempt jurisdictions or in taxable jurisdictions where we have valuation allowances against our deferred tax assets, and therefore, we do not realize any tax benefit on such losses or expenses.

For the three and nine months ended September 30, 2018, our overall effective tax rate was impacted by non-deductible and non-taxable items associated with our U.S. and Ghanaian operations and other losses and expenses, primarily related to

exploration operations in tax-exempt jurisdictions or in taxable jurisdictions where we have valuation allowances against our deferred tax assets, and therefore, we do not realize any tax benefit on such losses or expenses.

The Company files income tax returns in all jurisdictions where such requirements exist, however, our primary tax jurisdictions are the United States, Ghana and Equatorial Guinea. The Company is open to tax examinations in the United States, for federal income tax return years 2016 through 2018, in Ghana to federal income tax return years 2014 through 2018, and in Equatorial Guinea to federal income tax return year2018.

As of September 30, 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.

XML

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY - USD ($) shares in Thousands, $ in Thousands	Total	Common Shares	Additional Paid-in Capital	Accumulated Deficit	Treasury Stock
Balance at the beginning (in shares) at Dec. 31, 2017		398,599
Balance at the beginning at Dec. 31, 2017	$ 897,112	$ 3,986	$ 2,014,525	$ (1,073,202)	$ (48,197)
Increase (Decrease) in Shareholders' Equity
Equity-based compensation	8,392		8,392
Restricted stock awards and units (in shares)		6,380
Restricted stock awards and units	0	$ 64	(64)
Purchase of treasury stock / tax withholdings	(11,874)		(11,364)		(510)
Net (loss) income	(50,226)			(50,226)
Balance at the end (in shares) at Mar. 31, 2018		404,979
Balance at the end at Mar. 31, 2018	843,404	$ 4,050	2,011,489	(1,123,428)	(48,707)
Balance at the beginning (in shares) at Dec. 31, 2017		398,599
Balance at the beginning at Dec. 31, 2017	897,112	$ 3,986	2,014,525	(1,073,202)	(48,197)
Increase (Decrease) in Shareholders' Equity
Net (loss) income	(279,556)
Balance at the end (in shares) at Sep. 30, 2018		442,856
Balance at the end at Sep. 30, 2018	934,933	$ 4,429	2,331,969	(1,352,758)	(48,707)
Balance at the beginning (in shares) at Mar. 31, 2018		404,979
Balance at the beginning at Mar. 31, 2018	843,404	$ 4,050	2,011,489	(1,123,428)	(48,707)
Increase (Decrease) in Shareholders' Equity
Equity-based compensation	9,821		9,821
Restricted stock awards and units (in shares)		2,578
Restricted stock awards and units	0	$ 26	(26)
Purchase of treasury stock / tax withholdings	(5,821)		(5,821)
Net (loss) income	(103,273)			(103,273)
Balance at the end (in shares) at Jun. 30, 2018		407,557
Balance at the end at Jun. 30, 2018	744,131	$ 4,076	2,015,463	(1,226,701)	(48,707)
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	8,915		8,915
Restricted stock awards and units (in shares)		305
Restricted stock awards and units	0	$ 3	(3)
Net (loss) income	(126,057)			(126,057)
Balance at the end (in shares) at Sep. 30, 2018		442,856
Balance at the end at Sep. 30, 2018	934,933	$ 4,429	2,331,969	(1,352,758)	(48,707)
Balance at the beginning (in shares) at Dec. 31, 2018		442,915
Balance at the beginning at Dec. 31, 2018	941,478	$ 4,429	2,341,249	(1,167,193)	(237,007)
Increase (Decrease) in Shareholders' Equity
Dividends ($0.0452 per share)	(18,744)		(18,744)
Equity-based compensation	8,744		8,744
Restricted stock awards and units (in shares)		2,610
Restricted stock awards and units	0	$ 26	(26)
Purchase of treasury stock / tax withholdings	(1,979)		(1,979)
Net (loss) income	(52,906)			(52,906)
Balance at the end (in shares) at Mar. 31, 2019		445,525
Balance at the end at Mar. 31, 2019	876,593	$ 4,455	2,329,244	(1,220,099)	(237,007)
Balance at the beginning (in shares) at Dec. 31, 2018		442,915
Balance at the beginning at Dec. 31, 2018	941,478	$ 4,429	2,341,249	(1,167,193)	(237,007)
Increase (Decrease) in Shareholders' Equity
Net (loss) income	(20,004)
Balance at the end (in shares) at Sep. 30, 2019		445,757
Balance at the end at Sep. 30, 2019	891,030	$ 4,458	2,310,776	(1,187,197)	(237,007)
Balance at the beginning (in shares) at Mar. 31, 2019		445,525
Balance at the beginning at Mar. 31, 2019	876,593	$ 4,455	2,329,244	(1,220,099)	(237,007)
Increase (Decrease) in Shareholders' Equity
Dividends ($0.0452 per share)	(18,740)		(18,740)
Equity-based compensation	9,525		9,525
Restricted stock awards and units (in shares)		113
Restricted stock awards and units	0	$ 1	(1)
Purchase of treasury stock / tax withholdings	(4)		(4)
Net (loss) income	16,837			16,837
Balance at the end (in shares) at Jun. 30, 2019		445,638
Balance at the end at Jun. 30, 2019	884,211	$ 4,456	2,320,024	(1,203,262)	(237,007)
Increase (Decrease) in Shareholders' Equity
Dividends ($0.0452 per share)	(18,753)		(18,753)
Equity-based compensation	9,507		9,507
Restricted stock awards and units (in shares)		119
Restricted stock awards and units	0	$ 2	(2)
Net (loss) income	16,065			16,065
Balance at the end (in shares) at Sep. 30, 2019		445,757
Balance at the end at Sep. 30, 2019	$ 891,030	$ 4,458	$ 2,310,776	$ (1,187,197)	$ (237,007)

XML

Suspended Well Costs (Tables)

9 Months Ended

Sep. 30, 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 drilled wells as of and during the nine months ended September 30, 2019. The table excludes $1.4 million in costs that were capitalized and subsequently expensed during the same period.

	September 30, 2019
	(In thousands)
Beginning balance	$	367,665
Additions to capitalized exploratory well costs pending the determination of proved reserves	55,244
Reclassification due to determination of proved reserves	(10,711		)
Capitalized exploratory well costs charged to expense	—
Ending balance	$	412,198

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 an 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:

	September 30, 2019		December 31, 2018
	(In thousands, except well counts)
Exploratory well costs capitalized for a period of one year or less	$	—	$	—
Exploratory well costs capitalized for a period of one to two years	77,995		299,253
Exploratory well costs capitalized for a period of three years or greater	334,203		68,412
Ending balance	$	412,198	$	367,665
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year	3		3

XML

Organization

9 Months Ended

Sep. 30, 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, in the United States of America, (the "Redomestication") in December 2018. 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 New York Stock Exchange and London Stock Exchange and is traded under the ticker symbol KOS.

Kosmos is engaged in a single line of business, which is the exploration, development, and production of oil and natural gas. Substantially all of our long-lived assets and all of our product sales are related to operations in four geographic areas: Ghana, Equatorial Guinea, Mauritania/Senegal and U.S. Gulf of Mexico. In addition, we have exploration activities in other countries in the Atlantic Margins.

XML

Equity Method Investments - Asset Acquisition (Details) - USD ($) $ in Thousands		9 Months Ended
	Jan. 01, 2019	Sep. 30, 2019	Dec. 31, 2018
Liabilities assumed:
Asset retirement obligations		$ 9,706
Carrying value:
Equity method investment carrying value at December 31, 2018		$ 0	$ 51,896
Ceiba Field And Okume Complex Acquisition
Schedule of Equity Method Investments [Line Items]
Direct ownership percentage	40.375%
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

XML

Accounting Policies - Summary of Oil and Gas Revenue (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Disaggregation of Revenue [Line Items]
Provisional oil sales contracts	$ 31,683	$ (54,267)	$ (34,003)	$ (232,057)
Oil and gas revenue	357,036	242,833	1,049,759	585,220
Oil and gas revenue
Disaggregation of Revenue [Line Items]
Provisional oil sales contracts	4,668	3,075	1,881	3,584
Oil and gas revenue	357,036	242,833	1,049,759	585,220
Equatorial Guinea
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	54,894	0	207,173	0
Ghana
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	173,613	215,581	502,413	557,459
Gulf of Mexico
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	$ 123,861	$ 24,177	$ 338,292	$ 24,177

XML

Suspended Well Costs - Summary of Suspended Well Costs (Details) $ in Thousands	9 Months Ended
	Sep. 30, 2019 USD ($)	Sep. 30, 2019 USD ($) project	Dec. 31, 2018 USD ($) project
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Capitalized exploratory well costs subsequently expensed in the same period	$ 1,400
Reconciliation of capitalized exploratory well costs on completed wells
Beginning balance	367,665
Additions to capitalized exploratory well costs pending the determination of proved reserves	55,244
Reclassification due to determination of proved reserves	(10,711)
Capitalized exploratory well costs charged to expense	0
Ending balance	412,198
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		$ 0	$ 0
Exploratory well costs capitalized for a period of one to two years		77,995	299,253
Exploratory well costs capitalized for a period of three years or greater		334,203	68,412
Ending balance	$ 412,198	$ 412,198	$ 367,665
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year | project		3	3

XML

Net Income (Loss) Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended						9 Months Ended
	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Sep. 30, 2019	Sep. 30, 2018
Numerator:
Net (loss) income	$ 16,065	$ 16,837	$ (52,906)	$ (126,057)	$ (103,273)	$ (50,226)	$ (20,004)	$ (279,556)
Weighted average number of shares outstanding:
Basic (in shares)	401,466			404,536			401,319	399,026
Restricted stock units (in shares)	9,526			0			0	0
Diluted (in shares)	410,992			404,536			401,319	399,026
Net income (loss) per share:
Basic (in dollars per share)	$ 0.04			$ (0.31)			$ (0.05)	$ (0.70)
Diluted (in dollars per share)	$ 0.04			$ (0.31)			$ (0.05)	$ (0.70)
Outstanding restricted stock awards and units excluded from the computations of diluted net income per share (in shares)	700			13,100			15,400	14,500

XML

Fair Value Measurements (Details) - USD ($) $ in Thousands	Sep. 30, 2019	Dec. 31, 2018
Carrying Value
Liabilities:
Long-term debt	$ 2,142,318	$ 2,161,873
Fair Value
Liabilities:
Long-term debt	2,170,514	2,175,026
7.125% Senior Notes due 2026 | Senior Notes | Carrying Value
Liabilities:
Long-term debt	642,318	0
7.125% Senior Notes due 2026 | Senior Notes | Fair Value
Liabilities:
Long-term debt	670,514	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 | Facility | Carrying Value
Liabilities:
Long-term debt	0	325,000
Corporate Revolver | Facility | Fair Value
Liabilities:
Long-term debt	0	325,000
The Facility | Facility | Carrying Value
Liabilities:
Long-term debt	1,500,000	1,325,000
The Facility | Facility | Fair Value
Liabilities:
Long-term debt	1,500,000	1,325,000
Recurring basis
Liabilities:
Total fair value, net	21,442	30,744
Recurring basis | Commodity
Assets:
Derivative asset, fair value	32,602	53,097
Liabilities:
Derivative liability, fair value	(11,160)	(22,353)
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1)
Liabilities:
Total fair value, net	0	0
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Commodity
Assets:
Derivative asset, fair value	0	0
Liabilities:
Derivative liability, fair value	0	0
Recurring basis | Significant Other Observable Inputs (Level 2)
Liabilities:
Total fair value, net	21,442	30,744
Recurring basis | Significant Other Observable Inputs (Level 2) | Commodity
Assets:
Derivative asset, fair value	32,602	53,097
Liabilities:
Derivative liability, fair value	(11,160)	(22,353)
Recurring basis | Significant Unobservable Inputs (Level 3)
Liabilities:
Total fair value, net	0	0
Recurring basis | Significant Unobservable Inputs (Level 3) | Commodity
Assets:
Derivative asset, fair value	0	0
Liabilities:
Derivative liability, fair value	$ 0	$ 0

XML

Debt - 7.875% Senior Secured Notes due 2021 (Details) - USD ($)	1 Months Ended			3 Months Ended		9 Months Ended
	Apr. 30, 2019	Apr. 30, 2015	Aug. 31, 2014	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Debt Instrument [Line Items]
Loss on extinguishment of debt				$ 0	$ 268,000	$ 24,794,000	$ 4,324,000
Senior Notes | 7.875% senior notes due 2021
Debt Instrument [Line Items]
Interest rate			7.875%
Senior notes offering face amount		$ 225,000,000.0	$ 300,000,000.0
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

XML

Debt - Schedule of Instruments (Details) - USD ($) $ in Thousands	Sep. 30, 2019	Dec. 31, 2018
Debt
Outstanding debt principal	$ 2,150,000	$ 2,175,000
Unamortized issuance costs and discount	(43,798)	(54,453)
Long-term debt, net	2,106,202	2,120,547
The Facility | Revolving Credit Facility
Debt
Outstanding debt principal	1,500,000	1,325,000
Unamortized issuance costs and discount	(34,400)	(40,500)
Corporate Revolver | Revolving Credit Facility
Debt
Outstanding debt principal	0	325,000
7.125% Senior Notes due 2026 | Senior Notes
Debt
Outstanding debt principal	650,000	0
Unamortized issuance costs and discount	(9,400)
7.875% senior notes due 2021 | Senior Notes
Debt
Outstanding debt principal	$ 0	525,000
Unamortized issuance costs and discount		$ (14,000)

XML

Derivative Financial Instruments - Schedule of oil derivative contracts (Details)	9 Months Ended
	Sep. 30, 2019 $ / bbl MBbls
Dated Brent | Term October 2019 To December 2019 | Three-way collars
Derivative Financial Instruments
Volume (mbbls) | MBbls	2,628
Weighted Average Price Per Bbl [Abstract]
Net Deferred Premium Payable/(Receivable)	1.17
Swap (usd per bbl)	0
Sold Put (usd per bbl)	43.81
Floor (usd per bbl)	53.33
Ceiling (usd per bbl)	73.57
Dated Brent | Term October 2019 To December 2019 | Sold calls
Derivative Financial Instruments
Volume (mbbls) | MBbls	230
Weighted Average Price Per Bbl [Abstract]
Net Deferred Premium Payable/(Receivable)	0
Swap (usd per bbl)	0
Sold Put (usd per bbl)	0
Floor (usd per bbl)	0
Ceiling (usd per bbl)	80.00
Dated Brent | Term January 2020 To December 2020 | Three-way collars
Derivative Financial Instruments
Volume (mbbls) | MBbls	6,000
Weighted Average Price Per Bbl [Abstract]
Net Deferred Premium Payable/(Receivable)	0.45
Swap (usd per bbl)	0
Sold Put (usd per bbl)	45.00
Floor (usd per bbl)	57.50
Ceiling (usd per bbl)	80.18
Dated Brent | Term January 2020 To December 2020 | Swaps with sold puts
Derivative Financial Instruments
Volume (mbbls) | MBbls	2,000
Weighted Average Price Per Bbl [Abstract]
Net Deferred Premium Payable/(Receivable)	0
Swap (usd per bbl)	60.53
Sold Put (usd per bbl)	48.75
Floor (usd per bbl)	0
Ceiling (usd per bbl)	0
Dated Brent | Term January 2020 To December 2020 | Put spread
Derivative Financial Instruments
Volume (mbbls) | MBbls	2,000
Weighted Average Price Per Bbl [Abstract]
Net Deferred Premium Payable/(Receivable)	2.59
Swap (usd per bbl)	0
Sold Put (usd per bbl)	50.00
Floor (usd per bbl)	60.00
Ceiling (usd per bbl)	0
Dated Brent | Term January 2020 To December 2020 | Sold calls
Derivative Financial Instruments
Volume (mbbls) | MBbls	8,000
Weighted Average Price Per Bbl [Abstract]
Net Deferred Premium Payable/(Receivable)	1.17
Swap (usd per bbl)	0
Sold Put (usd per bbl)	0
Floor (usd per bbl)	0
Ceiling (usd per bbl)	85.00
Dated Brent | Term January 2021 To December 2021 | Sold calls
Derivative Financial Instruments
Volume (mbbls) | MBbls	1,000
Weighted Average Price Per Bbl [Abstract]
Net Deferred Premium Payable/(Receivable)	0
Swap (usd per bbl)	0
Sold Put (usd per bbl)	0
Floor (usd per bbl)	0
Ceiling (usd per bbl)	75.00
NYMEX WTI | Term October 2019 To December 2019 | Swaps
Derivative Financial Instruments
Volume (mbbls) | MBbls	265
Weighted Average Price Per Bbl [Abstract]
Net Deferred Premium Payable/(Receivable)	0
Swap (usd per bbl)	51.61
Sold Put (usd per bbl)	0
Floor (usd per bbl)	0
Ceiling (usd per bbl)	0
Argus LLS | Term October 2019 To December 2019 | Collars
Derivative Financial Instruments
Volume (mbbls) | MBbls	250
Weighted Average Price Per Bbl [Abstract]
Net Deferred Premium Payable/(Receivable)	0
Swap (usd per bbl)	0
Sold Put (usd per bbl)	0
Floor (usd per bbl)	60.00
Ceiling (usd per bbl)	88.75

XML

Debt

9 Months Ended

Sep. 30, 2019

Debt Disclosure [Abstract]

Debt

Debt

	September 30, 2019			December 31, 2018
	(In thousands)
Outstanding debt principal balances:
Facility	$	1,500,000		$	1,325,000
Corporate Revolver	—			325,000
Senior Notes	650,000			—
Senior Secured Notes	—			525,000
Total	2,150,000			2,175,000
Unamortized deferred financing costs and discounts(1)	(43,798		)	(54,453		)
Long-term debt, net	$	2,106,202		$	2,120,547

__________________________________

(1) Includes $34.4 million and $40.5 million of unamortized deferred financing costs related to the Facility as of September 30, 2019 and December 31, 2018, respectively; $9.4 million of unamortized deferred financing costs and discounts related to the Senior Notes as of September 30, 2019; and $14.0 million of unamortized deferred financing costs and discounts related to the Senior Secured Notes as of 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. The borrowing base calculation includes value related to the Jubilee, TEN, Ceiba and Okume fields. 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 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 September 30, 2019, we have $34.4 million of unamortized issuance costs related to the Facility, which will be amortized over the remaining term of the Facility. As of September 30, 2019, the undrawn availability under the Facility was $100.0 million. The commitments were reduced by $100.0 million to $1.6 billion following the Senior Notes issuance in April 2019.

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 September 30, 2019, we had no letters of credit issued under the Facility.

We were in compliance with the financial covenants contained in the Facility as of September 30, 2019 (the most recent assessment date). The Facility contains customary cross default provisions.

Corporate Revolver

In August 2018, we amended and restated the Corporate Revolver from a number of financial institutions, 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 September 30, 2019, the undrawn availability under the Corporate Revolver was $400.0 million. As of September 30, 2019, we have $7.0 million of net deferred financing costs related to the Corporate Revolver, which will be amortized over its remaining term. 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

Our revolving letter of credit facility agreement (“LC Facility”) expired in July 2019, however, as of September 30, 2019, there were six outstanding letters of credit totaling $9.4 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 7.875% Senior Secured Notes due 2021 (the "Senior Secured Notes") and received net proceeds of approximately $292.5 million after deducting discounts, commissions and debt issue 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 had identical terms to the initial $300.0 million of 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 (the "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 September 30, 2019, the estimated repayments of debt during the five fiscal year periods and thereafter are as follows:

	Payments Due by Year
	Total		2019(2)		2020		2021		2022		2023		Thereafter
	(In thousands)
Principal debt repayments(1)	$	2,150,000	$	—	$	—	$	274,800	$	284,200	$	271,600	$	1,319,400

__________________________________

(1) Includes the scheduled principal 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 September 30, 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.

(2) Represents payments for the period October 1, 2019 through December 31, 2019.

Interest and other financing costs, net

Interest and other financing costs, net incurred during the periods is comprised of the following:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
	(In thousands)
Interest expense	$	34,944		$	27,317		$	111,566		$	77,121
Amortization—deferred financing costs	2,285			2,346			6,974			7,069
Loss on extinguishment of debt	—			268			24,794			4,324
Capitalized interest	(7,077		)	(7,097		)	(21,330		)	(21,209		)
Deferred interest	290			(194		)	1,559			(1,284		)
Interest income	(972		)	(788		)	(2,215		)	(2,579		)
Other, net	1,251			1,697			4,217			4,671
Interest and other financing costs, net	$	30,721		$	23,549		$	125,565		$	68,113

XML

Joint Interest Billings, Related Party Receivables and Notes Receivables

9 Months Ended

Sep. 30, 2019

Joint Interest Billings

Joint Interest Billings, Related Party Receivables and Notes Receivables

Joint Interest Billings, Related Party Receivables and Notes Receivables

Joint Interest Billings

The Company’s joint interest billings generally 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 2014, GNPC notified us and our block partners of its request for the contractor group to pay GNPC’s 5% share of the Tweneboa, Enyenra and Ntomme (“TEN”) development costs. The block partners are being reimbursed for such costs plus interest out of a portion of GNPC’s TEN production revenues. As of September 30, 2019 and December 31, 2018, the current portions 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 portions were $17.2 million and $14.0 million, respectively.

Related Party Receivables

The Company's related party receivables consists primarily of receivables from Trident which, until January 2019, we shared a 50% interest in KTIPI. As of December 31, 2018 the balance due from Trident consisted of $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 September 30, 2019, the balance due from the national oil companies was $19.8 million, which is classified as Long-term receivables in our consolidated balance sheets.

XML

Organization (Details)	9 Months Ended
	Sep. 30, 2019 segment
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of reportable segments	4

XML

Derivative Financial Instruments (Tables)

9 Months Ended

Sep. 30, 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 September 30, 2019. Volumes and weighted average prices are net of any offsetting derivative contracts entered into.

				Weighted Average Price per Bbl
				Net Deferred
				Premium
Term	Type of Contract	Index	MBbl	Payable/(Receivable)		Swap		Sold Put		Floor		Ceiling
2019:
Oct — Dec	Three-way collars	Dated Brent	2,628	$	1.17	$	—	$	43.81	$	53.33	$	73.57
Oct — Dec	Sold calls(1)	Dated Brent	230	—		—		—		—		80.00
Oct — Dec	Swaps	NYMEX WTI	265	—		51.61		—		—		—
Oct — Dec	Collars	Argus LLS	250	—		—		—		60.00		88.75
2020:
Jan — Dec	Three-way collars	Dated Brent	6,000	$	0.45	$	—	$	45.00	$	57.50	$	80.18
Jan — Dec	Swaps with sold puts	Dated Brent	2,000	—		60.53		48.75		—		—
Jan — Dec	Put spread	Dated Brent	2,000	2.59		—		50.00		60.00		—
Jan — Dec	Sold calls(1)(2)	Dated Brent	8,000	1.17		—		—		—		85.00
2021:
Jan — Dec	Sold calls(1)	Dated Brent	1,000	$	—	$	—	$	—	$	—	$	75.00

__________________________________

(1) Represents call option contracts sold to counterparties to enhance other derivative positions.

(2)

Deferred premium payable to be paid October 1, 2019 — December 31, 2019.

Schedule of derivative instruments by balance sheet location

The following tables disclose the Company’s derivative instruments as of September 30, 2019 and December 31, 2018, and gain/(loss) from derivatives during the three and nine months ended September 30, 2019 and 2018, respectively:

		Estimated Fair Value
		Asset (Liability)
Type of Contract	Balance Sheet Location	September 30, 2019			December 31, 2018
		(In thousands)
Derivatives not designated as hedging instruments:
Derivative assets:
Commodity(1)	Derivatives assets—current	$	22,067		$	38,785
Commodity(2)	Derivatives assets—long-term	10,535			14,312
Derivative liabilities:
Commodity(3)	Derivatives liabilities—current	(8,461		)	(12,172		)
Commodity(4)	Derivatives liabilities—long-term	(2,699		)	(10,181		)
Total derivatives not designated as hedging instruments		$	21,442		$	30,744

__________________________________

(1) Includes zero and $0.4 million as of September 30, 2019 and December 31, 2018, respectively which represents our provisional oil sales contract. Also, includes net deferred premiums payable of $4.1 million and $1.6 million related to commodity derivative contracts as of September 30, 2019 and December 31, 2018, respectively.

(2) Includes net deferred premiums payable of $2.6 million and $1.3 million related to commodity derivative contracts as of September 30, 2019 and December 31, 2018, respectively.

(3) Includes net deferred premiums payable of $6.5 million and $18.0 million related to commodity derivative contracts as of September 30, 2019 and December 31, 2018, respectively.

(4)

Includes net deferred premiums payable of zero and $0.5 million related to commodity derivative contracts as of September 30, 2019 and December 31, 2018, respectively.

Schedule of derivative instruments by location of gain/(loss)

		Amount of Gain/(Loss)					Amount of Gain/(Loss)
		Three Months Ended					Nine Months Ended
		September 30,					September 30,
Type of Contract	Location of Gain/(Loss)	2019		2018			2019			2018
		(In thousands)
Derivatives not designated as hedging instruments:
Commodity(1)	Oil and gas revenue	$	4,667	$	3,075		$	1,881		$	3,584
Commodity	Derivatives, net	27,016		(57,357		)	(35,884		)	(236,107		)
Interest rate	Interest expense	—		15			—			466
Total derivatives not designated as hedging instruments		$	31,683	$	(54,267	)	$	(34,003	)	$	(232,057	)

__________________________________

(1)

Amounts represent the change in fair value of our provisional oil sales contracts.

XML

Net Income (Loss) Per Share (Tables)

9 Months Ended

Sep. 30, 2019

Earnings Per Share [Abstract]

Schedule of reconciliation between net income (loss) and amounts used to compute basic and diluted EPS

The following table is a 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:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2019		2018			2019			2018
	(In thousands, except per share data)
Numerator:
Net income (loss) allocable to common stockholders	$	16,065	$	(126,057	)	$	(20,004	)	$	(279,556	)
Denominator:
Weighted average number of shares outstanding:
Basic	401,466		404,536			401,319			399,026
Restricted stock units(1)	9,526		—			—			—
Diluted	410,992		404,536			401,319			399,026
Net income (loss) per share:
Basic	$	0.04	$	(0.31	)	$	(0.05	)	$	(0.70	)
Diluted	$	0.04	$	(0.31	)	$	(0.05	)	$	(0.70	)

__________________________________

(1)

We excluded outstanding restricted stock awards and units of 0.7 million and 13.1 million for the three months ended September 30, 2019 and 2018, respectively, and 15.4 million and 14.5 million for the nine months ended September 30, 2019 and 2018, respectively, from the computations of diluted net income (loss) per share because the effect would have been anti-dilutive.