Kosmos Energy Ltd. - Quarter Report: 2023 June (Form 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 June 30, 2023


☐			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 August 3, 2023
Common Shares, $0.01 par value						460,109,397

Table of Contents

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			7
Consolidated Balance Sheets			7
Consolidated Statements of Operations			8
Consolidated Statements of Stockholders’ Equity			9
Consolidated Statements of Cash Flows			10
Notes to Consolidated Financial Statements			11
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			29
Item 3. Quantitative and Qualitative Disclosures about Market Risk			43
Item 4. Controls and Procedures			45

PART II. OTHER INFORMATION

Item 1. Legal Proceedings			45
Item 1A. Risk Factors			45
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			45
Item 3. Defaults Upon Senior Securities			45
Item 4. Mine Safety Disclosures			45
Item 5. Other Information			45
Signatures			46
Item 6. Exhibits			46
Index to Exhibits			47

Table of Contents

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.
“Asset Coverage Ratio”						The “Asset Coverage Ratio” as defined in the GoM Term Loan means, as of each March 31, June 30, September 30 and December 31 of each Fiscal Year, commencing December 31, 2020, the ratio of (a) Total PDP PV-10 (as defined in the GoM Term Loan) as of such date to (b) outstanding principal amount of Loans (as defined in the GoM Term Loan) as of such date.
“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. and related subsidiaries.
“Bwpd”						Barrels of water per day.
“Corporate Revolver”						Prior to March 31, 2022, this term refers to the Revolving Credit Facility Agreement dated November 23, 2012 (as amended or as amended and restated from time to time), and on or after March 31, 2022, this term refers to the new Revolving Credit Facility Agreement dated March 31, 2022.
“COVID-19”						Coronavirus disease 2019.
“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.
“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.
“DST”						Drill stem test.
“Dry hole” or “Unsuccessful well”						A well that has not encountered a hydrocarbon bearing reservoir expected to produce in commercial quantities.
“DT”						Deepwater Tano.

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“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.
“ESG”						Environmental, social, and governance.
“ESP”						Electric submersible pump.
“E&P”						Exploration and production.
“Facility”						Facility agreement dated March 28, 2011 (as amended or as amended and restated from time to time).
“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.
“GAAP”						Generally Accepted Accounting Principles in the United States of America.
“GEPetrol”						Guinea Equatorial De Petroleos.
“GHG”						Greenhouse gas.
“GJFFDP”						Greater Jubilee Full Field Development Plan.
“GNPC”						Ghana National Petroleum Corporation.
“GoM Term Loan”						Senior Secured Term Loan Credit Agreement dated September 30, 2020.
“Greater Tortue Ahmeyim”						Ahmeyim and Guembeul discoveries.
“GTA UUOA”						Unitization and Unit Operating Agreement covering the Greater Tortue Ahmeyim Unit.
“HLS”						Heavy Louisiana Sweet.
“Jubilee UUOA”						Unitization and Unit Operating Agreement covering the Jubilee Unit.
“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.
“LNG”						Liquefied natural gas.
“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, however, forecasted capital expenditures in relation to the additional interests in Ghana acquired in the October 2021 acquisition of Anadarko WCTP are not included, to (y) the aggregate loan amounts outstanding under the Facility.
“LIBOR”						London Interbank Offered Rate
“LSE”						London Stock Exchange.
“LTIP”						Long Term Incentive Plan.

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“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.
“Net debt”						Total long-term debt less cash and cash equivalents and total restricted cash.
“NYSE”						New York Stock Exchange.
“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.
“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 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.
“RSC”						Ryder Scott Company, L.P.
“SOFR”						Secured Overnight Financing Rate
“SEC”						Securities and Exchange Commission.
“7.125% Senior Notes”						7.125% Senior Notes due 2026.
“7.750% Senior Notes”						7.750% Senior Notes due 2027.
“7.500% Senior Notes”						7.500% Senior Notes due 2028.
“Shelf margin”						The path created by the change in direction of the shoreline in reaction to the filling of a sedimentary basin.
“Shell”						Royal Dutch Shell and related subsidiaries.
“SMH”						Societe Mauritanienne des Hydrocarbures
“Stratigraphy”						The study of the composition, relative ages and distribution of layers of sedimentary rock.

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“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 gas in the strata.
“Structural‑stratigraphic trap”						A structural‑stratigraphic trap is a combination trap with structural and stratigraphic features.
“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.
“TAG GSA”						TEN Associated Gas - Gas Sales Agreement.
“TEN”						Tweneboa, Enyenra and Ntomme.
“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.
“Tortue Phase 1 SPA”						Greater Tortue Ahmeyim Agreement for a Long Term Sale and Purchase of LNG.
“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.
“WCTP”						West Cape Three Points.

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KOSMOS ENERGY LTD.

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)


	June 30, 2023		December 31, 2022
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	85,729	$	183,405

Receivables:
Joint interest billings, net	34,234		28,851
Oil sales	47,411		67,483

Other	16,853		23,401
Inventories	191,412		133,515
Prepaid expenses and other	32,639		24,722
Derivatives	11,270		7,344
Total current assets	419,548		468,721
Property and equipment:
Oil and gas properties, net	4,073,399		3,837,437
Other property, net	4,422		5,210
Property and equipment, net	4,077,821		3,842,647
Other assets:

Restricted cash	3,416		3,416
Long-term receivables	278,744		235,696
Deferred financing costs, net of accumulated amortization of $14,423 and $13,263 at June 30, 2023 and December 31, 2022, respectively	3,480		4,640

Derivatives	3,505		1,725
Other	21,105		23,143
Total assets	$	4,807,619	$	4,579,988
Liabilities and stockholders’ equity
Current liabilities:
Accounts payable	$	263,753	$	212,275
Accrued liabilities	243,880		325,206
Current maturities of long-term debt	15,000		30,000
Derivatives	1,097		6,773
Total current liabilities	523,730		574,254
Long-term liabilities:
Long-term debt, net	2,358,689		2,195,911
Derivatives	138		778
Asset retirement obligations	310,542		300,800
Deferred tax liabilities	459,417		468,445
Other long-term liabilities	251,199		251,952
Total long-term liabilities	3,379,985		3,217,886
Stockholders’ equity:
Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at June 30, 2023 and December 31, 2022	—		—
Common stock, $0.01 par value; 2,000,000,000 authorized shares; 504,344,893 and 500,161,421 issued at June 30, 2023 and December 31, 2022, respectively	5,043		5,002
Additional paid-in capital	2,515,055		2,505,694
Accumulated deficit	(1,379,187)		(1,485,841)
Treasury stock, at cost, 44,263,269 shares at June 30, 2023 and December 31, 2022, respectively	(237,007)		(237,007)
Total stockholders’ equity	903,904		787,848
Total liabilities and stockholders’ equity	$	4,807,619	$	4,579,988

See accompanying notes.

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KOSMOS ENERGY LTD.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

(Unaudited)


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2023		2022		2023		2022
Revenues and other income:
Oil and gas revenue	$	273,255	$	620,368	$	667,495	$	1,279,383
Gain on sale of assets	—		471		—		471
Other income, net	60		43		(313)		95
Total revenues and other income	273,315		620,882		667,182		1,279,949
Costs and expenses:
Oil and gas production	63,579		90,189		147,515		214,892
Facilities insurance modifications, net	—		(384)		—		6,752
Exploration expenses	11,015		89,565		23,015		101,441
General and administrative	23,444		24,624		52,611		50,417
Depletion, depreciation and amortization	89,913		121,679		199,287		280,648

Interest and other financing costs, net	24,371		29,382		48,939		62,521
Derivatives, net	3,031		75,204		(3,809)		357,376
Other expenses, net	4,779		(3,528)		6,809		(1,102)
Total costs and expenses	220,132		426,731		474,367		1,072,945
Income before income taxes	53,183		194,151		192,815		207,004
Income tax expense	29,838		76,978		86,161		88,431
Net income	$	23,345	$	117,173	$	106,654	$	118,573

Net income per share:
Basic	$	0.05	$	0.26	$	0.23	$	0.26
Diluted	$	0.05	$	0.25	$	0.22	$	0.25

Weighted average number of shares used to compute net income per share:
Basic	459,984		455,512		459,155		454,811
Diluted	479,016		475,645		478,902		473,471

See accompanying notes.

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KOSMOS ENERGY LTD.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In thousands)

(Unaudited)


				Additional
	Common Shares			Paid-in		Accumulated		Treasury
	Shares	Amount		Capital		Deficit		Stock		Total
2023:
Balance as of December 31, 2022	500,161	$	5,002	$	2,505,694	$	(1,485,841)	$	(237,007)	$	787,848

Equity-based compensation	—	—		10,093		—		—		10,093
Restricted stock units	3,691	37		(37)		—		—		—
Tax withholdings on restricted stock units	—	—		(11,810)		—		—		(11,810)
Net income	—	—		—		83,309		—		83,309
Balance as of March 31, 2023	503,852	5,039		2,503,940		(1,402,532)		(237,007)		869,440
Dividends	—	—		(1)		—		—		(1)
Equity-based compensation	—	—		11,121		—		—		11,121
Restricted stock units	493	4		(4)		—		—		—
Tax withholdings on restricted stock units	—	—		(1)		—		—		(1)
Net income	—	—		—		23,345		—		23,345






Balance as of June 30, 2023	504,345	$	5,043	$	2,515,055	$	(1,379,187)	$	(237,007)	$	903,904

2022:
Balance as of December 31, 2021	496,152	$	4,962	$	2,473,674	$	(1,712,392)	$	(237,007)	$	529,237
Dividends	—	—		12		—		—		12
Equity-based compensation	—	—		8,425		—		—		8,425
Restricted stock units	3,377	33		(33)		—		—		—
Tax withholdings on restricted stock units	—	—		(2,753)		—		—		(2,753)
Net income	—	—		—		1,400		—		1,400
Balance as of March 31, 2022	499,529	$	4,995	$	2,479,325	$	(1,710,992)	$	(237,007)	$	536,321
Dividends	—	—		(14)		—		—		(14)
Equity-based compensation	—	—		8,886		—		—		8,886
Restricted stock awards and units	487	5		(5)		—		—		—
Tax withholdings on restricted stock units	—	—		—		—		—		—
Net income	—	—		—		117,173		—		117,173
Balance as of June 30, 2022	500,016	$	5,000	$	2,488,192	$	(1,593,819)	$	(237,007)	$	662,366

See accompanying notes.

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KOSMOS ENERGY LTD.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	Six Months Ended June 30,
	2023		2022
Operating activities
Net income	$	106,654	$	118,573
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization (including deferred financing costs)	204,368		285,909
Deferred income taxes	(9,029)		(83,432)
Unsuccessful well costs and leasehold impairments	1,313		73,662

Change in fair value of derivatives	(220)		367,374
Cash settlements on derivatives, net (including $(8.2) million and $(212.9) million on commodity hedges during 2023 and 2022)	(10,632)		(223,618)
Equity-based compensation	21,198		17,129
Gain on sale of assets	—		(471)
Loss on extinguishment of debt	—		192
Other	(1,474)		(3,742)
Changes in assets and liabilities:
(Increase) decrease in receivables	16,330		(103,589)
(Increase) in inventories	(60,836)		(9,398)
(Increase) in prepaid expenses and other	(5,988)		(4,261)
Increase in accounts payable	51,478		78,179
Increase (decrease) in accrued liabilities	(91,199)		95,679
Net cash provided by operating activities	221,963		608,186
Investing activities
Oil and gas assets	(416,867)		(320,787)
Acquisition of oil and gas properties	—		(21,205)
Proceeds on sale of assets	—		118,693
Notes receivable from partners	(33,295)		(11,428)
Net cash used in investing activities	(450,162)		(234,727)
Financing activities
Borrowings under long-term debt	150,000		—
Payments on long-term debt	(7,500)		(315,000)

Tax withholdings on restricted stock units	(11,811)		(2,753)
Dividends	(166)		(655)
Deferred financing costs	—		(6,288)
Net cash provided by (used in) financing activities	130,523		(324,696)
Net increase (decrease) in cash, cash equivalents and restricted cash	(97,676)		48,763
Cash, cash equivalents and restricted cash at beginning of period	186,821		174,896
Cash, cash equivalents and restricted cash at end of period	$	89,145	$	223,659

Supplemental cash flow information
Cash paid for:
Interest, net of capitalized interest	$	32,468	$	46,262
Income taxes, net of refund received	$	145,365	$	137,099

See accompanying notes.

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KOSMOS ENERGY LTD.

Notes to Consolidated Financial Statements

(Unaudited)

1. Organization

Kosmos Energy Ltd. is incorporated in the State of Delaware as a holding company for Kosmos Energy Delaware Holdings, LLC, a Delaware limited liability company. As a holding company, Kosmos Energy Ltd.’s management operations are conducted through a wholly-owned subsidiary, Kosmos Energy, LLC. The terms “Kosmos,” the “Company,” “we,” “us,” “our,” “ours,” and similar terms refer to Kosmos Energy Ltd. and its wholly-owned subsidiaries, unless the context indicates otherwise.

Kosmos is a full-cycle, deepwater, independent oil and gas exploration and production company focused along the offshore Atlantic Margins. Our key assets include production offshore Ghana, Equatorial Guinea and the U.S. Gulf of Mexico, as well as world-class gas projects offshore Mauritania and Senegal. We also pursue a proven basin exploration program in Equatorial Guinea and the U.S. Gulf of Mexico. Kosmos is listed on the NYSE and LSE and is traded under the ticker symbol KOS.

Kosmos is engaged in a single line of business, which is the exploration, 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 the U.S. Gulf of Mexico.

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 interim consolidated financial statements were prepared in accordance with the requirements of the SEC for interim reporting. As permitted under those rules, certain notes or other financial information that are normally required by GAAP have been condensed or omitted from these interim consolidated financial statements. These interim consolidated financial statements and the accompanying notes should be read in conjunction with our audited consolidated financial statements for the year ended December 31, 2022, 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, current assets, total assets, current liabilities, total liabilities, stockholders’ equity or cash flows.

Cash, Cash Equivalents and Restricted Cash


	June 30, 2023		December 31, 2022
	(In thousands)
Cash and cash equivalents	$	85,729	$	183,405

Restricted cash - long-term	3,416		3,416
Total cash, cash equivalents and restricted cash shown in the consolidated statements of cash flows	$	89,145	$	186,821

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.

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Joint Interest Billings

The Company’s joint interest billings consist of receivables from partners with interests in common oil and gas properties operated by the Company for shared costs. Joint interest billings are classified on the face of the consolidated balance sheets as current and long-term receivables based on when collection is expected to occur.

Inventories

Inventories consisted of $143.4 million and $125.3 million of materials and supplies and $48.0 million and $8.2 million of hydrocarbons as of June 30, 2023 and December 31, 2022, 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.

Revenue Recognition

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 of or month after the sale.

Oil and gas revenue is composed of the following:


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
	(In thousands)
Revenues from contract with customers - Equatorial Guinea	$	37,542	$	113,608	$	107,739	$	222,353
Revenues from contract with customers - Ghana	143,060		325,078		380,579		742,185
Revenues from contract with customers - U.S. Gulf of Mexico	91,740		183,046		182,766		324,843
Provisional oil sales contracts	913		(1,364)		(3,589)		(9,998)
Oil and gas revenue	$	273,255	$	620,368	$	667,495	$	1,279,383

Concentration of Credit Risk

Our revenue can be materially affected by current economic conditions and the price of oil and natural gas. However, based on the current demand for crude oil and natural gas and the fact that alternative purchasers are readily available, we believe that the loss of our purchasers and/or marketing agents would not have a long‑term material adverse effect on our financial position or results of operations.

3. Acquisitions and Divestitures

In February 2023, Kosmos and Panoro Energy ASA (“Panoro”) entered into a petroleum contract covering Block EG-01 offshore Equatorial Guinea with the Republic of Equatorial Guinea. Kosmos holds a 24% participating interest in the block and the operator, Panoro, holds a 56% participating interest. The Equatorial Guinean national oil company, Guinea Equatorial De Petroles (“GEPetrol”), currently has a 20% carried participating interest during the exploration period. Should a commercial discovery be made, GEPetrol’s 20% carried interest will convert to a 20% participating interest. Block EG-01 currently comprises approximately 59,400 acres (240 square kilometers), with a first exploration period of three years from the effective date (March 1, 2023).

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In March 2023, we closed a farm-out agreement with Panoro, whereby Panoro acquired a 6.0% participating interest in Block S offshore Equatorial Guinea. As a result of the farm-out agreement, Kosmos’ participating interest in Block S was reduced to 34.0%.

4. Long-term Receivables

In February 2019, Kosmos and BP signed Carry Advance Agreements with the national oil companies of Mauritania and Senegal obligating us to finance a portion of the respective national oil company’s share of certain development costs incurred through first gas production for Greater Tortue Ahmeyim Phase 1, currently targeted in the first quarter of 2024. Kosmos’ share for the two agreements combined is originally estimated at approximately $240.0 million, which is to be repaid with interest through the national oil companies’ share of future revenues. As of June 30, 2023 and December 31, 2022, the balance due from the national oil companies (including interest) was $259.0 million and $218.4 million, respectively, which is classified as Long-term receivables on our consolidated balance sheets. Interest income on the long-term notes receivable was $3.8 million and $2.3 million for the three months ended June 30, 2023 and 2022, respectively, and $7.3 million and $4.3 million for the six months ended June 30, 2023 and 2022, respectively.

5. Property and Equipment

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


	June 30, 2023		December 31, 2022
	(In thousands)
Oil and gas properties:
Proved properties	$	7,358,007	$	6,953,435
Unproved properties	356,288		341,334
Total oil and gas properties	7,714,295		7,294,769
Accumulated depletion	(3,640,896)		(3,457,332)
Oil and gas properties, net	4,073,399		3,837,437

Other property	61,478		60,730
Accumulated depreciation	(57,056)		(55,520)
Other property, net	4,422		5,210

Property and equipment, net	$	4,077,821	$	3,842,647

We recorded depletion expense of $82.0 million and $114.7 million for the three months ended June 30, 2023 and 2022, respectively, and $183.6 million and $266.4 million for the six months ended June 30, 2023 and 2022, respectively.

6. Suspended Well Costs

The following table reflects the Company’s capitalized exploratory well costs on drilled wells as of and during the six months ended June 30, 2023.


	June 30, 2023
	(In thousands)
Beginning balance	$	145,957
Additions to capitalized exploratory well costs pending the determination of proved reserves	5,228
Reclassification due to determination of proved reserves	—
Capitalized exploratory well costs charged to expense	—
Ending balance	$	151,185

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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:


	June 30, 2023		December 31, 2022
	(In thousands, except project counts)
Exploratory well costs capitalized for a period of one year or less	$	—	$	—
Exploratory well costs capitalized for a period of one to three years	33,248		32,770
Exploratory well costs capitalized for a period of four to seven years	117,937		113,187
Ending balance	$	151,185	$	145,957
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year	2		2

As of June 30, 2023, the projects with exploratory well costs capitalized for more than one year since the completion of drilling are related to the Yakaar and Teranga discoveries in the Cayar Offshore Profond block offshore Senegal and the Asam discovery in Block S offshore Equatorial Guinea.

Yakaar and Teranga Discoveries — In May 2016, we drilled the Teranga-1 exploration well in the Cayar Offshore Profond block offshore Senegal, which encountered hydrocarbon pay. In June 2017, we drilled 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 drilled the Yakaar-2 appraisal well which encountered hydrocarbon pay. The Yakaar-2 well was drilled approximately nine kilometers from the Yakaar-1 exploration well. In July 2021, the current phase of the Cayar Block exploration license was extended up to an additional three years to 2024. The Yakaar and Teranga discoveries are being analyzed as a joint development. During the first and second quarter of 2023 we have continued progressing appraisal studies and maturing concept design. Following additional evaluation, a decision regarding commerciality is expected to be made.

Asam Discovery — In October 2019, we drilled the S-5 exploration well offshore Equatorial Guinea, which encountered hydrocarbon pay. The discovery was subsequently named Asam. In July 2020, an appraisal work program was approved by the government of Equatorial Guinea. The well is located within tieback range of the Ceiba FPSO and the appraisal work program is currently ongoing to integrate all available data into models to establish the scale of the discovered resource and evaluate the optimum development solution. During the fourth quarter of 2022, we received approval from the Government of Equatorial Guinea to enter the second sub-period phase of the Block S exploration license with a scheduled expiration in December 2024. Additionally, in December 2022 the Asam Field appraisal report was submitted to the Government of Equatorial Guinea. During the first and second quarter of 2023, studies and concept design continued to progress. Following additional evaluation, a decision regarding commerciality is expected to be made.

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7. Debt


	June 30, 2023		December 31, 2022
	(In thousands)
Outstanding debt principal balances:
Facility	$	775,000	$	625,000

7.125% Senior Notes	650,000		650,000
7.750% Senior Notes	400,000		400,000
7.500% Senior Notes	450,000		450,000
GoM Term Loan	137,500		145,000
Total long-term debt	2,412,500		2,270,000
Unamortized deferred financing costs and discounts	(38,811)		(44,089)
Total debt, net	2,373,689		2,225,911
Less: Current maturities of long-term debt	(15,000)		(30,000)
Long-term debt, net	$	2,358,689	$	2,195,911

Facility

The Facility supports our oil and gas exploration, appraisal and development programs and corporate activities. As of June 30, 2023, borrowings under the Facility totaled $775.0 million and the undrawn availability under the Facility was $370.1 million. Final maturity of the Facility is in March 2027. In April 2023, during the Spring 2023 redetermination, the Company’s lending syndicate approved a borrowing base capacity of approximately $1.15 billion resulting in a reduction of approximately $100 million of availability under the Facility. The borrowing base amount is based on the sum of the net present values of net cash flows and relevant capital expenditures reduced by certain percentages as well as value attributable to certain assets’ reserves and/or resources in the Company’s production assets in Ghana (excluding the additional interests in Jubilee and TEN acquired in the acquisition of Anadarko WCTP in October 2021) and Equatorial Guinea.

On November 23, 2022, the Company amended the Facility to update the interest rate benchmark from LIBOR to term SOFR, effective as of April 19, 2023. As amended, interest on the Facility is the aggregate of the applicable margin (3.75% to 5.00%, depending on the length of time that has passed from the date the Facility was entered into), plus the term SOFR reference rate administered by CME Group Benchmark Administration Limited for the relevant period published and a credit adjustment spread. Interest is payable on the last day of each interest period (and, if the interest period is longer than six months, on the dates falling at six-month intervals after the first day of the interest period). We pay commitment fees on the undrawn and unavailable portion of the total commitments, if any. Commitment fees are equal to 30% per annum of the then-applicable respective margin when a commitment is available for utilization and, equal to 20% per annum of the then-applicable respective margin when a commitment is not available for utilization. We recognize interest expense in accordance with ASC 835 — Interest, which requires interest expense to be recognized using the effective interest method. We determined the effective interest rate based on the estimated level of borrowings under the Facility.

We were in compliance with the financial covenants contained in the Facility as of March 31, 2023 (the most recent assessment date). The Facility, as amended, contains customary cross default provisions.

Corporate Revolver

The Corporate Revolver is available for general corporate purposes and for oil and gas exploration, appraisal and development programs. As of June 30, 2023, there were no outstanding borrowings under the Corporate Revolver and the undrawn availability was $250.0 million with an expiration date of December 31, 2024.

The Company capitalized $6.1 million of deferred financing costs associated with entering into the new revolving credit facility in March 2022, which is being amortized over the term of the new revolving credit facility. On November 23, 2022, the Company amended the Corporate Revolver to update the interest rate benchmark from compounded SOFR to term SOFR, effective as of April 19, 2023. As amended, interest on the Corporate Revolver is the aggregate of a 7.0% margin, the term SOFR reference rate administered by CME Group Benchmark Administration Limited for the relevant period published and a credit adjustment spread. Interest is payable on the last day of each interest period (and, if the interest period is longer than six months, on the dates falling at six-month intervals after the first day of the interest period). We pay commitment fees

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on the undrawn portion of the total commitments. Commitment fees for the lenders are equal to 30% per annum of the respective margin when a commitment is available for utilization.

We were in compliance with the financial covenants contained in the Corporate Revolver as of March 31, 2023 (the most recent assessment date). The Corporate Revolver contains customary cross default provisions.

7.125% Senior Notes due 2026

In April 2019, the Company issued $650.0 million of 7.125% Senior Notes and received net proceeds of approximately $640.0 million after deducting commissions and other expenses.

The 7.125% Senior Notes mature on April 4, 2026. Interest is payable in arrears each April 4 and October 4, commencing on October 4, 2019. The 7.125% 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, 7.750% Senior Notes and the 7.500% Senior Notes) and rank effectively junior in right of payment to all of its existing and future secured indebtedness (including all borrowings under the Facility) and all borrowings under the GoM Term Loan. The 7.125% Senior Notes are guaranteed on a senior, unsecured basis by certain subsidiaries owning the Company's U.S. Gulf of Mexico assets and the interests acquired in the Anadarko WCTP acquisition, and on a subordinated, unsecured basis by certain subsidiaries that borrow under, or guarantee, the Facility and that guarantee the Corporate Revolver, the 7.750% Senior Notes and the 7.500% Senior Notes. The 7.125% Senior Notes contain customary cross default provisions.

7.750% Senior Notes due 2027

In October 2021, the Company issued $400.0 million of 7.750% Senior Notes and received net proceeds of approximately $395.0 million after deducting fees.

The 7.750% Senior Notes mature on May 1, 2027. Interest is payable in arrears each May 1 and November 1, commencing on May 1, 2022. The 7.750% 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, the 7.125% Senior Notes and the 7.500% Senior Notes) and rank effectively junior in right of payment to all of its existing and future secured indebtedness (including all borrowings under the Facility) and all borrowings under the GoM Term Loan. The 7.750% Senior Notes are guaranteed on a senior, unsecured basis by certain subsidiaries owning the Company's U.S. Gulf of Mexico assets and the interests acquired in the Anadarko WCTP acquisition, and on a subordinated, unsecured basis by certain subsidiaries that borrow under, or guarantee, the Facility and that guarantee the Corporate Revolver, the 7.125% Senior Notes and the 7.500% Senior Notes. The 7.750% Senior Notes contain customary cross default provisions.

7.500% Senior Notes due 2028

In March 2021, the Company issued $450.0 million of 7.500% Senior Notes and received net proceeds of approximately $444.4 million after deducting fees.

The 7.500% Senior Notes mature on March 1, 2028. Interest is payable in arrears each March 1 and September 1, commencing on September 1, 2021. The 7.500% 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, the 7.125% Senior Notes and the 7.750% Senior Notes) and rank effectively junior in right of payment to all of its existing and future secured indebtedness (including all borrowings under the Facility) and all borrowings under the GoM Term Loan. The 7.500% Senior Notes are guaranteed on a senior, unsecured basis by certain subsidiaries owning the Company's U.S. Gulf of Mexico assets and the interests in the Anadarko WCTP acquisition, and on a subordinated, unsecured basis by certain subsidiaries that borrow under, or guarantee, the Facility and that guarantee the Corporate Revolver, and the 7.125% Senior Notes and the 7.750% Senior Notes. The 7.500% Senior Notes contain customary cross default provisions.

GoM Term Loan

In September 2020, the Company entered into a five-year $200.0 million senior secured term-loan credit agreement secured against the Company's U.S. Gulf of Mexico assets with net proceeds received of $197.7 million after deducting fees and other expenses. The GoM Term Loan also includes an accordion feature providing for incremental commitments of up to $100.0 million subject to certain conditions. The GoM Term Loan bears interest at the weighted average margin of 5.9% per annum plus a benchmark rate of 0.35% and Federal Funds Rate and matures in 2025, with quarterly principal repayments having started since the fourth quarter of 2021. In June 2023, the Company amended the GoM Term Loan deferring the scheduled quarterly principal repayments through March 31, 2024 and extending the deferred repayments to the maturity date.

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As of June 30, 2023, $15.0 million of the total $137.5 million outstanding under the GoM Term Loan has been classified within Current maturities of long-term debt on our consolidated balance sheet.

We were in compliance with the covenants, representations and warranties contained in the GoM Term Loan as of March 31, 2023 (the most recent assessment date). The GoM Term Loan contains customary cross default provisions.

Principal Debt Repayments

At June 30, 2023, the estimated repayments of debt during the five fiscal year periods and thereafter are as follows:


	Payments Due by Year
	Total		2023(2)		2024		2025		2026		2027		Thereafter
	(In thousands)
Principal debt repayments(1)	$	2,412,500	$	—	$	123,047	$	334,950	$	929,282	$	575,221	$	450,000

__________________________________

(1)Includes the scheduled maturities for outstanding principal debt balances. The scheduled maturities of debt related to the Facility as of June 30, 2023 are based on 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 July 1, 2023 through December 31, 2023.

Interest and other financing costs, net

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
	(In thousands)
Interest expense	$	51,965	$	43,016	$	100,480	$	86,178
Amortization—deferred financing costs	2,530		2,591		5,081		5,261
Loss on extinguishment of debt	—		—		—		192
Capitalized interest	(33,688)		(19,187)		(63,891)		(35,326)
Deferred interest	670		10		353		(1,440)
Interest income	(4,445)		(3,344)		(8,586)		(4,884)
Other, net	7,339		6,296		15,502		12,540
Interest and other financing costs, net	$	24,371	$	29,382	$	48,939	$	62,521

Capitalized interest for the six months ended June 30, 2023 and 2022 primarily relates to spend on the Greater Tortue Ahmeyim Phase 1 project. After first gas production on the Greater Tortue Ahmeyim Phase 1 project, which is targeted in the first quarter of 2024, we will no longer capitalize interest on the project.

8. Derivative Financial Instruments

We use financial derivative contracts to manage exposures to commodity price and interest rate fluctuations. We do not hold or issue derivative financial instruments for trading purposes.

We manage market and counterparty credit risk in accordance with our policies and guidelines. In accordance with these policies and guidelines, our management determines the appropriate timing and extent of derivative transactions. We have included an estimate of non-performance risk in the fair value measurement of our derivative contracts as required by ASC 820 — Fair Value Measurement.

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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 June 30, 2023. Volumes and weighted average prices are net of any offsetting derivative contracts entered into.


				Weighted Average Price per Bbl
				Net Deferred
				Premium
				Payable/		Sold
Term	Type of Contract	Index	MBbl	(Receivable)		Put		Floor		Ceiling
2023:
Jul - Dec	Three-way collars	Dated Brent	3,000	$	1.34	$	49.17	$	71.67	$	107.58
Jul - Dec	Two-way collars	Dated Brent	2,500	1.69		—		72.00		112.00


2024:
Jan - Dec	Three-way collars	Dated Brent	2,000	1.35		45.00		70.00		97.50
Jan - Jun	Two-way collars	Dated Brent	2,000	1.24		—		65.00		85.00

__________________________________

In July 2023, we entered into Dated Brent three-way collar contracts for 2.0 MMBbl from January 2024 through December 2024 with sold put price of $45.00 per barrel, a floor price of $70.00 per barrel and a ceiling price of $95.00 per barrel.

The following tables disclose the Company’s derivative instruments as of June 30, 2023 and December 31, 2022, and gain/(loss) from derivatives during the three and six months ended June 30, 2023 and 2022, respectively:


		Estimated Fair Value
		Asset (Liability)
Type of Contract	Balance Sheet Location	June 30, 2023		December 31, 2022
		(In thousands)
Derivatives not designated as hedging instruments:
Derivative assets:
Commodity	Derivatives assets—current	$	11,270	$	7,344
Provisional oil sales	Receivables: Oil sales	—		1,170
Commodity	Derivatives assets—long-term	3,505		1,725
Derivative liabilities:
Commodity	Derivatives liabilities—current	(1,097)		(6,773)
Commodity	Derivatives liabilities—long-term	(138)		(778)
Total derivatives not designated as hedging instruments		$	13,540	$	2,688


		Amount of Gain/(Loss)				Amount of Gain/(Loss)
		Three Months Ended				Six Months Ended
		June 30,				June 30,
Type of Contract	Location of Gain/(Loss)	2023		2022		2023		2022
		(In thousands)
Derivatives not designated as hedging instruments:
Provisional oil sales	Oil and gas revenue	$	913	$	(1,364)	$	(3,589)	$	(9,998)
Commodity	Derivatives, net	(3,031)		(75,204)		3,809		(357,376)
Total derivatives not designated as hedging instruments		$	(2,118)	$	(76,568)	$	220	$	(367,374)

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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 June 30, 2023 and December 31, 2022, 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.

9. Fair Value Measurements

In accordance with ASC 820 — Fair Value Measurement, 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 June 30, 2023 and December 31, 2022, 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)
June 30, 2023
Assets:
Commodity derivatives	$	—	$	14,775	$	—	$	14,775
Provisional oil sales	—		—		—		—

Liabilities:
Commodity derivatives	—		(1,235)		—		(1,235)

Total	$	—	$	13,540	$	—	$	13,540
December 31, 2022
Assets:
Commodity derivatives	$	—	$	9,069	$	—	$	9,069
Provisional oil sales	—		1,170		—		1,170

Liabilities:
Commodity derivatives	—		(7,551)		—		(7,551)

Total	$	—	$	2,688	$	—	$	2,688

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 credit losses, and other long-term assets approximate fair value. The estimates of fair value of these items are based on Level 2 inputs.

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Commodity Derivatives

Our commodity derivatives represent crude oil collars, put options and call options for notional barrels of oil at fixed Dated Brent or NYMEX WTI oil prices. The values attributable to our oil derivatives are based on (i) the contracted notional volumes, (ii) independent active futures price quotes for the respective index, (iii) a credit-adjusted yield curve applicable to each counterparty by reference to the credit default swap (“CDS”) market and (iv) an independently sourced estimate of volatility for the respective index. The volatility estimate was provided by certain independent brokers who are active in buying and selling oil options and was corroborated by market-quoted volatility factors. The deferred premium is included in the fair market value of the commodity derivatives. See Note 8 — 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 June 30, 2023 and December 31, 2022:


	June 30, 2023				December 31, 2022
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In thousands)
7.125% Senior Notes	$	646,294	$	572,598	$	645,699	$	558,201
7.750% Senior Notes	396,297		343,516		395,893		335,592
7.500% Senior Notes	445,921		372,893		445,564		361,958
GoM Term Loan	137,500		137,500		145,000		145,000

Facility	775,000		775,000		625,000		625,000
Total	$	2,401,012	$	2,201,507	$	2,257,156	$	2,025,751

The carrying values of our 7.125% Senior Notes, 7.750% Senior Notes and 7.500% Senior Notes represent the principal amounts outstanding less unamortized discounts. The fair values of our 7.125% Senior Notes, 7.750% Senior Notes and 7.500% Senior Notes are based on quoted market prices, which results in a Level 1 fair value measurement. The carrying values of the GoM Term Loan and Facility approximate fair value since they are subject to short-term floating interest rates that approximate the rates available to us for those periods.

Nonrecurring Fair Value Measurements - Long-lived assets

Certain long-lived assets are reported at fair value on a non-recurring basis on the Company's consolidated balance sheet. These long-lived assets are not measured at fair value on an ongoing basis but are subject to fair value adjustments in certain circumstances. Our long-lived assets are reviewed for impairment when changes in circumstances indicate that the carrying amount of an asset may not be recoverable.

The Company calculates the estimated fair values of its long-lived assets using the income approach described in the ASC 820 — Fair Value Measurements. Significant inputs associated with the calculation of estimated discounted future net cash flows include anticipated future production, pricing estimates, capital and operating costs, market-based weighted average cost of capital, and risk adjustment factors applied to reserves. These are classified as Level 3 fair value assumptions. The Company utilizes an average of third-party industry forecasts of Dated Brent, adjusted for location and quality differentials, to determine our pricing assumptions. In order to evaluate the sensitivity of the assumptions, we analyze sensitivities to prices, production, and risk adjustment factors.

During the three and six months ended June 30, 2023 and 2022, the Company did not recognize impairment of proved oil and gas properties as no impairment indicators were identified. If we experience material declines in oil pricing expectations

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in the future, significant increases in our estimated future expenditures or a significant decrease in our estimated production profile, our long-lived assets could be at risk of impairment.

10. 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 LTIP awards. We recorded compensation expense from awards granted under our LTIP of $11.1 million and $8.7 million during the three months ended June 30, 2023 and 2022, respectively, and $21.2 million and $17.1 million during the six months ended June 30, 2023 and 2022, respectively. The total tax benefit for the three months ended June 30, 2023 and 2022 was $1.9 million and $1.5 million, respectively, and $3.7 million and $2.9 million during the six months ended June 30, 2023 and 2022, respectively. Additionally, we recorded a net tax shortfall (windfall) related to equity-based compensation of $(0.5) million and $(0.5) million for the three months ended June 30, 2023 and 2022, respectively, and $(3.1) million and $0.7 million during the six months ended June 30, 2023 and 2022, respectively. The fair value of awards vested during the three months ended June 30, 2023 and 2022 was $3.8 million and $4.0 million, respectively, and $44.8 million and $21.3 million during the six months ended June 30, 2023 and 2022, 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 of these grants vest over three years. Upon vesting, restricted stock units become issued and outstanding stock.

In June 2023, the Company’s stockholders approved the Amended and Restated Kosmos Energy Ltd. Long Term Incentive Plan, which authorized an additional 17.0 million shares of common stock available for issuance under the LTIP.

The following table reflects the outstanding restricted stock units as of June 30, 2023:


		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, 2022	4,916	$	4.18	12,041	$	5.61
Granted(1)	2,687	7.60		3,415	12.25
Forfeited(1)	(151)	5.46		(64)	8.47
Vested	(2,728)	3.86		(2,949)	8.22
Outstanding at June 30, 2023	4,724	5.70		12,443	6.57

__________________________________

(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 June 30, 2023, total equity-based compensation to be recognized on unvested restricted stock units is $49.7 million over a weighted average period of 1.92 years. At June 30, 2023, the Company had approximately 18.5 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 $1.06 to $12.33 per award. The Monte Carlo simulation model utilized multiple input variables that determined the probability of satisfying the market condition stipulated in the award grant and calculated 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 50.0% to 105.0%. 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 0.2% to 3.7%.

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11. Income Taxes

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 statutory 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.

Income before income taxes is composed of the following:


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
	(In thousands)
United States	$	(24,529)	$	52,381	$	(49,123)	$	61,664
Foreign	77,712		141,770		241,938		145,340
Income before income taxes	$	53,183	$	194,151	$	192,815	$	207,004

For the three months ended, June 30, 2023 and 2022, our effective tax rate was 56% and 40%, respectively. For the six months ended June 30, 2023 and 2022, our effective tax rate was 45% and 43%, respectively. For the three and six months ended June 30, 2023 and 2022, our overall effective tax rates were 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,

•Jurisdictions that have a 0% statutory tax rate or that are tax exempt,

•Jurisdictions where we have incurred losses and have recorded valuation allowances against the corresponding deferred tax assets, and

•Other non-deductible expenses, primarily in the U.S.

12. Net Income Per Share

The following table is a reconciliation between net income and the amounts used to compute basic and diluted net income per share and the weighted average shares outstanding used to compute basic and diluted net income per share:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2023		2022		2023		2022
	(In thousands, except per share data)
Numerator:
Net income allocable to common stockholders	$	23,345	$	117,173	$	106,654	$	118,573




Denominator:
Weighted average number of shares outstanding:
Basic	459,984		455,512		459,155		454,811
Restricted stock units(1)	19,032		20,133		19,747		18,660
Diluted	479,016		475,645		478,902		473,471
Net income per share:
Basic	$	0.05	$	0.26	$	0.23	$	0.26
Diluted	$	0.05	$	0.25	$	0.22	$	0.25

__________________________________

(1)We excluded restricted stock units of 1.8 million and 0.1 million for the three months ended June 30, 2023 and 2022, respectively, and 1.4 million and 0.1 million for the six months ended June 30, 2023 and 2022, respectively from the computations of diluted net income per share because the effect would have been anti-dilutive.

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13. 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 have a commitment to drill three development wells and one exploration well in Equatorial Guinea. We have a $200.2 million FPSO Contract Liability in Other long-term liabilities related to the deferred sale of the Greater Tortue FPSO.

Performance Obligations

As of June 30, 2023 and December 31, 2022, the Company had performance bonds totaling $195.5 million for our supplemental bonding requirements stipulated by the BOEM and $9.7 million to third parties 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.

14. Additional Financial Information

Accrued Liabilities

Accrued liabilities consisted of the following:


	June 30, 2023		December 31, 2022
	(In thousands)
Accrued liabilities:
Exploration, development and production	$	66,331	$	80,598
Revenue payable	20,676		26,087
Current asset retirement obligations	9,504		1,732
General and administrative expenses	18,028		32,069
Interest	40,951		44,740
Income taxes	77,199		127,183
Taxes other than income	1,510		1,524
Derivatives	1,242		6,440
Other	8,439		4,833
	$	243,880	$	325,206

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Asset Retirement Obligations

The following table summarizes the changes in the Company's asset retirement obligations as of and during the six months ended June 30, 2023:


	June 30, 2023
	(In thousands)
Asset retirement obligations:
Beginning asset retirement obligations	$	302,534
Liabilities incurred during period	6,580
Liabilities settled during period	(3,342)
Revisions in estimated retirement obligations	88
Accretion expense	14,186
Ending asset retirement obligations	$	320,046

Other Expenses, Net

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
	(In thousands)
Loss on disposal of inventory	$	2,704	$	68	$	2,939	$	285
Loss on asset retirement obligations liability settlements	—		238		115		620
Restructuring charges	—		(9)		—		(4)
Other, net	2,075		(3,825)		3,755		(2,003)
Other expenses, net	$	4,779	$	(3,528)	$	6,809	$	(1,102)

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15. Business Segment Information

Kosmos is engaged in a single line of business, which is the exploration, development and production of oil and gas. At June 30, 2023, the Company had operations in four geographic reporting segments: Ghana, Equatorial Guinea, Mauritania/Senegal and the U.S. Gulf of Mexico. To assess performance of the reporting segments, the Chief Operating Decision Maker 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 June 30, 2023
Revenues and other income:
Oil and gas revenue	$	146,850	$	34,665	$	—	$	91,740	$	—	$	—	$	273,255

Other income, net	—		10		—		1,067		42,940		(43,957)		60
Total revenues and other income	146,850		34,675		—		92,807		42,940		(43,957)		273,315
Costs and expenses:
Oil and gas production	21,627		14,840		—		27,112		—		—		63,579

Exploration expenses	163		1,796		3,605		3,552		1,899		—		11,015
General and administrative	3,284		1,151		1,830		4,673		53,431		(40,925)		23,444
Depletion, depreciation and amortization	42,347		8,557		207		38,449		353		—		89,913

Interest and other financing costs, net(1)	8,408		(699)		(29,547)		3,000		43,209		—		24,371
Derivatives, net	—		—		—		—		3,031		—		3,031
Other expenses, net	2,903		383		1,516		1,678		1,331		(3,032)		4,779
Total costs and expenses	78,732		26,028		(22,389)		78,464		103,254		(43,957)		220,132
Income (loss) before income taxes	68,118		8,647		22,389		14,343		(60,314)		—		53,183
Income tax expense	24,465		3,775		—		225		1,373		—		29,838
Net income (loss)	$	43,653	$	4,872	$	22,389	$	14,118	$	(61,687)	$	—	$	23,345

Consolidated capital expenditures, net	$	83,556	$	17,823	$	46,689	$	19,639	$	1,938	$	—	$	169,645

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	Ghana		Equatorial Guinea		Mauritania/Senegal		U.S. Gulf of Mexico		Corporate & Other		Eliminations		Total
	(In thousands)
Six months ended June 30, 2023
Revenues and other income:
Oil and gas revenue	$	380,100	$	104,629	$	—	$	182,766	$	—	$	—	$	667,495

Other income, net	(425)		10		—		2,086		70,914		(72,898)		(313)
Total revenues and other income	379,675		104,639		—		184,852		70,914		(72,898)		667,182
Costs and expenses:
Oil and gas production	51,236		43,923		—		52,356		—		—		147,515

Exploration expenses	637		4,083		8,219		7,177		2,899		—		23,015
General and administrative	7,446		2,662		4,803		9,807		104,600		(76,707)		52,611
Depletion, depreciation and amortization	100,108		22,083		402		75,964		730		—		199,287

Interest and other financing costs, net(1)	28,167		(1,386)		(55,649)		6,092		71,715		—		48,939
Derivatives, net	—		—		—		—		(3,809)		—		(3,809)
Other expenses, net	(3,655)		(47)		2,721		2,801		1,180		3,809		6,809
Total costs and expenses	183,939		71,318		(39,504)		154,197		177,315		(72,898)		474,367
Income (loss) before income taxes	195,736		33,321		39,504		30,655		(106,401)		—		192,815
Income tax expense	69,864		13,360		—		1,065		1,872		—		86,161
Net income (loss)	$	125,872	$	19,961	$	39,504	$	29,590	$	(108,273)	$	—	$	106,654

Consolidated capital expenditures, net	$	149,478	$	24,956	$	149,751	$	48,319	$	3,574	$	—	$	376,078

As of June 30, 2023
Property and equipment, net	$	1,262,286	$	401,672	$	1,599,864	$	797,556	$	16,443	$	—	$	4,077,821
Total assets	$	3,198,853	$	1,610,111	$	2,340,829	$	3,780,742	$	20,248,788	$	(26,371,703)	$	4,807,619

______________________________________

(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.

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	Ghana(2)		Equatorial Guinea		Mauritania/Senegal		U.S. Gulf of Mexico		Corporate & Other		Eliminations		Total
	(In thousands)
Three months ended June 30, 2022
Revenues and other income:
Oil and gas revenue	$	326,091	$	111,231	$	—	$	183,046	$	—	$	—	$	620,368
Gain on sale of assets	—		—		—		471		—		—		471
Other income, net	—		—		—		484		108,192		(108,633)		43
Total revenues and other income	326,091		111,231		—		184,001		108,192		(108,633)		620,882
Costs and expenses:
Oil and gas production	37,776		25,839		—		26,574		—		—		90,189
Facilities insurance modifications, net	(384)		—		—		—		—		—		(384)
Exploration expenses	1,903		1,366		74,975		10,520		801		—		89,565
General and administrative	3,444		1,415		2,270		3,433		47,491		(33,429)		24,624
Depletion, depreciation and amortization	62,376		15,050		61		43,753		439		—		121,679

Interest and other financing costs, net(1)	14,260		(607)		(15,662)		2,734		28,657		—		29,382
Derivatives, net	—		—		—		—		75,204		—		75,204
Other expenses, net	66,235		4,894		(1,930)		4,295		(1,818)		(75,204)		(3,528)
Total costs and expenses	185,610		47,957		59,714		91,309		150,774		(108,633)		426,731
Income (loss) before income taxes	140,481		63,274		(59,714)		92,692		(42,582)		—		194,151
Income tax expense	49,798		24,719		—		—		2,461		—		76,978
Net income (loss)	$	90,683	$	38,555	$	(59,714)	$	92,692	$	(45,043)	$	—	$	117,173

Consolidated capital expenditures, net	$	56,128	$	14,074	$	136,615	$	39,940	$	1,534	$	—	$	248,291

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	Ghana(2)		Equatorial Guinea		Mauritania/Senegal		U.S. Gulf of Mexico(3)		Corporate & Other		Eliminations		Total
	(In thousands)
Six months ended June 30, 2022
Revenues and other income:
Oil and gas revenue	$	735,571	$	218,969	$	—	$	324,843	$	—	$	—	$	1,279,383
Gain on sale of assets	—		—		—		471		—		—		471
Other income, net	1		—		—		1,028		423,304		(424,238)		95
Total revenues and other income	735,572		218,969		—		326,342		423,304		(424,238)		1,279,949
Costs and expenses:
Oil and gas production	113,119		48,464		—		53,309		—		—		214,892
Facilities insurance modifications, net	6,752		—		—		—		—		—		6,752
Exploration expenses	1,974		2,976		78,089		17,096		1,306		—		101,441
General and administrative	7,413		3,017		4,266		8,377		94,206		(66,862)		50,417
Depletion, depreciation and amortization	163,786		32,988		115		82,947		812		—		280,648

Interest and other financing costs, net(1)	29,286		(1,088)		(28,501)		5,458		57,366		—		62,521
Derivatives, net	—		—		—		—		357,376		—		357,376
Other expenses, net	316,797		24,017		(1,344)		17,672		(868)		(357,376)		(1,102)
Total costs and expenses	639,127		110,374		52,625		184,859		510,198		(424,238)		1,072,945
Income (loss) before income taxes	96,445		108,595		(52,625)		141,483		(86,894)		—		207,004
Income tax expense	34,780		48,049		—		3,102		2,500		—		88,431
Net income (loss)	$	61,665	$	60,546	$	(52,625)	$	138,381	$	(89,394)	$	—	$	118,573

Consolidated capital expenditures, net	$	(8,057)	$	24,296	$	147,416	$	64,244	$	2,712	$	—	$	230,611

As of June 30, 2022
Property and equipment, net	$	1,661,177	$	389,499	$	1,092,873	$	870,768	$	18,010	$	—	$	4,032,327
Total assets	$	3,127,071	$	1,097,801	$	1,540,896	$	3,605,374	$	18,046,768	$	(22,486,720)	$	4,931,190

______________________________________

(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.

(2)Includes activity related to the interest pre-empted by Tullow prior to the March 17, 2022 closing date of the Tullow pre-emption transaction. Additionally, cash consideration of $118.2 million is included as reduction in Consolidated capital expenditures for the six months ended June 30, 2022.

(3)Includes activity related to our acquisition of an additional interest in the Kodiak Oil Field commencing June 9, 2022, the acquisition date. Additionally, cash consideration paid of $29.0 million is included in consolidated capital expenditures for the three and six months ended June 30, 2022.

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	Six Months Ended June 30,
	2023		2022
	(In thousands)
Consolidated capital expenditures:
Consolidated Statements of Cash Flows - Investing activities:
Oil and gas assets	$	416,867	$	320,787
Acquisition of oil and gas properties	—		21,205
Proceeds on sale of assets	—		(118,693)
Adjustments:
Changes in capital accruals	1,290		7,061
Exploration expense, excluding unsuccessful well costs and leasehold impairments(1)	21,702		27,779
Capitalized interest	(63,891)		(35,326)
Other	110		7,798
Total consolidated capital expenditures, net	$	376,078	$	230,611

______________________________________

(1)Unsuccessful well costs and leasehold impairments 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, 2022, 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 offshore Atlantic Margins. Our key assets include production offshore Ghana, Equatorial Guinea and the U.S. Gulf of Mexico, as well as world-class gas projects offshore Mauritania and Senegal. We also pursue a proven basin exploration program in Equatorial Guinea and the U.S. Gulf of Mexico.

Globally, the impacts of Russia’s war in Ukraine, a potential recession, COVID-19 and other varying macroeconomic conditions have impacted supply and demand for oil and gas, which also resulted in significant variability in oil and gas prices, and could materially impact the Company’s business in future periods. The Company’s revenues, earnings, cash flows, capital investments, debt capacity and, ultimately, future rate of growth are highly dependent on these commodity prices.

Recent Developments

Ghana

During the second quarter of 2023, Ghana production averaged approximately 108,500 Boepd gross (33,700 Boepd net).

The Jubilee development drilling campaign continued to progress during the second quarter of 2023 bringing one producer well in the Jubilee Main Field online during the quarter and successful start-up of the Jubilee South East project with two producers online in July 2023. The Jubilee partnership now expects to bring an additional three new wells online in the second half of 2023; one additional producer well and one water injection well in the Jubilee Main Field as well as one additional water injection well related to Jubilee South East which has been accelerated into 2023 given the efficiency of the drilling program in Ghana.

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In connection with the approval of the Jubilee Phase 1 PoD in 2009, the Jubilee Field partners agreed to provide the first 200 Bcf of natural gas produced from the Jubilee Field Phase 1 development to the Government of Ghana at no cost. As of January 1, 2023, the Jubilee partners had fulfilled this commitment, providing 200 Bcf of natural gas to the Government of Ghana. From 2018 through 2022, approximately 19 Bcf of the first 200 Bcf of natural gas was substituted from the TEN Fields in order to maintain consistent gas volumes to shore for Ghana domestic power purposes. Commencing on January 1, 2023, the volume of approximately 19 Bcf of Jubilee gas (in restoration of the amount originally substituted from TEN) has been sold to Ghana under the terms of the TAG GSA at $0.50 per MMBtu. The Jubilee partners have reached an interim agreement to sell Jubilee Field gas at a price of $2.90 per MMBtu to the Government of Ghana beyond the 19 Bcf from the Jubilee Field through September 2023, while the partners continue on-going discussions with the Government of Ghana regarding a long-term future gas sales agreement covering both the Jubilee and TEN Fields. During the second quarter of 2023, the operator submitted a draft amended plan of development for TEN, as well as a term sheet for a gas sales agreement covering future gas sales from both the Jubilee and TEN Fields, to the Government of Ghana.

U.S. Gulf of Mexico

Production from the U.S. Gulf of Mexico averaged approximately 15,900 Boepd net (~81% oil) for the second quarter of 2023.

The Kodiak #3 infill well located in Mississippi Canyon was brought online in April 2021. The well experienced production issues and was shut-in. In March 2022, the Company commenced operations to plug back and side-track the original Kodiak #3 infill well. The Kodiak-3ST well was brought online in early September 2022. Well results and initial production were in line with expectations, however well productivity declined through the end of the third quarter of 2022. Workover plans have been developed for remediation and are now expected to commence around the middle of 2024 given the better than forecast performance of the well this quarter.

The Winterfell development project continued to make progress during the second quarter of 2023. Drilling and completion of the three wells for the first phase of development under the Field Development Plan is expected to start in the third quarter of 2023 and first production for the project is targeted to be around the end of the first quarter of 2024. The host facility production handling agreement and midstream export agreements are expected to be completed by the end of 2023.

The Odd Job Field subsea pump installation project was approximately 55% complete as of the end of the second quarter of 2023 with an expected online date in the middle of 2024. The project is expected to extend the life and increase reserves of the Odd Job Field.

In July 2023, Kosmos spud the Tiberius infrastructure-led exploration prospect, which is located in block 964 of Keathley Canyon (33% working interest) in the Outer Wilcox play. We expect results of the Tiberius exploration well around the end of the third quarter of 2023.

Equatorial Guinea

Production in Equatorial Guinea averaged approximately 24,000 Bopd gross (8,400 Bopd net) in the second quarter of 2023.

The 2023 Ceiba Field and Okume Complex development drilling campaign is expected to begin in the fourth quarter of 2023. The drilling campaign is planned to include two production well workovers, three in-fill production wells and an ILX well (Akeng Deep) in Block S.

Mauritania and Senegal

Greater Tortue Ahmeyim Unit

Critical path to first gas on Phase 1 of the Greater Tortue project is through the completion of the subsea work scope. As a result of a delay in these activities, first gas for the project is now targeted in the first quarter of 2024, with the delivery of the other work scopes being optimized for the updated project schedule. The following milestones were achieved through the second quarter of 2023 and filing date:

•FLNG: Construction and mechanical completion activities are finishing and pre-commissioning work is underway. Sailaway is targeted around the end of the third quarter of 2023 with the vessel expected to arrive on location offshore Mauritania/Senegal around the end of 2023 when hookup work is expected to commence.

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•FPSO: In January 2023, the FPSO vessel departed China making a planned stopover in Singapore to install the fair leads. Arrival on location offshore Mauritania/Senegal is expected in the fourth quarter of 2023 to align with the revised schedule for the subsea work scope.

•Hub Terminal: Construction work is complete, and activity is focused on progressing handover to operations in the third quarter of 2023.

•Subsea: Due to a delay in the subsea workstream, the operator has put in place a plan to finish installation of the infield flowlines and subsea structures in the first quarter of 2024.

•Drilling: Successfully drilled and completed all four wells with expected production capacity significantly higher than what is required for first gas.

Sao Tome and Principe

In the second quarter of 2023, we received approval for a twelve month extension to May 2024 for the current exploration phase for Block 5 offshore Sao Tome and Principe.

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Results of Operations

All of our results, as presented in the table below, represent operations from Ghana, the U.S. Gulf of Mexico and Equatorial Guinea. Certain operating results and statistics for the three and six months ended June 30, 2023 and 2022 are included in the following tables:


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
	(In thousands, except per volume data)
Sales volumes:
Oil (MBbl)	3,547		5,339		8,492		11,569
Gas (MMcf)	2,774		1,252		5,535		2,256
NGL (MBbl)	107		129		203		246
Total (MBoe)	4,116		5,677		9,618		12,191
Total (Boepd)	45,234		62,381		53,135		67,354

Revenues:
Oil sales	$	267,149	$	604,668	$	655,248	$	1,254,676
Gas sales	3,568		10,271		7,434		15,207
NGL sales	2,538		5,429		4,813		9,500
Total oil and gas revenue	$	273,255	$	620,368	$	667,495	$	1,279,383

Average oil sales price per Bbl	$	75.32	$	113.25	$	77.16	$	108.45
Average gas sales price per Mcf	1.29		8.20		1.34		6.74
Average NGL sales price per Bbl	23.72		42.09		23.71		38.62
Average total sales price per Boe	66.38		109.28		69.40		104.94

Costs:
Oil and gas production, excluding workovers	$	59,302	$	88,120	$	141,817	$	209,343
Oil and gas production, workovers	4,277		2,069		5,698		5,549
Total oil and gas production costs	$	63,579	$	90,189	$	147,515	$	214,892

Depletion, depreciation and amortization	$	89,913	$	121,679	$	199,287	$	280,648

Average cost per Boe:
Oil and gas production, excluding workovers	$	14.41	$	15.52	$	14.75	$	17.17
Oil and gas production, workovers	1.04		0.36		0.59		0.46
Total oil and gas production costs	15.45		15.88		15.34		17.63

Depletion, depreciation and amortization	21.84		21.43		20.72		23.02
Total	$	37.29	$	37.31	$	36.06	$	40.65

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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 June 30, 2023:


	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	0.39	—	—	8	3.09
TEN	—	—	—	—	—	—	5	1.02
Equatorial Guinea
Block S	—	—	—	—	1	0.34	—	—
Okume	—	—	—	—	—	—	1	0.40
U.S. Gulf of Mexico
Winterfell	—	—	—	—	—	—	2	0.50

Mauritania / Senegal

Mauritania BirAllah Block	—	—	—	—	2	0.56	—	—
Greater Tortue Ahmeyim Unit	—	—	—	—	1	0.27	—	—
Senegal Cayar Profond	—	—	—	—	3	0.90	—	—
Total	—	—	1	0.39	7	2.07	16	5.01

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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 June 30, 2023 compared to three months ended June 30, 2022


	Three Months Ended
	June 30,				Increase
	2023		2022		(Decrease)
	(In thousands)
Revenues and other income:
Oil and gas revenue	$	273,255	$	620,368	$	(347,113)
Gain on sale of assets	—		471		(471)
Other income, net	60		43		17
Total revenues and other income	273,315		620,882		(347,567)
Costs and expenses:
Oil and gas production	63,579		90,189		(26,610)
Facilities insurance modifications, net	—		(384)		384
Exploration expenses	11,015		89,565		(78,550)
General and administrative	23,444		24,624		(1,180)
Depletion, depreciation and amortization	89,913		121,679		(31,766)

Interest and other financing costs, net	24,371		29,382		(5,011)
Derivatives, net	3,031		75,204		(72,173)
Other expenses, net	4,779		(3,528)		8,307
Total costs and expenses	220,132		426,731		(206,599)
Income before income taxes	53,183		194,151		(140,968)
Income tax expense (benefit)	29,838		76,978		(47,140)
Net income	$	23,345	$	117,173	$	(93,828)

Oil and gas revenue. Oil and gas revenue decreased by $347.1 million during the three months ended June 30, 2023, as compared to the three months ended June 30, 2022 primarily as a result of the timing of our international oil liftings, lower average oil prices and lower production due to natural field decline. We sold 4,116 MBoe at an average realized price per barrel equivalent of $66.38 during the three months ended June 30, 2023 and 5,677 MBoe at an average realized price per barrel equivalent of $109.28 during the three months ended June 30, 2022.

Oil and gas production. Oil and gas production costs decreased by $26.6 million during the three months ended June 30, 2023, as compared to the three months ended June 30, 2022 primarily as a result of decreased sales volumes due to the timing of our international oil liftings and natural field decline, along with lower operating costs from the Jubilee Field.

Exploration expenses. Exploration expenses decreased by $78.6 million during the three months ended June 30, 2023, as compared to the three months ended June 30, 2022 primarily a result of the $64.2 million of previously capitalized costs related to the BirAllah and Orca discoveries incurred under the Block C8 license offshore Mauritania that were written off to exploration expense with the expiration of the exploration period of Block C8 during the three months ended June 30, 2022.

Depletion, depreciation and amortization. Depletion, depreciation and amortization decreased $31.8 million during the three months ended June 30, 2023, as compared with the three months ended June 30, 2022 primarily as a result of lower sales volumes during the quarter.

Derivatives, net. During the three months ended June 30, 2023 and 2022, we recorded a loss of $3.0 million and a loss of $75.2 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.

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Income tax expense (benefit). For the three months ended June 30, 2023 and 2022, our overall effective tax rates were 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, jurisdictions that have a 0% statutory tax rate, jurisdictions where we have incurred losses and have recorded valuation allowances against the corresponding deferred tax assets, and other non-deductible, expenses, primarily in the U.S.

Six months ended June 30, 2023 compared to six months ended June 30, 2022


	Six Months Ended
	June 30,				Increase
	2023		2022		(Decrease)
	(In thousands)
Revenues and other income:
Oil and gas revenue	$	667,495	$	1,279,383	$	(611,888)
Gain on sale of assets	—		471		(471)
Other income, net	(313)		95		(408)
Total revenues and other income	667,182		1,279,949		(612,767)
Costs and expenses:
Oil and gas production	147,515		214,892		(67,377)
Facilities insurance modifications, net	—		6,752		(6,752)
Exploration expenses	23,015		101,441		(78,426)
General and administrative	52,611		50,417		2,194
Depletion, depreciation and amortization	199,287		280,648		(81,361)

Interest and other financing costs, net	48,939		62,521		(13,582)
Derivatives, net	(3,809)		357,376		(361,185)

Other expenses, net	6,809		(1,102)		7,911
Total costs and expenses	474,367		1,072,945		(598,578)
Income before income taxes	192,815		207,004		(14,189)
Income tax expense (benefit)	86,161		88,431		(2,270)
Net income	$	106,654	$	118,573	$	(11,919)

Oil and gas revenue. Oil and gas revenue decreased by $611.9 million during the six months ended June 30, 2023, as compared to the six months ended June 30, 2022 as a result of the timing of our international oil liftings and lower average oil prices and lower production due to concluding the pre-emption transaction in March 2022 and natural field decline. We sold 9,618 MBoe at an average realized price per barrel equivalent of $69.40 during the six months ended June 30, 2023 and 12,191 MBoe at an average realized price per barrel equivalent of $104.94 during the six months ended June 30, 2022.

Oil and gas production. Oil and gas production costs decreased by $67.4 million during the six months ended June 30, 2023, as compared to the six months ended June 30, 2022 primarily as a result of decreased sales volumes due to the timing of our international oil liftings, concluding the pre-emption transaction in March 2022 and natural field decline, along with lower operating costs from the Jubilee Field.

Exploration expenses. Exploration expenses decreased by $78.4 million during the six months ended June 30, 2023, as compared to the six months ended June 30, 2022 primarily a result of the $64.2 million of previously capitalized costs related to the BirAllah and Orca discoveries incurred under the Block C8 license offshore Mauritania that were written off to exploration expense with the expiration of the exploration period of Block C8 during the six months ended June 30, 2022.

Depletion, depreciation and amortization. Depletion, depreciation and amortization decreased $81.4 million during the six months ended June 30, 2023, as compared with the six months ended June 30, 2022 primarily as a result of lower sales volumes in the current year.

Interest and other financing costs, net. Interest and other financing costs, net decreased $13.6 million during the six months ended June 30, 2023, as compared to the six months ended June 30, 2022, primarily as a result of increased capitalized

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interest related to the Greater Tortue Ahmeyim project partially offset by increased interest expenses related to higher interest rates.

Derivatives, net. During the six months ended June 30, 2023 and 2022, we recorded a gain of $3.8 million and a loss of $357.4 million, respectively, on our outstanding hedge positions. The changes recorded were a result of changes in the forward curve of oil prices during the respective periods.

Income tax expense (benefit). For the six months ended June 30, 2023 and 2022, our overall effective tax rates were 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, jurisdictions that have a 0% statutory tax rate or where we have incurred losses and have recorded valuation allowances against the corresponding deferred tax assets, and other non-deductible expenses, primarily in the U.S.

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.

Oil prices are historically volatile and a significant decrease in oil prices could negatively impact our ability to generate sufficient operating cash flows to meet our funding requirements. This volatility could also result in wide fluctuations in future oil prices, which could impact our ability to comply with our financial covenants. To partially mitigate this price volatility, we maintain an active hedging program and review our capital spending program on a regular basis. Our investment decisions are based on longer-term commodity prices based on the nature of our projects and development plans. Current commodity prices, combined with our hedging program and our current liquidity position support our remaining capital program for 2023.

As such, our 2023 capital budget is based on our exploitation and production plans for Ghana, Equatorial Guinea and the U.S. Gulf of Mexico, our infrastructure-led exploration and appraisal program in the U.S. Gulf of Mexico and Equatorial Guinea, and our appraisal and development activities in the U.S. Gulf of Mexico, Mauritania and Senegal.

Our future financial condition and liquidity can be impacted by, among other factors, the success of our exploitation, exploration and appraisal drilling programs, the number of commercially viable oil and natural gas discoveries made and the quantities of oil and natural gas discovered, the speed with which we can bring such discoveries to production, the reliability of our oil and gas production facilities, our ability to continuously export oil and gas, our ability to secure and maintain partners and their alignment with respect to capital plans, the actual cost of exploitation, exploration, appraisal and development of our oil and natural gas assets, and coverage of any claims under our insurance policies.

As of June 30, 2023, borrowings under the Facility totaled $775.0 million and the undrawn availability under the Facility was $370.1 million. In April 2023, during the Spring 2023 redetermination, the Company’s lending syndicate approved a borrowing base capacity of approximately $1.15 billion. As of June 30, 2023, there were no outstanding borrowings under the Corporate Revolver and the undrawn availability was $250.0 million.

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Sources and Uses of Cash

The following table presents the sources and uses of our cash and cash equivalents and restricted cash for the six months ended June 30, 2023 and 2022:


	Six Months Ended
	June 30,
	2023		2022
	(In thousands)
Sources of cash, cash equivalents and restricted cash:
Net cash provided by operating activities	$	221,963	$	608,186

Borrowings under long-term debt	150,000		—
Proceeds on sale of assets	—		118,693
	371,963		726,879
Uses of cash, cash equivalents and restricted cash:
Oil and gas assets	416,867		320,787
Acquisition of oil and gas properties	—		21,205
Notes receivable from partners	33,295		11,428
Payments on long-term debt	7,500		315,000
Tax withholdings on restricted stock units	11,811		2,753
Dividends	166		655
Deferred financing costs	—		6,288
	469,639		678,116
Increase (decrease) in cash, cash equivalents and restricted cash	$	(97,676)	$	48,763

Net cash provided by operating activities. Net cash provided by operating activities for the six months ended June 30, 2023 was $222.0 million compared with net cash provided by operating activities for the six months ended June 30, 2022 of $608.2 million. The decrease in cash provided by operating activities in the six months ended June 30, 2023 when compared to the same period in 2022 is primarily a result of lower average oil prices and lower sales volumes due to concluding the pre-emption transaction in March 2022 and natural field decline.

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The following table presents our liquidity and financial position as of June 30, 2023 and December 31, 2022:


	June 30, 2023		December 31, 2022
	(In thousands)
Borrowings under the Facility	$	775,000	$	625,000
7.125% Senior Notes	650,000		650,000
7.750% Senior Notes	400,000		400,000
7.500% Senior Notes	450,000		450,000

GoM Term Loan	137,500		145,000
Total long-term debt	2,412,500		2,270,000
Cash and cash equivalents	85,729		183,405
Total restricted cash	3,416		3,416
Net debt	$	2,323,355	$	2,083,179

Availability under the Facility	$	370,083	$	618,034
Availability under the Corporate Revolver	$	250,000	$	250,000
Available borrowings plus cash and cash equivalents	$	705,812	$	1,051,439

Capital Expenditures and Investments

We expect to incur capital costs as we:

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

• execute appraisal and development activities in Ghana, the U.S. Gulf of Mexico, Mauritania and Senegal; and

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

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, health, 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 assets, 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.

2023 Capital Program

We estimate we will spend approximately $700-$750 million of capital for the year ending December 31, 2023, excluding any acquisitions or divestiture of oil and gas properties during the year. This capital expenditure budget consists of:

•Approximately $250-$300 million related to maintenance activities across our Ghana, Equatorial Guinea and U.S. Gulf of Mexico assets, including infill development drilling and integrity spend;

•Approximately $350-$400 million related to the development of Jubilee South East in Ghana, Phase 1 of Greater Tortue Ahmeyim in Mauritania and Senegal, and Winterfell in the U.S. Gulf of Mexico;

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•Approximately $50-$100 million related to progressing our infrastructure-led exploration and appraisal programs in the U.S. Gulf of Mexico and Equatorial Guinea, as well as the appraisal plans of our greater gas resources in Mauritania and Senegal, including Phase 2 of Greater Tortue Ahmeyim, BirAllah and Yakaar-Teranga.

The ultimate amount of capital we will spend may fluctuate materially based on market conditions and the success of our exploitation and drilling results among other factors. Our future financial condition and liquidity will be impacted by, among other factors, our level of production of oil and the prices we receive from the sale of oil, our ability to effectively hedge future production volumes, the success of our multi-faceted infrastructure-led exploration and appraisal drilling programs, the number of commercially viable oil and natural gas discoveries made and the quantities of oil and natural gas discovered, the speed with which we can bring such discoveries to production, our partners’ alignment with respect to capital plans, and the actual cost of exploitation, exploration, appraisal and development of our oil and natural gas assets, and coverage of any claims under our insurance policies.

Significant Sources of Capital

Facility

The Facility supports our oil and gas exploration, appraisal and development programs and corporate activities. The amount of funds available to be borrowed under the Facility, also known as the borrowing base amount, is determined every March and September. The borrowing base amount is based on the sum of the net present values of net cash flows and relevant capital expenditures reduced by certain percentages as well as value attributable to certain assets’ reserves and/or resources in the Jubilee and TEN Fields in Ghana and the Ceiba and Okume Fields in Equatorial Guinea, however, excludes the additional interests in Jubilee and TEN acquired in the October 2021 acquisition of Anadarko WCTP. As of June 30, 2023, borrowings under the Facility totaled $775.0 million and the undrawn availability under the Facility was $370.1 million.

On November 23, 2022, the Company amended the Facility to update the interest rate benchmark from LIBOR to term SOFR, effective as of April 19, 2023. In April 2023, during the Spring 2023 redetermination, the Company’s lending syndicate approved a borrowing base capacity of approximately $1.15 billion resulting in a reduction of approximately $100 million of availability under the Facility.

The Facility provides a revolving credit and letter of credit facility. The availability period for the revolving credit facility expires one month prior to the final maturity date. The letter of credit facility expires on the final maturity date. The available facility amount is subject to borrowing base constraints and, beginning on March 31, 2024, outstanding borrowings will be constrained by an amortization schedule. The Facility has a final maturity date of March 31, 2027. As of June 30, 2023, we had no letters of credit issued under the Facility. We have the right to cancel all the undrawn commitments under the amended and restated Facility.

If an event of default exists under the Facility, the lenders can accelerate the maturity and exercise other rights and remedies, including the enforcement of security granted pursuant to the Facility over certain assets. We were in compliance with the financial covenants contained in the Facility as of March 31, 2023 (the most recent assessment date). The Facility contains customary cross default provisions.

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Corporate Revolver

The Corporate Revolver is available for general corporate purposes and for oil and gas exploration, appraisal and development programs. On November 23, 2022, the Company amended the Corporate Revolver to update the interest rate benchmark from compounded SOFR to term SOFR. As of June 30, 2023, there were no outstanding borrowings under the Corporate Revolver and the undrawn availability was $250.0 million with an expiration date of December 31, 2024.

The available amount is not subject to borrowing base constraints. We have the right to cancel all the undrawn commitments under the Corporate Revolver. We are required to repay certain amounts due under the Corporate Revolver with sales of certain subsidiaries or sales of certain assets. If an event of default exists under the Corporate Revolver, the lenders can accelerate the maturity and exercise other rights and remedies, including the enforcement of security granted pursuant to the Corporate Revolver over certain assets held by us.

The U.S. and many foreign economies continue to experience uncertainty driven by varying macroeconomic conditions. Although some of these economies have shown signs of improvement, macroeconomic recovery remains uneven. Uncertainty in the macroeconomic environment and associated global economic conditions have resulted in extreme volatility in credit, equity, and foreign currency markets, including the European sovereign debt markets and volatility in various other markets. If any of the financial institutions within our Facility or Corporate Revolver are unable to perform on their commitments, our liquidity could be impacted. We actively monitor all of the financial institutions participating in our Facility and Corporate Revolver. None of the financial institutions have indicated to us that they may be unable to perform on their commitments. In addition, we periodically review our banking and financing relationships, considering the stability of the institutions and other aspects of the relationships. Based on our monitoring activities, we currently believe our banks will be able to perform on their commitments.

Senior Notes

We have three series of senior notes outstanding, which we collectively referred to as the “Senior Notes.” Our 7.125% Senior Notes mature on April 4, 2026, and interest is payable on the 7.125% Senior Notes each April 4 and October 4. Our 7.500% Senior Notes mature on March 1, 2028, and interest is payable on the 7.500% Senior Notes each March 1 and September 1. Our 7.750% Senior Notes mature on May 1, 2027, and interest is payable on the 7.750% Senior Notes each May 1 and November 1.

The Senior Notes are senior, unsecured obligations of Kosmos Energy Ltd. and rank equally 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 and the GoM Term Loan). The Senior Notes are jointly and severally guaranteed on a senior, unsecured basis by certain subsidiaries owning the Company's U.S. Gulf of Mexico assets and the interests acquired in the Anadarko WCTP Acquisition, and on a subordinated, unsecured basis by entities that borrow under, or guarantee, our Facility.

GoM Term Loan

In September 2020, the Company entered into a five-year $200.0 million senior secured term-loan credit agreement secured against the Company's U.S. Gulf of Mexico assets with net proceeds received of $197.7 million after deducting fees and other expenses. The GoM Term Loan also includes an accordion feature providing for incremental commitments of up to $100.0 million subject to certain conditions. As of March 31, 2023, borrowings under the GoM Term Loan totaled $137.5 million. In June 2023, the Company amended the GoM Term Loan deferring the scheduled quarterly principal repayments through March 31, 2024 and extending the deferred repayments to the maturity date. As of June 30, 2023, $15.0 million of the total $137.5 million outstanding under the GoM Term Loan has been classified within Current maturities of long-term debt on our consolidated balance sheet.

The GoM Term Loan contains customary affirmative and negative covenants, including covenants that affect our ability to incur additional indebtedness, create liens, merge, dispose of assets, and make distributions, dividends, investments or capital expenditures, among other things. The GoM Term Loan is guaranteed on a senior, secured basis by certain subsidiaries owning the Company's U.S. Gulf of Mexico assets.

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The GoM Term Loan includes certain representations and warranties, indemnities and events of default that, subject to certain materiality thresholds and grace periods, arise as a result of a payment default, failure to comply with covenants, material inaccuracy of representation or warranty, and certain bankruptcy or insolvency proceedings. If there is an event of default, all or any portion of the outstanding indebtedness may be immediately due and payable and other rights may be exercised including against the collateral.

Contractual Obligations

The following table summarizes by period the payments due for our estimated contractual obligations as of June 30, 2023 and the weighted average interest rates expected to be paid on the Facility, Corporate Revolver and GoM Term Loan given current contractual terms and market conditions, and the instrument’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,																				June 30,
	2023(2)			2024			2025			2026			2027			Thereafter			Total		2023
	(In thousands, except percentages)
Fixed rate debt:
7.125% Senior Notes	$	—		$	—		$	—		$	650,000		$	—		$	—		$	650,000	$	572,598
7.750% Senior Notes	—			—			—			—			400,000			—			$	400,000	$	343,516
7.500% Senior Notes	—			—			—			—			—			450,000			450,000		372,893

Variable rate debt:
Weighted average interest rate	9.64		%	9.55		%	8.56		%	8.27		%	8.45		%	—		%
Facility(1)	$	—		$	93,047		$	227,450		$	279,282		$	175,221		$	—		$	775,000	$	775,000

GoM Term Loan(3)	—			30,000			107,500			—			—			—			137,500		137,500

Total principal debt repayments(1)	$	—		$	123,047		$	334,950		$	929,282		$	575,221		$	450,000		$	2,412,500
Interest & commitment fee payments on long-term debt	105,663			204,738			167,168			115,148			52,959			16,875			662,551
Operating leases(4)	2,029			4,121			4,192			4,264			4,204			6,652			25,462
Purchase obligations(5)	61,105			34,976			—			—			—			—			96,081

__________________________________

(1)The amounts included in the table represent principal maturities only. The scheduled maturities of debt related to the Facility are based on the level of borrowings and the available borrowing base as of June 30, 2023. 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 the period July 1, 2023 through December 31, 2023.

(3)In June 2023, the Company amended the GoM Term Loan pausing the scheduled quarterly principal repayments through March 31, 2024 and extending the deferred repayments to the maturity date.

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

(5)Represents gross contractual obligations to execute planned future capital projects. Other joint owners in the properties operated by Kosmos will be billed for their working interest share of such costs. Does not include our share of operator’s 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 14 - Additional Financial Information for additional information regarding these liabilities.

We have a commitment to drill 3 development wells and one exploration well in Equatorial Guinea. We have a $200.2 million FPSO Contract Liability in Other long-term liabilities related to the deferred sale of the Greater Tortue FPSO.

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 companies’ share of certain development costs. Kosmos’ total share for the two agreements combined originally estimated at approximately $240.0 million, of which $230.2 million has been incurred through June 30, 2023, excluding accrued interest. These amounts will be repaid through the national oil companies’ share of future revenues.

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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 items 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, 2022.

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:

•the impact of a potential regional or global recession, inflationary pressures and other varying macroeconomic conditions on us and the overall business environment;

•the impact of Russia’s war in Ukraine and the effects it has on the oil and gas industry as a whole, including increased volatility with respect to oil, natural gas and NGL prices and operating and capital expenditures;

•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, as well as our ability to implement hedges addressing such volatility on commercially reasonable terms;

•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, applicable monetary/foreign exchange sectors 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, or new, environmental, health and safety or climate change or GHG laws, regulations and executive orders, or the implementation, or interpretation, of those laws, regulations and executive orders;

•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, including the impact of the COVID-19 pandemic, terrorist acts, wars or embargoes;

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•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, but not limited to, tropical storms and hurricanes, and the physical effects of climate change;

•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;

•our ability to obtain surety or performance bonds on commercially reasonable terms;

•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 our quarterly reports 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 six months ended June 30, 2023:


	Derivative Contracts Assets (Liabilities)
	Commodities
	(In thousands)
Fair value of contracts outstanding as of December 31, 2022	$	2,688
Changes in contract fair value	220
Contract maturities	10,632
Fair value of contracts outstanding as of June 30, 2023	$	13,540

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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, and Heavy Louisiana Sweet. Oil prices in the first six months of 2023 ranged between $71.71 and $88.21 per Bbl for Dated Brent, with Heavy Louisiana Sweet experiencing similar volatility during the first six months of 2023.

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 and call options. 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. In addition, a reduction in our ability to access credit could reduce our ability to implement derivative contracts on commercially reasonable terms.

Commodity Price Sensitivity

The following table provides information about our oil derivative financial instruments that were sensitive to changes in oil prices as of June 30, 2023. Volumes and weighted average prices are net of any offsetting derivatives entered into.


				Weighted Average Price per Bbl						Asset
				Net Deferred								(Liability)
				Premium								Fair Value at
				Payable/		Sold						June 30,
Term	Type of Contract	Index	MBbl	(Receivable)		Put		Floor		Ceiling		2023(1)
												(In thousands)
2023:
Jul - Dec	Three-way collars	Dated Brent	3,000	$	1.34	$	49.17	$	71.67	$	107.58	$	5,203
Jul - Dec	Two-way collars	Dated Brent	2,500	1.69		—		72.00		112.00		3,771


2024:
Jan - Dec	Three-way collars	Dated Brent	2,000	1.35		45.00		70.00		97.50		5,764
Jan - Jun	Two-way collars	Dated Brent	2,000	1.24		—		65.00		85.00		(1,198)

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(1)Fair values are based on the average forward oil prices on June 30, 2023.

At June 30, 2023, our open commodity derivative instruments were in a net asset position of $13.5 million. As of June 30, 2023, a hypothetical 10% price increase in the commodity futures price curves would decrease future pre-tax earnings by approximately $27.5 million. Similarly, a hypothetical 10% price decrease would increase future pre-tax earnings by approximately $36.1 million.

Interest Rate Sensitivity

Changes in market interest rates affect the amount of interest we pay on certain of our borrowings. Outstanding borrowings under the Facility and GoM Term Loan, which as of June 30, 2023 total $912.5 million and have a weighted average interest rate of 9.4%, are subject to variable interest rates which expose us to the risk of earnings or cash flow loss due to potential increases in market interest rates. If the floating market rate increased 10% at this level of floating rate debt, we would pay an estimated additional $4.8 million 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. All of our other long-term indebtedness is fixed rate and does not expose us to the risk of cash flow loss due to changes in market interest rates. Additionally, a change in the market interest rates could impact interest costs associated with future debt issuances or any future borrowings.

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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 June 30, 2023, 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” sections of our annual report on Form 10-K for the year ended December 31, 2022.

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

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.

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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	August 7, 2023	/s/ NEAL D. SHAH
		Neal D. Shah
		Senior Vice President and Chief Financial Officer
		(Principal Financial Officer)

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.

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INDEX OF EXHIBITS


Exhibit Number						Description of Document
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

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