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Kosmos Energy Ltd. changed its jurisdiction of incorporation from Bermuda to the State of Delaware, in the United States of America, (the "Redomestication") in December 2018. As a holding company, Kosmos Energy Ltd.’s management operations are conducted through a wholly-owned subsidiary, Kosmos Energy, LLC. The terms “Kosmos,” the “Company,” “we,” “us,” “our,” “ours,” and similar terms refer to Kosmos Energy Ltd. and its wholly-owned subsidiaries, unless the context indicates otherwise.

Kosmos is a full-cycle deepwater independent oil and gas exploration and production company focused along the Atlantic Margins. Our key assets include production offshore Ghana, Equatorial Guinea and U.S. Gulf of Mexico, as well as a world-class gas development offshore Mauritania and Senegal. We also maintain a sustainable exploration program balanced between proven basin infrastructure-led exploration (Equatorial Guinea and U.S. Gulf of Mexico), emerging basins (Mauritania, Senegal and Suriname) and frontier basins (Namibia, Sao Tome and Principe, and South Africa). Kosmos is listed on the New York Stock Exchange and London Stock Exchange and is traded under the ticker symbol KOS.

 

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

 

General

 

The interim consolidated financial statements included in this report are unaudited and, in the opinion of management, include all adjustments of a normal recurring nature necessary for a fair presentation of the results for the interim periods. The results of the interim periods shown in this report are not necessarily indicative of the final results to be expected for the full year. The consolidated financial statements were prepared in accordance with the requirements of the Securities and Exchange Commission (“SEC”) for interim reporting. As permitted under those rules, certain notes or other financial information that are normally required by Generally Accepted Accounting Principles in the United States of America (“GAAP”) have been condensed or omitted from these interim consolidated financial statements. These consolidated financial statements and the accompanying notes should be read in conjunction with our audited consolidated financial statements for the year ended December 31, 2019, included in our annual report on Form 10-K and our quarterly report on Form 10-Q for the quarter ended March 31, 2020.

Reclassifications

 

Certain prior period amounts have been reclassified to conform with the current presentation. Such reclassifications had no significant impact on our reported net income (loss), current assets, total assets, current liabilities, total liabilities, stockholders’ equity or cash flows.

Cash, Cash Equivalents and Restricted Cash 

	June 30, 2020				December 31, 2019
	(In thousands)
Cash and cash equivalents	$	164,091			$	224,502
Restricted cash - current	186				4,302
Restricted cash - long-term	542				542
Total cash, cash equivalents and restricted cash shown in the consolidated statements of cash flows	$	164,819			$	229,346

 

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Cash and cash equivalents include demand deposits and funds invested in highly liquid instruments with original maturities of three months or less at the date of purchase.

 

In accordance with certain of our petroleum contracts, we have posted letters of credit related to performance guarantees for our minimum work obligations. Certain of these letters of credit are cash collateralized in accounts held by us and as such are classified as restricted cash. Upon completion of the minimum work obligations and/or entering into the next phase of the respective petroleum contract, the requirement to post the existing letters of credit will be satisfied and the cash collateral will be released. However, additional letters of credit may be required should we choose to move into the next phase of certain of our petroleum contracts.

 

Inventories

 

Inventories consisted of $115.2 million and $112.3 million of materials and supplies and $15.1 million and $2.1 million of hydrocarbons as of June 30, 2020 and December 31, 2019, 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 after the sale.

    

Oil and gas revenue is composed of the following:

	Three Months Ended June 30,								Six Months Ended June 30,
	2020				2019				2020				2019
	(In thousands)
Revenues from contract with customer - Equatorial Guinea	$	28,147			$	63,165			$	52,518			$	152,279
Revenues from contract with customer - Ghana	64,577				209,469				114,250				328,800
Revenues from contract with customers - U.S. Gulf of Mexico	39,222				129,364				142,674				214,431
Provisional oil sales contracts	(4,632		)		(6,065		)		(4,348		)		(2,787		)
Oil and gas revenue	$	127,314			$	395,933			$	305,094			$	692,723

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Restructuring Charges

The Company accounts for restructuring charges and related termination benefits in accordance with ASC 712—Compensation-Nonretirement Postemployment Benefits. Under this standard, the costs associated with termination benefits are recorded during the period in which the liability is incurred. During the three and six months ended June 30, 2020, we recognized $(0.6) million and $13.3 million, respectively, in restructuring charges for employee severance and related benefit costs incurred as part of a corporate reorganization in Other expenses, net in the consolidated statement of operations.

Concentration of Credit Risk

Our revenue can be materially affected by current economic conditions and the price of oil. However, based on the current demand for crude oil and the fact that alternative purchasers are available, we believe that the loss of our marketing agent and/or any of the purchasers identified by our marketing agent would not have a long‑term material adverse effect on our financial position or results of operations. The continued economic disruption resulting from the COVID-19 pandemic could materially impact the Company’s business in future periods. Any potential disruption will depend on the duration and intensity of these events, which are highly uncertain and cannot be predicted at this time. For our U.S. Gulf of Mexico operations, crude oil and natural gas are transported to customers using third-party pipelines. For the three months ended June 30, 2020 and 2019, revenue from Phillips 66 Company made up approximately 24% and 22%, respectively, and revenue from Shell Trading (US) Company made up approximately 8% and 9%, respectively, of our total consolidated revenue and was included in our U.S. Gulf of Mexico segment. For the six months ended June 30, 2020 and 2019, revenue from Phillips 66 Company made up approximately 37% and 22%, respectively, and revenue from Shell Trading (US) Company made up approximately 15% and 7%, respectively, of our total consolidated revenue and was included in our U.S. Gulf of Mexico segment.

Recent Accounting Standards

In June 2016, ASU 2016-13, "Measurement of Credit Losses on Financial Instruments," was issued requiring measurement of all expected credit losses for certain types of financial instruments, including trade receivables, held at the reporting date based on historical experience, current conditions and reasonable and supportable forecasts. This standard was effective January 1, 2020. We assessed all receivable positions for expected credit losses through the implementation of ASU 2016-13, current expected credit loss standard (CECL). Our receivables are collectible in the original term of the underlying agreements and current expected credit losses under the CECL standard are not significant.

In December 2019, the FASB issued ASU 2019-12, “Simplifying the Accounting for Income Taxes”. The amendments in the ASU are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020. Early adoption is permitted, however, we do not plan to early adopt ASU 2019-12 at this time. ASU 2019-12 is not expected to have a material impact on our income tax expense.

2020 Transactions

During the second quarter of 2020, Kosmos made a decision to withdraw from our blocks offshore Cote d'Ivoire following our evaluation of seismic data.

In July 2020, we provided notice to Staatsolie that we declined to enter the final exploration phase of the Suriname Block 45 petroleum agreement.

2019 Transactions

During the first quarter of 2019, we agreed a petroleum contract covering offshore Marine XXI block with the national oil company of the Republic of the Congo, Societe Nationale des Petroles du Congo. The petroleum contract was subject to a required governmental approval process before the petroleum contract could be made effective. The petroleum contract had not been approved by the government of the Republic of Congo nor entered into force when, in February 2020, we terminated our interests in the Marine XXI block petroleum contract.

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Joint Interest Billings

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

 

In Ghana, the contractor group funded GNPC’s 5% share of the TEN development costs. The block partners are being reimbursed for such costs plus interest out of a portion of GNPC’s TEN production revenues. As of June 30, 2020 and December 31, 2019, the current portions of the joint interest billing receivables due from GNPC for the TEN fields development costs were $9.1 million and $14.0 million, respectively, and the long-term portions were $17.0 million and $16.0 million, respectively.

Notes Receivables    

In February 2019, Kosmos and BP signed Carry Advance Agreements with the national oil companies of Mauritania and Senegal which obligate us separately to finance the respective national oil company’s share of certain development costs incurred through first gas production for Greater Tortue Ahmeyim Phase 1, currently projected in 2023. Kosmos’ share for the two agreements combined is up to $239.7 million, which is to be repaid with interest through the national oil companies’ share of future revenues. As of June 30, 2020 and December 31, 2019, the balance due from the national oil companies was $71.1 million and $27.4 million, respectively, which is classified as Long-term receivables on our consolidated balance sheets.

 

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

 

	June 30, 2020				December 31, 2019
	(In thousands)
Oil and gas properties:
Proved properties	$	5,129,222			$	4,904,648
Unproved properties	533,393				814,065
Total oil and gas properties	5,662,615				5,718,713
Accumulated depletion	(2,296,869		)		(2,093,962		)
Oil and gas properties, net	3,365,746				3,624,751
Other property	59,686				61,598
Accumulated depreciation	(46,767		)		(44,017		)
Other property, net	12,919				17,581
Property and equipment, net	$	3,378,665			$	3,642,332

 

We recorded depletion expense of $115.7 million and $144.0 million for the three months ended, June 30, 2020 and 2019, respectively, and $202.9 million and $255.0 million for the six months ended June 30, 2020 and 2019, respectively. As a result of the impact of COVID-19 on the demand for oil and the related significant decrease in oil prices, we reviewed our long-lived assets for impairment at March 31, 2020. Oil prices improved during the three months ended June 30, 2020. During the three months ended June 30, 2020 and 2019, no oil and gas asset impairments were recorded. During the six months ended June 30, 2020 and 2019, we recorded asset impairments totaling $150.8 million and zero, respectively, in our consolidated statement of operations in connection with fair value assessments for oil and gas proved properties in the U.S. Gulf of Mexico.

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The following table reflects the Company’s capitalized exploratory well costs on drilled wells as of and during the six months ended June 30, 2020. The table excludes $9.6 million in costs that were capitalized and expensed during the same period. During the first quarter of 2020, the exploratory well costs associated with the Greater Tortue Ahmeyim Unit were reclassified to proved property as the execution of the Tortue Phase 1 SPA in February 2020 resulted in recognition of proved undeveloped reserves at that time.

 

	June 30, 2020
	(In thousands)
Beginning balance	$	445,790
Additions to capitalized exploratory well costs pending the determination of proved reserves	1,140
Reclassification due to determination of proved reserves	(263,849		)
Capitalized exploratory well costs charged to expense	—
Ending balance	$	183,081

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, 2020				December 31, 2019
	(In thousands, except well counts)
Exploratory well costs capitalized for a period of one year or less	$	29,616			$	29,121
Exploratory well costs capitalized for a period of one to two years	—				78,245
Exploratory well costs capitalized for a period of three years or greater	153,465				338,424
Ending balance	$	183,081			$	445,790
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year	2				3

 

As of June 30, 2020, the projects with exploratory well costs capitalized for more than one year since the completion of drilling are related to the BirAllah discovery (formerly known as the Marsouin discovery) in Block C8 offshore Mauritania and the Yakaar and Teranga discoveries in the Cayar Offshore Profond block offshore Senegal.

 

BirAllah Discovery — In November 2015, we completed the Marsouin-1 exploration well in the northern part of Block C8 offshore Mauritania, which encountered hydrocarbon pay. Following additional evaluation, a decision regarding commerciality is expected to be made. During the fourth quarter of 2019, we completed the nearby Orca-1 exploration well which encountered hydrocarbon pay. Following additional evaluation, a decision regarding commerciality is expected to be made. The BirAllah and Orca discoveries are being analyzed as a joint development.

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

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We have commitments under operating leases primarily related to office leases. Our leases have initial lease terms ranging from one year to ten years. Certain lease agreements contain provisions for future rent increases.

The components of lease cost for the three and six months ended June 30, 2020 and 2019 are as follows:

	Three Months Ended June 30,								Six months ended June 30,
	2020				2019				2020				2019
	(In thousands)
Operating lease cost	$	1,899			$	1,602			$	3,157			$	3,009
Short-term lease cost(1)	2,434				582				12,802				587
Total lease cost	$	4,333			$	2,184			$	15,959			$	3,596

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(1)	Includes $2.3 million and zero during the three months ended June 30, 2020 and 2019, respectively, and $12.2 million and zero during the six months ended June 30, 2020 and 2019, respectively, of costs associated with short-term drilling contracts.

Other information related to operating leases at June 30, 2020 and 2019, is as follows:

	June 30, 2020				December 31, 2019
(In thousands, except lease term and discount rate)
Balance sheet classifications
Other assets (right-of-use assets)	$	18,775			$	20,008
Accrued liabilities (current maturities of leases)	2,005				1,139
Other long-term liabilities (non-current maturities of leases)	21,078				22,240
Weighted average remaining lease term	8.4 years				8.8 years
Weighted average discount rate	9.9		%		9.8		%

The table below presents supplemental cash flow information related to leases during the six months ended June 30, 2020 and 2019:

	Six Months Ended June 30,
	2020				2019
	(In thousands)
Operating cash flows for operating leases	$	1,909			$	1,750
Investing cash flows for operating leases(1)	12,225				—

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(1)	Represents costs associated with short-term drilling contracts.

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Future minimum rental commitments under our leases at June 30, 2020, are as follows:

	Operating Leases(1)
	(In thousands)
2020(2)	$	2,061
2021	4,174
2022	4,237
2023	4,301
2024	3,464
Thereafter	16,041
Total undiscounted lease payments	$	34,278
Less: Imputed interest	(11,195		)
Total lease liabilities	$	23,083

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

(2)	Represents payments for the period from July 1, 2020 through December 31, 2020.

 

	June 30, 2020				December 31, 2019
	(In thousands)
Outstanding debt principal balances:
Facility	$	1,450,000			$	1,400,000
Corporate Revolver	100,000				—
Senior Notes	650,000				650,000
Total	2,200,000				2,050,000
Unamortized deferred financing costs and discounts(1)	(36,347		)		(41,937		)
Total debt, net	2,163,653				2,008,063
Less: Current maturities of long-term debt	(56,000		)		—
Long-term debt, net	$	2,107,653			$	2,008,063

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(1)	Includes $27.8 million and $32.8 million of unamortized deferred financing costs related to the Facility as of June 30, 2020 and December 31, 2019, respectively; $8.5 million and $9.1 million of unamortized deferred financing costs and discounts related to the Senior Notes as of June 30, 2020 and December 31, 2019, respectively.

Facility

 

In April 2020, following the lenders' annual redetermination, the available borrowing base and Facility size were both reduced from $1.6 billion to $1.5 billion. In addition, as part of the redetermination process, the Company agreed to conduct an additional redetermination in September 2020. The Facility supports our oil and gas exploration, appraisal and development programs and corporate activities. As of June 30, 2020, borrowings under the Facility totaled $1.45 billion and the undrawn availability under the facility was $0.05 billion.

The Facility provides a revolving credit and letter of credit facility. The availability period for the revolving credit facility expires one month prior to the final maturity date. The letter of credit facility expires on the final maturity date. The available facility amount is subject to borrowing base constraints and, beginning on March 31, 2022, outstanding borrowings will be constrained by an amortization schedule. The Facility has a final maturity date of March 31, 2025. As of June 30, 2020, we had no letters of credit issued under the Facility.

 

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As result of the impact of COVID-19 on the demand for oil and the related significant decrease in oil prices, our ability to comply with one of our financial covenants, the debt cover ratio, may be impacted in future periods. Therefore, in July 2020, we proactively worked with our lender group, prior to any inability to comply with the financial covenants thereunder, to amend the debt cover ratio calculation through December 31, 2021. The amendment makes this covenant less restrictive during the stated period up to a maximum of 4.75x and thereafter gradually returns to the originally agreed upon ratio of 3.5x. In addition, as part of the amendment to relax the debt cover ratio, we agreed to include the advanced amounts under the Production Prepayment Agreement as part of the debt cover ratio calculation. We were in compliance with the financial covenants as of the most recent assessment date. The Facility contains customary cross default provisions.

 

Corporate Revolver

 

In August 2018, we amended and restated the Corporate Revolver from a number of financial institutions, maintaining the borrowing capacity at $400.0 million, extending the maturity date from November 2018 to May 2022 and lowering the margin 100 basis points to 5%. This results in lower commitment fees on the undrawn portion of the total commitments, which is 30% per annum of the respective margin. The Corporate Revolver is available for general corporate purposes and for oil and gas exploration, appraisal and development programs.

 

As of June 30, 2020, there were $100.0 million in outstanding borrowings under the Corporate Revolver and the undrawn availability was $300.0 million. As of June 30, 2020, we have $5.0 million of net deferred financing costs related to the Corporate Revolver, which will be amortized over its remaining term.

As result of the impact of COVID-19 on the demand for oil and the related significant decrease in oil prices, our ability to comply with one of our financial covenants, the debt cover ratio, may be impacted in future periods. Therefore, in July 2020, we proactively worked with our lender group, prior to any inability to comply with the financial covenants thereunder, to amend the debt cover ratio calculation through December 31, 2021. The amendment makes this covenant less restrictive during the stated period up to a maximum of 4.75x and thereafter gradually returns to the originally agreed upon ratio of 3.5x. In addition, as part of the amendment to relax the debt cover ratio, we agreed to include the advanced amounts under the Production Prepayment Agreement as part of the debt cover ratio calculation. We were in compliance with the financial covenants as of the most recent assessment date. The Corporate Revolver contains customary cross default provisions.

 

Revolving Letter of Credit Facility

 

Our revolving letter of credit facility agreement (“LC Facility”) expired in July 2019.In May 2020, the remaining five outstanding letters of credit under the LC Facility totaling $3.1 million were released and the LC Facility was subsequently terminated in June 2020.

In 2019, we issued two letters of credit totaling $20.4 million under a new letter of credit arrangement, which does not currently require cash collateral.

 

7.125% Senior Notes due 2026

In April 2019, the Company issued $650.0 million of 7.125% Senior Notes and received net proceeds of approximately $640.0 million after deducting commissions and other expenses. We used the net proceeds to redeem all of the Senior Secured Notes, repay a portion of the outstanding indebtedness under the Corporate Revolver and pay fees and expenses related to the redemption, repayment and the issuance of the Senior Notes.

The Senior Notes mature on April 4, 2026. Interest is payable in arrears each April 4 and October 4, commencing on October 4, 2019. The Senior Notes are senior, unsecured obligations of Kosmos Energy Ltd. and rank equal in right of payment with all of its existing and future senior indebtedness (including all borrowings under the Corporate Revolver) and rank effectively junior in right of payment to all of its existing and future secured indebtedness (including all borrowings under the Facility). The Senior Notes are guaranteed on a senior, unsecured basis by certain subsidiaries owning the Company's Gulf of Mexico assets, and on a subordinated, unsecured basis by certain subsidiaries that guarantee the Facility. We were in compliance with the financial covenants contained in the Senior Notes as of March 31, 2020. The Senior Notes contain customary cross default provisions.

    

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At June 30, 2020, the estimated repayments of debt during the five fiscal year periods and thereafter are as follows:

 

	Payments Due by Year
	Total				2020(2)				2021				2022				2023				2024				Thereafter
	(In thousands)
Principal debt repayments(1)	$	2,200,000			$	—			$	56,000			$	422,571			$	428,571			$	428,572			$	864,286

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(1)

Includes the scheduled principal maturities for the $650.0 million aggregate principal amount of Senior Notes and borrowings under the Facility and Corporate Revolver. The scheduled maturities of debt related to the Facility as of June 30, 2020 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, 2020 through December 31, 2020.

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,
	2020				2019				2020				2019
	(In thousands)
Interest expense	$	28,504			$	38,450			$	60,270			$	76,622
Amortization—deferred financing costs	2,192				2,302				4,475				4,689
Loss on extinguishment of debt	2,215				24,794				2,215				24,794
Capitalized interest	(5,729		)		(7,002		)		(12,256		)		(14,253		)
Deferred interest	1,182				433				1,496				1,270
Interest income	(1,023		)		(591		)		(2,102		)		(1,243		)
Other, net	933				1,417				2,011				2,965
Interest and other financing costs, net	$	28,274			$	59,803			$	56,109			$	94,844

	June 30, 2020				December 31, 2019
	(In thousands)
Production prepayment	$	50,000			$	—
Unamortized deferred financing costs	(667		)		—
Production prepayment agreement, net	$	49,333			$	—

In June 2020, the Company received $50 million from Trafigura under a Production Prepayment Agreement of crude oil sales related to a portion of our U.S. Gulf of Mexico production primarily in 2022 and 2023, The Production Prepayment Agreement is for up to $200 million of crude oil sales, with an additional $100 million committed by Trafigura in addition to the $50 million received in June 2020. The Company will sell to Trafigura a specified volume of crude oil each month as defined in the Volume Model, which is expected to be finalized in the third quarter of 2020 in accordance with the terms of the Production Prepayment Agreement (estimated at approximately 2 million barrels total), for no more than 60 months following the funding in June 2020, such final delivery date being the "Final Delivery Date," provided, however, if the market value of the crude oil volumes delivered prior to the Final Delivery Date is equal to $57.5 million, then the Company's obligation would be considered fully satisfied. Under the Production Prepayment Agreement, upon the satisfaction of certain conditions provided in the Production Prepayment Agreement, the Company may elect for Trafigura to prepay for two additional tranches of crude oil in the amount of $100 million

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on September 30, 2020 and $50 million on or before March 31, 2021. If the Company makes such election, the total volume of crude oil to be sold will be adjusted accordingly.

Financing costs includes the applicable margin of 5%; LIBOR; and mandatory costs. We recognize interest expense in accordance with ASC 835 — Interest, which requires interest expense to be recognized using the effective interest method. The total financing costs associated with the Production Prepayment Agreement are based on the estimated market value of the crude oil to be delivered to Trafigura compared to the cash proceeds received, which is expected to be $7.5 million as of June 30, 2020.

As a condition to Trafigura’s obligations, the Company will ‎grant a mortgage interest in certain specified production fields located in the U.S. Gulf of Mexico.

    

During the term of the Production Prepayment Agreement, the Company will be required to ‎maintain certain ongoing ratios as defined in the Production Prepayment Agreement. We were in compliance with the financial covenants contained in the Production Prepayment Agreement as of June 30, 2020, which requires the maintenance of:

•	the Guarantor Liquidity Ratio (as defined in the glossary), not less than 1.20x and

•	the GoM Liquidity Ratio (as defined in the glossary), not less than 1.50x

    

At June 30, 2020, based on quoted future market prices, the value of the estimated volumes to be delivered under the Production Prepayment Agreement during the five fiscal year periods and thereafter are as follows:

	Payments Due by Year
	Total				2020(2)				2021				2022				2023				2024				Thereafter
	(In thousands)
Production Prepayment Agreement(1)	$	50,000			$	—			$	15,729			$	30,799			$	3,472			$	—			$	—

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(1)	Any increases or decreases in future market prices would impact the scheduled maturities during the next five years and thereafter.

(2)	Represents payments for the period July 1, 2020 through December 31, 2020.

 

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, 2020. Volumes and weighted average prices are net of any offsetting derivative contracts entered into.

									Weighted Average Price per Bbl
									Net Deferred
									Premium
Term		Type of Contract		Index		MBbl			Payable/(Receivable)				Swap				Sold Put				Floor				Ceiling				Purchased Call
2020:
Jul — Dec		Swaps		Dated Brent		5,275			$	—			$	42.67			$	—			$	—			$	—			$	—
Jul — Dec		Swaps		Argus LLS		3,000			—				29.98				—				—				—				—
Jul — Dec		Call spreads		NYMEX WTI		(1)			1.20				—				—				—				45.00				35.00
Jul — Dec		Swaps with sold puts		Dated Brent		333			—				35.00				25.00				—				—				—
Jul — Dec		Three-way collars		Dated Brent		1,000			—				—				25.00				32.50				40.00				—
Jul — Dec		Sold calls(2)		Dated Brent		4,750			(0.19		)		—				—				—				80.83				—
2021:
Jan — Dec		Swaps with sold puts		Dated Brent		5,000			$	—			$	54.70			$	43.50			$	—			$	—			—
Jan — Dec		Three-way collars		Dated Brent		1,000			1.00				—				30.00				40.00				55.40				—
Jan — Dec		Sold calls(2)		Dated Brent		7,000			—				—				—				—				70.09				—
2022:
Jan — Dec		Sold calls(2)		Dated Brent		1,581			—				—				—				—				60.00				—

__________________________________

(1)	Added call spreads on 1.0 million barrels to open upside for U.S. Gulf of Mexico production.

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

    

In April 2020, we restructured the majority of our May 2020 through December 2020 derivative contracts, whereby we converted the existing hedges into 7.0 MMBbls of Dated Brent swap contracts with an average fixed price of $42.67 per barrel. In July 2020, we entered into Dated Brent costless three-way collar contracts for 1.0 MMBbl from January 2021 through December 2021 with a sold put price of $30.00 per barrel, a floor price of $40.00 per barrel and a ceiling price of $55.00 per barrel. The following tables disclose the Company’s derivative instruments as of June 30, 2020 and December 31, 2019, and gain/(loss) from derivatives during the three and six months ended June 30, 2020 and 2019, respectively:

 

				Estimated Fair Value
				Asset (Liability)
Type of Contract		Balance Sheet Location		June 30, 2020				December 31, 2019
				(In thousands)
Derivatives not designated as hedging instruments:
Derivative assets:
Commodity		Derivatives assets—current		$	30,289			$	12,856
Provisional oil sales		Receivables: Oil Sales		—				(3,287		)
Commodity		Derivatives assets—long-term		11,271				2,302
Derivative liabilities:
Commodity		Derivatives liabilities—current		(43,974		)		(8,914		)
Commodity		Derivatives liabilities—long-term		(9,306		)		(11,478		)
Total derivatives not designated as hedging instruments				$	(11,720	)		$	(8,521	)

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				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)		2020				2019				2020				2019
				(In thousands)
Derivatives not designated as hedging instruments:
Commodity(1)		Oil and gas revenue		$	(4,632	)		$	(6,064	)		$	(4,348	)		$	(2,786	)
Commodity		Derivatives, net		(100,075		)		14,185				35,963				(62,900		)
Total derivatives not designated as hedging instruments				$	(104,707	)		$	8,121			$	31,615			$	(65,686	)

__________________________________

(1)	Amounts represent the change in fair value of our provisional oil sales contracts.

Offsetting of Derivative Assets and Derivative Liabilities

 

Our derivative instruments which are subject to master netting arrangements with our counterparties only have the right of offset when there is an event of default. As of June 30, 2020 and December 31, 2019, 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.

 

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.

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The following tables present the Company’s assets and liabilities that are measured at fair value on a recurring basis as of June 30, 2020 and December 31, 2019, 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, 2020
Assets:
Commodity derivatives	$	—			$	41,560			$	—			$	41,560
Provisional oil sales	—				—				—				—
Liabilities:
Commodity derivatives	—				(53,280		)		—				(53,280		)
Total	$	—			$	(11,720	)		$	—			$	(11,720	)
December 31, 2019
Assets:
Commodity derivatives	$	—			$	15,158			$	—			$	15,158
Provisional oil sales	—				(3,287		)		—				(3,287		)
Liabilities:
Commodity derivatives	—				(20,392		)		—				(20,392		)
Total	$	—			$	(8,521	)		$	—			$	(8,521	)

 

The book values of cash and cash equivalents and restricted cash approximate fair value based on Level 1 inputs. Joint interest billings, oil sales and other receivables, and accounts payable and accrued liabilities approximate fair value due to the short-term nature of these instruments. Our long-term receivables, after any allowances for doubtful accounts, and other long-term assets approximate fair value. The estimates of fair value of these items are based on Level 2 inputs.

 

Commodity Derivatives

 

Our commodity derivatives represent crude oil collars, put options, call options and swaps for notional barrels of oil at fixed Dated Brent, NYMEX WTI, or Argus LLS oil prices. The values attributable to our oil derivatives are based on (i) the contracted notional volumes, (ii) independent active futures price quotes for the respective index, (iii) a credit-adjusted yield curve applicable to each counterparty by reference to the credit default swap (“CDS”) market and (iv) an independently sourced estimate of volatility for the respective index. The volatility estimate was provided by certain independent brokers who are active in buying and selling oil options and was corroborated by market-quoted volatility factors. The deferred premium is included in the fair market value of the commodity derivatives. See Note 10 — 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.

 

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Debt and Production Prepayment Agreement

 

The following table presents the carrying values and fair values at June 30, 2020 and December 31, 2019:

 

	June 30, 2020								December 31, 2019
	Carrying Value				Fair Value				Carrying Value				Fair Value
	(In thousands)
Senior Notes	$	643,028			$	580,554			$	642,550			$	664,957
Production Prepayment Agreement	50,000				57,500				—				—
Corporate Revolver	100,000				100,000				—				—
Facility	1,450,000				1,450,000				1,400,000				1,400,000
Total	$	2,243,028			$	2,188,054			$	2,042,550			$	2,064,957

 

The carrying value of our Senior Notes and Production Prepayment Agreement represents the principal amounts outstanding less unamortized discounts. The fair value of our Senior Notes is based on quoted market prices, which results in a Level 1 fair value measurement. The fair value of the Production Prepayment Agreement represents the estimated value of the crude oil barrels in the Volume Model agreed to be delivered based on quoted market prices which results in a Level 2 fair value measurement. At June 30, 2020, the value of the crude oil volumes to be delivered exceeds $57.5 million prior to the Final Delivery Date, which results in the Company's obligation being fully satisfied when delivered. The carrying value of the Facility approximates fair value since it is subject to short-term floating interest rates that approximate the rates available to us for those periods.

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.

As a result of the impact of COVID-19 on the demand for oil and the related significant decrease in oil prices, we reviewed our long-lived assets for impairment at March 31, 2020, which resulted in impairment charges against earnings of $150.8 million, reducing the carrying value of the properties to their estimated fair values of $243.7 million. As part of our impairment analysis, the average per barrel Dated Brent price of third-party industry forecasts used for purposes of determining discounted future cash flows ranged from the mid-$30s in 2020 increasing to the mid-$50s over several years. The expected future cash flows were discounted using a rate of approximately 10 percent, which the Company believes is a market-based weighted average cost of capital for industry peers determined appropriate at the time of the valuation. These impairment charges are included in Impairments of long-lived assets on the consolidated statement of operations. The Company did not recognize additional impairment of proved oil and gas properties during the three months ended June 30, 2020 as no impairment indicators were identified. If we experience further declines in oil pricing expectations, increases in our estimated future expenditures or a decrease in our estimated production profile, our long-lived assets could be at risk of additional impairment.

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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 $8.3 million and $9.5 million during the three months ended June 30, 2020 and 2019, respectively, and $17.7 million and $17.9 million during the six months ended June 30, 2020 and 2019, respectively. The total tax benefit for the three months ended June 30, 2020 and 2019 was $1.7 million and $1.5 million, respectively, and $3.8 million and $2.8 million during the six months ended June 30, 2020 and 2019, respectively. Additionally, we recorded a net tax shortfall (windfall) related to equity-based compensation of $0.2 million and nil for the three months ended June 30, 2020 and 2019, respectively, and $1.1 million and $1.2 million during the six months ended June 30, 2020 and 2019, respectively. The fair value of awards vested during the three months ended June 30, 2020 and 2019 was $0.4 million and $0.8 million, respectively, and $25.8 million and $14.0 million during the six months ended June 30, 2020 and 2019, respectively. The Company granted restricted stock units with service vesting criteria and a combination of market and service vesting criteria under the LTIP. Substantially all these grants vest over three years. Upon vesting, restricted stock units become issued and outstanding stock.

 

The following table reflects the outstanding restricted stock units as of June 30, 2020:

 

				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, 2019	4,731			$	5.71			7,798			$	8.42
Granted(1)	3,474			5.49				3,392			8.37
Forfeited(1)	(901	)		6.17				(476	)		8.02
Vested	(2,067	)		5.86				(2,582	)		9.47
Outstanding at June 30, 2020	5,237			5.41				8,132			8.11

__________________________________

(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, 2020, total equity-based compensation to be recognized on unvested restricted stock units is $41.6 million over a weighted average period of 2.02 years. In March 2018, the board of directors approved an amendment to the LTIP to add 11.0 million shares to the plan, which was approved by our stockholders at the Annual General Meeting in June 2018. The LTIP provides for the issuance of 50.5 million shares pursuant to awards under the plan. At June 30, 2020, the Company had approximately 6.0 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 $12.96 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 44.0% to 52.0%. The risk-free interest rate was based on the U.S. treasury rate for a term commensurate with the expected life of the grant and ranged from 0.8% to 2.5%. For the restricted stock units awarded in 2019 and 2020, the Monte Carlo simulation model included estimated quarterly dividend inputs ranging from $0.045 to $0.050.

We provide for income taxes based on the laws and rates in effect in the countries in which our operations are conducted. The relationship between our pre‑tax income or loss from continuing operations and our income tax expense or benefit varies from period to period as a result of various factors, which include changes in total pre‑tax income or loss, the jurisdictions in which our income (loss) is earned, and the tax laws in those jurisdictions. We evaluate our estimated annual effective income tax rate each

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quarter, based on current and forecasted business results and enacted tax laws, and apply this tax rate to our ordinary income or loss to calculate our estimated tax expense or benefit. The Company excludes zero tax rate and tax-exempt jurisdictions from our evaluation of the estimated annual effective income tax rate. The tax effect of discrete items are recognized in the period in which they occur at the applicable statutory tax rate.

The income tax provision consists of United States, Ghanaian, and Equatorial Guinean income taxes, and Texas margin taxes. Our operations in other foreign jurisdictions have a 0% effective tax rate because they reside in countries with a 0% statutory rate or we have incurred losses in those jurisdictions and have full valuation allowances against the corresponding net deferred tax assets.

 

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. For the three and six months ended June 30, 2020, we increased our valuation allowance associated with our U.S. deferred tax assets by $16.7 million and $86.1 million, respectively, resulting in $30.9 million of net U.S. deferred tax expense. The valuation allowance was necessary due to the recent decline in oil prices and the impact on our expected ability to utilize U.S. tax losses in the future.

In March 2020, the Coronavirus Aid, Relief, and Economic Security ACT ("CARES Act") became law. Among other things, the CARES Act permits taxpayers to carry back U.S. taxable losses generated during tax years 2018 through 2020 to the five tax years preceding the loss year to obtain tax refunds. Certain of our U.S. legal entities qualify for such relief and we recorded a current tax benefit of $4.9 million during the first quarter of 2020, with a total $12.2 million income tax refund claim. Other provisions of the CARES Act are not expected to have a material impact to our tax expense.

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

 

	Three Months Ended June 30,								Six Months Ended June 30,
	2020				2019				2020				2019
	(In thousands)
United States	$	(79,703	)		$	(18,499	)		$	(269,840	)		$	(74,240	)
Foreign—other	(167,113		)		67,938				(94,200		)		62,099
Income (loss) before income taxes	$	(246,816	)		$	49,439			$	(364,040	)		$	(12,141	)

 

For the three months ended, June 30, 2020 and 2019, our effective tax rate was 19% and 66%, respectively. For the six months ended, June 30, 2020 and 2019, our effective tax rate was 5% and 197%, respectively.

For the three and six months ended June 30, 2020, our overall effective tax rate was impacted by deferred tax expense related to valuation allowances on certain U.S. deferred tax assets and by a current tax benefit related to certain U.S. tax losses incurred in 2018 and carried back to years with a higher income tax rate. Additionally, for the three and six months ended June 30, 2020 and 2019, 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, non-deductible and non-taxable items associated with our U.S., Ghanaian, and Equatorial Guinean operations, and other losses and expenses, primarily related to exploration operations in tax-exempt jurisdictions or in taxable jurisdictions where we have valuation allowances against our deferred tax assets, and therefore, we do not realize any tax benefit on such losses or expenses.

The Company files income tax returns in all jurisdictions where such requirements exist, however, our primary tax jurisdictions are the United States, Ghana and Equatorial Guinea. The Company is open to tax examinations in the United States for federal income tax return years 2016 through 2019 and in Ghana to federal income tax return years 2014 through 2019.

 

As of June 30, 2020, the Company had no material uncertain tax positions. The Company’s policy is to recognize potential interest and penalties related to income tax matters in income tax expense.

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

 

	Three Months Ended								Six Months Ended
	June 30,								June 30,
	2020				2019				2020				2019
	(In thousands, except per share data)
Numerator:
Net income (loss) allocable to common stockholders	$	(199,391	)		$	16,837			$	(382,158	)		$	(36,069	)
Denominator:
Weighted average number of shares outstanding:
Basic	405,195				401,323				404,990				401,244
Restricted stock awards and units(1)(2)	—				6,907				—				—
Diluted	405,195				408,230				404,990				401,244
Net income (loss) per share:
Basic	$	(0.49	)		$	0.04			$	(0.94	)		$	(0.09	)
Diluted	$	(0.49	)		$	0.04			$	(0.94	)		$	(0.09	)

__________________________________

(1)	We excluded outstanding restricted stock awards and units of 11.6 million and 1.1 million for the three months ended June 30, 2020 and 2019, respectively, and 11.3 million and 12.9 million for the six months ended June 30, 2020 and 2019, respectively, from the computations of diluted net income (loss) per share because the effect would have been anti-dilutive.

 

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

 

We currently have a commitment to drill one exploration well in each of Sao Tome and Principe and Namibia and two exploration wells in Mauritania. In Sao Tome and Principe, we also have 3D seismic acquisition requirements of approximately 8,800 square kilometers, and in Mauritania we have 100 line km requirement for controlled source electromagnetic data acquisition. In South Africa we have 2D seismic acquisition requirements of approximately 500 line kilometers.

Performance Obligations

As of June 30, 2020 and December 31, 2019, the Company had performance bonds totaling $208.7 million for our supplemental bonding requirements stipulated by the BOEM and $7.2 million to other operators related to costs anticipated for the plugging and abandonment of certain wells and the removal of certain facilities in our U.S. Gulf of Mexico fields. As of June 30, 2020 and December 31, 2019, we had zero cash collateral against these secured performance bonds.

Dividends

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Accrued Liabilities

 

Accrued liabilities consisted of the following:

 

	June 30, 2020				December 31, 2019
	(In thousands)
Accrued liabilities:
Exploration, development and production	$	83,052			$	152,490
Revenue payable	22,028				32,482
Current asset retirement obligations	2,810				4,527
General and administrative expenses	3,518				44,575
Interest	22,953				33,584
Income taxes	56,649				103,566
Taxes other than income	3,230				3,375
Derivatives	5,340				4,837
Other	3,695				1,268
	$	203,275			$	380,704

Asset Retirement Obligations

 

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

	June 30, 2020
	(In thousands)
Asset retirement obligations:
Beginning asset retirement obligations	$	235,053
Liabilities incurred during period	—
Liabilities settled during period	(3,905		)
Revisions in estimated retirement obligations	2,138
Accretion expense	9,369
Ending asset retirement obligations	$	242,655

Facilities Insurance Modifications, Net

 

Facilities insurance modifications, net consists of costs associated with the long-term solution to convert the Jubilee FPSO to a permanently spread moored facility, net of related insurance reimbursements. During the three months ended June 30, 2020 and 2019, we incurred approximately $0.1 million and $11.2 million, respectively in expenditures offset by approximately zero and $8.9 million, respectively, in insurance recoveries. During the six months ended, June 30, 2020 and 2019, we incurred approximately $8.1 million and $22.2 million, respectively, in expenditures offset by approximately zero and $39.9 million, respectively, in insurance recoveries.

 

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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,
	2020				2019				2020				2019
	(In thousands)
Loss on disposal of inventory	$	361			$	—			$	1,828			$	187
(Gain) loss on ARO liability settlements	(28		)		(5		)		2,122				1,913
Restructuring charges	(575		)		—				13,340				—
Other, net	1,470				(1,788		)		7,867				(1,774		)
Other expenses, net	$	1,228			$	(1,793	)		$	25,157			$	326

 

The restructuring charges are for employee severance and related benefit costs incurred as part of a corporate reorganization.

Kosmos is engaged in a single line of business, which is the exploration and development of oil and gas. At June 30, 2020, the Company had operations in four geographic reporting segments: Ghana, Equatorial Guinea, Mauritania/Senegal and the U.S. Gulf of Mexico. To assess performance of the reporting segments, the Chief Operating Decision Maker ("CODM") reviews capital expenditures. Capital expenditures, as defined by the Company, may not be comparable to similarly titled measures used by other companies and should be considered in conjunction with our consolidated financial statements and notes thereto. Financial information for each area is presented below:

	Ghana				Equatorial Guinea				Mauritania/Senegal				U.S. Gulf of Mexico				Corporate & Other				Eliminations				Total
	(In thousands)
Three months ended June 30, 2020
Revenues and other income:
Oil and gas revenue	$	61,192			$	26,901			$	—			$	39,221			$	—			$	—			$	127,314
Other income, net	—				—				—				4				121,264				(121,268		)		—
Total revenues and other income	61,192				26,901				—				39,225				121,264				(121,268		)		127,314
Costs and expenses:
Oil and gas production	46,568				25,414				—				16,765				—				—				88,747
Facilities insurance modifications, net	52				—				—				—				—				—				52
Exploration expenses	13				2,117				985				6,594				6,002				—				15,711
General and administrative	3,132				1,222				2,176				2,849				28,217				(19,410		)		18,186
Depletion, depreciation and amortization	64,917				19,409				16				36,880				635				—				121,857
Impairment of long-lived assets	—				—				—				—				—				—				—
Interest and other financing costs, net(1)	13,322				(331		)		(6,222		)		2,991				20,297				(1,783		)		28,274
Derivatives, net	—				—				—				—				100,075				—				100,075
Other expenses, net	54,048				6,379				(322		)		40,093				1,105				(100,075		)		1,228
Total costs and expenses	182,052				54,210				(3,367		)		106,172				156,331				(121,268		)		374,130
Income (loss) before income taxes	(120,860		)		(27,309		)		3,367				(66,947		)		(35,067		)		—				(246,816		)
Income tax expense (benefit)	(44,051		)		(13,258		)		—				(1		)		9,885				—				(47,425		)
Net income (loss)	$	(76,809	)		$	(14,051	)		$	3,367			$	(66,946	)		$	(44,952	)		$	—			$	(199,391	)
Consolidated capital expenditures	$	8,590			$	9,335			$	2,202			$	39,897			$	6,360			$	—			$	66,384

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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, 2020
Revenues and other income:
Oil and gas revenue	$	110,900			$	51,520			$	—			$	142,674			$	—			$	—			$	305,094
Other income, net	1				—				—				451				9,255				(9,706		)		1
Total revenues and other income	110,901				51,520				—				143,125				9,255				(9,706		)		305,095
Costs and expenses:
Oil and gas production	64,610				36,889				—				48,851				—				—				150,350
Facilities insurance modifications, net	8,090				—				—				—				—				—				8,090
Exploration expenses	98				4,836				4,459				20,561				30,362				—				60,316
General and administrative	7,022				2,960				4,285				6,853				60,079				(42,102		)		39,097
Depletion, depreciation and amortization	84,648				28,303				31				100,714				1,463				—				215,159
Impairment of long-lived assets	—				—				—				150,820				—				—				150,820
Interest and other financing costs, net(1)	28,153				(700		)		(12,848		)		7,680				37,391				(3,567		)		56,109
Derivatives, net	—				—				—				—				(35,963		)		—				(35,963		)
Other expenses, net	(62,324		)		(9,377		)		2,471				43,745				14,679				35,963				25,157
Total costs and expenses	130,297				62,911				(1,602		)		379,224				108,011				(9,706		)		669,135
Income (loss) before income taxes	(19,396		)		(11,391		)		1,602				(236,099		)		(98,756		)		—				(364,040		)
Income tax expense (benefit)	(5,830		)		(8,670		)		—				30,902				1,716				—				18,118
Net income (loss)	$	(13,566	)		$	(2,721	)		$	1,602			$	(267,001	)		$	(100,472	)		$	—			$	(382,158	)
Consolidated capital expenditures	$	25,076			$	16,106			$	5,323			$	78,551			$	25,795			$	—			$	150,851
As of June 30, 2020
Property and equipment, net	$	1,429,160			$	453,178			$	451,140			$	1,018,586			$	26,601			$	—			$	3,378,665
Total assets	$	1,567,529			$	692,283			$	650,351			$	3,067,724			$	12,404,285			$	(14,395,681	)		$	3,986,491

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(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				Equatorial Guinea				Mauritania/Senegal				U.S. Gulf of Mexico				Corporate & Other				Eliminations				Total
	(In thousands)
Three months ended June 30, 2019
Revenues and other income:
Oil and gas revenue	$	202,085			$	64,484			$	—			$	129,364			$	—			$	—			$	395,933
Other income, net	1				—				—				124				19,079				(19,203		)		1
Total revenues and other income	202,086				64,484				—				129,488				19,079				(19,203		)		395,934
Costs and expenses:
Oil and gas production	44,954				16,670				—				29,353				—				—				90,977
Facilities insurance modifications, net	2,278				—				—				—				—				—				2,278
Exploration expenses	56				2,472				2,043				11,015				14,319				—				29,905
General and administrative	6,002				1,539				1,540				4,893				44,313				(30,215		)		28,072
Depletion, depreciation and amortization	75,898				16,287				15				58,215				1,023				—				151,438
Interest and other financing costs, net(1)	19,026				—				(6,524		)		5,642				43,443				(1,784		)		59,803
Derivatives, net	—				—				—				(1,390		)		(12,795		)		—				(14,185		)
Other expenses, net	(12,982		)		(2,583		)		412				553				11				12,796				(1,793		)
Total costs and expenses	135,232				34,385				(2,514		)		108,281				90,314				(19,203		)		346,495
Income (loss) before income taxes	66,854				30,099				2,514				21,207				(71,235		)		—				49,439
Income tax expense (benefit)	24,683				11,762				—				4,439				(8,282		)		—				32,602
Net income (loss)	$	42,171			$	18,337			$	2,514			$	16,768			$	(62,953	)		$	—			$	16,837
Consolidated capital expenditures	$	33,496			$	6,115			$	4,039			$	41,177			$	15,858			$	—			$	100,685

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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, 2019
Revenues and other income:
Oil and gas revenue	$	325,003			$	153,289			$	—			$	214,431			$	—			$	—			$	692,723
Other income, net	1				—				—				259				91,888				(92,147		)		1
Total revenues and other income	325,004				153,289				—				214,690				91,888				(92,147		)		692,724
Costs and expenses:
Oil and gas production	75,010				39,276				—				56,490				—				—				170,776
Facilities insurance modifications, net	(17,743		)		—				—				—				—				—				(17,743		)
Exploration expenses	107				5,643				8,485				22,209				23,805				—				60,249
General and administrative	11,958				3,584				3,827				12,286				88,519				(56,194		)		63,980
Depletion, depreciation and amortization	130,761				39,304				31				97,409				2,028				—				269,533
Interest and other financing costs, net(1)	39,679				—				(13,317		)		11,571				60,478				(3,567		)		94,844
Derivatives, net	—				—				—				30,513				32,387				—				62,900
Other expenses, net	32,118				(2,243		)		641				2,145				51				(32,386		)		326
Total costs and expenses	271,890				85,564				(333		)		232,623				207,268				(92,147		)		704,865
Income (loss) before income taxes	53,114				67,725				333				(17,933		)		(115,380		)		—				(12,141		)
Income tax expense (benefit)	19,700				27,293				—				(3,766		)		(19,299		)		—				23,928
Net income (loss)	$	33,414			$	40,432			$	333			$	(14,167	)		$	(96,081	)		$	—			$	(36,069	)
Consolidated capital expenditures	$	68,463			$	21,051			$	6,290			$	87,059			$	28,050			$	—			$	210,913
As of June 30, 2019
Property and equipment, net	$	1,643,410			$	460,679			$	422,539			$	1,281,439			$	39,506			$	—			$	3,847,573
Total assets	$	1,872,202			$	498,195			$	546,454			$	3,343,917			$	12,051,009			$	(13,846,043	)		$	4,465,734

______________________________________

(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.

	Six Months Ended June 30,
	2020				2019
	(In thousands)
Consolidated capital expenditures:
Consolidated Statements of Cash Flows - Investing activities:
Oil and gas assets	$	135,242			$	153,268
Other property	1,536				5,230
Adjustments:
Changes in capital accruals	(20,392		)		13,684
Exploration expense, excluding unsuccessful well costs and leasehold impairments(1)	39,461				53,150
Capitalized interest	(12,256		)		(14,253		)
Other	7,260				(166		)
Total consolidated capital expenditures	$	150,851			$	210,913

______________________________________

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

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•

Delay to the installation of the Ghana Jubilee catenary anchor leg mooring (“CALM”) buoy. The Government of Ghana implemented certain travel restrictions pertaining to its borders. The contractor responsible for the installation and commissioning of the Jubilee CALM buoy decided to suspend operations and demobilize from Ghana. Kosmos expects the contractor to return to Ghana this year to complete installation and commissioning of the CALM buoy. As a result of the delay, the Jubilee joint venture is expected to continue to incur an estimated $6 million (gross) per month conducting ship to ship transfer operations until the CALM buoy is installed and commissioned.

•	Deferral of the current Ghana drilling program associated with the termination of the Ghana drilling rig contract. The Company did not incur material costs associated with the termination of the drilling contract.

•	Elected to defer completion operations on the Kodiak in-fill well drilled during 2020 in the U.S. Gulf of Mexico. Additionally, our U.S. Gulf of Mexico infrastructure led exploration (ILX) program was suspended. The Company did not incur material costs associated with the decision not to extend the drilling contract.

•	Suspension of the 2020-2021 Equatorial Guinea drilling program and ESP program. The Company did not incur material costs associated with the suspension of the programs.

•

Delay of the construction of the Greater Tortue Ahmeyim Phase 1 development project by approximately 12 months, with first gas now expected in the first half of 2023. Phase 1 of the project is currently approximately 40% complete. This delay is expected to result in a significant reduction in budgeted spend in 2020 as activity and milestone payments are delayed. With the re-phasing of the project timeline, the partnership has approved a revised budget and, as a result, the carry of our capital obligations is expected to be extended through the end of this year. In addition, we continue with the Tortue sell down process to support a self-funded gas business.

•

Government of Sao Tome and Principe implemented certain travel regulations restricting international travelers from entering the country. These restrictions made it impossible for the Company to safely manage the seismic acquisition in Blocks 10 and 13. As the technical operator of the seismic acquisition, the Company declared force majeure on the seismic acquisition contract and terminated it. Thereafter, BP, as operator of Blocks 10 and 13, declared force majeure on the blocks.

•	Delayed expected spud date of the Jaca exploration well in Sao Tome Block 6 from the fourth quarter of 2020 to the second half of 2021.

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•	Suspension of the quarterly dividend by the Board of Directors.

•	During the first quarter of 2020, reduced Company headcount resulting in restructuring charges for employee severance and related benefits totaling approximately $13.3 million during the six months ended June 30, 2020.

•	During the first quarter of 2020, recorded asset impairments totaling $150.8 million during the three months ended March 31, 2020 primarily as a result of lower oil prices arising from the COVID-19 pandemic. The Company did not recognize additional impairment of proved oil and gas properties during the three months ended June 30, 2019 as no impairment indicators were identified.

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(1)	Represents commitments under the Production Prepayment Agreement to be advanced in September 2020, subject to Kosmos' election.

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•	the guarantor liquidity ratio (as defined in the glossary), not less than 1.20x and

•	the GoM liquidity ratio (as defined in the glossary), not less than 1.50x

(1)

Includes the scheduled principal maturities for the $650.0 million aggregate principal amount of Senior Notes issued in April 2019, and borrowings under the Facility and the Corporate Revolver. The scheduled maturities of debt related to the Facility are based on, as of June 30, 2020, 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 estimated value of crude oil to be delivered based on quoted future market prices, including $7.5 million of financing costs to be paid under the Production Prepayment Agreement. Volumes delivered prior to July 2021 are associated with financing costs. Any increases or decreases in future market prices would impact the scheduled maturities during the next five years and thereafter.

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

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

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(5)

Does not include purchase commitments for jointly owned fields and facilities where we are not the operator and excludes commitments for exploration activities, including well commitments and seismic obligations, in our petroleum contracts. The Company's liabilities for asset retirement obligations associated with the dismantlement, abandonment and restoration costs of oil and gas properties are not included. See Note 16 — Additional Financial Information for additional information regarding these liabilities.

(6)	Represents the period from July 1, 2020 through December 31, 2020.

(1)	The amounts included in the table represent principal maturities only. The scheduled maturities of debt are based on the level of borrowings and the available borrowing base as of June 30, 2020. Any increases or decreases in the level of borrowings or increases or decreases in the available borrowing base would impact the scheduled maturities of debt during the next five years and thereafter.

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

(3)	Represents estimated value of crude oil to be delivered as principal repayment based on quoted future market prices. Any increases or decreases in future market prices would impact the scheduled maturities during the next five years and thereafter.

(4)	Represents the period July 1, 2020 through December 31, 2020.

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•	the impact of the COVID-19 pandemic on the Company and the overall business environment;

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

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

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

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

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

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

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

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

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

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

•	other competitive pressures;

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

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

•	cost of compliance with laws and regulations;

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

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

•	environmental liabilities;

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

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

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

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

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

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

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

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

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

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

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(1)	Added call spreads on 1.0 million barrels to open upside for U.S. Gulf of Mexico production.

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

(3)	Fair values are based on the average forward oil prices on June 30, 2020.

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