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Kosmos Energy Ltd. - Quarter Report: 2020 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, 2020
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
 
kos_logo.jpg
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 July 30, 2020
Common Shares, $0.01 par value
 
405,410,075
 




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
 
 
 
 
 
 
 
PART II. OTHER INFORMATION
 
 
 
KOSMOS ENERGY LTD.
GLOSSARY AND SELECTED ABBREVIATIONS
 
The following are abbreviations and definitions of certain terms that may be used in this report. Unless listed below, all defined terms under Rule 4-10(a) of Regulation S-X shall have their statutorily prescribed meanings.
 
“2D seismic data”
    
Two‑dimensional seismic data, serving as interpretive data that allows a view of a vertical cross‑section beneath a prospective area.
“3D seismic data”
 
Three‑dimensional seismic data, serving as geophysical data that depicts the subsurface strata in three dimensions. 3D seismic data typically provides a more detailed and accurate interpretation of the subsurface strata than 2D seismic data.
"ANP-STP"
 
Agencia Nacional Do Petroleo De Sao Tome E Principe.
“API”
 
A specific gravity scale, expressed in degrees, that denotes the relative density of various petroleum liquids. The scale increases inversely with density. Thus lighter petroleum liquids will have a higher API than heavier ones.
“ASC”
 
Financial Accounting Standards Board Accounting Standards Codification.
“ASU”
 
Financial Accounting Standards Board Accounting Standards Update.

2


“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"
 
Revolving Credit Facility Agreement dated November 23, 2012 (as amended or as amended and restated from time to time)
"COVID-19"
 
Coronavirus disease 2019.
“Developed acreage”
 
The number of acres that are allocated or assignable to productive wells or wells capable of production.
“Development”
 
The phase in which an oil or natural gas field is brought into production by drilling development wells and installing appropriate production systems.
"DGE"
 
Deep Gulf Energy (together with its subsidiaries).
"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.
“EBITDAX”
 
Net income (loss) plus (i) exploration expense, (ii) depletion, depreciation and amortization expense, (iii) equity‑based compensation expense, (iv) unrealized (gain) loss on commodity derivatives (realized losses are deducted and realized gains are added back), (v) (gain) loss on sale of oil and gas properties, (vi) interest (income) expense, (vii) income taxes, (viii) loss on extinguishment of debt, (ix) doubtful accounts expense and (x) similar other material items which management believes affect the comparability of operating results. The Facility EBITDAX definition includes 50% of the EBITDAX adjustments of Kosmos-Trident International Petroleum Inc for the period it was an equity method investment and includes Last Twelve Months ("LTM") EBITDAX for any acquisitions and excludes LTM EBITDAX for any divestitures.
"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.
"FLNG"
 
Floating liquefied natural gas.
“FPS”
 
Floating production system.
“FPSO”
 
Floating production, storage and offloading vessel.
"Galp"
 
Galp Energia Sao Tome E Principe, Unipessoal, LDA.
"GEPetrol"
 
Guinea Equatorial De Petroleos.
"GHG"
 
Greenhouse gas.

3


"GJFFDP"
 
Greater Jubilee Full Field Development Plan.
"GNPC"
 
Ghana National Petroleum Corporation.
GoM Liquidity Ratio
 
The "GoM Liquidity Ratio" is broadly defined, for each applicable forecast period, as the ratio of (1) net cash flow of our U.S. Gulf of Mexico business unit over the immediately succeeding six (6) months from the sale of the volumes of crude oil using certain agreed pricing metrics and models set forth in the Production Prepayment Agreement, to (2) the portion of the Prepaid Value to be delivered to Trafigura as determined by the Volume Model for the same six (6) month period.
“Greater Tortue Ahmeyim”
 
Ahmeyim and Guembeul discoveries.
"GTA UUOA"
 
Unitization and Unit Operating Agreement covering the Greater Tortue Ahmeyim Unit.
"Guarantor Liquidity Ratio"
 
The "Guarantor Liquidity Ratio" is broadly defined, for each applicable forecast period, as the ratio of (1) the sum of (A) projected revenues of the Company from the sale of hydrocarbons over the four quarters beginning on or after the calculation date, (B) the expected income from hedges then in effect (but not less than zero), (C) its cash balance as of the calculation date, and (D) the amount of the Prepayments available under the Production Prepayment Agreement and any other committed sources of capital of the Company, to (2) the sum of all forecast cash costs of the Company over the four quarters beginning on or after the calculation date.
"Hess"
 
Hess Corporation.
"HLS"
 
Heavy Louisiana Sweet.
"H&M"
 
Hull and Machinery insurance.
"Jubilee UUOA"
 
Unitization and Unit Operating Agreement covering the Jubilee Unit.
"KTEGI"
 
Kosmos-Trident Equatorial Guinea Inc.
"KTIPI"
 
Kosmos-Trident International Petroleum Inc.
"LNG"
 
Liquefied natural gas.
"LOPI"
 
Loss of Production Income.
"LSE"
 
London Stock Exchange.
"LTIP"
 
Long Term Incentive Plan.
“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.
"NAMCOR"
 
National Petroleum Corporation of Namibia.
“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.
"NYSE"
 
New York Stock Exchange.
"Ophir"
 
Ophir Energy plc.
"PETROCI"
 
PETROCI Holding.
“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.

4


"Prepaid Value"
 
As defined in the Production Prepayment Agreement attached as exhibit 10.3 hereto.
“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.
"SEC"
 
Securities and Exchange Commission.
"Senior Notes"
 
7.125% Senior Notes due 2026.
"Senior Secured Notes"
 
7.875% Senior Secured Notes due 2021.
“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.
"SNPC"
 
Société Nationale des Pétroles du Congo.
“Stratigraphy”
 
The study of the composition, relative ages and distribution of layers of sedimentary rock.
“Stratigraphic trap”
 
A stratigraphic trap is formed from a change in the character of the rock rather than faulting or folding of the rock and oil is held in place by changes in the porosity and permeability of overlying rocks.
“Structural trap”
 
A topographic feature in the earth’s subsurface that forms a high point in the rock strata. This facilitates the accumulation of oil and 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.
"Trafigura
 
Trafigura Group PTD, Ltd. and related subsidiaries including Trafigura Trading LLC.
“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.
"Volume Model"
 
As defined in the Production Prepayment Agreement attached as exhibit 10.3 hereto.
"WCTP"
 
West Cape Three Points.


5




KOSMOS ENERGY LTD. 
CONSOLIDATED BALANCE SHEETS 
(In thousands, except share data)
 
June 30,
2020
 
December 31,
2019
 
(Unaudited)
 
 
Assets
 

 
 

Current assets:
 

 
 

Cash and cash equivalents
$
164,091

 
$
224,502

Restricted cash
186

 
4,302

Receivables:
 
 
 
Joint interest billings, net
56,267

 
81,424

Oil sales
33,497

 
64,142

Other
26,797

 
28,727

Inventories
130,299

 
114,412

Prepaid expenses and other
39,573

 
36,192

Derivatives
30,289

 
12,856

Total current assets
480,999

 
566,557

Property and equipment:
 

 
 

Oil and gas properties, net
3,365,746

 
3,624,751

Other property, net
12,919

 
17,581

Property and equipment, net
3,378,665

 
3,642,332

Other assets:
 

 
 

Restricted cash
542

 
542

Long-term receivables
88,137

 
43,430

Deferred financing costs, net of accumulated amortization of $15,989 and $14,681 at June 30, 2020 and December 31, 2019, respectively
5,013

 
6,321

Deferred tax assets

 
32,779

Derivatives
11,271

 
2,302

Other
21,864

 
22,969

Total assets
$
3,986,491

 
$
4,317,232

Liabilities and stockholders’ equity
 

 
 

Current liabilities:
 

 
 

Accounts payable
$
145,670

 
$
149,483

Accrued liabilities
203,275

 
380,704

Current maturities of long-term debt
56,000

 

Derivatives
43,974

 
8,914

Total current liabilities
448,919

 
539,101

Long-term liabilities:
 

 
 

Long-term debt, net
2,107,653

 
2,008,063

Production prepayment agreement, net
49,333

 

Derivatives
9,306

 
11,478

Asset retirement obligations
239,845

 
230,526

Deferred tax liabilities
644,091

 
653,221

Other long-term liabilities
33,157

 
33,141

Total long-term liabilities
3,083,385

 
2,936,429

Stockholders’ equity:
 

 
 

Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at June 30, 2020 and December 31, 2019

 

Common stock, $0.01 par value; 2,000,000,000 authorized shares; 449,574,638 and 445,779,367 issued at June 30, 2020 and December 31, 2019, respectively
4,496

 
4,458

Additional paid-in capital
2,291,826

 
2,297,221

Accumulated deficit
(1,605,128
)
 
(1,222,970
)
Treasury stock, at cost, 44,263,269 shares at June 30, 2020 and December 31, 2019, respectively
(237,007
)
 
(237,007
)
Total stockholders’ equity
454,187

 
841,702

Total liabilities and stockholders’ equity
$
3,986,491

 
$
4,317,232

See accompanying notes.

6


KOSMOS ENERGY LTD.
 
CONSOLIDATED STATEMENTS OF OPERATIONS
 
(In thousands, except per share data)
 
(Unaudited)
 
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2020
 
2019
 
2020
 
2019
Revenues and other income:
 

 
 

 
 

 
 

Oil and gas revenue
$
127,314

 
$
395,933

 
$
305,094

 
$
692,723

Other income, net

 
1

 
1

 
1

Total revenues and other income
127,314

 
395,934

 
305,095

 
692,724

Costs and expenses:
 

 
 

 
 

 
 

Oil and gas production
88,747

 
90,977

 
150,350

 
170,776

Facilities insurance modifications, net
52

 
2,278

 
8,090

 
(17,743
)
Exploration expenses
15,711

 
29,905

 
60,316

 
60,249

General and administrative
18,186

 
28,072

 
39,097

 
63,980

Depletion, depreciation and amortization
121,857

 
151,438

 
215,159

 
269,533

Impairment of long-lived assets

 

 
150,820

 

Interest and other financing costs, net
28,274

 
59,803

 
56,109

 
94,844

Derivatives, net
100,075

 
(14,185
)
 
(35,963
)
 
62,900

Other expenses, net
1,228

 
(1,793
)
 
25,157

 
326

Total costs and expenses
374,130

 
346,495

 
669,135

 
704,865

Income (loss) before income taxes
(246,816
)
 
49,439

 
(364,040
)
 
(12,141
)
Income tax expense (benefit)
(47,425
)
 
32,602

 
18,118

 
23,928

Net income (loss)
$
(199,391
)
 
$
16,837

 
$
(382,158
)
 
$
(36,069
)
 
 
 
 
 
 
 
 
Net income (loss) per share:
 

 
 

 
 

 
 

Basic
$
(0.49
)
 
$
0.04

 
$
(0.94
)
 
$
(0.09
)
Diluted
$
(0.49
)
 
$
0.04

 
$
(0.94
)
 
$
(0.09
)
 
 
 
 
 
 
 
 
Weighted average number of shares used to compute net income (loss) per share:
 

 
 

 
 

 
 

Basic
405,195

 
401,323

 
404,990

 
401,244

Diluted
405,195

 
408,230

 
404,990

 
401,244

 
 
 
 
 
 
 
 
Dividends declared per common share
$

 
$
0.0452

 
$
0.0452

 
$
0.0904

 
See accompanying notes.

7


KOSMOS ENERGY LTD.
 
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
 
(In thousands)
 
(Unaudited)
 
 
 
 
 
 
Additional
 
 
 
 
 
 
 
Common Shares
 
Paid-in
 
Accumulated
 
Treasury
 
 
 
Shares
 
Amount 
 
Capital
 
Deficit
 
Stock
 
Total
2020:
 
 
 
 
 
 
 
 
 
 
 
Balance as of December 31, 2019
445,779

 
$
4,458

 
$
2,297,221

 
$
(1,222,970
)
 
$
(237,007
)
 
$
841,702

Dividends ($0.0452 per share)

 

 
(18,918
)
 

 

 
(18,918
)
Equity-based compensation

 

 
10,078

 

 

 
10,078

Restricted stock awards and units
3,590

 
36

 
(36
)
 

 

 

Purchase of treasury stock / tax withholdings

 

 
(4,947
)
 

 

 
(4,947
)
Net loss

 

 

 
(182,767
)
 

 
(182,767
)
Balance as of March 31, 2020
449,369

 
4,494

 
2,283,398

 
(1,405,737
)
 
(237,007
)
 
645,148

Dividends

 

 
24

 

 

 
24

Equity-based compensation

 

 
8,406

 

 

 
8,406

Restricted stock awards and units
206

 
2

 
(2
)
 

 

 

Net loss

 

 

 
(199,391
)
 

 
(199,391
)
Balance as of June 30, 2020
449,575

 
$
4,496

 
$
2,291,826

 
$
(1,605,128
)
 
$
(237,007
)
 
$
454,187

 
 
 
 
 
 
 
 
 
 
 
 
2019:
 
 
 
 
 
 
 
 
 
 


Balance as of December 31, 2018
442,915

 
$
4,429

 
$
2,341,249

 
$
(1,167,193
)
 
$
(237,007
)
 
$
941,478

Dividends ($0.0452 per share)

 

 
(18,744
)
 

 

 
(18,744
)
Equity-based compensation

 

 
8,744

 

 

 
8,744

Restricted stock awards and units
2,610

 
26

 
(26
)
 

 

 

Purchase of treasury stock / tax withholdings

 

 
(1,979
)
 

 

 
(1,979
)
Net loss

 

 

 
(52,906
)
 

 
(52,906
)
Balance as of March 31, 2019
445,525

 
$
4,455

 
$
2,329,244

 
$
(1,220,099
)
 
$
(237,007
)
 
$
876,593

Dividends ($0.0452 per share)

 

 
(18,740
)
 

 

 
(18,740
)
Equity-based compensation

 

 
9,525

 

 

 
9,525

Restricted stock awards and units
113

 
1

 
(1
)
 

 

 

Purchase of treasury stock / tax withholdings

 

 
(4
)
 

 

 
(4
)
Net income

 

 

 
16,837

 

 
16,837

Balance as of June 30, 2019
445,638

 
$
4,456

 
$
2,320,024

 
$
(1,203,262
)
 
$
(237,007
)
 
$
884,211

 
 
 
 
 
 
 
 
 
 
 
 
 
See accompanying notes.

8


KOSMOS ENERGY LTD.
 
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
(In thousands)
 
(Unaudited)
 
Six Months Ended June 30,
 
2020

2019
Operating activities
 

 
 

Net loss
$
(382,158
)
 
$
(36,069
)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
 
 
 
Depletion, depreciation and amortization (including deferred financing costs)
219,634

 
274,222

Deferred income taxes
23,650

 
(56,730
)
Unsuccessful well costs and leasehold impairments
20,855

 
7,099

Impairment of long-lived assets
150,820

 

Change in fair value of derivatives
(31,615
)
 
65,686

Cash settlements on derivatives, net (including $42.4 million and $(18.7) million on commodity hedges during 2020 and 2019)
34,814

 
(21,044
)
Equity-based compensation
17,693

 
17,932

Loss on extinguishment of debt
2,215

 
24,794

Other
6,529

 
7,417

Changes in assets and liabilities:
 
 
 
(Increase) decrease in receivables
57,593

 
(23,996
)
Increase in inventories
(17,715
)
 
(19,021
)
(Increase) decrease in prepaid expenses and other
(3,464
)
 
29,380

Decrease in accounts payable
(3,813
)
 
(76,031
)
Increase (decrease) in accrued liabilities
(157,874
)
 
28,751

Net cash provided by (used in) operating activities
(62,836
)
 
222,390

Investing activities
 

 
 

Oil and gas assets
(135,242
)
 
(153,268
)
Other property
(1,536
)
 
(5,230
)
Proceeds on sale of assets
1,713

 

Notes receivable from partners
(42,362
)
 
(5,983
)
Net cash used in investing activities
(177,427
)
 
(164,481
)
Financing activities
 

 
 

Borrowings under long-term debt
150,000

 
175,000

Payments on long-term debt

 
(300,000
)
Advances under production prepayment agreement
50,000

 

Net proceeds from issuance of senior notes

 
641,875

Redemption of senior secured notes

 
(535,338
)
Purchase of treasury stock / tax withholdings
(4,947
)
 
(1,983
)
Dividends
(19,181
)
 
(36,289
)
Deferred financing costs
(136
)
 
(1,981
)
Net cash provided by (used in) financing activities
175,736

 
(58,716
)
Net decrease in cash, cash equivalents and restricted cash
(64,527
)
 
(807
)
Cash, cash equivalents and restricted cash at beginning of period
229,346

 
185,616

Cash, cash equivalents and restricted cash at end of period
$
164,819

 
$
184,809

 
 
 
 
Supplemental cash flow information
 

 
 

Cash paid for:
 

 
 

Interest, net of capitalized interest
$
58,096

 
$
65,307

Income taxes
$
54,199

 
$
14,619

 See accompanying notes.





9



KOSMOS ENERGY LTD.
 
Notes to Consolidated Financial Statements
(Unaudited)
 
1. Organization
 
Kosmos Energy Ltd. changed its jurisdiction of incorporation from Bermuda to the State of Delaware, in the United States of America, (the "Redomestication") in December 2018. As a holding company, Kosmos Energy Ltd.’s management operations are conducted through a wholly-owned subsidiary, Kosmos Energy, LLC. The terms “Kosmos,” the “Company,” “we,” “us,” “our,” “ours,” and similar terms refer to Kosmos Energy Ltd. and its wholly-owned subsidiaries, unless the context indicates otherwise.
Kosmos is a full-cycle deepwater independent oil and gas exploration and production company focused along the Atlantic Margins. Our key assets include production offshore Ghana, Equatorial Guinea and U.S. Gulf of Mexico, as well as a world-class gas development offshore Mauritania and Senegal. We also maintain a sustainable exploration program balanced between proven basin infrastructure-led exploration (Equatorial Guinea and U.S. Gulf of Mexico), emerging basins (Mauritania, Senegal and Suriname) and frontier basins (Namibia, Sao Tome and Principe, and South Africa). Kosmos is listed on the New York Stock Exchange and London Stock Exchange and is traded under the ticker symbol KOS.
 
Kosmos is engaged in a single line of business, which is the exploration, development, and production of oil and natural gas. Substantially all of our long-lived assets and all of our product sales are related to operations in four geographic areas: Ghana, Equatorial Guinea, Mauritania/Senegal and U.S. Gulf of Mexico. In addition, we have exploration activities in other countries in the Atlantic Margins.
 
2. Accounting Policies
 
General
 
The interim consolidated financial statements included in this report are unaudited and, in the opinion of management, include all adjustments of a normal recurring nature necessary for a fair presentation of the results for the interim periods. The results of the interim periods shown in this report are not necessarily indicative of the final results to be expected for the full year. The consolidated financial statements were prepared in accordance with the requirements of the Securities and Exchange Commission (“SEC”) for interim reporting. As permitted under those rules, certain notes or other financial information that are normally required by Generally Accepted Accounting Principles in the United States of America (“GAAP”) have been condensed or omitted from these interim consolidated financial statements. These consolidated financial statements and the accompanying notes should be read in conjunction with our audited consolidated financial statements for the year ended December 31, 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


 

10


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




11


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.

3. Acquisitions and Divestitures

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.

In March 2019, we completed an agreement to acquire Ophir's remaining interest in Block EG-24, offshore Equatorial Guinea, which increased our participating interest to 80% and named Kosmos as operator.


12


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

The Company’s joint interest billings generally consist of receivables from partners with interests in common oil and gas properties operated by the Company for shared costs. Joint interest billings are classified on the 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.

5. Property and Equipment
 
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.
 

13


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, 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.


14



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

The components of lease cost for the three 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

 
__________________________________
(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

 

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


15


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

 
__________________________________
(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.


8. Debt
 
 
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

__________________________________
(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.
 

16


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.
    




17


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

__________________________________
(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





9. Production Prepayment Agreement, net

 
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

18


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

 
$

 
$

__________________________________
(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.


10. 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.
 

19


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
)




20


 
 
 
 
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.

11. 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.


21


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.
 

22


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.

 

23


12. 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 $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.
  
13. Income Taxes

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

24


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.
 

25


14. Net Income (Loss) Per Share
 
The following table is a reconciliation between net income (loss) and the amounts used to compute basic and diluted net income (loss) per share and the weighted average shares outstanding used to compute basic and diluted net income (loss) per share:
 
 
Three Months Ended
 
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.  

15. Commitments and Contingencies
 
From time to time, we are involved in litigation, regulatory examinations and administrative proceedings primarily arising in the ordinary course of our business in jurisdictions in which we do business. Although the outcome of these matters cannot be predicted with certainty, management believes none of these matters, either individually or in the aggregate, would have a material effect upon the Company’s financial position; however, an unfavorable outcome could have a material adverse effect on our results from operations for a specific interim period or year.
 
We currently have a commitment to drill one exploration well in each of Sao Tome and Principe and Namibia and two exploration wells in Mauritania. In Sao Tome and Principe, we also have 3D seismic acquisition requirements of approximately 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

On March 26, 2020, the quarterly cash dividend of $0.0452 per common share was paid to stockholders of record as of March 5, 2020. In March 2020, in response to economic conditions, including oil price volatility and the impact of COVID-19 pandemic, the Board of Directors decided to suspend the dividend.


26


16. Additional Financial Information
 
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.
 

27


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.
 
17. Business Segment Information
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

 
 
 
 
 
 
 
 
 
 
 
 
 
 

28


 
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

______________________________________
(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.


29



 
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

 
 
 
 
 
 
 
 
 
 
 
 
 
 

30


 
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.




31


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, 2019, included in our annual report on Form 10-K along with the section Management’s Discussion and Analysis of financial condition and Results of Operations contained in such annual report. Any terms used but not defined in the following discussion have the same meaning given to them in the annual report. Our discussion and analysis includes forward-looking statements that involve risks and uncertainties and should be read in conjunction with “Risk Factors” under Item 1A of this report and in the annual report, along with “Forward-Looking Information” at the end of this section for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.
 
Overview
 
We are a full-cycle deepwater independent oil and gas exploration and production company focused along the Atlantic Margins. Our key assets include production offshore Ghana, Equatorial Guinea and U.S. Gulf of Mexico, as well as a world-class gas development offshore Mauritania and Senegal. We also maintain a sustainable exploration program balanced between proven basin infrastructure-led exploration (Equatorial Guinea and U.S. Gulf of Mexico), emerging basins (Mauritania, Senegal and Suriname) and frontier basins (Namibia, Sao Tome and Principe, and South Africa).

The ongoing COVID-19 pandemic that emerged at the beginning of 2020 has resulted in increased travel restrictions, including border closures, travel bans, social distancing restrictions and office closures being ordered in the various countries in which we operate, impacting some of our business operations. These ongoing restrictions have had an impact on the supply chain, resulting in the delay of various operational projects. Globally, the impact of COVID-19 has decreased demand for oil, which has also resulted in significant declines in oil prices. The Company’s revenues, earnings, cash flows, capital investments and, ultimately, future rate of growth are highly dependent on oil prices. Due to the COVID-19 pandemic, our operations have been impacted as follows:

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.

32



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.


Recent Developments
    
Ghana
 
Jubilee
 
During the second quarter of 2020, Jubilee production averaged approximately 90,000 Bopd (gross) with consistent water injection and gas offtake since the work to enhance gas handling capacity was successfully performed by the operator during the first quarter of 2020.
TEN
During the second quarter of 2020, TEN production averaged approximately 50,000 Bopd (gross). In the third quarter of 2020, Kosmos expects the NT-09 well to be brought online.

U.S. Gulf of Mexico

Production from the U.S. Gulf of Mexico averaged approximately 20,200 Boepd (net) for the second quarter of 2020, including the impact of approximately 6,000 Boepd shut-in during the quarter.

As a result of market conditions in the second quarter, the operator of the Delta House platform in the U.S. Gulf of Mexico shut-in the facility during the month of May 2020 and accelerated planned maintenance. The shut-ins were primarily limited to May 2020 and all shut-in fields were brought back online by early June 2020.

In the first half of 2020, we successfully drilled a Kodiak development well located in Mississippi Canyon Block 727 (29.1% working interest). The well is a subsea tieback, which is expected to be brought online through existing infrastructure to the Devils Tower SPAR in the first half of 2021.

In Q2 2020, Tornado 4 development well located in Green Canyon Block 280 (35.0% working interest) was successfully drilled by the operator. Kosmos expects the well to be brought online in the second half of 2020, produce for approximately 6 months, and then be converted to a waterflood well.

Equatorial Guinea
    
Production in Equatorial Guinea averaged approximately 34,000 Bopd (gross) in the second quarter of 2020.

Mauritania and Senegal

Greater Tortue Ahmeyim Unit

The Tortue Phase 1 SPA was signed on February 11, 2020, resulting in approximately 100 MMBoe of proved undeveloped reserves being recognized at that time as evaluated by the Company's independent reserve auditor, Ryder Scott, LP.

Suriname

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

33



Sao Tome and Principe

In July 2020, we received approval for a one year extension to the current exploration phase for Block 11 offshore Sao Tome and Principe to July 2022.

Cote d'Ivoire

In May 2020, a withdrawal notice for our offshore blocks CI-526, CI-602, CI-603, CI-707, and CI-708 offshore Cote d'Ivoire was issued to partners and the Government of Cote d'Ivoire.

Republic of the Congo

In February 2020, notice of withdrawal from the approval process awarding Kosmos' interest in the offshore Marine XXI block was issued to the Republic of the Congo.

    

34


Results of Operations
 
All of our results, as presented in the table below, represent operations from Jubilee and TEN fields in Ghana, the U.S. Gulf of Mexico and Equatorial Guinea. Certain operating results and statistics for the three and six months ended June 30, 2020 and 2019 are included in the following tables:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
 
2020
 
2019
 
2020
 
2019
 
 
(In thousands, except per volume data)
 
Sales volumes:
 
 
 
 
 
 
 
 
Oil (MBbl)
5,751

 
5,851

 
9,202

 
10,541

 
Gas (MMcf)
1,303

 
1,663

 
3,284

 
3,464

 
NGL (MBbl)
142

 
139

 
335

 
251

 
Total (MBoe)
6,110

 
6,267

 
10,084

 
11,369

 
Total (Boepd)
67,145

 
68,870

 
55,408

 
62,814

 
 
 
 
 
 
 
 
 
 
Revenues:
 
 
 
 
 
 
 
 
Oil sales
$
124,813

 
$
389,286

 
$
296,729

 
$
680,150

 
Gas sales
2,113

 
4,145

 
5,832

 
7,807

 
NGL sales
388

 
2,502

 
2,533

 
4,766

 
Total revenues
$
127,314

 
$
395,933

 
$
305,094

 
$
692,723

 
 
 
 
 
 
 
 
 
 
Average oil sales price per Bbl
$
21.70

 
$
66.53

 
$
32.25

 
$
64.52

 
Average gas sales price per Mcf
1.62

 
2.49

 
1.78

 
2.25

 
Average NGL sales price per Bbl
2.73

 
18.01

 
7.56

 
19.00

 
Average total sales price per Boe
20.84

 
63.18

 
30.25

 
60.93

 
 
 
 
 
 
 
 
 
 
Costs:
 
 
 
 
 
 
 
 
Oil and gas production, excluding workovers
$
87,726

 
$
85,351

 
$
145,143

 
$
158,066

 
Oil and gas production, workovers
1,021

 
5,626

 
5,207

 
12,710

 
Total oil and gas production costs
$
88,747

 
$
90,977

 
$
150,350

 
$
170,776

 
 
 
 
 
 
 
 
 
 
Depletion, depreciation and amortization
$
121,857

 
$
151,438

 
$
215,159

 
$
269,533

 
 
 
 
 
 
 
 
 
 
Average cost per Boe:
 
 
 
 
 
 
 
 
Oil and gas production, excluding workovers
$
14.36

 
$
13.62

 
$
14.39

 
$
13.90

 
Oil and gas production, workovers
0.17

 
0.90

 
0.52

 
1.12

 
Total oil and gas production costs
14.53

 
14.52

 
14.91

 
15.02

 
 
 
 
 
 
 
 
 
 
Depletion, depreciation and amortization
19.94

 
24.16

 
21.34

 
23.71

 
Total
$
34.47

 
$
38.68

 
$
36.25

 
$
38.73

 





35


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, 2020:
 
 
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

 

 

 

 

 

 
9

 
2.17

TEN

 

 
1

 
0.17

 

 

 
7

 
1.19

Equatorial Guinea
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Block S

 

 

 

 
1

 
0.40

 

 

U.S. Gulf of Mexico
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Tornado 4

 

 
1

 
0.35

 

 

 

 

Kodiak 727 #3

 

 

 

 

 

 
1

 
0.29

Mauritania / Senegal
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Mauritania C8

 

 

 

 
2

 
0.56

 

 

Greater Tortue Ahmeyim Unit

 

 

 

 
3

 
0.80

 
1

 
0.27

Senegal Cayar Profond

 

 

 

 
3

 
0.90

 

 

Total

 

 
2

 
0.52

 
9

 
2.66

 
18

 
3.92


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, 2020 compared to three months ended June 30, 2019
 
 
Three Months Ended
 
 
 
June 30,
 
Increase
 
2020
 
2019
 
(Decrease)
 
(In thousands)
Revenues and other income:
 

 
 

 
 

Oil and gas revenue
$
127,314

 
$
395,933

 
$
(268,619
)
Other income, net

 
1

 
(1
)
Total revenues and other income
127,314

 
395,934

 
(268,620
)
Costs and expenses:
 

 
 

 
 

Oil and gas production
88,747

 
90,977

 
(2,230
)
Facilities insurance modifications, net
52

 
2,278

 
(2,226
)
Exploration expenses
15,711

 
29,905

 
(14,194
)
General and administrative
18,186

 
28,072

 
(9,886
)
Depletion, depreciation and amortization
121,857

 
151,438

 
(29,581
)
Impairment of long-lived assets

 

 

Interest and other financing costs, net
28,274

 
59,803

 
(31,529
)
Derivatives, net
100,075

 
(14,185
)
 
114,260

Other expenses, net
1,228

 
(1,793
)
 
3,021

Total costs and expenses
374,130

 
346,495

 
27,635

Income (loss) before income taxes
(246,816
)
 
49,439

 
(296,255
)
Income tax expense (benefit)
(47,425
)
 
32,602

 
(80,027
)
Net income (loss)
$
(199,391
)
 
$
16,837

 
$
(216,228
)
 

36


Oil and gas revenue.  Oil and gas revenue decreased by $268.6 million as a result of lower oil prices stemming from the excess market supplies related to the COVID-19 pandemic. We sold 6,110 MBoe at an average realized price per barrel equivalent of $20.84 during the three months ended June 30, 2020 and 6,267 MBoe at an average realized price per barrel equivalent of $63.18 during the three months ended June 30, 2019.

Oil and gas production.  Oil and gas production costs decreased by $2.2 million during the three months ended June 30, 2020, as compared to the three months ended June 30, 2019 as a result of lower workover costs in the current period.
 
Facilities insurance modifications, net. During the three months ended June 30, 2020, we incurred $0.1 million of facilities insurance modifications costs associated with the long-term solution to the Jubilee turret bearing issue versus $11.2 million during the three months ended June 30, 2019. During the three months ended June 30, 2020 and 2019, these costs were offset by zero and $8.9 million, respectively, of hull and machinery insurance proceeds.
 
Exploration expenses.  Exploration expenses decreased by $14.2 million during the three months ended June 30, 2020, as compared to the three months ended June 30, 2019. The decrease is primarily a result of lower seismic costs incurred in 2020 versus the prior period related to the U.S. Gulf of Mexico business unit.

General and administrative. General and administrative costs decreased by $9.9 million during the three months ended June 30, 2020, as compared to the three months ended June 30, 2019 primarily as a result of headcount and other cost reductions.

Depletion, depreciation and amortization.  Depletion, depreciation and amortization decreased $29.6 million during the three months ended June 30, 2020, as compared with the three months ended June 30, 2019 primarily as a result of increased reserves recorded in the fourth quarter of 2019 and a lower cost basis in the U.S. Gulf of Mexico associated with an impairment recorded in the first quarter of 2020.

Interest and other financing costs, net.  Interest and other financing costs, net decreased $31.5 million primarily a result of the $24.8 million loss on extinguishment of debt primarily associated with the refinancing of our senior notes recorded during the second quarter of 2019 and lower interest rates during the current period.

Derivatives, net.  During the three months ended June 30, 2020 and 2019, we recorded a loss of $100.1 million and a gain of $14.2 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.

Income tax expense (benefit). For the three months ended June 30, 2020, and 2019, our overall effective tax rates were impacted by the 35% statutory tax rates applicable to our Ghanaian and Equatorial Guinean operations, non-deductible and non-taxable items associated with our 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.


37


Six months ended June 30, 2020 compared to six months ended June 30, 2019

 
 
 
 
 
 
 
Six Months Ended
 
 
 
June 30,
 
Increase
 
2020
 
2019
 
(Decrease)
 
(In thousands)
Revenues and other income:
 

 
 

 
 

Oil and gas revenue
$
305,094

 
$
692,723

 
$
(387,629
)
Other income, net
1

 
1

 

Total revenues and other income
305,095

 
692,724

 
(387,629
)
Costs and expenses:
 

 
 

 
 

Oil and gas production
150,350

 
170,776

 
(20,426
)
Facilities insurance modifications, net
8,090

 
(17,743
)
 
25,833

Exploration expenses
60,316

 
60,249

 
67

General and administrative
39,097

 
63,980

 
(24,883
)
Depletion, depreciation and amortization
215,159

 
269,533

 
(54,374
)
Impairment of long-lived assets
150,820

 

 
150,820

Interest and other financing costs, net
56,109

 
94,844

 
(38,735
)
Derivatives, net
(35,963
)
 
62,900

 
(98,863
)
Other expenses, net
25,157

 
326

 
24,831

Total costs and expenses
669,135

 
704,865

 
(35,730
)
Income (loss) before income taxes
(364,040
)
 
(12,141
)
 
(351,899
)
Income tax expense (benefit)
18,118

 
23,928

 
(5,810
)
Net income (loss)
$
(382,158
)
 
$
(36,069
)
 
$
(346,089
)

Oil and gas revenue.  Oil and gas revenue decreased by $387.6 million as a result of lower volumes sold due to cargo timing in our international operations and lower oil prices stemming from the excess market supplies related to the COVID-19 pandemic. We sold 10,084 MBoe at an average realized price per barrel equivalent of $30.25 during the six months ended June 30, 2020 and 11,369 MBoe at an average realized price per barrel equivalent of $60.93 during the six months ended June 30, 2019.
 
Oil and gas production.  Oil and gas production costs decreased by $20.4 million during the six months ended June 30, 2020, as compared to the six months ended June 30, 2019 as a result of lower sales volumes in the current versus prior period due to cargo timing in our international operations.
 
Facilities insurance modifications, net. During the six months ended June 30, 2020, we incurred $8.1 million of facilities insurance modifications costs associated with the long-term solution to the Jubilee turret bearing issue versus $22.2 million during the six months ended June 30, 2019. During the six months ended June 30, 2020 and 2019, these costs were offset by zero and $39.9 million, respectively, of hull and machinery insurance proceeds.
 
General and administrative.  General and administrative costs decreased by $24.9 million during the six months ended June 30, 2020, as compared with the six months ended June 30, 2019 primarily as a result of headcount and other cost reductions.

Depletion, depreciation and amortization.  Depletion, depreciation and amortization decreased $54.4 million during the six months ended June 30, 2020, as compared with the six months ended June 30, 2019 primarily as a result of increased reserves recorded in the fourth quarter of 2019, a lower cost basis in the U.S. Gulf of Mexico associated with an impairment recorded in the first quarter of 2020 and lower sales volumes during the current period.

 Impairment of long-lived assets. As a result of the impact of COVID-19 on the demand for oil and the related significant decrease in oil prices, we recorded asset impairments totaling $150.8 million during the six months ended June 30, 2020 for oil and gas proved properties in the U.S. Gulf of Mexico.

Interest and other financing costs, net.  Interest and other financing costs, net decreased $38.7 million primarily a result of the $24.8 million loss on extinguishment of debt primarily associated with the refinancing of our senior notes recorded during

38


the second quarter of 2019 and lower interest rates during the six months ended June 30, 2020, as compared to the six months ended June 30, 2019.
 
Derivatives, net.  During the six months ended June 30, 2020 and 2019, we recorded a gain of $36.0 million and a loss of $62.9 million, respectively, on our outstanding hedge positions. The losses recorded were a result of changes in the forward curve of oil prices during the respective periods.

Other expenses, net.  Other expenses, net increased $24.8 million primarily related to $13.3 million in restructuring charges for employee severance and related benefit costs and asset impairments of $4.5 million.
 
Income tax expense (benefit).  For the six months ended June 30, 2020, our overall effective tax rate was impacted by increases to our valuation allowance associated with our U.S. deferred tax assets, resulting in $30.9 million net U.S. deferred tax expense and by a $4.9 million current tax benefit related to certain U.S. tax losses carried back to years with a higher income tax rate. Additionally, for the six months ended June 30, 2020, and 2019, our overall effective tax rates were impacted by 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.

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.
Current oil prices are volatile and could negatively impact our ability to generate sufficient operating cash flows to meet our funding requirements. This volatility could 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. Also, BP has agreed to partially carry our exploration, appraisal and development program in Mauritania and Senegal up to a contractually agreed cap. Current commodity prices, combined with our hedging program, partner carries and our current liquidity position support our remaining capital program for 2020.

39


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, 2020 and 2019:
 
 
Six Months Ended
 
June 30,
 
2020
 
2019
 
(In thousands)
Sources of cash, cash equivalents and restricted cash:
 

 
 

Net cash provided by (used in) operating activities
$
(62,836
)
 
$
222,390

Net proceeds from issuance of senior notes

 
641,875

Borrowings under long-term debt
150,000

 
175,000

Advances under production prepayment agreement
50,000

 

Proceeds on sale of assets
1,713

 

 
138,877

 
1,039,265

Uses of cash, cash equivalents and restricted cash:
 

 
 

Oil and gas assets
135,242

 
153,268

Other property
1,536

 
5,230

Notes receivable from partners
42,362

 
5,983

Payments on long-term debt

 
300,000

Redemption of senior secured notes

 
535,338

Purchase of treasury stock
4,947

 
1,983

Dividends
19,181

 
36,289

Deferred financing costs
136

 
1,981

 
203,404

 
1,040,072

Decrease in cash, cash equivalents and restricted cash
$
(64,527
)
 
$
(807
)
 
Net cash provided by (used in) operating activities.  Net cash used in operating activities for the six months ended June 30, 2020 was $62.8 million compared with net cash provided by operating activities for the six months ended June 30, 2019 of $222.4 million. The decrease in cash provided by operating activities in the six months ended June 30, 2020 when compared to the same period in 2019 is primarily a result of lower volumes sold due to cargo timing in our international operations and lower oil prices stemming from the excess market supplies related to the COVID-19 pandemic.

40


The following table presents our net debt and liquidity as of June 30, 2020:
 
 
June 30, 2020
 
(In thousands)
Cash and cash equivalents
$
164,091

Restricted cash
728

Senior Notes at par
650,000

Borrowings under the Facility
1,450,000

Borrowings under the Corporate Revolver
100,000

Net debt
$
2,035,181

Production prepayment agreement
50,000

Net debt and production prepayment agreement
$
2,085,181

 
 

Availability under the Facility
$
50,000

Availability under the Corporate Revolver
$
300,000

Available borrowings plus cash and cash equivalents
$
514,091

Availability under the Production Prepayment Agreement(1)
100,000

Available borrowings plus cash and cash equivalents plus Production Prepayment Agreement
$
614,091

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

Capital Expenditures and Investments

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.
 
In response to current economic conditions including the volatility in oil price and the COVID-19 pandemic, we have reduced our base business 2020 capital program by approximately 40%. We have identified capital reductions from discretionary expenditures related to exploration activities in the U.S. Gulf of Mexico, our basin-opening exploration portfolio and other non-critical work that does not impact safety and asset integrity. We currently estimate that we will spend approximately $200 - $225 million of capital expenditures on our base business, net of carry amounts related to the Mauritania and Senegal transactions with BP, for the year ending December 31, 2020. Through June 30, 2020, we have spent approximately $151 million.

Significant Sources of Capital
 
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.

41


 
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.
 
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 under the Corporate Revolver was $300 million.

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 require cash collateral. This arrangement 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. 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 on 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.

42


Production Prepayment Agreement
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) 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 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

Contractual Obligations
 
The following table summarizes by period the payments due for our estimated contractual obligations as of June 30, 2020:
 
 
Payments Due By Year(5)
 
Total
 
2020(6)
 
2021
 
2022
 
2023
 
2024
 
Thereafter
 
(In thousands)
Principal debt repayments(1)
$
2,200,000

 
$

 
$
56,000

 
$
422,571

 
$
428,571

 
$
428,572

 
$
864,286

Production prepayment agreement(2)
57,500

 
$
2,741

 
$
18,729

 
$
32,397

 
$
3,633

 

 

Interest payments on long-term debt(3)
475,459

 
55,254

 
104,801

 
96,546

 
80,561

 
66,159

 
72,138

Operating leases(4)
34,278

 
2,061

 
4,174

 
4,237

 
4,301

 
3,464

 
16,041

__________________________________
(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.

43


(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.

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.

 The following table presents maturities by expected maturity dates, the weighted average interest rates expected to be paid on the Facility, Corporate Revolver and Production Prepayment Agreement 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,
 
2020(4)
 
2021
 
2022
 
2023
 
2024
 
Thereafter
 
2020
 
(In thousands, except percentages)
Fixed rate debt:
 

 
 

 
 

 
 

 
 

 
 

 
 

Senior Secured Notes
$

 
$

 
$

 
$

 
$

 
$
650,000

 
$
(580,554
)
Fixed interest rate
7.13
%
 
7.13
%
 
7.13
%
 
7.13
%
 
7.13
%
 
7.13
%
 
 
Variable rate debt:
 

 
 

 
 

 
 

 
 

 
 

 
 

Facility(1)
$

 
$
56,000

 
$
322,571

 
$
428,571

 
$
428,572

 
$
214,286

 
$
(1,450,000
)
Corporate Revolver

 

 
100,000

 

 

 

 
(100,000
)
Weighted average interest rate(2)
3.73
%
 
3.48
%
 
3.74
%
 
3.94
%
 
4.56
%
 
4.98
%
 
 

Production Prepayment Agreement:
 
 
 
 
 
 
 
 
 
 
 
 
 
Production Prepayment Agreement(3)
$

 
$
15,729

 
$
30,799

 
$
3,472

 
$

 
$

 
$
(57,500
)
Weighted average interest rate(2)
5.18
%
 
5.12
%
 
5.12
%
 
5.15
%
 
%
 
%
 
 
__________________________________
(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.

Off-Balance Sheet Arrangements
 
We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of June 30, 2020, our off-balance sheet arrangements and transactions include short-term operating leases and undrawn letters of credit. There are no other transactions, arrangements, or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect Kosmos’ liquidity or availability of or requirements for capital resources.
 

44


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. 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, 2019 and in the "Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations" section in our quarterly report on Form 10-Q for the quarter ended March 31, 2020.


 
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 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;

45


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.

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 10 — Derivative Financial Instruments and Note 11 — 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, 2020:
 
 
Derivative Contracts Assets (Liabilities)
 
 
Commodities
 
 
(In thousands)
 
Fair value of contracts outstanding as of December 31, 2019
$
(8,521
)
 
Changes in contract fair value
31,615

 
Contract maturities
(34,814
)
 
Fair value of contracts outstanding as of June 30, 2020
$
(11,720
)
 
 
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 half of 2020 ranged between $13.24 and $69.96 per Bbl for Dated Brent, with Heavy Louisiana Sweet experiencing similar volatility during the first half of 2020.


46


Commodity Derivative Instruments
 
We enter into various oil derivative contracts to mitigate our exposure to commodity price risk associated with anticipated future oil production. These contracts currently consist of collars, put options, call options and swaps. In regards to our obligations under our various commodity derivative instruments, if our production does not exceed our existing hedged positions, our exposure to our commodity derivative instruments would increase.
 
Commodity Price Sensitivity
 
The following table provides information about our oil derivative financial instruments that were sensitive to changes in oil prices as of June 30, 2020. Volumes and weighted average prices are net of any offsetting derivatives entered into. 
 
 
 
 
 
 
 
 
Weighted Average Price per Bbl
 
Asset (Liability)
 
 
 
 
 
 
 
 
Net Deferred
 
 
 
 
 
 
 
 
 
 
 
Fair Value at
 
 
 
 
 
 
 
 
Premium
 
 
 
 
 
 
 
 
 
 
 
June 30,
Term
 
Type of Contract
 
Index
 
MBbl
 
Payable/(Receivable)
 
Swap
 
Sold Put
 
Floor
 
Ceiling
 
Purchased Call
 
2020(3)
 
 
 
 
 
 
 
 
 
 
 

 
 

 
 

 
 

 
 

 
(In thousands)
2020:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jul — Dec
 
Swaps
 
Dated Brent
 
5,275

 
$

 
$
42.67

 
$

 
$

 
$

 
$

 
$
9,856

Jul — Dec
 
Swaps
 
Argus LLS
 
3,000

 

 
29.98

 

 

 

 

 
(32,420
)
Jul — Dec
 
Call spreads
 
NYMEX WTI
 
(1)
 
1.20

 

 

 

 
45.00

 
35.00

 
3,551

Jul — Dec
 
Swaps with sold puts
 
Dated Brent
 
333

 

 
35.00

 
25.00

 

 

 

 
(2,040
)
Jul — Dec
 
Three-way collars
 
Dated Brent
 
1,000

 

 

 
25.00

 
32.50

 
40.00

 

 
(3,251
)
Jul — Dec
 
Sold calls(2)
 
Dated Brent
 
4,750

 
(0.19
)
 

 

 

 
80.83

 

 
673

2021:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jan — Dec
 
Swaps with sold puts
 
Dated Brent
 
5,000

 
$

 
$
54.70

 
$
43.50

 
$

 
$

 

 
$
21,981

Jan — Dec
 
Three-way collars
 
Dated Brent
 
1,000

 
1.00

 

 
30.00

 
40.00

 
55.40

 

 
(126
)
Jan — Dec
 
Sold calls(2)
 
Dated Brent
 
7,000

 

 

 

 

 
70.09

 

 
(5,044
)
2022:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jan — Dec
 
Sold calls(2)
 
Dated Brent
 
1,581

 

 

 

 

 
60.00

 

 
(4,900
)
__________________________________
(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.

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.

At June 30, 2020, our open commodity derivative instruments were in a net liability position of $11.7 million. Future fluctuations in oil prices could have a material impact on the valuation of our derivative financial instruments. As of June 30, 2020, a hypothetical 10% price increase in the commodity futures price curves would decrease future pre-tax earnings by approximately $59.5 million. Similarly, a hypothetical 10% price decrease would increase future pre-tax earnings by approximately $53.8 million.
 

47


Interest Rate Sensitivity
 
At June 30, 2020, we had indebtedness outstanding under the Facility of $1.45 billion and the Corporate Revolver of $100.0 million, which bore interest at floating rates. The interest rate on this indebtedness as of June 30, 2020 was approximately 3.8% and 5.2% respectively. If LIBOR increased by 10% at this level of floating rate debt, we would pay an additional $0.3 million in interest expense per year. The commitment fees on the undrawn availability under the Facility and the Corporate Revolver are not subject to changes in interest rates.

Item 4. Controls and Procedures
 
Evaluation of Disclosure Controls and Procedures
 
As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) was performed under the supervision and with the participation of the Company’s management, including our Chief Executive Officer and Chief Financial Officer. This evaluation considered the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in the SEC reports we file or submit under the Exchange Act is accurate, complete and timely. However, a control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. The design of a control system must reflect the fact that there are resource constraints, and the benefit of controls must be considered relative to their costs. Consequently, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected. Based upon this evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of June 30, 2020, in ensuring that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, including that such information is accumulated and communicated to the Company’s management, including our Chief Executive Officer and our Chief Financial Officer, to allow timely decisions regarding required disclosure.
 
Evaluation of Changes in Internal Control over Financial Reporting
 
There were no changes in our internal control over financial reporting that occurred during our most recent fiscal quarter that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.


PART II. OTHER INFORMATION
 
Item 1. Legal Proceedings 
 
There have been no material changes from the information concerning legal proceedings discussed in the “Item 3. Legal Proceedings” section of our annual report on Form 10-K.
 
Item 1A. Risk Factors
 
There have been no material changes from the risks discussed in the “Item 1A. Risk Factors” section of our annual report on Form 10-K for the year ended December 31, 2019 and in the "Item 1A. Risk Factors" section of our quarterly report on form 10-Q for the quarter ended March 31, 2020.


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.

48


 
Item 5.    Other Information.
 
There have been no material changes required to be reported under this Item that have not previously been disclosed in the annual report on Form 10-K.
 
Item 6. Exhibits
 
The information required by this Item 6 is set forth in the Index to Exhibits accompanying this quarterly report on Form 10‑Q.

49


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 3, 2020
 
/s/ Neal D. Shah
 
 
Neal D. Shah
 
 
Senior Vice President and Chief Financial Officer
 
 
(Principal Financial Officer)


50


INDEX OF EXHIBITS
 
Exhibit
Number
 
Description of Document
10.1
 
 
 
 
10.2
 
 
 
 
10.3†
 
 
 
 
31.1
 
 
 
 
31.2
 
 
 
 
32.1
 
 
 
 
32.2
 
 
 
 
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

___________________________________
†     Certain confidential portions of this Exhibit have been omitted pursuant to Item 601(b) of Regulation S-K because the identified confidential portions (i) are not material and (ii) would be competitively harmful if publicly disclosed.





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