A N N U A L R E P O R T
Kosmos Energy is a full-cycle oil and gas exploration and
production company focused on the Atlantic Margins
with a diversified portfolio of low cost, lower carbon
assets, including oil production in Ghana, the U.S. Gulf of
Mexico and Equatorial Guinea, as well as world-class gas
development projects offshore Mauritania and Senegal.
As a responsible company, we are working to supply the
energy the world needs today, find and develop cleaner
energy to advance the energy transition, and be a force
for good in our host countries.
Fellow Shareholders,
Just as we were looking forward to the resurgence
of the global economy after the difficult years of the
pandemic, Russia’s invasion of Ukraine has shocked
the world and illustrated the fragility of the peace and
democracy we hold so dear. The tragic loss of life, the
displacement of millions of people, and the economic
devastation will cast a long shadow.
For the energy sector, the conflict is re-shaping the
industry’s outlook. At the most basic level, it has
reminded the world of the need to pursue the energy
transition while ensuring energy security. Europe’s
reliance on Russia highlights the need for new sources
of energy, ultimately renewables with hydrocarbons
playing a long-term role in the transition. Kosmos can
play a role in meeting that challenge with a portfolio
of low cost, lower carbon oil production, and low cost,
lower carbon liquified natural gas (LNG) projects
offshore Mauritania and Senegal, which are poised
ANDREW G. I NGLIS
Chairman and
Chief Executive Officer
in our most recent report has been reviewed by our
independent auditor. This is an added step we have
taken to increase confidence in our reporting, further
demonstrating our commitment to transparency and
openness.
The outlook for Kosmos in 2022 and beyond remains
to bring a new source of gas to the world as soon as
positive. The company is underpinned by low-cost,
production starts late next year. By sourcing LNG from
lower carbon assets – world class fields that have the
Mauritania and Senegal, Europe would enhance its
longevity to deliver sustainable, high-margin cash
energy security and help these countries meet their
flow at current prices. With our existing assets and
own development goals – a positive and necessary
sanctioned projects, production is expected to grow
outcome for all involved. For Kosmos, this illustrates our
around 50% in the next two years, with a growing
role in bringing a just and secure energy transition to
natural gas weighting at a time when there is a need
life, and 2021 was a productive year for the company in
for new sources of gas. With growing production
fulfilling that vision.
We rebuilt operational momentum across the portfolio
with a return to drilling in Ghana, Equatorial Guinea,
and the Gulf of Mexico. This increased activity helped
push net production above our year-end exit target of
75,000 barrels of oil equivalent per day. Importantly,
this increased production boosted free cash flow
and reduced leverage to around 2.5 times at year-
end. Our LNG development offshore Mauritania
and a strong commodity price backdrop, we expect
to make further progress de-leveraging the balance
sheet, with a year-end 2022 leverage target of around
1.5 times at current prices. As we deliver on this plan
and new projects start up, sustainable free cash flow is
expected to increase materially, creating the potential
for meaningful shareholder returns.
Kosmos has emerged from the last two years of the
pandemic with a stronger business and an important
and Senegal made significant progress with Greater
role to play in supporting the energy transition and
Tortue Ahmeyim Phase 1 around 70% complete at year
strengthening energy security. We are excited about
end. In addition, Kosmos executed a highly accretive
the future.
transaction in Ghana, acquiring additional interests in
the Jubilee and TEN fields, which has helped transform
the balance sheet and further increase free cash flow
generation.
As we executed the company’s strategy in 2021,
we continued to be guided by our long-standing
commitment to sustainability. Our most recent TCFD-
aligned Sustainability Report advances the approach
we introduced last year and covers our full ESG agenda,
including the actions we have taken to mitigate climate-
related risks and enhance the resilience of our business.
Given the importance of ESG performance, the data
On behalf of the entire board of directors, I thank you
for your investment in our company.
Sincerely yours,
ANDREW G. I NGLIS
Chairman and Chief Executive Officer
Financial Highlights
Year Ended (in thousands, except volume data)
2021
2020
2019
Revenues and other income
Net loss
$ 1,333,839
$ 896,198
$ 1,509,909
(77,836)
(411,586)
(55,777)
Net cash provided by operating activities
374,344
196,145
628,150
Pro Forma EBITDAX
Capital expenditures1
Total Assets
Net Debt
969,136
424,987
989,638
924,214
273,979
440,736
4,940,651
3,867,593
4,317,232
2,500,104
2,000,236
1,820,654
Average oil sales price per Bbl
70.10
38.29
68.99
Sales volumes (million barrels of oil equivalent)
Total proved reserves (million barrels of oil equivalent)2
Crude oil (million barrels)2
Natural gas (billion cubic feet)2
1. Includes acquisitions and divestitures
2. 1P Reserves as per Ryder Scott year end SEC Reserve Reports
EBI TDAX RECONCI LIATION
19.9
301
185
695
22.1
139
127
69
24.9
169
154
92
Year Ended December 31,
Net income (loss)
Exploration expenses
2021
2020
2019
$ (77,836)
$ (411,586)
$ (55,777)
65,382
84,616
180,955
Facilities insurance modifications, net
(1,586)
13,161
(24,254)
Depletion, depreciation and amortization
467,221
485,862
563,861
Impairment of long-lived assets
Equity-based compensation
Derivatives, net
—
153,959
—
31,651
32,706
32,370
270,185
17,180
71,885
Cash settlements on commodity derivatives
(224,421)
(2,715)
(36,341)
Restructuring and other
Other, net
Gain on sale of assets
3,823
6,288
29,167
27,350
10,215
4,149
(1,564)
(92,163)
(10,528)
Interest and other financing costs, net
128,371
109,794
155,074
Income tax expense (benefit)
34,456
(5,209)
80,894
EBITDAX
Acquired Ghana Interest EBITDAX1
Pro Forma EBITDAX
$ 701,970
$ 424,987
$ 989,638
267,166
$ 969,136
1. Twelve Months Ended December 31, 2021 EBITDAX for the Acquired Ghana Interest of $267.2 million is comprised of Revenues of $332.3 million less direct operating expenses
of $65.1 million for the acquired properties. Consistent with the definition of EBITDAX, $1.9 million of Facilities insurance modifications, net has been excluded from the results to
present the Acquired Ghana Interests Twelve Months Ended December 31, 2021 EBITDAX. The results are presented on the accrual basis of accounting, however as the acquired
properties were not accounted for or operated as a separate segment, division, or entity, complete financial statements under U.S. generally accepted accounting principles
are not available or practicable to produce. The results are not intended to be a complete presentation of the results of operations of the acquired properties and may not be
representative of future operations as they do not include general and administrative expenses; interest expense; depreciation, depletion, and amortization; provision for income
taxes; and certain other revenues and expenses not directly associated with revenues from the sale of crude oil.
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
☒
☐
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2021
For the transition period from to
Commission file number: 001-35167
Kosmos Energy Ltd.
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of
incorporation or organization)
8176 Park Lane
Dallas, Texas
(Address of principal executive offices)
98-0686001
(I.R.S. Employer
Identification No.)
75231
(Zip Code)
Registrant’s telephone number, including area code: +1 214 445 9600
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Common Stock $0.01 par value
Trading Symbol
KOS
Name of each exchange on which registered:
New York Stock Exchange
London Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well‑known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒
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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S‑K (§229.405 of this chapter) is not contained
herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in
Part III of this Form 10‑K or any amendment to this Form 10‑K. ☒
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 ☒
Non-accelerated filer ☐
(Do not check if a smaller reporting company)
Accelerated filer
☐
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 has filed a report on and attestation to its management's assessment of the effectiveness of its
internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm
that prepared or issued its audit report. ☒
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b‑2 of the Exchange Act). Yes ☐ No ☒
The aggregate market value of the voting and non‑voting common stock held by non‑affiliates, based on the per‑share closing price of the
registrant’s common stock as of the last business day of the registrant’s most recently completed second fiscal quarter was $1,384,993,421.
The number of the registrant’s Common Stock outstanding as of February 24, 2022 was 455,265,466.
Part III, Items 10‑14, is incorporated by reference from the Proxy Statement for the Annual Meeting of Shareholders which will be filed
with the Securities and Exchange Commission not later than 120 days subsequent to December 31, 2021.
Certain exhibits previously filed with the Securities and Exchange Commission are incorporated by reference into Part IV of this report.
DOCUMENTS INCORPORATED BY REFERENCE
TABLE OF CONTENTS
Unless otherwise stated in this report, references to “Kosmos,” “we,” “us” or “the company” refer to Kosmos
Energy Ltd. and its subsidiaries. On December 28, 2018, we changed our jurisdiction of incorporation from Bermuda to the
State of Delaware, which we refer to herein as the Redomestication. All references to “Kosmos,” “we,” “us” or “the
company” on or before December 28, 2018 refer to Kosmos Energy Ltd., an exempted company incorporated pursuant to the
laws of Bermuda, and its subsidiaries. All such references after December 28, 2018 refer to Kosmos Energy Ltd., a Delaware
corporation, and its subsidiaries. In addition, all references to “common stock” on or before December 28, 2018 refer to the
common shares of Kosmos Energy Ltd. prior to the Redomestication, and all such references after December 28, 2018 refer to
the common stock of Kosmos Energy Ltd. after the Redomestication. For additional detail, please see “Item 1. Business—
Corporate Information.”
In addition, we have provided definitions for some of the industry terms used in this report in the “Glossary and
Selected Abbreviations” beginning on page 3.
Glossary and Selected Abbreviations
Cautionary Statement Regarding Forward‑Looking Statements
PART I
Business
Risk Factors
Unresolved Staff Comments
Properties
Legal Proceedings
Mine Safety Disclosures
PART II
Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of
Equity Securities
Selected Financial Data
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Quantitative and Qualitative Disclosures About Market Risk
Financial Statements and Supplementary Data
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
Controls and Procedures
Other Information
Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
PART III
Directors, Executive Officers and Corporate Governance
Executive Compensation
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Certain Relationships and Related Transactions, and Director Independence
Principal Accounting Fees and Services
PART IV
Exhibits, Financial Statement Schedules
Form 10-K Summary
Item 1.
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
Item 9C.
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
Item 15.
Item 16.
Page
4
8
10
35
61
61
61
61
62
64
65
79
82
130
130
130
131
131
131
131
131
131
131
136
3
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”
“3D seismic data”
“ANP-STP”
“API”
“Asset Coverage Ratio”
“ASC”
“ASU”
“Barrel” or “Bbl”
“BBbl”
“BBoe”
“Bcf”
“Boe”
“BOEM”
“Boepd”
“Bopd”
“BP”
“Bwpd”
“Corporate Revolver”
“COVID-19”
“Debt cover ratio”
“Developed acreage”
“Development”
“DGE”
Two‑dimensional seismic data, serving as interpretive data that allows a view of a
vertical cross‑section beneath a prospective area.
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.
Agencia Nacional Do Petroleo De Sao Tome E Principe.
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.
The “Asset Coverage Ratio” as defined in the GoM Term Loan means, as of each
March 31, June 30, September 30 and December 31 of each Fiscal Year, commencing
December 31, 2020, the ratio of (a) Total PDP PV-10 (as defined in the GoM Term
Loan) as of such date to (b) outstanding principal amount of Loans (as defined in the
GoM Term Loan) as of such date.
Financial Accounting Standards Board Accounting Standards Codification.
Financial Accounting Standards Board Accounting Standards Update.
A standard measure of volume for petroleum corresponding to approximately 42
gallons at 60 degrees Fahrenheit.
Billion barrels of oil.
Billion barrels of oil equivalent.
Billion cubic feet.
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.
Bureau of Ocean Energy Management.
Barrels of oil equivalent per day.
Barrels of oil per day.
BP p.l.c. and related subsidiaries.
Barrels of water per day.
Revolving Credit Facility Agreement dated November 23, 2012 (as amended or as
amended and restated from time to time).
Coronavirus disease 2019.
The “debt cover ratio” is broadly defined, for each applicable calculation date, as the
ratio of (x) total long‑term debt less cash and cash equivalents and restricted cash, to
(y) the aggregate EBITDAX (see below) of the Company for the previous twelve
months.
The number of acres that are allocated or assignable to productive wells or wells
capable of production.
The phase in which an oil or natural gas field is brought into production by drilling
development wells and installing appropriate production systems.
Deep Gulf Energy (together with its subsidiaries).
“DST”
“Dry hole” or “Unsuccessful well” A well that has not encountered a hydrocarbon bearing reservoir expected to produce
Drill stem test.
“DT”
in commercial quantities.
Deepwater Tano.
4
“EBITDAX”
“ESG”
“ESP”
“E&P”
“Facility”
“FASB”
“Farm‑in”
“Farm‑out”
“FEED”
“Field life cover ratio”
“FLNG”
“FPS”
“FPSO”
“GAAP”
“GEPetrol”
“GHG”
“GJFFDP”
“GNPC”
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.
Environmental, social, and governance.
Electric submersible pump.
Exploration and production.
Facility agreement dated March 28, 2011 (as amended or as amended and restated
from time to time).
Financial Accounting Standards Board.
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.
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.
Front End Engineering Design.
The “field life cover ratio” is broadly defined, for each applicable forecast period, as
the ratio of (x) the forecasted net present value of net cash flow through depletion plus
the net present value of the forecast of certain capital expenditures incurred in relation
to the Ghana and Equatorial Guinea assets, to (y) the aggregate loan amounts
outstanding under the Facility.
Floating liquefied natural gas.
Floating production system.
Floating production, storage and offloading vessel.
Generally Accepted Accounting Principles in the United States of America.
Guinea Equatorial De Petroleos.
Greenhouse gas.
Greater Jubilee Full Field Development Plan.
Ghana National Petroleum Corporation.
“GoM Term Loan”
Senior Secured Term Loan Credit Agreement dated September 30, 2020.
“Greater Tortue Ahmeyim”
Ahmeyim and Guembeul discoveries.
“GTA UUOA”
“HLS”
“Jubilee UUOA”
“KTIPI”
“Interest cover ratio”
“LNG”
“Loan life cover ratio”
“LSE”
“LTIP”
“MBbl”
Unitization and Unit Operating Agreement covering the Greater Tortue Ahmeyim
Unit.
Heavy Louisiana Sweet.
Unitization and Unit Operating Agreement covering the Jubilee Unit.
Kosmos-Trident International Petroleum Inc.
The “interest cover ratio” is broadly defined, for each applicable calculation date, as
the ratio of (x) the aggregate EBITDAX (see above) of the Company for the previous
twelve months, to (y) interest expense less interest income for the Company for the
previous twelve months.
Liquefied natural gas.
The “loan life cover ratio” is broadly defined, for each applicable forecast period, as
the ratio of (x) net present value of forecasted net cash flow through the final maturity
date of the Facility plus the net present value of forecasted capital expenditures
incurred in relation to the Ghana and Equatorial Guinea assets, to (y) the aggregate
loan amounts outstanding under the Facility.
London Stock Exchange.
Long Term Incentive Plan.
Thousand barrels of oil.
5
“MBoe”
“Mcf”
“Mcfpd”
“MMBbl”
“MMBoe”
“MMBtu”
“MMcf”
“MMcfd”
“MMTPA”
Thousand barrels of oil equivalent.
Thousand cubic feet of natural gas.
Thousand cubic feet per day of natural gas.
Million barrels of oil.
Million barrels of oil equivalent.
Million British thermal units.
Million cubic feet of natural gas.
Million cubic feet per day of natural gas.
Million metric tonnes per annum.
“Natural gas liquid” or “NGL”
“NYSE”
“Ophir”
“Petroleum contract”
“Petroleum system”
Components of natural gas that are separated from the gas state in the form of liquids.
These include propane, butane, and ethane, among others.
New York Stock Exchange.
Ophir Energy plc.
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.
A petroleum system consists of organic material that has been buried at a sufficient
depth to allow adequate temperature and pressure to expel hydrocarbons and cause the
movement of oil and natural gas from the area in which it was formed to a reservoir
rock where it can accumulate.
“Plan of development” or “PoD”
A written document outlining the steps to be undertaken to develop a field.
“Productive well”
“Prospect(s)”
“Proved reserves”
“Proved developed reserves”
“Proved undeveloped reserves”
“RSC”
“SEC”
“7.125% Senior Notes”
“7.750% Senior Notes”
“7.500% Senior Notes”
“Shelf margin”
“Shell”
“Stratigraphy”
“Stratigraphic trap”
“Structural trap”
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.
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.
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).
Those proved reserves that can be expected to be recovered through existing wells and
facilities and by existing operating methods.
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.
Ryder Scott Company, L.P.
Securities and Exchange Commission.
7.125% Senior Notes due 2026.
7.750% Senior Notes due 2027.
7.500% Senior Notes due 2028.
The path created by the change in direction of the shoreline in reaction to the filling of
a sedimentary basin.
Royal Dutch Shell and related subsidiaries.
The study of the composition, relative ages and distribution of layers of sedimentary
rock.
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.
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.
6
“Structural‑stratigraphic trap”
“Submarine fan”
“TAG GSA”
“TEN”
“Three‑way fault trap”
“Tortue Phase 1 SPA”
“Trafigura”
“Trap”
“Trident”
“Undeveloped acreage”
A structural‑stratigraphic trap is a combination trap with structural and stratigraphic
features.
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.
TEN Associated Gas - Gas Sales Agreement.
Tweneboa, Enyenra and Ntomme.
A structural trap where at least one of the components of closure is formed by offset of
rock layers across a fault.
Greater Tortue Ahmeyim Agreement for a Long Term Sale and Purchase of LNG.
Trafigura Group PTD, Ltd. and related subsidiaries including Trafigura Trading LLC.
A configuration of rocks suitable for containing hydrocarbons and sealed by a
relatively impermeable formation through which hydrocarbons will not migrate.
Trident Energy.
Lease acreage on which wells have not been drilled or completed to a point that would
permit the production of commercial quantities of natural gas and oil regardless of
whether such acreage contains discovered resources.
“WCTP”
West Cape Three Points.
7
Cautionary Statement Regarding Forward‑Looking Statements
This annual report on Form 10‑K contains estimates and forward‑looking statements, principally in “Item 1. Business,”
“Item 1A. Risk Factors” and “Item 7. 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
annual report on Form 10‑K, may adversely affect our results as indicated in forward‑looking statements. You should read this
annual report on Form 10‑K and the documents that we have filed as exhibits hereto 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 us 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, as well as our ability to implement hedges addressing such volatility
on commercially reasonable terms;
the availability, cost, function and reliability of developing appropriate infrastructure around and transportation to our
discoveries and prospects;
the availability and cost of drilling rigs, production equipment, supplies, personnel and oilfield services;
other competitive pressures;
potential liabilities inherent in oil and natural gas operations, including drilling and production risks and other
operational and environmental risks and hazards;
current and future government regulation of the oil and gas industry or regulation of the investment in or ability to do
business with certain countries or regimes;
cost of compliance with laws and regulations;
changes in, or new, environmental, health and safety or climate change or GHG laws, regulations and executive orders,
or the implementation, or interpretation, of those laws, regulations and executive orders;
adverse effects of sovereign boundary disputes in the jurisdictions in which we operate;
environmental liabilities;
geological, geophysical and other technical and operations problems including drilling and oil and gas production and
processing;
• military operations, civil unrest, outbreaks of disease, terrorist acts, wars or embargoes;
8
•
•
•
•
•
•
•
•
•
the cost and availability of adequate insurance coverage and whether such coverage is enough to sufficiently mitigate
potential losses and whether our insurers comply with their obligations under our coverage agreements;
our vulnerability to severe weather events, including tropical storms and hurricanes in the Gulf of Mexico;
our ability to meet our obligations under the agreements governing our indebtedness;
the availability and cost of financing and refinancing our indebtedness;
the amount of collateral required to be posted from time to time in our hedging transactions, letters of credit,
performance bonds and other secured debt;
our ability to obtain surety or performance bonds on commercially reasonable terms;
the result of any legal proceedings, arbitrations, or investigations we may be subject to or involved in;
our success in risk management activities, including the use of derivative financial instruments to hedge commodity
and interest rate risks; and
other risk factors discussed in the “Item 1A. Risk Factors” section of this 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 annual report on Form 10‑K
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.
9
Item 1. Business
General
PART I
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 the U.S. Gulf of Mexico, as well as
a world-class gas development offshore Mauritania and Senegal. We also maintain a sustainable proven basin exploration
program in Equatorial Guinea, Ghana and the U.S. Gulf of Mexico. Kosmos is listed on the NYSE and LSE and is traded under
the ticker symbol KOS.
Kosmos was founded in 2003 to find oil in under‑explored or overlooked parts of West Africa. In its relatively brief
history, we have successfully opened two new hydrocarbon basins through the discovery of the Jubilee field offshore Ghana in
2007 and the Greater Tortue Ahmeyim field in 2015 (which includes the Ahmeyim and Guembeul-1 discovery wells offshore
Mauritania and Senegal in 2015 and 2016, respectively). Jubilee was one of the largest oil discoveries worldwide in 2007 and is
considered one of the largest finds offshore West Africa discovered during that decade. The Ahmeyim discovery was one of the
largest natural gas discoveries worldwide in 2015 and is one of the largest gas discoveries ever offshore West Africa.
Over the past few years, our business strategy has evolved to focus on production enhancing infill drilling and well
work, infrastructure-led exploration as well as value-accretive acquisitions. This strategic evolution was initially enabled by our
acquisition of the Ceiba Field and Okume Complex assets offshore Equatorial Guinea in 2017, together with access to
surrounding exploration licenses, and bolstered by the 2018 acquisition of Deep Gulf Energy, a deepwater company operating
in the U.S. Gulf of Mexico, which further enhanced our production, exploitation and infrastructure-led exploration capabilities.
Most recently, this strategy was demonstrated by the recent acquisition of additional interests in the Jubilee and TEN fields
offshore Ghana.
Our Business Strategy
As a full-cycle deepwater E&P company, our mission is to safely deliver production and free cash flow from a
portfolio rich in opportunities through a disciplined allocation of capital and optimal portfolio management for the benefit of
our shareholders and stakeholders. As a responsible company, we are working to supply the energy the world needs today, find
and develop cleaner energy to advance the energy transition, and be a force for good in our host countries.
Our business strategy is designed to accomplish this mission by focusing on three key objectives: (1) maximize the
value of our producing assets; (2) progress our discovered resources toward project sanction and into proved reserves,
production, and cash flow through efficient appraisal, development and exploitation; and (3) add new lower carbon resources
through an efficient low cost exploration program in proven basins or acquisitions. We are focused on increasing production,
cash flows and reserves from our producing assets in Equatorial Guinea, Ghana, and the U.S. Gulf of Mexico. In Mauritania
and Senegal, we are progressing our Greater Tortue Ahmeyim development with the objective of reaching first gas in the third
quarter of 2023 while advancing the second phase of the development. In addition, our portfolio consists of large discovered
resources and an inventory of prospects, which we plan to continue to mature for future drilling and development, providing us
access to additional high return growth potential in the coming years. We are also working with our partners and host
governments on projects to reduce the carbon intensity of our production assets, such as the elimination of routine flaring in
Ghana.
Grow cash flow, proved reserves and production through exploitation, development and infrastructure-led
exploration activities
We plan to grow cash flow, proved reserves and production by further exploiting our fields offshore Equatorial
Guinea, Ghana, and the U.S. Gulf of Mexico. In Equatorial Guinea, our activity set is expanding beyond production
optimization projects, such as utilizing electrical submersible pumps, to include development drilling and infrastructure-led
exploration which, if successful, can be brought online quickly via subsea tieback to existing infrastructure. In Ghana, we plan
to continue drilling additional development and production wells at both the Jubilee and TEN fields. In the U.S. Gulf of
Mexico, we plan to continue development drilling in existing fields and maintain a deep inventory of infrastructure-led
exploration targets. In addition, we have sanctioned the first phase of the Greater Tortue Ahmeyim development offshore
Mauritania and Senegal, which defines the timing and path to first gas. Beyond the Phase 1 development of Greater Tortue
Ahmeyim, growth is also expected to be realized through additional development phases of Greater Tortue Ahmeyim and
through the development of all or a portion of our other natural gas discoveries in Mauritania and Senegal. During 2022, we
10
plan to continue to mature development concepts from previous discoveries in Mauritania, Senegal, the U.S. Gulf of Mexico
and Equatorial Guinea, as well as mature additional infrastructure-led prospects in the U.S. Gulf of Mexico, Equatorial Guinea,
and Ghana.
Focus on optimally developing our discoveries to initial production
Our approach to development is designed to deliver first production on an accelerated timeline, leverage early
learnings to improve future outcomes and maximize returns. In certain circumstances, we believe a phased approach can be
employed to optimize full‑field development. A phased approach facilitates refinement of the development plans based on
experience gained in initial phases of production and by leveraging existing infrastructure as subsequent phases of development
are implemented. Production and reservoir performance from the initial phases are monitored closely to determine the most
efficient and effective techniques to maximize the recovery of reserves and returns. Other benefits include minimizing upfront
capital costs, reducing execution risks through smaller initial infrastructure requirements, and enabling cash flow from the
initial phases of production to fund a portion of capital costs for subsequent phases. Our development of the Jubilee Field is an
example of this approach. The Greater Tortue Ahmeyim development is also being developed in a phased approach, consistent
with our business strategy. This is anticipated to result in first gas approximately eight years after initial discovery. Finally, our
approach to discoveries in the U.S. Gulf of Mexico is to develop them via subsea tie-back to existing host facilities with spare
capacity, which reduces development costs and the average timeline to first production. The Winterfell discovery (2021) and
subsequent appraisal success (early 2022) is an example of this, with development expected to deliver first production in around
two years.
Apply our entrepreneurial culture, which fosters innovation and creativity, to continue our successful exploration
and development program
Our employees are critical to the success of our business strategy, and we have created an environment that enables
them to focus their knowledge, skills and experience on finding, developing and producing new fields and optimizing
production from existing fields. Culturally, we have an open, team‑oriented work environment that fosters entrepreneurial,
creative and contrarian thinking. This approach enables us to fully consider and understand both risk and reward, as well as
deliberately and collectively pursue ideas that create and maximize value and free cash flow.
We are led by an experienced management team with a successful track record. Our management team members
average over 25 years of industry experience and have participated in discovering and developing multiple large-scale upstream
projects around the world. Our experience, industry relationships and technical expertise are our core competitive strengths and
are crucial to our success.
Our returns focused exploration approach
Our exploration activity, which is deeply rooted in a fundamental, geologic approach, is focused on proven basins with
high-graded infrastructure-led prospects and material play extension opportunities. We target specific areas with sufficient size
to manage exploration risks and provide scale should the exploration concept prove successful. We also look for: (i) long‑term
contract durations to enable the “right” exploration program to be executed, (ii) play type diversity to provide multiple
exploration concept options, (iii) prospect dependency to enhance the chance of replicating success, and (iv) attractive fiscal
terms to maximize the commercial viability of discovered hydrocarbons. Alongside the subsurface analysis, Kosmos gains a
thorough understanding of the “above‑ground” dynamics in each of the countries in which we operate, which may influence a
particular country’s relative desirability from an overall oil and natural gas operating and risk adjusted return perspective.
Our approach is aimed at areas where we have existing production and where there is sufficient infrastructure capacity
to enable the development of new discoveries via subsea tieback. Acquisition of the Ceiba Field and Okume Complex in
Equatorial Guinea and assets in the U.S. Gulf of Mexico have added high-quality prospectivity to our inventory of
infrastructure-led exploration opportunities given their attractive acreage positions within proximity of existing infrastructure
with excess capacity available. Existing infrastructure allows us to shorten the time cycle from discovery to first production,
lower the capital requirements and increase the returns.
Pursuing value accretive, opportunistic transactions that meet our strategic and financial objectives
Since 2017, we have completed three separate significant acquisitions of oil and natural gas producing properties for
total value of approximately $2.0 billion dollars, as of the effective date of the acquisitions. These acquisitions were targeted to
increase and complement our existing properties, providing production diversification while increasing the quality of
investment opportunities in our portfolio. Our experienced team of management and technical professionals intend to continue
11
identifying, evaluating and pursuing transactions involving oil and natural gas properties that are complementary to our core
operating areas, as well as opportunities in other basins where we can apply our existing knowledge, expertise and relationships
to create shareholder value. Our focus is on transactions where we can leverage our operational experience and expertise to
provide productivity and cost improvements, invest in additional developmental opportunities in such assets and implement an
infrastructure-led exploration program for nearby prospects.
Secure a premium license to operate through industry-leading ESG performance
We recognize that advancing the societies in which we work and operating in a manner that protects the environment
is critical for creating long-term returns. We aim to continuously improve our ESG credentials by working with a range of
stakeholders, including shareholders, partners, suppliers, host governments and civil society organizations.
We aim to act as a force for good by advancing the “Just Transition” in our host countries and communities – namely
by supporting economic and social development in the places where we work while lowering emissions. We use the United
Nations Sustainable Development Goals to understand how our activities promote economic and social progress in host
countries. Adopted in 2013, our Business Principles reflect our shared values as a company, define how we conduct our
business and set the standards to which we hold ourselves accountable. Our Business Principles are supported by more detailed
policies, procedures, and management systems. Each year, we report on our ESG approach and performance in our
Sustainability Report and on our website.
Most recently, we have focused on evaluating the costs, benefits, risks, and opportunities that climate change and the
global energy transition may present to our business and integrating them into our business strategy. As part of this effort, we
established governance structures to monitor and manage climate-related risks and opportunities; developed a strategy to
measure and reduce greenhouse gas emissions from our own operations and mitigate remaining emissions through innovative
nature-based solutions. We have published a Climate Risk and Resilience Report that adheres to the recommendations of the
Task Force on Climate-related Disclosure (“TCFD”). The report reviews how we are identifying and managing climate-related
risks and opportunities across four categories: Governance, Strategy, Risk Management, and Metrics and Targets. In addition,
the report sets forth our goal to achieve operated Scope 1 and Scope 2 carbon neutrality by 2030 or sooner, a scenario analysis
demonstrating the resilience of our portfolio under a scenario aligned with the Paris Agreement’s goals, and a description of
innovative nature-based carbon capture projects used to mitigate emissions that cannot be eliminated.
Maintain financial discipline
Execution of our strategy requires us to maintain a conservative financial approach with a strong balance sheet, ample
liquidity, and a commitment to low leverage. As of December 31, 2021, our liquidity was approximately $770 million.
Additionally, we use derivative instruments to partially limit our exposure to fluctuations in oil prices. We have an
active commodity hedging program where we aim to hedge a portion of our anticipated sales volumes on a two to three year
rolling basis, with the goal to protect against the downside price scenario while still retaining partial exposure to the upside. As
of December 31, 2021, we have hedged positions covering approximately 12.5 million barrels of oil production in 2022. We
also maintain insurance to partially protect against loss of production revenues from certain of our producing assets.
12
Operations by Geographic Area
We currently have operations in Africa and the U.S. Gulf of Mexico. Presently, our operating revenues are generated
from our operations offshore Ghana, Equatorial Guinea, and the U.S. Gulf of Mexico. The following tables provide a summary
of certain key 2021 data for our geographic areas.
Geographic Area
Ghana(2)
Equatorial Guinea
Mauritania/Senegal
U.S. Gulf of Mexico
Total
Sales Volumes
(Net to
Kosmos)
(in MMboe)
9.0
3.7
—
7.2
19.9
Percentage of
Total Sales
Volumes
Revenue
Year-End
Estimated
Proved
Reserves(1)
Percentage of
Total
Estimated
Proved
Reserves
(in thousands)
(in MMboe)
45 % $
644,232
19 %
260,520
—
—
36 %
427,261
100 % $
1,332,013
131
27
106
36
301
44 %
9 %
35 %
12 %
100 %
______________________________________
(1)
(2)
For information concerning our estimated proved reserves as of December 31, 2021, see “—Our Reserves.” Totals
within table may not add a result of rounding.
Our sales volumes during 2021 includes activity related to our acquisition of additional interests in Ghana from
October 13, 2021, the acquisition date, through December 31, 2021. Our year-end proved reserves also include the
additional interests acquired.
13
Information about our deepwater fields is summarized in the following table.
Fields
Ghana(1)
Jubilee
TEN
U.S. Gulf of Mexico(1)
Barataria
Big Bend
Don Larsen
Gladden
Kodiak
Marmalard
Nearly Headless Nick
Danny Noonan
Odd Job
Sargent
SOB II
S. Santa Cruz
Tornado
Winterfell
Mauritania
Greater Tortue Ahmeyim
Bir Allah
Orca
Senegal
License
WCTP/DT
(2)
DT
MC 521
MC 697 / 698 / 742
EB 598
MC 800
MC 727 / 771
MC 255 / 300
MC 387
EC 381 / GB 506
MC 214 / 215
GB 339
MC 431
MC 563
GC 281
GC 943 / 944
Block C8
Block C8
Block C8
(3)
Greater Tortue Ahmeyim
Saint Louis Offshore
Profond
(3)
Teranga
Yakaar
Cayar Offshore
Profond
Cayar Offshore
Profond
Equatorial Guinea(1)
Ceiba Field and Okume Complex
Asam
Block G
Block S
______________________________________
Kosmos
Participating
Interest
Operator
Stage
Expiration
License
42.1 % (2)
28.1 % (4)
Tullow
Tullow
Production
Production
2034
2036
22.5 %
5.3 %
20.0 %
20.0 %
29.1 %
11.4 %
21.9 %
30.0 %
Various
(5)
50.0 %
11.8 %
40.5 %
35.0 %
16.4 %
Kosmos
Fieldwood
Occidental
W&T
Kosmos
Murphy
Murphy
Talos
Kosmos
Kosmos
Murphy
Kosmos
Talos
Beacon
26.8 %
28.0 % (6)
28.0 % (6)
26.7 %
BP
BP
BP
BP
Production
Production
Production
Production
Production
Production
Production
Production
Production
Production
Production
Production
Production
Appraisal
(8)
(8)
(8)
(8)
(8)
(8)
(8)
(8)
(8)
(8)
(8)
(8)
(8)
(8)
Development
2049(9)
Appraisal
Appraisal
2022
2022
Development
2044(10)
30.0 % (7)
BP
Appraisal
2024
30.0 % (7)
BP
Appraisal
2024
40.4 %
40.0 %
Trident
Kosmos
Production
2029/2034(11)
Appraisal
2022
(1)
(2)
(3)
For information concerning our estimated proved reserves as of December 31, 2021, see “—Our Reserves.”
The Jubilee Field straddles the boundary between the WCTP petroleum contract and the DT petroleum contract
offshore Ghana. To optimize resource recovery in this field, we entered into the Jubilee UUOA in July 2009 with
GNPC and the other block partners of each of these two blocks. The Jubilee UUOA governs the interests in and
development of the Jubilee Field and created the Jubilee Unit from portions of the WCTP petroleum contract and the
DT petroleum contract areas. The interest percentage is subject to redetermination of the participating interests in the
Jubilee Field pursuant to the terms of the Jubilee UUOA. Our current paying interest on development activities in the
Jubilee Field is 47.0%. Table above reflects additional interests acquired in the recent acquisition of additional
interests in Ghana. See “Item 8. Financial Statements and Supplementary Data—Note 3—Acquisitions and
Divestitures” for discussion of potential pre-emption impact.
The Greater Tortue Ahmeyim Unit, which includes the Ahmeyim discovery in Mauritania Block C8 and the Guembeul
discovery in the Senegal Saint Louis Offshore Profond Block, straddles the border between Mauritania and Senegal.
To optimize resource recovery in this field, we entered into the GTA UUOA in February 2019 with the governments
of Mauritania and Senegal. The GTA UUOA governs interests in and development of the Greater Tortue Ahmeyim
Field and created the Greater Tortue Ahmeyim Unit from portions of the Mauritania Block C8 and the Senegal Saint
Louis Offshore Profond Block areas. These interest percentages are subject to redetermination of the participating
14
interests in the Greater Tortue Ahmeyim Field pursuant to the terms of the GTA UUOA. Our current payment interest
on development activities in the Greater Tortue Ahmeyim Unit is 26.7%.
Our paying interest on development activities in the TEN fields is 31.4%. Table above reflects additional interests
acquired in recent acquisition of additional interests in Ghana. See “Item 8. Financial Statements and Supplementary
Data—Note 3—Acquisitions and Divestitures” for discussion of potential pre-emption impact.
Our interests in blocks MC 214 and MC 215 are 61.1% and 54.9%, respectively.
SMH has the option to acquire up to an additional 4% participating interest in a commercial development on Block C8.
These interest percentages do not give effect to the exercise of such option.
PETROSEN has the option to acquire up to an additional 10% participating interest in a commercial development on
the Saint Louis Offshore Profond and Cayar Offshore Profond Blocks. The interest percentage does not give effect to
the exercise of such option.
Our U.S. Gulf of Mexico blocks are held by production/operations, and the lease periods extend as long as production/
governmental approved operations continue on the relevant block.
(4)
(5)
(6)
(7)
(8)
(9)
License expiration date can be extended by an additional ten years subject to certain conditions being met.
(10)
License expiration date can be extended by an additional twenty years subject to certain conditions being met.
(11)
The Ceiba and Okume Complex are two approved fields within the Production Sharing Contract for Block G. Based
on Commercial Discovery approval date for each field by the Ministry of Mines and Hydrocarbons, the Ceiba field
Production Sharing Contract expires in 2029, and the Okume Complex field Production Sharing Contract expires in
2034.
Exploration License and Lease Areas
Country
Equatorial Guinea
Mauritania
Sao Tome and Principe
Senegal
U.S. Gulf of Mexico
Kosmos Average
Number of
Participating
Blocks
4
2
1
1
59
Interest
50.0%
28.0%
58.9%
30.0%
39.9%
Operator(s)
(1) Kosmos
(2) BP
(3) Kosmos
(4) BP
Kosmos, Murphy, Talos,
Fieldwood, Occidental, W&T
Offshore, LLOG, Beacon
Current Phase
Expiration Range
2022
2022
2022
2024
through 2029
(5)
______________________________________
(1)
(2)
(3)
(4)
(5)
Should a commercial discovery be made, GEPetrol's 20% carried interest will convert to a 20% participating interest
for all development and production operations.
Should a commercial discovery be made, SMH’s 10% carried interest is extinguished and SMH will have an option to
obtain a participating interest in the discovery area between 10% and 14%. SMH will pay its portion of development
and production costs in a commercial development on the blocks. The interest percentage does not give effect to the
exercise of such option.
ANP-STP's carried interest may be converted to a full participating interest at any time. ANP-STP will reimburse any
costs, expenses and any amount incurred on its behalf prior to the election.
PETROSEN has the option to obtain up to an additional 10% paying interest in a commercial development on the
Cayar Offshore Profond Block. The interest percentage does not give effect to the exercise of such option.
Our U.S. Gulf of Mexico blocks can be held by operations or commercial production, and the corresponding lease
periods extend as long as governmental approved operations continue on the relevant block. This can extend the lease
expiration to a date later than 2029.
15
Ghana
The WCTP Block and DT Block are located within the Tano Basin, offshore Ghana. This basin contains a proven
world‑class petroleum system as evidenced by our discoveries. In October 2021, Kosmos completed the acquisition of
Anadarko WCTP Company which owned a participating interest in the WCTP Block and DT Block offshore Ghana, including
an 18.0% participating interest in the Jubilee Unit Area and an 11.1% participating interest in the TEN fields. Following closing
of the acquisition, Kosmos’ interest in the Jubilee Unit Area increased from 24.1% to 42.1%, and Kosmos’ interest in the TEN
fields increased from 17.0% to 28.1%. Under the Deepwater Tano Block Joint Operating Agreement, certain joint venture
partners have pre-emption rights that, if fully exercised and approved by the Government of Ghana, could reduce our ultimate
interest in the Jubilee Unit Area by 3.8% to 38.3%, and our ultimate interest in the TEN fields by 8.3% to 19.8%. In November
2021, we received notice from certain joint venture partners that they intend to exercise their pre-emption rights in relation to
Kosmos' acquisition of Anadarko WCTP Company. The exercise of pre-emption rights is subject to finalizing definitive
agreements with Kosmos and requires approval from GNPC and the Ghanaian Ministry of Energy. The following is a brief
discussion of our discoveries on our license areas offshore Ghana.
Jubilee Field
The Jubilee Field was discovered by Kosmos in 2007, with first oil produced in 2010. Appraisal activities confirmed
that the Jubilee discovery straddled the WCTP and DT Blocks. Pursuant to the terms of the Jubilee UUOA, the discovery area
was unitized for purposes of joint development by the WCTP and DT Block partners.
The Jubilee Field is located approximately 60 kilometers offshore Ghana in water depths of approximately 1,000 to
1,800 meters, which led to the decision to implement an FPSO based development. The FPSO is designed to provide water and
natural gas injection to support reservoir pressure, to process and store oil and to export gas through a pipeline to the mainland.
The Jubilee Field is being developed in a phased approach. The initial phase provided subsea infrastructure capacity for
additional production and injection wells to be drilled in future phases of development.
The Government of Ghana completed the construction and connection of a gas pipeline in 2017 from the Jubilee Field
to transport natural gas to the mainland for processing and sale. In 2021, the partnership exported approximately 85 million
standard cubic feet per day (gross) on average from the Jubilee field to the mainland. In the absence of continuous export of
large quantities of natural gas from the Jubilee Field, it is anticipated that we will need to re-inject or flare such natural gas. Our
inability to continuously export associated natural gas from the Jubilee Field could impact our oil production.
In February 2016, the Jubilee Field operator identified an issue with the turret bearing of the FPSO Kwame Nkrumah.
Kosmos and its partners completed the lifting and locking of the main turret bearing, and the rotation of the vessel to its final
heading in the second half of 2018. Permanent spread mooring of the vessel was completed in 2019. The catenary anchor leg
mooring (“CALM”) Buoy, the final phase of the turret remediation project, was installed and commissioned in February 2021.
Oil production from the Jubilee Field averaged approximately 74,900 Bopd gross (20,200 Bopd net) during 2021.
TEN
The TEN fields are located in the western and central portions of the DT Block, approximately 48 kilometers offshore
Ghana in water depths of approximately 1,000 to 1,700 meters. The discoveries are being jointly developed with shared
infrastructure and a single FPSO, with first oil produced in 2016.
Similar to Jubilee, the TEN fields are being developed in a phased manner. The TEN PoD was designed to include an
expandable subsea system that would provide for multiple phases.
Oil production from TEN averaged approximately 32,800 Bopd gross (5,900 Bopd net) during 2021.
The construction and connection of a gas pipeline between the Jubilee and TEN fields to transport natural gas to the
mainland for processing and sale was completed in 2017. In December 2017, we signed the TAG GSA. In 2021, the partnership
exported approximately 8 million standard cubic feet per day (gross) on average from the TEN field to the mainland. Our
inability to continuously export associated natural gas from the TEN fields could impact our oil production.
16
U.S. Gulf of Mexico
In the U.S. Gulf of Mexico, Kosmos maintains: (i) a portfolio of producing assets that Kosmos can continue to exploit,
(ii) infrastructure-led exploration growth assets, and (iii) a high-quality inventory of exploration prospects across the Garden
Banks, Green Canyon and Mississippi Canyon protraction areas. We have expanded our inventory through the U.S. Gulf of
Mexico Federal lease sales and farm-in transactions, including expansion into the Walker Ridge, De Soto Canyon and Keathley
Canyon protraction areas of the U.S. Gulf of Mexico. Our U.S. Gulf of Mexico assets averaged approximately 19,700 Boepd
net (~ 82% oil) from 12 fields during 2021.
The following is a brief discussion of our key producing fields in the U.S. Gulf of Mexico.
Odd Job
The Odd Job field is producing through the Delta House FPS, operated by Murphy. The technical team initially
identified the Middle Miocene sands at the Odd Job prospect, and these sands are currently producing. The Odd Job 214 #2
well, the third well in the Odd Job field, was drilled in 2018, and came online in the fourth quarter of 2019. Net production
during 2021 averaged approximately 6,500 Boepd net.
Tornado
The Tornado field is producing from three Pliocene wells through the Helix Producer I, a ship-shaped, dynamically-
positioned production platform in the deepwater U.S. Gulf of Mexico, which is operated by Talos Energy. To help enhance
overall recoveries in the Tornado field, the Tornado 4 water injection well was drilled and came online in 2020. During the
second quarter of 2021, the Tornado 5 infill well was successfully drilled and completed. The Tornado 5 well was brought
online in July 2021. Net production during 2021 averaged approximately 5,800 Boepd net.
Kodiak
The Kodiak field is producing from one well, which is completed in the Middle Miocene sands. This well is flowing
through the Devils Tower Spar platform, which is operated by ENI. In April 2021, a second development well was brought
online through existing infrastructure to the Devils Tower Spar platform with one of two zones intermittently producing. During
the third quarter of 2021, the well continued to experience production issues and was shut-in. We have agreed with partners to
side-track the well in the first half of 2022 to restore production from the second Kodiak development well. Net production
during 2021 averaged approximately 2,700 Boepd net.
Marmalard
The Marmalard field produces from four wells, each completed in Middle Miocene sands. These wells are flowing
through the Delta House FPS, operated by Murphy. Net production during 2021 averaged approximately 1,800 Boepd net.
South Santa Cruz / Barataria
The South Santa Cruz field is producing from one well in a Late Miocene sand. The Barataria field is also producing
from one well in a Late Miocene sand. Both fields produce through the Blind Faith semi-submersible platform, which is
operated by Chevron. Net production from these two wells during 2021 averaged approximately 900 Boepd net.
Mauritania
The C8 and C12 blocks are located on the western margin of the Mauritania Salt Basin offshore Mauritania and range
in water depths from 100 to 3,000 meters. These blocks are located in a proven petroleum system, with our primary targets
being Cretaceous sands in structural and stratigraphic traps.
These blocks cover an aggregate area of approximately 2.4 million acres (gross). We have acquired approximately
2,500 line-kilometers of 2D seismic data and 9,600 square kilometers of 3D seismic data covering portions of our blocks in
Mauritania. Based on these 2D and 3D seismic programs, we have drilled three successful exploration wells and an appraisal
well and have identified additional prospects in our blocks. We continue to integrate the results of our drilling program in
Mauritania. In 2021, at the conclusion of the second exploration period, Block C13 offshore Mauritania was relinquished.
17
Senegal
The Senegal Blocks are located in the Senegal River Cretaceous petroleum system and range in water depth from 300
to 3,100 meters. The area is an extension of the working petroleum system in the Mauritania Salt Basin. We acquired
approximately 3,700 square kilometers of 3D seismic data over the Senegal Blocks in 2015 and 2016. We have drilled three
successful exploration wells and two appraisal wells.
The following is a brief discussion of our discoveries to date offshore Mauritania and Senegal.
Greater Tortue Ahmeyim Development
The Greater Tortue Ahmeyim discoveries are significant, play-opening gas discoveries for the outboard Cretaceous
petroleum system and are located approximately 120 kilometers offshore Mauritania and Senegal. The Greater Tortue
Ahmeyim development straddles Block C8 offshore Mauritania and Saint Louis Offshore Profond Block offshore Senegal.
We have drilled four wells within the Greater Tortue Ahmeyim development, Tortue-1, Guembeul-1, Ahmeyim-2 and
Greater Tortue Ahmeyim-1 (GTA-1). The wells penetrated multiple, excellent quality gas reservoirs, including the Lower
Cenomanian, Upper Cenomanian and underlying Albian. The wells successfully delineated the Ahmeyim and Guembeul gas
discoveries and demonstrated reservoir continuity, as well as static pressure communication between the three wells drilled
within the Lower Cenomanian reservoir. The discovery ranges in water depths from approximately 2,700 meters to 2,800
meters, with total depths drilled ranging from approximately 5,100 meters to 5,250 meters.
The Tortue-1 discovery well, located in Block C8 offshore Mauritania, intersected approximately 117 meters of net
hydrocarbon pay. A single gas pool was encountered in the Lower Cenomanian objective, which is comprised of three
reservoirs totaling 88 meters in thickness over a gross hydrocarbon interval of 160 meters. A fourth reservoir totaling 19 meters
was penetrated within the Upper Cenomanian target over a gross hydrocarbon interval of 150 meters. The exploration well also
intersected an additional 10 meters of net hydrocarbon pay in the lower Albian section, which is interpreted to be gas.
The Guembeul-1 discovery well, located in the northern part of the Saint Louis Offshore Profond area in Senegal, is
located approximately five kilometers south of the Tortue-1 exploration well in Mauritania. The well encountered 101 meters of
net gas pay in two excellent quality reservoirs, including 56 meters in the Lower Cenomanian and 45 meters in the underlying
Albian, with no water encountered.
The Ahmeyim-2 appraisal well is located in Block C8 offshore Mauritania, approximately five kilometers northwest,
and 200 meters down-dip of the basin-opening Tortue-1 discovery. The well confirmed significant thickening of the gross
reservoir sequences down-dip. The Ahmeyim-2 well encountered 78 meters of net gas pay in two excellent quality reservoirs,
including 46 meters in the Lower Cenomanian and 32 meters in the underlying Albian.
The Greater Tortue Ahmeyim-1 (GTA-1) appraisal well was drilled on the eastern anticline within the unit
development area of Greater Tortue Ahmeyim field. The GTA-1 well encountered approximately 30 meters of net gas pay in
high quality Albian reservoir. The well was drilled in approximately 2,500 meters of water, approximately 10 kilometers
inboard of the Guembeul-1A and Tortue-1 wells, to a total depth of 4,884 meters.
In 2017, we completed a DST on the Tortue-1 well, demonstrating that the Tortue field is a world-class resource and
confirming key development parameters including well deliverability, reservoir connectivity, and fluid composition. The
Tortue-1 well flowed at a sustained, equipment-constrained rate of approximately 60 MMcfd during the main extended flow
period, with minimal pressure drawdown, providing confidence in well designs that are each capable of producing
approximately 200 MMcfd. The DST results confirmed a connected volume per well consistent with the current development
scheme, which together with the high well rate is expected to result in a low number of development wells compared to
equivalent schemes. Initial analysis of fluid samples collected during the test indicate Tortue gas is well suited for liquefaction
given low levels of liquids and minimal impurities. Data acquired from the DST was used to further optimize field development
and to refine process design parameters critical to the FEED process.
In December 2018, we and our partners announced that a final investment decision for Phase 1 of the Greater Tortue
Ahmeyim project had been agreed. The Greater Tortue Ahmeyim project is designed to produce gas from a deepwater subsea
system to a mid-water FPSO, which processes the gas to make it liquefaction ready, and sends the gas through a pipeline to a
FLNG facility. The FLNG facility is protected behind a nearshore hub (which serves as a breakwater and LNG terminal) and is
located on the Mauritania and Senegal maritime border. The FLNG facility for Phase 1 is designed to produce approximately
2.5 million tons per annum on average. The project will provide LNG for global export, as well as make gas available for
18
domestic use in both Mauritania and Senegal. Following a competitive tender process, BP Gas Marketing was selected as the
buyer for the LNG offtake for Greater Tortue Ahmeyim Phase 1, and the Tortue Phase 1 SPA was executed in February 2020
with an initial term of up to 20 years. Phase 1 of the project was approximately 70% complete at year-end 2021, with first gas
for the project expected in the third quarter of 2023. The partnership has also been focused on optimizing Phase 2 of the project
to deliver competitive returns in the current environment. Phase 2 of the Greater Tortue Ahmeyim project targets an expansion
largely utilizing the infrastructure from Phase 1.
Other Mauritania and Senegal Discoveries
BirAllah and Orca Discoveries
The BirAllah discovery (formally known as Marsouin), located in Block C8 offshore Mauritania, is a significant, play-
extending gas discovery, building on our successful exploration program in the outboard Cretaceous petroleum system offshore
Mauritania. The Marsouin-1 well is located approximately 60 kilometers north of the Ahmeyim discovery and was drilled to a
total depth of 5,150 meters in nearly 2,400 meters of water. Based on analysis of drilling results and logging data, Marsouin-1
encountered at least 70 meters of net gas pay in Upper and Lower Cenomanian intervals comprised of excellent quality
reservoir sands.
The Orca-1 well, located in Block C8 offshore Mauritania, was drilled in October 2019 and delivered a major gas
discovery. The Orca-1 well, which targeted a previously untested Albian play, encountered 36 meters of net gas pay in excellent
quality reservoirs. In addition, the well extended the Cenomanian play fairway by confirming 11 meters of net gas pay in a
down-structure position relative to the original Marsouin-1 discovery well. The location of the Orca-1 well proved both the
structural and stratigraphic components of the trap are working, thereby proving a significant volume. The Orca-1 well was
drilled in approximately 2,510 meters of water to a total measured depth of around 5,266 meters.
In total, we believe that Orca-1 and Marsouin-1 have de-risked more than sufficient resource to support a world-scale
LNG project from the Cenomanian and Albian plays in the BirAllah area. The BirAllah and Orca discoveries are being
analyzed as a potential joint development. We are currently in discussions with the government of Mauritania to extend the
exploration phase of Block C8 which is currently set to expire in June 2022. As of December 31, 2021, capitalized costs related
to BirAllah and Orca discoveries approximates $62.0 million.
Yakaar and Teranga Discoveries
The Teranga discovery is located in the Cayar Offshore Profond block approximately 65 kilometers northwest of
Dakar and was our second exploration well offshore Senegal. The Teranga-1 discovery well is located in nearly 1,800 meters of
water and was drilled to a total depth of approximately 4,850 meters. The well encountered 31 meters of net gas pay in good
quality reservoir in the Lower Cenomanian objective. Well results confirm that a prolific inboard gas fairway extends
approximately 200 kilometers south from the Marsouin-1 well in Mauritania through the Greater Tortue Ahmeyim area on the
maritime boundary to the Teranga-1 well in Senegal.
The Yakaar discovery is located in the Cayar Offshore Profond block offshore Senegal, approximately 95 kilometers
northwest of Dakar in approximately 2,600 meters of water. The Yakaar-1 discovery well was drilled to a total depth of
approximately 4,900 meters. The well intersected a gross hydrocarbon column of 120 meters in three pools within the primary
Lower Cenomanian objective and encountered 45 meters of net pay. In September 2019, we completed the Yakaar-2 appraisal
well, which encountered approximately 30 meters of net gas pay. The Yakaar-2 well was drilled approximately nine kilometers
from the Yakaar-1 exploration well and further delineated the southern extension of the field.
The results of the Yakaar-2 well underpin our view that the Yakaar-Teranga resource base is world-scale and has the
potential to support an LNG project that provides significant volumes of natural gas to both domestic and export markets.
Development of Yakaar-Teranga is being considered in a phased approach with Phase 1 providing domestic gas and data to
optimize the development of future phases. It could also support the country’s “Plan Emergent Senegal” launched by the
President of Senegal in 2014.
Equatorial Guinea
The EG-21, EG-24, S, and W blocks are located in the southern part of the Gulf of Guinea, in the Republic of
Equatorial Guinea, west of the Rio Muni petroleum province with water depths up to 2,300 meters. These blocks are located in
a proven petroleum system, with our primary targets being Cretaceous sands in structural and stratigraphic traps. We have over
19
10,000 square kilometers of 3D seismic over the blocks. The seismic data is being interpreted and high graded prospects for
future drilling are being matured.
Ceiba Field and Okume Complex
In Equatorial Guinea, we maintain a 40.4% undivided participating interest in the Ceiba Field and Okume Complex.
These offshore assets in the Gulf of Guinea provide cash flow through production with the potential to increase production
through exploration opportunities with potential low cost tie-backs through the existing infrastructure.
The shared development of the Ceiba Field and Okume Complex consists of six subsea-well clusters that feed
production to the Ceiba FPSO which is shared by both fields through a system of risers. The Okume Complex includes six
platforms with an export line to move Okume production to the Ceiba FPSO.
Oil production from the Ceiba Field and Okume Complex averaged approximately 29,900 Bopd gross (9,700 Bopd
net) during 2021.
Asam Discovery
In October 2019, the S-5 exploration well was drilled to a total depth of 4,400 meters in Block S offshore Equatorial
Guinea, encountering 39 meters of net oil pay in good-quality Santonian reservoir. In July 2020, an appraisal plan was approved
by the government of Equatorial Guinea. The well is located within tieback range of the Ceiba FPSO and the appraisal program
is currently ongoing to establish the scale of the discovered resource and evaluate the optimum development solution.
Sao Tome and Principe
We are the operator for the petroleum contract covering Block 5, offshore Sao Tome and Principe in the Gulf of
Guinea. The block covers an area of approximately 0.5 million acres (gross) in water depths ranging from 2,150 to 3,000
meters.
Our block is adjacent to, and represents a potential extension of, a proven and prolific petroleum system offshore
Equatorial Guinea and northern Gabon comprising Cretaceous post-rift source rocks and Late Cretaceous reservoirs.
In August 2017, we completed a 3D seismic survey of approximately 2,500 square kilometers offshore Sao Tome and
Principe. Processing has been completed and the 3D seismic data has been integrated into our geological evaluation. We
continue to mature an inventory of prospects on the license area in Sao Tome and Principe and will continue to refine and
assess the prospectivity. In the fourth quarter of 2021, we received approval for a six month extension to the current exploration
phase for Block 5 offshore Sao Tome and Principe through November 2022.
Our Reserves
The following table sets forth summary information about our estimated proved reserves as of December 31, 2021. See
“Item 8. Financial Statements and Supplementary Data—Supplemental Oil and Gas Data (Unaudited)” for additional
information.
Our estimated proved reserves as of December 31, 2021, 2020, and 2019 were associated with our fields in Ghana,
Equatorial Guinea, Mauritania, Senegal and the U.S. Gulf of Mexico.
20
Summary of Oil and Gas Reserves
2021 Net Proved Reserves(1)
2020 Net Proved Reserves(1)
2019 Net Proved Reserves(1)
Oil,
Condensate,
NGLs
Natural
Gas(3)
Total
Oil,
Condensate,
NGLs
Natural
Gas(3)
Total
Oil,
Condensate,
NGLs
Natural
Gas(3)
Total
(MMBbl)
(Bcf)
(MMBoe)
(MMBbl)
(Bcf)
(MMBoe)
(MMBbl)
(Bcf)
(MMBoe)
Reserves Category
Proved developed
Ghana(2)
Equatorial Guinea
Mauritania/Senegal
U.S. Gulf of Mexico
Total proved developed
Proved undeveloped
Ghana(2)
Equatorial Guinea
Mauritania/Senegal(4)
U.S. Gulf of Mexico
Total proved undeveloped(5)
Total Kosmos proved reserves
52
20
—
28
100
68
5
8
4
85
185
56
11
—
20
87
12
—
590
6
608
695
61
22
—
31
115
70
5
106
5
186
301
26
21
—
32
79
42
4
—
2
48
127
23
11
—
25
60
8
—
—
2
10
70
30
23
—
36
89
43
4
—
3
50
139
47
23
—
34
104
41
3
—
6
50
154
31
12
—
28
71
14
—
—
7
21
92
52
25
—
39
116
43
3
—
7
53
169
______________________________________
(1) Totals within the table may not add as a result of rounding.
(2) Our reserves associated with the Jubilee Field are based on the 54.4%/45.6% redetermination split between the WCTP
Block and DT Block. Table above reflects additional interests acquired in the recent acquisition of additional interests in
Ghana. See “Item 8. Financial Statements and Supplementary Data—Note 3—Acquisitions and Divestitures” for
discussion of potential pre-emption impact.
(3) These reserves include the estimated quantity of gas to be exported as LNG from the Greater Tortue Ahmeyim project, as a
result of the Tortue SPA finalized in February of 2020. These reserves also include the estimated quantities of fuel gas
required to operate the Jubilee and TEN FPSOs and Equatorial Guinea facilities during normal field operations and the
associated gas forecasted to be exported from TEN. If and when a subsequent gas sales agreement is executed for Jubilee, a
portion of the remaining Jubilee gas may be recognized as reserves. If and when a gas sales agreement and the related
infrastructure are in place for the TEN fields non-associated gas, a portion of the remaining gas may be recognized as
reserves.
(4) The Mauritania/Senegal Natural Gas reserves presented consists of LNG and Fuel Gas in our reserve report. We note that
the LNG is presented as Plant Products in Mboe in our reserve report.
(5) All of our proved undeveloped reserves are expected to be developed within six years or less. Proved undeveloped reserves
expected to be developed beyond five years are related to long-term projects which will be completed under a continuous
drilling program.
Changes during the year ended December 31, 2021, at Greater Jubilee include a positive revision of 49.1 MMBoe, of
which 39.9 MMBoe were acquired on October 13, 2021 in the recent acquisition of additional interests in Ghana. The other 9.2
MMBoe of additions were primarily due to field performance, positive drilling results, and optimization of future development
plans. The additions were partially offset by net Greater Jubilee production of 7.4 MMBoe which includes production related to
our acquisition of additional interests in Ghana commencing October 13, 2021, the acquisition date. Changes at TEN include a
positive revision of 18.2 MMBoe, of which 16.2 MMBoe were acquired in the recent acquisition of additional interests in
Ghana. The other 2.0 MMBoe of additions were primarily due to an increase in estimated associated gas sales. The additions
were partially offset by net TEN production of 2.2 MMBoe. Changes at Equatorial Guinea included an increase of 3.7 MMBoe
related to Okume Complex performance and drilling results, which was offset by 3.6 MMBoe of net production. Changes at the
U.S. Gulf of Mexico included an increase of 4.4 MMBoe related to strong performance of certain fields, offset by net U.S. Gulf
of Mexico production of 7.2 MMBoe.
During the year ended December 31, 2021, we had an overall proved undeveloped reserves increase of 136.3 MMBoe
as a result of several factors, including the acquisition of additional interests in Ghana (+22.7 MMBoe for Greater Jubilee and
21
+6.6 MMBoe for TEN), optimization of future drilling in Greater Jubilee (+17.8 MMBoe), adding a future development well
and optimizing future development plans in the U.S. Gulf of Mexico and Equatorial Guinea (+6.8 MMBoe), and the economic
status of the Greater Tortue Ahmeyim project due to project progress and improved oil price (+106.5 MMBoe). Drilling activity
impact on proved undeveloped volume change includes the drilling of two wells in Greater Jubilee (-17.1 MMBoe), one well in
TEN (-3.6 MMBoe), two wells in Equatorial Guinea (-1.2 MMBoe), and one well in Tornado in the U.S. Gulf of Mexico (-2.1
MMBoe).
In Greater Jubilee, we converted 17.1 MMBoe of proved undeveloped reserves to proved developed with the drilling
of two wells at a cost of $25.2 million. In TEN, we converted 3.6 MMBoe of proved undeveloped reserves with the drilling of
one well at a cost of $8.9 million. In Equatorial Guinea we spent $35.6 million to drill two wells and to replace certain subsea
infrastructure, which converted 1.8 MMBoe of proved undeveloped reserves to proved developed. In the U.S. Gulf of Mexico,
we converted 2.1 MMBoe of proved undeveloped reserves to proved developed with the drilling of one well in Tornado at a
cost of $19.0 million.
Changes during the year ended December 31, 2020, were primarily due to 2020 production as well as lower prices.
Greater Jubilee includes a negative revision of 0.3 MMBbl related to delayed drilling of water injection wells that will provide
needed pressure support to certain production wells, in addition to net Greater Jubilee production of 7.0 MMBbl. Changes at
TEN included a decrease of 12.0 MMBbl related to performance, delayed drilling and alterations to future development plans,
in addition to net TEN production of 2.9 MMBoe. Changes at Equatorial Guinea included an increase of 2.0 MMBbl due to
strong base performance and positive stimulation results, offset by 4.0 MMBbl of net Equatorial Guinea production. Changes at
the U.S. Gulf of Mexico included an increase of 2.0 MMBoe primarily due to positive drilling and performance at Kodiak and
Tornado, offset by net U.S. Gulf of Mexico production of 8.3 MMBoe.
During the year ended December 31, 2020, we had an overall proved undeveloped reserves decrease of 3.3 MMboe as
a result of several factors, including adding additional wells to future development of Greater Jubilee (+4.7 MMboe), a negative
revision in TEN (-0.3 MMboe), drilling of one well in TEN (-3.0 MMboe), one well in the Kodiak field (-1.6 MMboe) and one
well in the Tornado field (-0.9 MMboe), and loss due to lower SEC pricing (-2.2 MMboe).
In TEN, we converted 3.0 MMboe of proved undeveloped reserves to proved developed with the drilling of a new
well, at a cost of $28.5 million. In the U.S. Gulf of Mexico, we spent $79.2 million to drill two new wells, which converted 2.5
MMboe of proved undeveloped reserves to proved developed.
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. Due to the decrease in commodity prices during 2020 and the related commodity price utilized to calculate proved reserves
for SEC purposes, the field did not have proved reserves recognition as of December 31, 2020.
Changes during the year ended December 31, 2019, at Greater Jubilee include a positive revision of 8.2 MMBbl
related to positive drilling results and increased original oil in place, and optimized development plan, partially offset by net
Greater Jubilee production of 7.6 MMBbl. Changes at TEN included an increase of 8.8 MMBoe related to original oil in place
adjustments based on updated static modeling and development plan updates, partially offset by net TEN production of 3.8
MMBoe. Changes at Equatorial Guinea included an increase of 6.3 MMBbl due to production optimization plans and plans for
new drilling, which was offset by 4.7 MMBbl of net production. Changes at the U.S. Gulf of Mexico included an increase of
2.9 MMBoe related to strong performance of certain fields and the Gladden Deep discovery, offset by net U.S. Gulf of Mexico
production of 8.8 MMBoe.
During the year ended December 31, 2019, we had an addition of 16.1 MMBoe of proved undeveloped reserves as a
result of several factors, including updated original oil in place due to positive drilling results and improved static models in
Greater Jubilee and TEN, plans for one new well to be drilled in TEN and three new wells to be drilled in the Okume Complex.
We converted a total of 13.7 MMBoe of proved undeveloped reserves to proved developed due to completions of three
new wells in Greater Jubilee, two new wells in TEN, and three new wells in the U.S. Gulf of Mexico with a combined cost of
$176.7 million. We spent $41.6 million to convert 4.0 MMBbl of proved undeveloped reserves in Greater Jubilee and $12.8
million to convert 2.5 MMBoe proved undeveloped reserves in TEN; and $122.3 million spent to convert 7.2 MMBoe of
proved undeveloped reserves in the U.S. Gulf of Mexico.
22
Estimated proved reserves
Unless otherwise specifically identified in this report, the summary data with respect to our estimated net proved
reserves for the years ended December 31, 2021, 2020 and 2019 has been prepared by RSC, our independent reserve
engineering firm for such years, in accordance with the rules and regulations of the SEC applicable to companies involved in oil
and natural gas producing activities. These rules require SEC reporting companies to prepare their reserve estimates using
reserve definitions and pricing based on 12‑month historical unweighted first‑day‑of‑the‑month average prices, rather than
year‑end prices. For a definition of proved reserves under the SEC rules, see the “Glossary and Selected Abbreviations.” For
more information regarding our independent reserve engineers, please see “—Independent petroleum engineers” below.
Our estimated proved reserves and related future net revenues, PV‑10 and Standardized Measure were determined in
accordance with SEC rules for proved reserves.
Future net revenues represent projected revenues from the sale of proved reserves net of production and development
costs (including operating expenses and production taxes). Such calculations at December 31, 2021 are based on costs in effect
at December 31, 2021 and the 12‑month unweighted arithmetic average of the first‑day‑of‑the‑month price for the year ended
December 31, 2021, adjusted for anticipated market premium, without giving effect to derivative transactions, and are held
constant throughout the life of the assets. There can be no assurance that the proved reserves will be produced within the
periods indicated or prices and costs will remain constant.
Independent petroleum engineers
Ryder Scott Company, L.P.
RSC, our independent reserve engineers for the years ended December 31, 2021, 2020 and 2019, was established in
1937. For over 80 years, RSC has provided services to the worldwide petroleum industry that include the issuance of reserves
reports and audits, appraisal of oil and gas properties including fair market value determination, reservoir simulation studies,
enhanced recovery services, expert witness testimony, and management advisory services. RSC professionals subscribe to a
code of professional conduct and RSC is a Registered Engineering Firm in the State of Texas.
For the years ended December 31, 2021, 2020 and 2019, we engaged RSC to prepare independent estimates of the
extent and value of the proved reserves of certain of our oil and gas properties. These reports were prepared at our request to
estimate our reserves and related future net revenues and PV‑10 for the periods indicated therein. Our estimated reserves at
December 31, 2021, 2020 and 2019 and related future net revenues and PV‑10 at December 31, 2021, 2020 and 2019 are taken
from reports prepared by RSC, in accordance with petroleum engineering and evaluation principles which RSC believes are
commonly used in the industry and definitions and current regulations established by the SEC. The December 31, 2021 reserve
report was completed on January 21, 2022, and a copy is included as an exhibit to this report.
In connection with the preparation of the December 31, 2021, 2020 and 2019 reserves report, RSC prepared its own
estimates of our proved reserves. In the process of the reserves evaluation, RSC did not independently verify the accuracy and
completeness of information and data furnished by us with respect to ownership interests, oil and gas production, well test data,
historical costs of operation and development, product prices or any agreements relating to current and future operations of the
fields and sales of production. However, if in the course of the examination something came to the attention of RSC which
brought into question the validity or sufficiency of any such information or data, RSC did not rely on such information or data
until it had satisfactorily resolved its questions relating thereto or had independently verified such information or data. RSC
independently prepared reserves estimates to conform to the guidelines of the SEC, including the criteria of “reasonable
certainty,” as it pertains to expectations about the recoverability of reserves in future years, under existing economic and
operating conditions, consistent with the definition in Rule 4‑10(a)(2) of Regulation S‑X. RSC issued a report on our proved
reserves at December 31, 2021, based upon its evaluation. RSC’s primary economic assumptions in estimates included an
ability to sell hydrocarbons at their respective adjusted benchmark prices and certain levels of future capital expenditures. The
assumptions, data, methods and precedents were appropriate for the purpose served by these reports, and RSC used all methods
and procedures as it considered necessary under the circumstances to prepare the report.
23
Technology used to establish proved reserves
Under the SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and
engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from
known reservoirs, and under existing economic conditions, operating methods, and government regulations. The term
“reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will
equal or exceed the estimate. Reasonable certainty can be established using techniques that have proved effective by actual
comparison of production from projects in the same reservoir interval, an analogous reservoir or by other evidence using
reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies
(including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results
with consistency and repeatability in the formation being evaluated or in an analogous formation.
In order to establish reasonable certainty with respect to our estimated proved reserves, RSC employed technologies
that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the
estimation of our proved reserves include, but are not limited to, production and injection data, electrical logs, radioactivity
logs, acoustic logs, whole core analysis, sidewall core analysis, downhole pressure and temperature measurements, reservoir
fluid samples, geochemical information, geologic maps, seismic data, well test and interference pressure and rate data. Reserves
attributable to undeveloped locations were estimated using performance from analogous wells with similar geologic
depositional environments, rock quality, appraisal plans and development plans to assess the estimated ultimate recoverable
reserves as a function of the original oil in place. These qualitative measures are benchmarked and validated against sound
petroleum reservoir engineering principles and equations to estimate the ultimate recoverable reserves volume. These
techniques include, but are not limited to, nodal analysis, material balance, and numerical flow simulation.
Internal controls over reserves estimation process
In our Reservoir Engineering team, we maintain an internal staff of petroleum engineering and geoscience
professionals with significant experience that contribute to our internal reserve and resource estimates. This team works closely
with our independent petroleum engineers to ensure the integrity, accuracy and timeliness of data furnished in their reserve and
resource estimation process. Our Reservoir Engineering team is responsible for overseeing the preparation of our reserves
estimates and has over 100 combined years of industry experience among them with positions of increasing responsibility in
engineering and evaluations. Each member of our team holds a minimum of a Bachelor of Science degree in petroleum
engineering or geology.
The RSC technical person primarily responsible for preparing the estimates set forth in the RSC reserves report
incorporated herein is Mr. Tosin Famurewa. Mr. Famurewa has been practicing consulting petroleum engineering at RSC since
2006. Mr. Famurewa is a Licensed Professional Engineer in the State of Texas (No. 100569) and has over 19 years of practical
experience in petroleum engineering. He graduated from University of California at Berkeley in 2000 with Bachelor of Science
Degrees in Chemical Engineering and Material Science Engineering, and he received a Master of Science degree in Petroleum
Engineering from University of Southern California in 2007. Mr. Famurewa meets or exceeds the education, training, and
experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves
Information promulgated by the Society of Petroleum Engineers and is proficient in judiciously applying industry standard
practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and
guidelines.
The Audit Committee provides oversight on the processes utilized in the development of our internal reserve and
resource estimates on an annual basis. In addition, our Reservoir Engineering team meets with representatives of our
independent reserve engineers to review our assets and discuss methods and assumptions used in preparation of the reserve and
resource estimates. Finally, our senior management reviews reserve and resource estimates on an annual basis.
24
Gross and Net Undeveloped and Developed Acreage
The following table sets forth certain information regarding the developed and undeveloped portions of our license and
lease areas as of December 31, 2021 for the countries in which we currently operate.
Ghana(2)
Equatorial Guinea
Mauritania
Sao Tome and Principe
Senegal
U.S. Gulf of Mexico
Total
Developed Area
Undeveloped Area
(Acres)
(Acres)
Total Area (Acres)
Gross
Net(1)
Gross
Net(1)
Gross
Net(1)
163
65
—
—
—
98
(In thousands)
53
26
—
—
—
28
34
2,355
2,430
527
917
223
11
1,292
679
310
271
105
197
2,420
2,430
527
917
321
64
1,318
679
310
271
133
326
107
6,486
2,668
6,812
2,775
______________________________________
(1)
(2)
Net acreage based on Kosmos’ participating interests, before the exercise of any options or back‑in rights, except for
our net acreage associated with the Jubilee, TEN, and Greater Tortue Ahmeyim fields, which are after the exercise of
options or back‑in rights. Our net acreage in Ghana may be affected by any redetermination of interests in the Jubilee
Unit and our net acreage in Mauritania and Senegal may be affected by any redetermination of interests in the Greater
Tortue Ahmeyim Unit.
The Exploration Period of the WCTP petroleum contract and DT petroleum contract has expired. The undeveloped
area reflected in the table above represents acreage within our discovery areas that were not subject to relinquishment
on the expiry of the Exploration Period. Table above reflects additional interests acquired in Ghana. See “Item 8.
Financial Statements and Supplementary Data—Note 3—Acquisitions and Divestitures” for discussion of potential
pre-emption impact.
Productive Wells
Productive wells consist of producing wells and wells capable of production, including wells awaiting connections.
For wells that produce both oil and gas, the well is classified as an oil well. The following table sets forth the number of
productive oil and gas wells in which we held an interest at December 31, 2021:
Ghana(2)
Equatorial Guinea
U.S. Gulf of Mexico
Total(1)
Productive
Oil Wells
Productive
Gas Wells
Total
Gross
Net
Gross
Net
Gross
Net
51
83
23
157
19.23
33.53
6.57
59.33
—
—
—
—
—
—
—
—
51
83
23
157
19.23
33.53
6.57
59.33
______________________________________
(1)
(2)
Of the 157 productive wells, 42 (gross) or 10.00 (net) have multiple completions within the wellbore.
Table above reflects our additional interests acquired in Ghana. See “Item 8. Financial Statements and Supplementary
Data—Note 3—Acquisitions and Divestitures” for discussion of potential pre-emption impact.
25
Drilling activity
The results of oil and natural gas wells drilled and completed for each of the last three years were as follows:
Exploratory and Appraisal Wells(1)
Development Wells(1)
Productive(2)
Dry(3)
Total
Productive(2)
Dry(3)
Total
Total
Total
Gross
Net
Gross
Net
Gross
Net
Gross
Net
Gross
Net
Gross
Net
Gross
Net
Year Ended
December 31, 2021
Ghana(4)
—
—
—
—
—
—
Equatorial Guinea
—
—
—
—
—
—
U.S. Gulf of Mexico
—
—
Total
—
—
1
1
0.38
0.38
1
1
0.38
0.38
4
2
1
7
1.54
—
—
0.80
—
—
0.29
—
—
2.63
—
—
4
2
1
7
1.54
0.80
0.29
2.63
4
2
2
8
1.54
0.80
0.67
3.01
Year Ended
December 31, 2020
Ghana
—
—
—
—
—
—
1
0.17
2
0.34
3
0.51
3
0.51
Equatorial Guinea
—
—
—
—
—
—
—
—
—
—
—
—
—
—
U.S. Gulf of Mexico
—
—
Total
—
—
1
1
0.40
0.40
1
1
0.40
0.40
1
2
0.35
—
—
0.52
2
0.34
1
4
0.35
0.86
2
5
0.75
1.26
Year Ended
December 31, 2019
Ghana
—
—
—
—
—
—
4
0.89
—
—
4
0.89
4
0.89
Equatorial Guinea
—
—
—
—
—
—
—
—
—
—
—
—
—
—
U.S. Gulf of Mexico
Total
2
2
0.42
0.42
1
1
0.50
0.50
3
3
0.92
0.92
2
6
0.96
—
—
1.85
—
—
2
6
0.96
1.85
5
9
1.88
2.77
______________________________________
(1)
(2)
(3)
(4)
As of December 31, 2021, ten exploratory and appraisal wells have been excluded from the table until a determination
is made if the wells have found proved reserves. Also excluded from the table are 14 development wells awaiting
completion. These wells are shown as “Wells Suspended or Waiting on Completion” in the table below.
A productive well is 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 producing well. Productive wells are included in the
table in the year they were determined to be productive, as opposed to the year the well was drilled.
A dry well is an exploratory or development well that is not a productive well. Dry wells are included in the table in
the year they were determined not to be a productive well, as opposed to the year the well was drilled.
Table above reflects additional interests acquired in the recent acquisition of additional interests in Ghana. See “Item 8.
Financial Statements and Supplementary Data—Note 3—Acquisitions and Divestitures” for discussion of potential
pre-emption impact.
26
The following table shows the number of wells that are in the process of being drilled or are in active completion
stages, and the number of wells suspended or waiting on completion as of December 31, 2021.
Ghana(1)
Jubilee Unit
TEN
Equatorial Guinea
Asam
Okume
U.S. Gulf of Mexico
Winterfell
Mauritania / Senegal
BirAllah-Orca
Greater Tortue Ahmeyim Unit
Yakaar-Teranga
Total
Actively Drilling or
Completing
Wells Suspended or
Waiting on Completion
Exploration
Development
Exploration
Development
Gross
Net
Gross
Net
Gross
Net
Gross
Net
—
—
—
—
—
—
—
—
1
0.16
—
—
—
1
—
—
—
0.16
1
—
—
—
—
—
—
—
1
0.42
—
—
—
—
—
—
—
—
—
1
—
1
2
3
3
0.42
10
—
—
0.40
—
0.16
0.56
0.80
0.90
2.82
7
5
—
1
—
—
1
—
14
2.95
1.40
—
0.43
—
—
0.27
—
5.05
______________________________________
(1)
Table above reflects additional interests acquired in the recent acquisition of additional interests in Ghana. See “Item 8.
Financial Statements and Supplementary Data—Note 3—Acquisitions and Divestitures” for discussion of potential
pre-emption impact.
Domestic Supply Requirements
Many of our petroleum contracts or, in some cases, the applicable law governing such agreements, grant a right to the
respective host country to purchase certain amounts of oil/gas produced pursuant to such agreements at international market
prices for domestic consumption. In addition, in connection with the approval of the Jubilee Phase 1 PoD, the Jubilee Field
partners agreed to provide the first 200 Bcf of natural gas produced from the Jubilee Field Phase 1 development to GNPC at no
cost. As of December 31, 2021, 159 Bcf of the 200 Bcf of natural gas has been provided.
Significant License Agreements
Below is a discussion concerning the petroleum contracts governing our current drilling and production operations.
Ghana West Cape Three Points Block
As a result of the approval of the GJFFDP by the Ghana Ministry of Energy in 2017, operatorship for the West Cape
Three Points Block, including the Mahogany and Teak discoveries, transferred to Tullow in February 2018 and are now
included in the Jubilee Unit. Kosmos is required to pay to the government of Ghana a fixed royalty of 5% and a potential
sliding‑scale royalty (“additional oil entitlement”), which comes into effect and escalates as the nominal project rate of return
increases above a certain threshold. These royalties are to be paid in‑kind or, at the election of the government of Ghana, in
cash. A corporate tax rate of 35% is applied to profits at a country level.
The WCTP petroleum contract has a duration of 30 years from its effective date (July 2004). In July 2011, at the end
of the seven‑year Exploration Period, parts of the WCTP Block on which we had not declared a discovery area, were not in a
development and production area, or were not in the Jubilee Unit, were relinquished (“WCTP Relinquishment Area”). We
maintain rights to the Akasa discovery within the WCTP Block as the WCTP petroleum contract remains in effect after the end
of the Exploration Period. We and our WCTP Block partners have certain rights to negotiate a new petroleum contract with
respect to certain portions of the WCTP Relinquishment Area. We and our WCTP Block partners, the Ghana Ministry of
Energy and GNPC have agreed such WCTP petroleum contract rights to negotiate extend from July 21, 2011 until such time as
27
either a new petroleum contract is negotiated and entered into with us or we decline to match a bona fide third-party offer
GNPC may receive for the WCTP Relinquishment Area.
Ghana Deepwater Tano Block
Tullow is the operator of the Deepwater Tano Block. Under the DT petroleum contract, GNPC exercised its option to
acquire an additional paying interest of 5% in the commercial discovery with respect to the Jubilee Field development and the
TEN Fields development. Kosmos is required to pay to the government of Ghana a fixed royalty of 5% and a potential
additional oil entitlement, which comes into effect and escalates as the nominal project rate of return increases above a certain
threshold. These royalties are to be paid in‑kind or, at the election of the government of Ghana, in cash. A corporate tax rate of
35% is applied to profits at a country level.
The DT petroleum contract has a duration of 30 years from its effective date (July 2006). In 2013, at the end of the
seven‑year Exploration Period, parts of the DT Block on which we had not declared a discovery area, were not in a
development and production area, or were not in the Jubilee Unit, were relinquished (“DT Relinquishment Area”). Our existing
Wawa discovery within the DT Block was not subject to relinquishment upon expiration of the Exploration Period of the DT
petroleum contract, as the DT petroleum contract remains in effect after the end of the Exploration Period while commerciality
is being determined. Pursuant to our DT petroleum contract, we and our DT Block partners have certain rights to negotiate a
new petroleum contract with respect to certain portions of the DT Relinquishment Area until such time as either a new
petroleum contract is negotiated and entered into with us or we decline to match a bona fide third-party offer GNPC may
receive for the DT Relinquishment Area.
The Ghanaian Petroleum Exploration and Production Law of 1984 (PNDCL 84) (the “1984 Ghanaian Petroleum
Law”) and the WCTP and DT petroleum contracts form the basis of our exploration, development and production operations on
the WCTP and DT blocks. Pursuant to these petroleum contracts, most significant decisions, including PoDs and annual work
programs, for operations other than exploration and appraisal, must be approved by a joint management committee, consisting
of representatives of certain block partners and GNPC. Certain decisions require unanimity.
Ghana Jubilee Field Unitization
The Jubilee Field, discovered by the Mahogany‑1 well in June 2007, covers an area within both the WCTP and DT
Blocks. To optimize resource recovery in the Jubilee Field, it was unitized and the Jubilee UUOA was agreed to in 2009 which
governs each party’s respective rights and duties in the Jubilee Unit and named Tullow as the Unit Operator. Although the
Jubilee Field is unitized, Kosmos’ participating interests in each block outside the boundary of the Jubilee Unit are not impacted
by the Jubilee UUOA. Currently, the WCTP petroleum contract has a 54.367% participating interest in the Jubilee Unit and the
DT petroleum contract has a 45.633% participating interest in the Jubilee Unit. Our participating interest in the Jubilee Unit is
based on these allocations and any event of redetermination in the future would impact Jubilee Unit participating interest.
Greater Tortue Ahmeyim Unitization
The Greater Tortue Ahmeyim Field, discovered by the Tortue‑1 well in May 2015, in Mauritania block C8 and by the
Guembuel-1 well in January 2016, in the Saint-Louis Offshore Profond Block in Senegal covers an area within both the C8 and
Saint-Louis Offshore Profond Blocks. Mauritania and Senegal agreed that the Greater Tortue Ahmeyim Field would be unitized
for optimal resource recovery in the Inter-State Cooperation Agreement (ICA) signed in February 2018. The GTA UUOA was
agreed between the contractor groups of the C8 and Saint-Louis Offshore Profond Blocks and approved by the appropriate
Ministers in Mauritania and Senegal in February 2019. BP Mauritania and BP Senegal are co-Unit Operator and will allocate
responsibilities for the initial development of the Greater Tortue Ahmeyim Field. During the second quarter of 2019, SMH and
PETROSEN elected to increase their respective interest in their portion of the Greater Tortue Ahmeyim Unit to the maximum
allowed percentages under the respective petroleum contracts. After the election, our interest in the exploration areas of Block
C8 offshore Mauritania and in Saint Louis Offshore Profound offshore Senegal are unchanged, however, our interest in the
Greater Tortue Ahmeyim Unit is now 26.7% and is subject to redetermination of the participating interests pursuant to the terms
of the GTA UUOA. In February 2019, Mauritania and Senegal each issued an exploitation authorization for the Greater Tortue
Ahmeyim Unit area covered by the GTA UUOA.
Mauritania Agreements
Effective June 2012, we entered into three petroleum contracts covering offshore Mauritania Blocks C8, C12 and C13
with the Islamic Republic of Mauritania. The Mauritanian national oil company, SMH, currently has a 10% carried interest
during the exploration period only. Should a commercial discovery be made, SMH’s 10% carried interest is extinguished and
28
SMH will have an option to obtain a participating interest between 10% and 14%. SMH will pay its portion of development and
production costs in a commercial development. Cost recovery oil is apportioned to the contractor from up to 55% (62% for gas)
of total production prior to profit oil being split between the government of Mauritania and the contractor. Profit oil is then
apportioned based upon “R‑factor” tranches, where the R‑factor is cumulative net revenues divided by the cumulative
investment. At the election of the government of Mauritania, the government may receive its share of production in cash or in
kind. A corporate tax rate of 27% is applied to profits at the license level. The terms of exploration periods of these Offshore
Blocks are all ten years and initially included a first exploration period of four years followed by the second exploration period
of three years and the third exploration period of three years. Kosmos is currently in the third exploration period for Blocks C8
and C12, expiring in June 2022. In 2021, at the conclusion of the second exploration period, Block C13 offshore Mauritania
was relinquished.
Senegal Agreements
In June 2018, we entered the final renewal of the exploration period for the Senegal Cayar Offshore Profond and Saint
Louis Offshore Profond Blocks. In July 2021, the term of the Cayar Offshore Profound license was extended for up to an
additional three years, ending in July 2024. In the event of commercial success, we have the right to develop and produce oil
and/or gas for a period of 25 years from the grant of an exploitation authorization from the government, which may be extended
on two separate occasions for a period of 10 years each under certain circumstances. The exploration period of the St. Louis
Offshore Profound license expired in July 2021.
Equatorial Guinea Exploration Agreements
In March 2018, we entered into petroleum contracts covering Blocks EG-21, S, and W with the Republic of Equatorial
Guinea. The Equatorial Guinean national oil company, GEPetrol, currently has a 20% carried participating interest during the
exploration period. Should a commercial discovery be made, GEPetrol's 20% carried interest will convert to a 20%
participating interest. The petroleum contracts cover approximately 6,000 square kilometers, with a first exploration sub-period
ending in March 2021. In August 2020, an extension was granted extending the first exploration sub-period ending to
December 2022.
In the first quarter of 2019, we became operator of Block EG-24 offshore Equatorial Guinea. GEPetrol, currently has
a 20% carried interest during the exploration period. In March 2020, we entered the first extension period ending in March
2021. In August 2020, an extension was granted extending the first extension period to December 2022. The petroleum contract
cover covers approximately 3,500 square kilometers. Should a commercial discovery be made, GEPetrol's 20% carried interest
will convert to a 20% participating interest for all development and production operations.
Sales and Marketing
As provided under the Jubilee UUOA and the WCTP and DT petroleum contracts, we are entitled to lift and sell our
share of the Jubilee and TEN production as are the other Jubilee Unit and TEN partners. Over the years, we have entered into
agreements with multiple oil marketing agents to market our share of the Jubilee and TEN fields oil, and we approve the terms
of each sale proposed by such agent. We currently have crude oil marketing sales agreements over the Jubilee and TEN fields
extending approximately three years.
In December 2017, we signed the TAG GSA and we began exporting TEN associated gas to shore in the fourth quarter
of 2018. The TAG GSA provides for an inflation-adjusted sales price of $0.50 per MMBtu.
In Equatorial Guinea, as provided under the petroleum contract for Block G, we are entitled to lift and sell our share of
the Ceiba Field production as are the other Ceiba Field partners. We have entered into an agreement with an oil marketing agent
to market our share of the Ceiba Field oil, and we approve the terms of each sale proposed by such agent.
In the U.S. Gulf of Mexico, we sell crude oil to purchasers typically through monthly contracts, with the sale taking
place at multiple points offshore, depending on the particular property. Natural gas is sold to purchasers through monthly
contracts, with the sale taking place either offshore or at an onshore gas processing plant after the removal of NGLs. We
actively market our crude oil and natural gas to purchasers, and sales prices for purchased oil and natural gas volumes are
negotiated with purchasers and are based on certain published indices. Since most of the oil and natural gas contracts are
generally month-to-month, there are very few dedications of production to any one purchaser. We sell the NGLs entrained in
the natural gas that we produce. The arrangements to sell these products first requires natural gas to be processed at an onshore
gas processing plant. Once the liquids are removed and fractionated (separated into the individual hydrocarbon chains for sale),
the products are sold by the processing plant. The residue gas left over is sold to natural gas purchasers as natural gas sales
29
(referenced above). The contracts for NGL sales are with the processing plant. The prices received for the NGLs are either tied
to indices or are based on what the processing plant can receive from a third-party purchaser. The gas processing and
subsequent sales of NGLs are subject to contracts with longer terms and dedications of life of lease production from the
Company’s leases offshore.
There are a variety of factors which affect the market for oil, including the proximity and capacity of transportation
facilities, demand for oil both within the local market and beyond, the marketing of competitive fuels and the effects of
government regulations on oil production and sales. 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 further 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.
In February 2020, we, along with the co-venturers in the Greater Tortue Ahmeyim Field signed the Tortue Phase 1
SPA with BP Gas Marketing Limited to sell LNG free on board (FOB) from the Greater Tortue Ahmeyim Field located
offshore Mauritania and Senegal. The annual contract quantity under the Tortue Phase 1 SPA is 127,951,000 MMBtu (the
“ACQ”) which is equivalent to approximately 2.45 million tonnes per annum, subject to limited downward adjustment by the
sellers. The sales price for LNG under the Tortue Phase 1 SPA is set as a percentage of a crude oil price benchmark for the
ACQ volumes (the “ACQ Sales Price”). The Tortue Phase 1 SPA has an initial term of up to twenty years that commences on
the “Commercial Operations Date”, which occurs after completion of certain LNG project facilities’ performance tests.
Competition
The oil and gas industry is competitive. We encounter strong competition from other independent operators and from
major oil companies in acquiring licenses and leases. Many of these competitors have financial and technical resources and staff
that are substantially larger than ours. As a result, our competitors may be able to pay more for desirable oil and natural gas
assets, or to evaluate, bid for and purchase a greater number of licenses and leases than our financial or personnel resources will
permit. Furthermore, these companies may also be better able to withstand the financial pressures of lower commodity prices,
unsuccessful wells, volatility in financial markets and generally adverse global and industry‑wide economic conditions. These
companies may also be better able to absorb the burdens resulting from changes in relevant laws and regulations, which may
adversely affect our competitive position.
Historically, we have also been affected by competition for drilling rigs and the availability of related equipment.
Higher commodity prices generally increase the demand for drilling rigs, supplies, services, equipment and crews. Shortages of,
or increasing costs for, experienced drilling crews and equipment and services may restrict our ability to drill wells and conduct
our operations.
The oil and gas industry as a whole has experienced continued volatility. Globally, the impact of COVID-19 has
impacted demand for oil, which also resulted in significant variations in oil prices. Dated Brent crude, the benchmark for our
international oil sales, ranged from approximately $50 to $86 per barrel during 2021. HLS crude, the benchmark for our U.S.
Gulf of Mexico oil sales, which generally trades at a discount to Dated Brent, ranged from approximately $50 to $84 during
2021. Excluding the impact of hedges, our realized price for 2021 was $70.10 per barrel.
Title to Property
We believe that we have satisfactory title to our oil and natural gas assets in accordance with standards generally
accepted in the international oil and gas industry. Our licenses and leases are subject to customary royalty and other interests,
liens under operating agreements and other burdens, restrictions and encumbrances customary in the oil and gas industry that
we believe do not materially interfere with the use of, or affect the carrying value of, our interests.
Environmental Matters
General
We are subject to various stringent and complex international, foreign, federal, state and local environmental, health
and safety laws and regulations governing matters including the emission and discharge of pollutants into the ground, air or
30
water; the generation, storage, handling, use and transportation of regulated materials; and the health and safety of our
employees. These laws and regulations may, among other things:
•
•
•
•
•
•
require the acquisition of various permits before operations commence or for operations to continue;
enjoin some or all of the operations or facilities deemed not in compliance with permits;
restrict the types, quantities and concentration of various substances that can be released into the environment in
connection with oil and natural gas drilling, production and transportation activities;
limit, cap, tax or otherwise restrict emissions of GHG and other air pollutants or otherwise seek to address or
minimize the effects of climate change;
limit or prohibit drilling activities in certain locations lying within protected or otherwise sensitive areas; and
require measures to mitigate or remediate pollution, including pollution resulting from our block partners’ or our
contractors’ operations.
These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would
otherwise be possible. Compliance with these laws can be costly; the regulatory burden on the oil and natural gas industry
increases the cost of doing business in the industry and consequently affects profitability. We are committed to continued
compliance with all environmental laws and regulations applicable to our operations in all countries in which we do business.
We have established policies, operating procedures and training programs designed to limit the environmental impact of our
operations and to identify and comply with changes in existing laws and regulations, however the cost of compliance with more
stringent laws and regulations in the future could have a material adverse effect on our financial condition and results of
operations.
Moreover, public interest in the protection of the environment continues to increase. Offshore drilling in some areas
has been opposed by environmental groups and, in other areas, has been restricted. Our operations could be adversely affected
to the extent laws or regulations are enacted or other governmental action is taken that prohibits or restricts offshore drilling or
imposes environmental requirements that increase costs to the oil and gas industry in general, such as more stringent or costly
waste handling, disposal or cleanup requirements or financial responsibility and assurance requirements.
Per common industry practice, under agreements governing the terms of use of the drilling rigs contracted by us or our
block or lease partners, the drilling rig contractors typically indemnify us and our block partners in respect of pollution and
environmental damage originating above the surface of the water and from such drilling rig contractor’s property, including
their drilling rig and other related equipment. Furthermore, pursuant to the terms of the operating agreements for our blocks and
leases, except in certain circumstances, each block or lease partner is responsible for its share of liabilities in proportion to its
participating interest incurred as a result of pollution and environmental damage, containment and clean‑up activities, loss or
damage to any well, loss of oil or natural gas resulting from a blowout, crater, fire, or uncontrolled well, loss of stored oil and
natural gas, as well as for plugging or bringing under control any well. We maintain insurance coverage typical of the industry
in the areas we operate in; these include property damage insurance, loss of production insurance, wreck removal insurance,
control of well insurance, general liability including pollution liability to cover pollution from wells and other operations. We
also participate in an insurance coverage program for the FPSOs which we own. We believe our insurance is carried in amounts
typical for the industry relative to our size and operations and in accordance with our contractual and regulatory obligations.
Capping and Containment (Excluding the U.S. Gulf of Mexico)
We entered into an agreement with a third-party service provider for it to supply subsea capping and containment
equipment on a global basis (excluding the U.S. Gulf of Mexico). The equipment includes capping stacks, debris removal,
subsea dispersant and auxiliary equipment. The equipment meets industry accepted standards and can be deployed by air cargo
and other conventional means to suit multiple application scenarios. We also developed an emergency response plan and
response organization to prepare and demonstrate our readiness to respond to a subsea well control incident. Capping and
containment for the U.S. Gulf of Mexico is detailed in the U.S. Gulf of Mexico (Operated and Non-operated) section below.
31
Oil Spill Response
To complement our agreement discussed above for subsea capping and containment equipment, we became a charter
member of the Global Dispersant Stockpile (“GSD”). The dispersant stockpile, which is managed by Oil Spill Response
Limited (“OSRL”) of Southampton, England, an oil spill response contractor, consists of 5,000 cubic meters of dispersant
strategically located at OSRL bases around the world. The total volume of the stockpile located at the OSRL bases is calculated
to provide members with the ability to respond to a major spill incident. Dispersant from the GSD can be used in the U.S. Gulf
of Mexico.
Mauritania and Senegal (Non-operated)
Kosmos transferred operatorship of Mauritania and Senegal operations to BP at the beginning of 2018 and was not the
operator for any operations during 2021.
Ghana (Non-operated)
Tullow, our partner and the operator of the Jubilee Unit and the TEN fields, maintains Oil Spill Contingency Plans
(“OSCP”) covering the Jubilee Field and Deepwater Tano Block. Under the OSCPs, emergency response teams may be
activated to respond to oil spill incidents. Tullow has access to OSRL’s oil spill response services comprising technical
expertise and assistance, including access to response equipment and dispersant spraying systems. Tullow maintains lease
agreements with OSRL for Tier 1 and Tier 2 packages of oil spill response equipment.
Equatorial Guinea (Operated and Non-operated)
Effective January 1, 2019, Trident became operator of the Ceiba Field and Okume Complex. In addition, Kosmos has
joined the Equatorial Guinea Oil and Gas Operators Emergency Resource Allocation Agreement to share equipment with other
in country operators in case of emergency. Our membership in OSRL provides access to Tier II and III equipment located in
Accra, Ghana and Southampton, England, UK.
U.S. Gulf of Mexico (Operated and Non-operated)
After the major well control incident and oil release in the U.S. Gulf of Mexico in 2010, the U.S. Department of
Interior updated regulations which govern the type, amount and capabilities of response equipment that needs to be available to
operators to respond to similar incidents. These regulations also dictate the type and frequency of training that operating
personnel need to receive and demonstrate proficiency in. Kosmos also has an Oil Spill Response Plan (“OSRP”) which is
approved by the Bureau of Safety and Environmental Enforcement (“BSEE”). This OSRP would be activated if needed in the
event of an oil spill or containment event in the U.S. Gulf of Mexico. Kosmos joined several cooperatives that were established
to meet the requirements of the new regulations. For capping and containment, Kosmos joined the Helix Well Containment
Group (“HWCG”) consortium whose capabilities include; (i) two dual ram capping stacks rated at 15,000 psi and 10,000 psi
respectively, (ii) intervention equipment to cap and contain a well with the mechanical and structural integrity to be shut in at
depths up to 10,000 feet, and (iii) the ability to capture and process 130,000 barrels of fluid per day and 220 Mcf of gas per day.
Kosmos is also a member of the Clean Gulf Associate (“CGA”) Oil Spill Cooperative, which provides oil spill response
capabilities to meet regulatory requirements. Equipment and services include a High Volume Open Sea Skimming System
(“HOSS”), dedicated oil spill response vessels strategically positioned along the U.S. gulf coast, dispersant and dispersant
delivery systems, various types of spill response booms and mobile wildlife rehabilitation equipment. Due to federal
regulations, all of the HWCG and CGA equipment is dedicated to U.S. operations and cannot be utilized outside the country.
Human Capital Resources
Health and Safety
The health and safety of our employees and those that work with us is a priority for Kosmos. Employees and
contractors are expected to take all necessary and reasonable actions to ensure safe operations by following safe work practices,
complying with relevant policies and regulations, and completing all applicable training. To support our dedication to health,
safety and the environment, we have a comprehensive Health, Safety, Environment and Security (“HSES”) management system
that applies to all Kosmos employees and contractors known as “The Standard.” In addition to adoption of The Standard,
Kosmos fosters a strong safety culture through online and in person training, regular emergency response drills, and impactful
safety discussions.
32
With the ongoing COVID-19 pandemic, the health of our employees and contractors continued to be a priority for
2021 including the establishment of a COVID-19 vaccination and testing policy, facilitating remote working flexibility for
employees normally based in the office, and safeguarding operations offshore through a variety of enhanced operational
safeguards and monitoring measures, including strict pre-embarkation quarantine procedures, wellness screenings, and
COVID-19 testing.
Culture, Engagement and Development
Kosmos aims to be a world-class company known for delivering results and being a workplace of choice. We pride
ourselves on our ability to provide employees with careers that are professionally challenging, personally rewarding, and
focused on delivering value. We aim to provide a stimulating and rewarding work environment through an inclusive culture that
promotes entrepreneurial thinking, facilitates teamwork, and embraces ethical behavior.
Kosmos is committed to investing in the development of our employees. We support development through a blend of
learning approaches including in-person and virtual training opportunities, on-the-job training, conferences, cross team projects
and experiences and our leadership development program. Each year, all employees also have an opportunity to provide
feedback on the employee experience and Kosmos culture through our annual employee opinion survey. In 2021, Kosmos
achieved top quartile performance relative to peer companies. The feedback received through this annual survey is used to
support continuous improvement and enhance the overall employee experience. In 2021, Kosmos had a retention rate greater
than 93%.
Diversity and Inclusion
Kosmos focuses on recruiting, retaining, and developing a diverse and inclusive workforce that embraces our values
and culture. We seek to promote diversity in our workforce both because it is the right thing to do and because it gives us access
to the widest range of talents. Through social and educational events that address the different backgrounds and identities of
employees, Kosmos helps foster a spirit of inclusion across the company. We promote and celebrate the array of diverse
perspectives and experiences of Kosmos employees and applicants, whether in terms of race, ethnicity, sex, gender, sexual
orientation, gender expression, religion, national origin, disability, or experiences.
We seek to employ qualified individuals from the countries in which we operate and are proud of our record of
recruitment and retention of local staff. This year we maintained 100% local employees across all our host country offices.
As of December 31, 2021, we had 229 employees with 199 being based in the United States and 30 residing in our
local offices. Our workforce was approximately 38% gender diverse and approximately 33% minority.
Employee Well-being
Kosmos offers employees a robust range of benefits, including health plans, equity opportunities, savings plans, short-
and long-term incentives. All domestic employees are awarded equity in the company as part of the total reward package,
aligning employee reward with shareholder interest. Our benefits package prioritizes emotional, physical, and financial health
and wellness. We also offer a strong Employee Assistance Program (EAP), which offers free and confidential assessments,
counseling, and follow-up services to employees with personal and/or work-related mental health problems.
These benefits are intended to both promote the long-term health and well-being of our employees and increase
employee engagement and retention. Additionally, we believe that these benefits help facilitate a strong work-life balance and a
culture that prioritizes overall employee wellness.
Corporate Information
In December 2018, Kosmos Energy Ltd. changed our jurisdiction of incorporation from Bermuda to the State of
Delaware, USA. We maintain a registered office in Delaware at Corporation Trust Center, 1209 Orange Street, Wilmington,
Delaware 19801. Our executive offices are maintained at 8176 Park Lane, Suite 500, Dallas, Texas 75231, and its telephone
number is +1 (214) 445 9600.
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Available Information
Kosmos is listed on the NYSE and LSE and our common stock is traded under the symbol KOS. We file or furnish
annual, quarterly and current reports, proxy statements and other information with the SEC as well as the London Stock
Exchange's Regulatory News Service (“LSE RNS”). The SEC maintains a website at http://www.sec.gov that contains
documents we file electronically with the SEC. The LSE RNS maintains a website at http://www.londonstockexchange.com
that contains documents we file electronically with the LSE RNS.
The Company also maintains an internet website under the name www.kosmosenergy.com. The information on our
website is not incorporated by reference into this annual report on Form 10‑K and should not be considered a part of this annual
report on Form 10‑K. Our website is included as an inactive technical reference only. We make available, free of charge, on our
website, our annual report on Form 10‑K, quarterly reports on Form 10‑Q, current reports on Form 8‑K and, if applicable,
amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably practicable
after such reports are electronically filed with, or furnished to, the SEC.
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Item 1A. Risk Factors
You should consider and read carefully all of the risks and uncertainties described below, together with all of the other
information contained in this report, including the consolidated financial statements and the related notes included in “Item 8.
Financial Statements and Supplementary Data.” If any of the following risks actually occurs, our business, business prospects,
financial condition, results of operations or cash flows could be materially adversely affected. The risks below are not the only
ones we face. Additional risks not currently known to us or that we currently deem immaterial may also adversely affect us.
Summary Risk Factors
Our business is subject to a number of risks, including risks that may prevent us from achieving our business
objectives or may adversely affect our business, financial condition, results of operations, cash flows, and prospects. These risks
are discussed more fully below and include, but are not limited to, risks related to:
Our Oil and Natural Gas Operations
• We have limited proved reserves;
• We face substantial uncertainties in estimating the characteristics of our discoveries and our prospects;
• Drilling wells is speculative and may not result in any discoveries;
• Development wells may not result in commercially productive quantities of oil and gas reserves;
• Our identified drilling and infrastructure locations are scheduled out over time, making them susceptible to
uncertainties;
• We are contractually obligated to drill wells and declare any discoveries in order to retain exploration and production
•
•
rights;
Inability of third parties who contract with us to meet their obligations may adversely affect our financial results;
The unit partners’ respective interests in the Jubilee Unit and Greater Tortue Ahmeyim Unit are subject to
redetermination;
• We are not the operator on all of our license areas and facilities and do not hold all of the working interests in certain
of our license areas;
• Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate;
•
The present value of future net revenues from our proved reserves will not necessarily be the same as the current
market value of our estimated oil and natural gas reserves;
• We may not be able to commercialize our interests in any natural gas produced from our license areas;
• Our inability to access appropriate equipment and infrastructure in a timely manner may hinder our access to oil and
natural gas markets or delay our oil and natural gas production;
• We are subject to numerous risks inherent to the exploration and production of oil and natural gas;
• We are subject to drilling and other operational and environmental risks and hazards;
• Our operations may be materially adversely affected by weather-related events including tropical storms and
hurricanes;
The development schedule of oil and natural gas projects is subject to delays and cost overruns;
•
• Our offshore and deepwater operations involve special risks that could adversely affect our results of operations;
• We have had disagreements with host governments regarding certain of our rights and responsibilities and may have
•
•
future disagreements with our host governments;
The geographic locations of our licenses in Africa and the U.S. Gulf of Mexico subject us to a risk of loss of revenue
or curtailment of production from factors specifically affecting those areas;
The COVID-19 pandemic and outbreaks of other diseases may adversely affect our business operations and financial
condition;
Our Business and Financial Condition
• A substantial or extended decline in oil and natural gas prices may adversely affect our business, financial condition
and results of operations;
• Our business plan requires substantial additional capital;
• We may be required to take write‑downs of the carrying values of our oil and natural gas assets as a result of decreases
in oil and natural gas prices;
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• We face various risks associated with increased activism against, or change in public sentiment for, oil and gas
exploration, development, and production activities and ESG considerations including climate change and the
transition to a lower carbon economy;
• Deterioration in the credit or equity markets could adversely affect us;
• We may incur substantial losses and become subject to liability claims as a result of future oil and natural gas
operations, for which we may not have adequate insurance coverage;
•
Slower global economic growth rates may materially adversely impact our operating results and financial position;
•
Increased costs and availability of capital could adversely affect our business;
• Our derivative activities could result in financial losses or could reduce our income;
• Our commercial debt facility, revolving credit facility, indentures governing our Senior Notes and GoM Term Loan
contain certain covenants that may inhibit our ability to make certain investments, incur additional indebtedness and
engage in certain other transactions;
Provisions of our Senior Notes could discourage an acquisition of us by a third-party;
•
• Our level of indebtedness may increase and thereby reduce our financial flexibility;
• We are a holding company and our ability to make payments on our outstanding indebtedness is dependent upon the
receipt of funds from our subsidiaries;
• We may be subject to risks in connection with acquisitions and the integration of significant acquisitions may be
•
difficult;
If we fail to realize the anticipated benefits of a significant acquisition, our results of operations may be adversely
affected;
• A cyber incident, including a breach of digital security, could result in information theft, data corruption, operational
disruption, and/or financial loss;
• Our ability to utilize net operating loss carryforwards may be subject to certain limitations;
•
Changes in the method of determining LIBOR, or the replacement of LIBOR with an alternative reference rate, may
adversely affect interest expense related to outstanding debt;
Regulation
• Our business, operations and financial condition may be directly and indirectly adversely affected by political,
economic, and environmental circumstances;
• More comprehensive and stringent regulation in the U.S. Gulf of Mexico has materially increased costs and delays in
•
•
offshore oil and natural gas exploration and production operations;
The oil and gas industry is intensely competitive and many of our competitors possess and employ substantially greater
resources than us;
Participants in the oil and gas industry are subject to numerous laws, regulations, and other legislative instruments that
can affect the cost, manner or feasibility of doing business;
• We are subject to numerous health, safety and environmental laws and regulations which may result in material
liabilities and costs;
• We may be exposed to assertions concerning or liabilities under anti‑corruption laws;
•
Federal regulatory law could have an adverse effect on our ability to use derivative instruments;
General Matters
• We are dependent on certain members of our management and technical team;
• We operate in a litigious environment;
• We face various risks associated with global populism;
• Our share price may be volatile, and purchasers of our common stock could incur substantial losses;
• A substantial portion of our total issued and outstanding common stock may be sold into the market at any time; and
•
Holders of our common stock will be diluted if additional shares are issued.
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Risks Relating to our Oil and Natural Gas Operations
We have limited proved reserves and areas that we decide to drill may not yield oil and natural gas in commercial quantities
or quality, or at all.
We have limited proved reserves. A portion of our oil and natural gas assets consists of discoveries without approved
PoDs and with limited well penetrations, as well as identified yet unproven prospects based on available seismic and geological
information that indicates the potential presence of hydrocarbons. However, the areas we decide to drill may not yield oil or
natural gas in commercial quantities or quality, or at all. Many of our current discoveries and all of our prospects are in various
stages of evaluation that will require substantial additional analysis and interpretation. Even when properly used and
interpreted, 2D and 3D seismic data and visualization techniques are only tools used to assist geoscientists in identifying
subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact,
present in those structures. Accordingly, we do not know if any of our discoveries or prospects will contain oil or natural gas in
sufficient quantities or quality to recover drilling and completion costs or to be economically viable. Even if oil or natural gas is
found on our discoveries or prospects in commercial quantities, construction costs of gathering lines, subsea infrastructure,
other production facilities and floating production systems and transportation costs may prevent such discoveries or prospects
from being economically viable, and approval of PoDs by various regulatory authorities, a necessary step in order to develop a
commercial discovery, may not be forthcoming. Additionally, the analogies drawn by us using available data from other wells,
more fully explored discoveries or producing fields may not prove valid with respect to our drilling prospects. We may
terminate our drilling program for a discovery or prospect if data, information, studies and previous reports indicate that the
possible development of a discovery or prospect is not commercially viable and, therefore, does not merit further investment. If
a significant number of our discoveries or prospects do not prove to be successful, our business, financial condition and results
of operations will be materially adversely affected.
The deepwater offshore Mauritania and Senegal, an area in which we currently focus a substantial amount of our
development efforts, has only recently been considered economically viable for hydrocarbon production due to the costs and
difficulties involved in drilling and development at such depths and the relatively recent discovery of commercial quantities of
hydrocarbons in the region. Likewise, our deepwater offshore Sao Tome and Principe license has not yet proved to be an
economically viable production area. We have limited proved reserves, and we may not be successful in developing additional
commercially viable production from our other discoveries and prospects.
We face substantial uncertainties in estimating the characteristics of our discoveries and our prospects.
In this report we provide numerical and other measures of the characteristics of our discoveries and prospects. These
measures may be incorrect, as the accuracy of these measures is a function of available data, geological interpretation and
judgment. To date, a limited number of our prospects have been drilled. Any analogies drawn by us from other wells,
discoveries or producing fields may not prove to be accurate indicators of the success of developing proved reserves from our
discoveries and prospects. Furthermore, we have no way of evaluating the accuracy of the data from analog wells or prospects
produced by other parties which we may use.
It is possible that few or none of our wells to be drilled will find accumulations of hydrocarbons in commercial quality
or quantity. Any significant variance between actual results and our assumptions could materially affect the quantities of
hydrocarbons attributable to any particular prospect.
Drilling wells is speculative, often involving significant costs that may be more than we estimate, and may not result in any
discoveries or additions to our future production or reserves. Any material inaccuracies in drilling costs, estimates or
underlying assumptions will materially affect our business.
Exploring for and developing hydrocarbon reserves involves a high degree of technical, operational and financial risk,
which precludes definitive statements as to the time required and costs involved in reaching certain objectives. The budgeted
costs of planning, drilling, completing and operating wells are often exceeded and can increase significantly when drilling costs
rise due to a tightening in the supply of various types of oilfield equipment and related services or unanticipated geologic
conditions.
Before a well is spud, we incur significant geological and geophysical (seismic) costs, which are incurred whether or
not a well eventually produces commercial quantities of hydrocarbons or is drilled at all. Drilling may be unsuccessful for many
reasons, including geologic conditions, weather, cost overruns, equipment shortages and mechanical difficulties or force
37
majeure events. Exploratory wells bear a much greater risk of failure than development wells. In the past we have experienced
unsuccessful drilling efforts, having drilled dry holes. Furthermore, the successful drilling of a well does not necessarily result
in the commercially viable development of a field or be indicative of the potential for the development of a commercially viable
field. A variety of factors, including geologic and market‑related, can cause a field to become uneconomic or only marginally
economic. A lack of drilling opportunities or projects that cease production may cause us to incur significant costs associated
with an idle rig and/or related services, particularly if we cannot contract out rig slots to other parties. Many of our prospects
that may be developed require significant additional exploration, appraisal and development, regulatory approval and
commitments of resources prior to commercial development. In addition, a successful discovery would require significant
capital expenditure in order to appraise, develop and produce oil and natural gas, even if we deemed such discovery to be
commercially viable. See “—Our business plan requires substantial additional capital, which we may be unable to raise on
acceptable terms or at all in the future, which may in turn limit our ability to develop our exploration, appraisal, development
and production activities.” In the international areas in which we operate, we face higher above‑ground risks necessitating
higher expected returns, the requirement for increased capital expenditures due to a general lack of infrastructure and
underdeveloped oil and gas industries, and increased transportation expenses due to geographic remoteness, which either
require a single well to be exceptionally productive, or the existence of multiple successful wells, to allow for the development
of a commercially viable field. See “—Our operations may be adversely affected by political and economic circumstances in
the countries in which we operate.” Furthermore, if our actual drilling and development costs are significantly more than our
estimated costs, we may not be able to continue our business operations as proposed and could be forced to modify our plan of
operation.
Development drilling may not result in commercially productive quantities of oil and gas reserves.
Our exploration success has provided us with major development projects on which we are moving forward, and any
future exploration discoveries will also require significant development efforts to bring to production. We must successfully
execute our development projects, including development drilling, in order to generate future production and cash flow.
However, development drilling is not always successful and the profitability of development projects may change over time.
For example, in new development projects available data may not allow us to completely know the extent of the
reservoir or choose the best locations for drilling development wells. A development well we drill may be a dry hole or result in
noncommercial quantities of hydrocarbons. All costs of development drilling and other development activities are capitalized,
even if the activities do not result in commercially productive quantities of hydrocarbon reserves. This puts a property at higher
risk for future impairment if commodity prices decrease or operating or development costs increase.
Our identified drilling and infrastructure locations are scheduled out over time, making them susceptible to uncertainties
that could materially alter the occurrence or timing of their drilling or infrastructure installation or modification.
Our management team has identified and scheduled drilling locations and possible infrastructure locations on our
license and lease areas over a multi‑year period. Our ability to drill and develop these locations depends on a number of factors,
including the availability of equipment and capital, approval by block or lease partners and national and state regulators,
seasonal conditions, oil prices, assessment of risks, costs and drilling results. For example, a shutdown of the U.S. federal
government could delay the regulatory review and approval process associated with drilling or developmental activities within
our license areas in the U.S. Gulf of Mexico. The final determination on whether to drill or develop any of these locations will
be dependent upon the factors described elsewhere in this report as well as, to some degree, the results of our drilling and
production activities with respect to our established wells and drilling locations. Because of these uncertainties, we do not know
if the drilling locations we have identified will be drilled or infrastructure installed or modified within our expected timeframe
or at all or if we will be able to economically produce hydrocarbons from these or any other potential drilling locations. As
such, our actual drilling and development activities may be materially different from our current expectations, which could
adversely affect our results of operations and financial condition.
Under the terms of our various petroleum contracts, we are contractually obligated to drill wells and declare any discoveries
in order to retain exploration and production rights. In the competitive market for our license areas, failure to drill these
wells or declare any discoveries may result in substantial license renewal costs or loss of our interests in the undeveloped
parts of our license areas, which may include certain of our prospects or undeveloped discoveries.
In order to protect our exploration and production rights in our license areas, we must meet various drilling and
declaration requirements. In general, unless we make and declare discoveries within certain time periods specified in our
various petroleum contracts and licenses, our interests in the undeveloped parts of our license areas may lapse. Should the
prospects yield discoveries, we cannot assure you that we will not face delays in the appraisal and development of these
prospects or otherwise have to relinquish these prospects. The costs to maintain petroleum contracts over such areas may
38
fluctuate and may increase significantly since the original term, and we may not be able to renew or extend such petroleum
contracts on commercially reasonable terms or at all. Our actual drilling activities may therefore materially differ from our
current expectations, which could adversely affect our business.
Under these petroleum contracts, we have work commitments to perform exploration and other related activities.
Failure to do so may result in our loss of the licenses. As of December 31, 2021, we have an unfulfilled drilling obligation in
one of our Mauritania petroleum contracts. In certain other petroleum contracts, we are in the initial exploration phases, some of
which have certain obligations that have yet to be fulfilled. Over the course of the next several years, we may choose to enter
into the next phase of those petroleum contracts which will likely include firm obligations to drill wells. Failure to execute our
obligations may result in our loss of the licenses.
The Exploration Period of each of the WCTP and DT petroleum contracts has expired. For each of our petroleum
contracts, we cannot assure you that any renewals or extensions will be granted or whether any new agreements will be
available on commercially reasonable terms, or, in some cases, at all. For additional detail regarding the status of our operations
with respect to our various petroleum contracts, please see “Item 1. Business—Operations by Geographic Area.”
The inability of one or more third parties who contract with us to meet their obligations to us may adversely affect our
financial results.
We may be liable for certain costs if third parties who contract with us are unable to meet their commitments under
such agreements. We are currently exposed to credit risk through joint interest receivables from our block and/or unit partners.
If any of our partners in the blocks or unit in which we hold interests are unable to fund their share of the exploration and
development expenses, we may be liable for such costs. In the past, certain of our partners have not paid their share of block
costs in the time frame required by the joint operating agreements for these blocks. This has resulted in such party being in
default, which in return requires Kosmos and its non‑defaulting block partners to pay their proportionate share of the defaulting
party’s costs during the default period. Should a default not be cured, Kosmos could be required to pay its share of the
defaulting party’s costs going forward.
In addition, we contract with third parties to conduct drilling and related services on our development projects and
exploration prospects. Such third parties may not perform the services they provide us on schedule or within budget.
Furthermore, the drilling equipment, facilities and infrastructure owned and operated by the third parties we contract with is
highly complex and subject to malfunction and breakdown. Any malfunctions or breakdowns may be outside our control and
result in delays, which could be substantial. Any delays in our drilling campaign caused by equipment, facility or equipment
malfunction or breakdown could materially increase our costs of drilling and cause an adverse effect on our business, financial
position and results of operations.
Our principal exposure to credit risk will be through receivables resulting from the sale of our oil, which we currently
sell to oil marketing companies, and to cover our commodity derivatives contracts. The inability or failure of our significant
customers or counterparties to meet their obligations to us or their insolvency or liquidation may adversely affect our financial
results. In addition, our oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by
counterparties. Joint interest receivables arise from our block partners. The inability or failure of third parties we contract with
to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. We are unable to
predict sudden changes in creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to
negate the risk may be limited and we could incur significant financial losses.
The unit partners’ respective interests in the Jubilee Unit and Greater Tortue Ahmeyim Unit are subject to redetermination
and our interests in each such unit may decrease as a result.
The interests in and development of the Jubilee Field are governed by the terms of the Jubilee UUOA. The parties to
the Jubilee UUOA, the collective interest holders in each of the WCTP and DT Blocks, initially agreed that interests in the
Jubilee Unit will be shared equally, with each block deemed to contribute 50% of the area of such unit. The respective interests
in the Jubilee Unit were therefore initially determined by the respective interests in such contributed block interests. Pursuant to
the terms of the Jubilee UUOA, the percentage of such contributed interests is subject to a process of redetermination once
sufficient development work has been completed in the unit. The initial redetermination process was completed on October 14,
2011. As a result of the initial redetermination process, the tract participation was determined to be 54.4% for the WCTP Block
and 45.6% for the DT Block. Consequently, our Unit Interest (participating interest in the Jubilee Unit) was increased from
23.5% to 24.1% upon completion of the initial redetermination process. Following the acquisition of Anadarko WCTP
Company, which owned a participating interest in the WCTP Block and DT Block, our Unit Interest (participating interest in
the Jubilee Unit) increased from 24.1% to 42.1%. An additional redetermination could occur sometime if requested by a party
that holds greater than a 10% interest in the Jubilee Unit. We cannot assure you that any redetermination pursuant to the terms
39
of the Jubilee UUOA will not negatively affect our interests in the Jubilee Unit or that such redetermination will be
satisfactorily resolved.
The interests in and development of the Greater Tortue Ahmeyim Field are governed by the terms of the GTA UUOA.
The parties to the GTA UUOA, the collective interest holders in each of the Mauritania Block C8 and Senegal Saint Louis
Offshore Profond blocks, initially agreed that interests in the Greater Tortue Ahmeyim Unit will be shared equally, with each
block deemed to contribute 50% of the area of such unit. The respective interests in the Greater Tortue Ahmeyim Unit were
therefore initially determined by the respective interests in such contributed block interests. Pursuant to the terms of the GTA
UUOA, the percentage of such contributed interests is subject to a process of redetermination once sufficient development work
has been completed in the unit. We cannot assure you that any redetermination pursuant to the terms of the GTA UUOA will
not negatively affect our interests in the Greater Tortue Ahmeyim Unit or that such redetermination will be satisfactorily
resolved.
We are not, and may not be in the future, the operator on all of our license areas and facilities and do not, and may not in
the future, hold all of the working interests in certain of our license areas. Therefore, we have reduced control over the
timing of exploration or development efforts, associated costs, and the rate of production of any non‑operated and to an
extent, any non‑wholly-owned, assets.
As we carry out our exploration and development programs, we have arrangements with respect to existing license
areas and may have agreements with respect to future license areas that result in a greater proportion of our license areas being
operated by others. Currently, we are not the operator of the Jubilee Unit, the TEN fields, Ceiba and Okume, the Greater Tortue
Ahmeyim Unit or certain producing fields in the U.S. Gulf of Mexico and do not hold operatorship in certain other offshore
blocks. As a result, we may have limited ability to exercise influence over the operations of the discoveries or prospects
operated by our block or unit partners, or which are not wholly-owned by us, as the case may be. Dependence on block or unit
partners could prevent us from realizing our target returns for those discoveries or prospects. Further, because we do not have
majority ownership in all of our properties, we may not be able to control the timing, or the scope, of exploration or
development activities or the amount of capital expenditures and, therefore, may not be able to carry out one of our key
business strategies of minimizing the cycle time between discovery and initial production. The success and timing of
exploration and development activities will depend on a number of factors that will be largely outside of our control, including:
•
•
•
•
•
•
•
the timing and amount of capital expenditures;
if the activity is operated by one of our block partners, the operator’s expertise and financial resources;
approval of other block partners in drilling wells;
the scheduling, pre‑design, planning, design and approvals of activities and processes;
selection of technology;
the available capacity of processing facilities and related pipelines; and
the rate of production of reserves, if any.
This limited ability to exercise control over the operations on our license areas may cause a material adverse effect on
our financial condition and results of operations.
Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant
inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of
our reserves.
The process of estimating oil and natural gas reserves is technically complex. It requires interpretations of available
technical data and many assumptions, including those relating to current and future economic conditions and commodity prices.
Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present
value of reserves shown in this report. See “Item 1. Business—Our Reserves” for information about our estimated oil and
natural gas reserves and the present value of our net revenues at a 10% discount rate (“PV‑10”) and Standardized Measure of
discounted future net revenues (as defined herein) as of December 31, 2021.
In order to prepare our estimates, we must project production rates and the timing of development expenditures. We
must also analyze available geological, geophysical, production and engineering data. The process also requires economic
40
assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and
availability of funds.
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses
and quantities of recoverable oil and natural gas reserves will vary from our estimates. Any significant variance could
materially affect the estimated quantities and present value of reserves shown in this report. In addition, we may adjust
estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas
prices and other factors, many of which are beyond our control.
The present value of future net revenues from our proved reserves will not necessarily be the same as the current market
value of our estimated oil and natural gas reserves.
You should not assume that the present value of future net revenues from our proved reserves is the current market
value of our estimated oil and natural gas reserves. In accordance with the SEC requirements, we have based the estimated
discounted future net revenues from our proved reserves on the 12‑month unweighted arithmetic average of the
first‑day‑of‑the‑month price for the preceding twelve months, adjusted for an anticipated market premium, without giving effect
to derivative transactions. Actual future net revenues from our oil and natural gas assets will be affected by factors such as:
•
•
•
•
•
actual prices we receive for oil and natural gas;
actual cost of development and production expenditures;
derivative transactions;
the amount and timing of actual production; and
changes in governmental regulations or taxation.
The timing of both our production and our incurrence of expenses in connection with the development and production
of oil and natural gas assets will affect the timing and amount of actual future net revenues from proved reserves, and thus their
actual present value. In addition, the 10% discount factor we use when calculating discounted future net revenues may not be
the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and
gas industry in general. Actual future prices and costs may differ materially from those used in the present value estimates
included in this report. Oil prices have recently experienced significant volatility. See “Item 1. Business—Our Reserves.”
We may not be able to commercialize our interests in any natural gas produced from our license areas.
The development of the market for natural gas in certain of our international license areas is in its early stages.
Currently the infrastructure to transport and process natural gas on commercial terms is limited and the expenses associated
with constructing such infrastructure ourselves may not be commercially viable given local prices currently paid for natural gas.
Accordingly, there may be limited or no value derived from any natural gas produced from some of our international license
areas.
In Ghana, we currently produce associated gas from the Jubilee and TEN fields. A gas pipeline from the Jubilee Field
has been constructed to transport such natural gas for processing and sale. However, we granted the Government of Ghana the
first 200 Bcf of natural gas exported from the Jubilee Field to shore at zero cost. Through December 31, 2021, the Jubilee
partners have provided approximately 159 Bcf from the Jubilee Field to the Government of Ghana and are currently forecasted
to provide the remaining portion of the first 200 Bcf of natural gas to the Government of Ghana in around one year. The Jubilee
partners are currently in discussions with the Government of Ghana regarding a gas sales agreement for volumes of Jubilee
natural gas beyond the first 200 Bcf. We do not currently book proved gas reserves associated with natural gas sales from the
Jubilee Field in Ghana. However, we expect to book gas reserves upon finalization and execution of a gas sales agreement for
such Jubilee Field natural gas that will have a price associated with it. A gas pipeline from the TEN fields to the Jubilee Field
was completed in 2017 to transport associated natural gas as well as non-associated natural gas for processing and sale. We
finalized the TAG GSA, and as a result, we booked proved gas reserves for the associated natural gas from the TEN fields in
Ghana. If and when a gas sales agreement and the related infrastructure are in place for the TEN fields non-associated gas, a
portion of the remaining gas may be recognized as reserves.
In Mauritania and Senegal, we plan to export the majority of our gas resource to the LNG market. However, that plan
is contingent on making additional final investment decisions on our gas discoveries and constructing the necessary
41
infrastructure to produce, liquefy and transport the gas to the market. Additionally, such plans are contingent upon receipt of
required partner and government approvals.
Our inability to access appropriate equipment and infrastructure in a timely manner may hinder our access to oil
and natural gas markets or delay our oil and natural gas production.
Our ability to market our oil and natural gas production will depend substantially on the availability and capacity of
processing facilities, oil and LNG tankers and other infrastructure, including FPSOs, owned and operated by third parties. Our
failure to obtain such facilities on acceptable terms could materially harm our business. We also rely on continuing access to
drilling rigs suitable for the environment in which we operate. The delivery of drilling rigs may be delayed or cancelled, and we
may not be able to gain continued access to suitable rigs in the future. We may be required to shut in oil and natural gas wells
because of the absence of a market or because access to processing facilities may be limited or unavailable. If that were to
occur, then we would be unable to realize revenue from those wells until arrangements were made to deliver the production to
market, which could cause a material adverse effect on our financial condition and results of operations. In addition, the
shutting in of wells can lead to mechanical problems upon bringing the production back online, potentially resulting in
decreased production and increased remediation costs.
Additionally, the future exploitation and sale of associated and non‑associated natural gas and liquids and LNG will be
subject to timely commercial processing and marketing of these products, which depends on the contracting, financing, building
and operating of infrastructure by third parties. The Government of Ghana completed the construction and connection of a gas
pipeline from the Jubilee Field and the pipeline between the Jubilee and TEN fields to transport such natural gas to the
mainland for processing and sale was completed in 2017. However, the uptime of the pipeline and processing facilities in future
periods is not known. In the absence of the continuous removal of natural gas, it is anticipated that we will either need to flare
such natural gas in order to maintain crude oil production or reduce crude oil production. If we are unable to resolve potential
issues related to the continuous removal of associated natural gas, our oil production will be negatively impacted.
We are subject to numerous risks inherent to the exploration and production of oil and natural gas.
Oil and natural gas exploration and production activities involve many risks that a combination of experience,
knowledge and interpretation may not be able to overcome. Our future will depend on the success of our exploration and
production activities and on the development of an infrastructure that will allow us to take advantage of our discoveries.
Additionally, many of our license areas are located in deepwater, which generally increases the capital and operating costs,
chances of delay, planning time, technical challenges and risks associated with oil and natural gas exploration and production
activities. See “— Our offshore and deepwater operations involve special risks that could adversely affect our results of
operation.” As a result, our oil and natural gas exploration and production activities are subject to numerous risks, including the
risk that drilling will not result in commercially viable oil and natural gas production. Our decisions to purchase, explore or
develop discoveries, prospects or licenses will depend in part on the evaluation of seismic data through geophysical and
geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying
interpretations.
Furthermore, the marketability of expected oil and natural gas production from our discoveries and prospects will also
be affected by numerous factors. These factors include, but are not limited to, market fluctuations of prices (such as recent
significant declines in oil and natural gas prices), proximity, capacity and availability of drilling rigs and related equipment,
qualified personnel and support vessels, processing facilities, transportation vehicles and pipelines, equipment availability,
access to markets and government regulations (including, without limitation, regulations relating to prices, taxes, royalties,
allowable production, domestic supply requirements, importing and exporting of oil and natural gas, the ability to flare or vent
natural gas, health and safety matters, environmental protection and climate change). The effect of these factors, individually or
jointly, may result in us not receiving an adequate return on invested capital.
In the event that our currently undeveloped discoveries and prospects are developed and become operational, they may
not produce oil and natural gas in commercial quantities or at the costs anticipated, and our projects may cease production, in
part or entirely, in certain circumstances. Discoveries may become uneconomic as a result of an increase in operating costs to
produce oil and natural gas. Our actual operating costs and rates of production may differ materially from our current estimates.
Moreover, it is possible that other developments, such as increasingly strict environmental, climate change, and health and
safety laws, regulations and executive orders and enforcement policies thereunder and claims for damages to property or
persons resulting from our operations, could result in substantial costs and liabilities, delays, an inability to complete the
development of our discoveries or the abandonment of such discoveries, which could cause a material adverse effect on our
financial condition and results of operations.
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We are subject to drilling and other operational and environmental risks and hazards.
The oil and natural gas business involves a variety of risks, including, but not limited to:
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fires, blowouts, spills, cratering and explosions;
• mechanical and equipment problems, including unforeseen engineering complications;
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uncontrolled flows or leaks of oil, well fluids, natural gas, brine, toxic gas or other pollutants or hazardous materials;
gas flaring operations;
• marine hazards with respect to offshore operations;
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formations with abnormal pressures;
pollution, environmental risks, and geological problems; and
weather conditions and natural or man‑made disasters.
These risks are particularly acute in deepwater drilling, exploration, and development. Any of these events could result
in loss of human life, significant damage to property, environmental or natural resource damage, impairment, delay or cessation
of our operations, lower production rates, adverse publicity, substantial losses and civil or criminal liability. We expect to
maintain insurance against some, but not all, of these risks and losses. The occurrence of any of these events, whether or not
covered by insurance, could have a material adverse effect on our financial position and results of operations.
Our operations may be materially adversely affected by weather-related events, including tropical storms and hurricanes.
Tropical storms, hurricanes and the threat of tropical storms and hurricanes often result in the shutdown of operations,
particularly in the U.S. Gulf of Mexico, as well as operations within the path and the projected path of the tropical storms or
hurricanes. In addition, climate change could result in an increase in the frequency and severity of tropical storms, hurricanes or
other extreme weather events. Weather events have caused significant disruption to the operations of offshore and coastal
facilities in the U.S. Gulf of Mexico region. In the future, during a shutdown period, we may be unable to access well sites and
our services may be shut down. Additionally, tropical storms or hurricanes may cause evacuation of personnel and damage to
our platforms and other equipment, which may result in suspension of our operations. The shutdowns, related evacuations and
damage can create unpredictability in activity and utilization rates, as well as delays and cost overruns, which could have a
material adverse effect on our business, financial condition and results of operations.
The development schedule of oil and natural gas projects, including the availability and cost of drilling rigs, equipment,
supplies, personnel and oilfield services, is subject to delays and cost overruns.
Historically, some oil and natural gas development projects have experienced delays and capital cost increases and
overruns due to, among other factors, the unavailability or high cost of drilling rigs and other essential equipment, supplies,
personnel and oilfield services, mechanical and technical issues, as well as weather-related delays. The cost to develop our
projects has not been fixed and remains dependent upon a number of factors, including the completion of detailed cost estimates
and final engineering, contracting and procurement costs. Our construction and operation schedules may not proceed as planned
and may experience delays or cost overruns. Any delays may increase the costs of the projects, requiring additional capital, and
such capital may not be available in a timely and cost‑effective fashion.
Our offshore and deepwater operations involve specific risks that could adversely affect our results of operations.
Offshore operations are subject to a variety of operating risks specific to the marine environment, such as capsizing,
sinking, collisions and damage or loss to pipeline, subsea or other facilities or from weather conditions. We could incur
substantial expenses that could reduce or eliminate the funds available for exploration, development or license acquisitions, or
result in loss of equipment and license interests.
Deepwater exploration generally involves greater operational and financial risks than exploration in shallower waters.
Deepwater drilling generally requires more time and more advanced drilling technologies, involving a higher risk of equipment
failure and usually higher drilling costs. In addition, there may be production risks of which we are currently unaware. If we
participate in the development of new subsea infrastructure and use floating production systems to transport oil from producing
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wells, these operations may require substantial time for installation or encounter mechanical difficulties and equipment failures
that could result in loss of production, significant liabilities, cost overruns or delays. For example, we have experienced
mechanical issues in the Jubilee Field, including failures of its gas and water injection facilities on the FPSO, and the turret
bearing issue on the FPSO. The equipment downtime caused by these mechanical issues negatively impacted oil production.
Furthermore, deepwater operations generally, and operations in Africa, in particular, lack the physical and oilfield
service infrastructure present in other regions. As a result, a significant amount of time may elapse between a deepwater
discovery and the marketing of the associated oil and natural gas, increasing both the financial and operational risks involved
with these operations. Because of the lack and high cost of this infrastructure, further discoveries we may make in Africa may
never be economically producible.
In addition, in the event of a well control incident, containment and, potentially, cleanup activities for offshore drilling
are costly. The resulting regulatory costs or penalties, and the results of third-party lawsuits, as well as associated legal and
support expenses, including costs to address negative publicity, could well exceed the actual costs of containment and cleanup.
As a result, a well control incident could result in substantial liabilities, and have a significant negative impact on our earnings,
cash flows, liquidity, financial position, and stock price.
We have had disagreements with host governments regarding certain of our rights and responsibilities and may have future
disagreements with our host governments.
There can be no assurance that future disagreements will not arise with any host government and/or national oil
companies that may have a material adverse effect on our exploration, development or production activities, our ability to
operate, our rights under our licenses and local laws or our rights to monetize our interests.
As an example, multiple discovered fields and a significant portion of our proved reserves are located offshore Ghana.
The WCTP petroleum contract, the DT petroleum contract and the Jubilee UUOA cover the two blocks and the Jubilee and
TEN fields that form the basis of our current operations in Ghana. Pursuant to these petroleum contracts, most significant
decisions, including our plans for development and annual work programs, must be approved by GNPC, the Ghanaian Revenue
Authority (the “GRA”), the Petroleum Commission and/or Ghana’s Ministry of Energy. We have previously had disagreements
with the Ministry of Energy and GNPC regarding certain of our rights and responsibilities under these petroleum contracts, the
1984 Ghanaian Petroleum Law and the Internal Revenue Act, 2000 (Act 592) (the “Ghanaian Tax Law”). These included
disagreements over sharing information with prospective purchasers of our interests, pledging our interests to finance our
development activities, potential liabilities arising from discharges of small quantities of drilling fluids into Ghanaian territorial
waters, the failure to approve the proposed sale of our Ghanaian assets, assertions that could be read to give rise to taxes or
other payments payable under the Ghanaian Tax Law, failure to approve PoDs relating to certain discoveries offshore Ghana
and the relinquishment of certain exploration areas on our licensed blocks offshore Ghana. The resolution of certain of these
disagreements required us to pay agreed settlement costs to GNPC and/or the government of Ghana. In Ghana, as part of its
normal course audit process the GRA has asserted that we have underpaid certain tax and other contractual fiscal obligations.
We believe that these claims are without merit and, if required, we intend to vigorously dispute them, but there can be no
assurance regarding the resolution of this or future disagreements.
The geographic locations of our licenses in Africa and the U.S. Gulf of Mexico subject us to a risk of loss of revenue or
curtailment of production from factors specifically affecting those areas.
A large portion of our current exploration licenses are located in Africa and, following our acquisition of Anadarko
WCTP, a significant proportion of our total production comes from the Jubilee Unit Area and TEN fields offshore Ghana. Some
or all of these licenses could be affected should any region experience any of the following factors (among others):
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severe weather, natural or man‑made disasters or acts of God;
delays or decreases in production, the availability of equipment, facilities, personnel or services;
delays or decreases in the availability of capacity to transport, gather or process production;
• military conflicts, civil unrest or political strife; and/or
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international border disputes.
For example, oil and natural gas operations in our license areas in Africa may be subject to higher political and
security risks than those operations under the sovereignty of the United States. We plan to maintain insurance coverage for only
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a portion of the risks we face from doing business in these regions. There also may be certain risks covered by insurance where
the policy does not reimburse us for all of the costs related to a loss.
Further, as many of our licenses are concentrated in the same geographic area, a number of our licenses could
experience the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they
might have on other companies that have a more diversified portfolio of licenses.
Risks Relating to our Business and Financial Condition
The COVID-19 pandemic has, and outbreaks of other diseases may, adversely affect our business operations and financial
condition.
The global spread of the COVID-19 pandemic, travel restrictions, “shelter-in-place” and various quarantine measures
and other governmental actions taken to inhibit its spread, has created significant volatility, uncertainty and economic
disruption in the markets in which we operate, which has affected our business and operations and those of our suppliers,
contractors and partners. For example, certain contracts necessary for our ongoing exploration, development and production
operations were suspended or terminated as a consequence of the pandemic, and the pandemic has constrained our ability and
the ability of our suppliers, contractors and partners to develop and implement effective plans to explore for oil and gas and to
develop or produce certain of our license areas. The measures taken to combat the pandemic have limited access to qualified
personnel, increased costs associated with ensuring the safety and health of our personnel, restricted the transportation of
personnel, equipment and supplies to and from our areas of operation, and they have diverted the time, attention and resources
of government agencies that are necessary to conduct our operations.
Access to our FPSOs and other production facilities could also be restricted and/or suspended as result of COVID-19.
Our FPSOs and production facilities are able to operate for short periods of time without access to the mainland, but if travel
restrictions are imposed again, we and the operators of the impacted fields could be required to cease production and other
operations until such restrictions were lifted. Any losses we experience as a result of COVID-19 that impact sales or delay
production may not be covered by our insurance policies.
The extent to which our results are affected by COVID-19 will largely depend on future developments that cannot be
accurately predicted. While the full impact of this pandemic is not yet known, we are closely monitoring COVID-19 and
continually assessing its potential effects on our liquidity, capital resources, operations and business and those of the third
parties we rely on. In addition, the adverse effect of the COVID-19 pandemic on our business, results of operations, financial
condition and cash flows may heighten many of the other risks described in the "Risk Factors" section of this report and our
Annual Report on Form 10-K for the fiscal year ended December 31, 2021.
Significant outbreaks of other contagious diseases, and other adverse public health developments, could have a
material impact on our business operations and financial condition. Many of our operations are currently, and will likely remain
in the near future, in developing countries which are susceptible to outbreaks of disease and may lack the resources to
effectively contain such an outbreak quickly. Such outbreaks may impact our ability to explore for oil and gas, develop or
produce our license areas by limiting access to qualified personnel, increasing costs associated with ensuring the safety and
health of our personnel, restricting transportation of personnel, equipment, supplies and oil and gas production to and from our
areas of operation and diverting the time, attention and resources of government agencies which are necessary to conduct our
operations. In addition, any losses we experience as a result of such outbreaks of disease which impact sales or delay production
may not be covered by our insurance policies.
An epidemic of the Ebola virus disease occurred in parts of West Africa in 2014 and continued through 2015. A
substantial number of deaths were reported by the World Health Organization (“WHO”) in West Africa, and the WHO declared
it a global health emergency. It is impossible to predict the effect and potential spread of new outbreaks of the Ebola virus in
West Africa and surrounding areas. Should another Ebola virus outbreak occur, including to the countries in which we operate,
or not be satisfactorily contained, our exploration, development and production plans for our operations could be delayed, or
interrupted after commencement. Any changes to these operations could significantly increase costs of operations. Our
operations require contractors and personnel to travel to and from Africa as well as the unhindered transportation of equipment
and oil and gas production (in the case of our producing fields). Such operations also rely on infrastructure, contractors and
personnel in Africa. If travel bans are implemented or extended to the countries in which we operate, or contractors or
personnel refuse to travel there, we could be adversely affected. If services are obtained, costs associated with those services
could be significantly higher than planned which could have a material adverse effect on our business, results of operations, and
future cash flow. In addition, should an Ebola virus outbreak spread to the countries in which we operate, access to the FPSOs
could be restricted and/or terminated. The FPSOs are potentially able to operate for a short period of time without access to the
45
mainland, but if restrictions extended for a longer period we and the operator of the impacted fields would likely be required to
cease production and other operations until such restrictions were lifted.
These or any further political or governmental developments or health concerns could result in social, economic and
labor instability. These uncertainties could have a material impact on our business operations and financial condition.
A substantial or extended decline in both global and local oil and natural gas prices may adversely affect our business,
financial condition and results of operations.
The prices that we will receive for our oil and natural gas will significantly affect our revenue, profitability, access to
capital and future growth rate. Historically, the oil and natural gas markets have been volatile and will likely continue to be
volatile in the future. Oil prices experienced significant and sustained declines in the past few years and will likely continue to
be volatile in the future. For example, the impact of the ongoing COVID-19 pandemic on demand for oil and natural gas has
resulted in significant variations in oil prices. The prices that we will receive for our production and the levels of our production
depend on numerous factors. These factors include, but are not limited to, the following:
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changes in supply and demand for oil and natural gas;
the actions of the Organization of the Petroleum Exporting Countries;
speculation as to the future price of oil and natural gas and the speculative trading of oil and natural gas futures
contracts;
global economic conditions;
political and economic conditions, including embargoes in oil‑producing countries or affecting other oil‑producing
activities, particularly in the Middle East, Africa, Russia and Central and South America;
the continued threat of terrorism and the impact of military and other action, including U.S. military operations
outside the United States;
the level of global oil and natural gas exploration and production activity;
the level of global oil inventories and oil refining capacities;
weather conditions and natural or man‑made disasters;
technological advances affecting energy consumption;
governmental regulations and taxation policies;
proximity and capacity of transportation facilities;
the development and exploitation of alternative fuels or energy sources;
the price and availability of competitors’ supplies of oil and natural gas; and
the price, availability or mandated use of alternative fuels or energy sources.
Lower oil prices may not only reduce our revenues but also may limit the amount of oil that we can produce
economically. A substantial or extended decline in oil and natural gas prices may materially and adversely affect our future
business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures. Additionally, a
substantial or extended decline in oil and natural gas prices could result in surety companies seeking additional collateral to
support existing surety or performance bonds, such as cash or letters of credit, and we cannot provide assurance that we will be
able to satisfy such collateral demands. If we are required to provide collateral in the form of cash or letters of credit, our
liquidity position could be negatively impacted and we may be required to seek alternative financing. To the extent we are
unable to secure adequate financing or obtain surety or performance bonds on commercially reasonable terms, we may be
forced to reduce our capital expenditures. These factors may make it more difficult for us to obtain the financial assurances
required by the BOEM to conduct operations in the U.S. Gulf of Mexico. These difficulties could result in increased costs on
our operations and consequently have a material adverse effect on our business and results of operations.
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Our business plan requires substantial additional capital, which we may be unable to raise on acceptable terms or at all in
the future, which may in turn limit our ability to develop our exploration, appraisal, development and production activities.
We expect our capital outlays and operating expenditures to be substantial as we expand our operations. Obtaining
seismic data, as well as exploration, appraisal, development and production activities entail considerable costs, and we may
need to raise substantial additional capital through additional debt financing, strategic alliances or future private or public equity
offerings if our cash flows from operations, or the timing of, are not sufficient to cover such costs.
Our future capital requirements will depend on many factors, including:
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the scope, rate of progress and cost of our exploration, appraisal, development and production activities;
the success of our exploration, appraisal, development and production activities;
oil and natural gas prices;
our ability to locate and acquire hydrocarbon reserves;
our ability to produce oil or natural gas from those reserves;
the terms and timing of any drilling and other production‑related arrangements that we may enter into;
the cost and timing of governmental approvals and/or concessions;
the effects of competition by other companies operating in the oil and gas industry, and
potential changes in investor and public preferences and sentiment towards ESG considerations including climate
change and the transition to a lower carbon economy.
We do not currently have any commitments for future external funding beyond the capacity of our commercial debt
facility and revolving credit facility. Additional financing may not be available on favorable terms, or at all. Even if we succeed
in selling additional equity securities to raise funds, at such time the ownership percentage of our existing shareholders would
be diluted, and new investors may demand rights, preferences or privileges senior to those of existing shareholders. If we raise
additional capital through debt financing, the financing may involve covenants that restrict our business activities. If we choose
to farm‑out interests in our licenses, we would dilute our ownership interest subject to the farm‑out and any potential value
resulting therefrom, and may lose operating control or influence over such license areas.
Assuming we are able to commence exploration, appraisal, development and production activities or successfully
exploit our licenses during the exploratory term, our interests in our licenses (or the development/production area of such
licenses as they existed at that time, as applicable) could extend beyond the term set for the exploratory phase of the license to a
fixed period or life of production, depending on the jurisdiction. If we are unable to meet our well commitments and/or declare
commerciality of the prospective areas of our licenses during this time, we may be subject to significant potential forfeiture of
all or part of the relevant license interests. If we are not successful in raising additional capital, we may be unable to continue
our exploration and production activities or successfully exploit our license areas, and we may lose the rights to develop these
areas. See “—Under the terms of our various license agreements, we are contractually obligated to drill wells and declare any
discoveries in order to retain exploration and production rights. In the competitive market for our license areas, failure to
declare any discoveries and thereby establish development areas may result in substantial license renewal costs or loss of our
interests in the undeveloped parts of our license areas, which may include certain of our prospects or undeveloped discoveries.”
All of our proved reserves, oil production and cash flows from operations are currently associated with our licenses
offshore Ghana, Equatorial Guinea, Mauritania, Senegal and the U.S. Gulf of Mexico. Should any event occur which adversely
affects such proved reserves, oil production and cash flows from these licenses, including, without limitation, any event
resulting from the risks and uncertainties outlined in this “Risk Factors” section, our business, financial condition, results of
operations, liquidity or ability to finance planned capital expenditures may be materially and adversely affected.
We may be required to take write‑downs of the carrying values of our oil and natural gas assets as a result of decreases in
oil and natural gas prices, and such decreases could result in reduced availability under our corporate revolver, commercial
debt facility, and GoM Term Loan.
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We capitalize costs to acquire, find and develop our oil and natural gas properties under the successful efforts
accounting method. Under such method, we are required to perform impairment tests on our assets periodically and whenever
events or changes in circumstances warrant a review of our assets. Based on specific market factors and circumstances at the
time of prospective impairment reviews, and the continuing evaluation of appraisal and development plans, production data, oil
and natural gas prices, economics and other factors, we may be required to write down the carrying value of our oil and natural
gas assets. A write‑down constitutes a non‑cash charge to earnings. If there is a significant and sustained drop in oil and natural
gas prices, we may incur future write‑downs and charges should prices remain at low levels for an extended period of time.
In addition, our borrowing base under the commercial debt facility is subject to periodic redeterminations. We could be
forced to repay a portion of our borrowings under the commercial debt facility due to redeterminations of our borrowing base.
Redeterminations may occur as a result of a variety of factors, including oil and natural gas commodity price assumptions,
assumptions regarding future production from our oil and natural gas assets, operating costs and tax burdens or assumptions
concerning our future holdings of proved reserves. If we are forced to do so, we may not have sufficient funds to make such
repayments. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new
financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and
financial results.
We face various risks associated with increased activism against, or change in public sentiment for, oil and gas exploration
development, and production activities and ESG considerations, including climate change and the transition to a lower
carbon economy.
Opposition toward oil and gas drilling, development, and production activity has been growing globally. Companies in
the oil and gas industry are often the target of activist efforts from both individuals and non‑governmental organizations and
other stakeholders regarding safety, human rights, climate change, environmental matters, sustainability, and business practices.
Anti‑development activists are working to, among other things, delay or cancel certain operations such as offshore drilling and
development.
Future activist efforts could result in the following:
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delay or denial of drilling permits;
shortening of lease terms or reduction in lease size;
restrictions or delays on our ability to obtain additional seismic data;
restrictions on installation or operation of gathering or processing facilities;
restrictions on the use of certain operating practices;
legal challenges or lawsuits;
pressure or requirements for more analysis and disclosure of environmental and climate change-related risks;
damaging publicity about us;
increased regulation;
increased costs of doing business;
reduced access to financing and hedging,
reduction in demand for our products; and
other adverse effects on our ability to develop our properties and/or undertake production operations.
Activism may continue to increase regardless of whether the Biden administration in the U.S. is perceived to be
following, or actually follows, through on President Biden’s campaign commitments to promote decreased fossil fuel
exploration and production in the U.S., including as a result of President Biden’s environmental and climate change executive
orders described later in this 10-K in the risk factor titled “Our business, operations and financial condition may be directly and
indirectly adversely affected by political, economic and environmental circumstances, and changes in laws and regulations, in
the countries and regions in which we operate.” Our need to incur costs associated with responding to these initiatives or
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complying with any resulting new legal or regulatory requirements resulting from these activities that are substantial and not
adequately provided for, could have a material adverse effect on our business, financial condition and results of operations. In
addition, a change in public sentiment regarding the oil and gas industry could result in a reduction in the demand for our
products or otherwise affect our results of operations or financial condition.
Deterioration in the credit or equity markets could adversely affect us.
We have exposure to different counterparties. For example, we have entered or may enter into transactions with
counterparties in the financial services industry, including commercial banks, investment banks, insurance companies,
investment funds, and other institutions. These transactions expose us to credit risk in the event of default by our counterparty.
Deterioration in the credit markets may impact the credit ratings of our current and potential counterparties and affect their
ability to fulfill existing obligations to us and their willingness to enter into future transactions with us. We may have exposure
to these financial institutions through any derivative transactions we have or may enter into. Moreover, to the extent that
purchasers of our future production, if any, rely on access to the credit or equity markets to fund their operations, there is a risk
that those purchasers could default in their contractual obligations to us if such purchasers were unable to access the credit or
equity markets for an extended period of time.
We may incur substantial losses and become subject to liability claims as a result of future oil and natural gas operations,
for which we may not have adequate insurance coverage.
We intend to maintain insurance against certain risks in the operation of the business we plan to develop and in
amounts in which we believe to be reasonable. Such insurance, however, may contain exclusions and limitations on coverage or
may not be available at a reasonable cost or at all. We may elect not to obtain insurance if we believe that the cost of available
insurance is excessive relative to the risks presented. Losses and liabilities arising from uninsured and underinsured events
could materially and adversely affect our business, financial condition and results of operations. Further, even in instances
where we maintain adequate insurance coverage, potential delays related to receipt of insurance proceeds as well as delays
associated with the repair or rebuilding of damaged facilities could also materially and adversely affect our business, financial
condition and results of operations.
Slower global economic growth rates may materially adversely impact our operating results and financial position.
Market volatility and reduced consumer demand may increase economic uncertainty. Many developed countries are
constrained by long term structural government budget deficits and international financial markets and credit rating agencies are
pressing for budgetary reform and discipline. This need for fiscal discipline is balanced by calls for continuing government
stimulus and social spending as a result of the impacts of the global economic crisis. As major countries implement government
fiscal reform, such measures, if they are undertaken too rapidly, could further undermine economic recovery, reducing demand
and slowing growth. Impacts of the crisis have spread to China and other emerging markets, which have fueled global
economic development in recent years, slowing their growth rates, reducing demand, and resulting in further drag on the global
economy.
Global economic growth drives demand for energy from all sources, including hydrocarbons. A lower future economic
growth rate is likely to result in decreased demand growth for our crude oil and natural gas production. A decrease in demand,
notwithstanding impacts from other factors, could potentially result in lower commodity prices, which would reduce our cash
flows from operations, our profitability and our liquidity and financial position.
Increased costs and availability of capital could adversely affect our business.
Our business and operating results can be harmed by factors such as the availability, terms and cost of capital,
increases in interest rates or a reduction in credit rating. Changes in any one or more of these factors could cause our cost of
doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows
available for drilling and place us at a competitive disadvantage. Recent and continuing disruptions and volatility in the global
financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance
our operations. We require continued access to capital. A significant reduction in the availability of credit could materially and
adversely affect our ability to achieve our planned growth and operating results.
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Our derivative activities could result in financial losses or could reduce our income.
To achieve more predictable cash flows and to reduce our exposure to adverse fluctuations in the prices of oil and
natural gas, we have and may in the future enter into derivative arrangements for a portion of our oil and natural gas production,
including, but not limited to, puts, collars and fixed‑price swaps. In addition, we may in the future, hold swaps designed to
hedge our interest rate risk. We do not currently designate any of our derivative instruments as hedges for accounting purposes
and record all derivative instruments on our balance sheet at fair value. Changes in the fair value of our derivative instruments
are recognized in earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our
derivative instruments.
Derivative arrangements also expose us to the risk of financial loss in some circumstances, including when:
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production is less than the volume covered by the derivative instruments;
the counter‑party to the derivative instrument defaults on its contract obligations; or
there is an increase in the differential between the underlying price and actual prices received in the derivative
instrument.
These types of derivative arrangements may limit the benefit we could receive from increases in the prices for oil and
natural gas or beneficial interest rate fluctuations and may expose us to cash margin requirements. In addition, a reduction in
our ability to access credit could reduce our ability to implement derivative arrangements on commercially reasonable terms.
Our commercial debt facility, revolving credit facility, the indentures governing our Senior Notes and our GoM Term Loan
contain certain covenants that may inhibit our ability to make certain investments, incur additional indebtedness and engage
in certain other transactions, which could adversely affect our ability to meet our future goals.
Our commercial debt facility, revolving credit facility, the indentures governing our Senior Notes and our GoM Term
Loan include certain covenants that, among other things, restrict:
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our investments, loans and advances and certain of our subsidiaries’ payment of dividends and other restricted
payments;
our incurrence of additional indebtedness;
the granting of liens, other than liens created pursuant to the commercial debt facility, revolving credit facility, the
indentures governing our Senior Notes or the GoM Term Loan and certain permitted liens;
• mergers, consolidations and sales of all or a substantial part of our business or licenses;
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the hedging, forward sale or swap of our production of crude oil or natural gas or other commodities;
the sale of assets (other than production sold in the ordinary course of business); and
in the case of the commercial debt facility, the revolving credit facility and the GoM Term Loan, our capital
expenditures that we can fund with the proceeds of our commercial debt facility, revolving credit facility and
GoM Term Loan.
Our commercial debt facility, revolving credit facility and GoM Term Loan require us to maintain certain financial
ratios, such as debt service coverage ratios and cash flow coverage ratios. All of these restrictive covenants may limit our ability
to move funds among our subsidiaries, operate our business, or expand or pursue our business strategies. Our ability to comply
with these and other provisions of our commercial debt facility, revolving credit facility, the indentures governing our Senior
Notes and our GoM Term Loan may be impacted by changes in economic or business conditions, our results of operations or
events beyond our control. The breach of any of these covenants could result in a default under our commercial debt facility,
revolving credit facility, the indentures governing our Senior Notes and our GoM Term Loan, in which case, depending on the
actions taken by the lenders thereunder or their successors or assignees, such lenders could elect to declare all amounts
borrowed under such debt instruments, together with accrued interest, to be due and payable. If we were unable to repay such
borrowings or interest, our lenders, successors or assignees could proceed against their collateral. If the indebtedness under our
commercial debt facility, revolving credit facility, the indentures governing our Senior Notes and our GoM Term Loan were to
be accelerated, our assets may not be sufficient to repay in full such indebtedness. In addition, the limitations imposed by such
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debt instruments on our ability to incur additional debt and to take other actions might significantly impair our ability to obtain
other financing.
Provisions of our Senior Notes could discourage an acquisition of us by a third-party.
Certain provisions of the indentures governing our Senior Notes could make it more difficult or more expensive for a
third-party to acquire us, or may even prevent a third-party from acquiring us. For example, upon the occurrence of a “change
of control triggering event” (as defined in the indentures governing our Senior Notes), holders of the notes will have the right,
at their option, to require us to repurchase all of their notes or any portion of the principal amount of such notes. By
discouraging an acquisition of us by a third-party, these provisions could have the effect of depriving the holders of our
common stock of an opportunity to sell their common stock at a premium over prevailing market prices.
Our level of indebtedness may increase and thereby reduce our financial flexibility.
At December 31, 2021, we had $1.0 billion outstanding and $235.2 million of committed undrawn available capacity
under our commercial debt facility, subject to borrowing base availability. As of December 31, 2021, there were no borrowings
outstanding under the Corporate Revolver and the undrawn availability was $400.0 million. As of December 31, 2021, we had
$1.5 billion principal amount of Senior Notes outstanding and $175 million outstanding under the GoM Term Loan. In the
future, we also may incur significant off-balance sheet obligations and/or significant indebtedness in order to make investments
or acquisitions or to explore, appraise or develop our oil and natural gas assets.
Our level of indebtedness could affect our operations in several ways, including the following:
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a significant portion or all of our cash flows, when generated, could be used to service our indebtedness;
a high level of indebtedness could increase our vulnerability to general adverse economic and industry conditions;
the covenants contained in the agreements governing our outstanding indebtedness will limit our ability to borrow
additional funds, dispose of assets, pay dividends and make certain investments;
a high level of indebtedness may place us at a competitive disadvantage compared to our competitors that are less
leveraged and therefore, may be able to take advantage of opportunities that our indebtedness could prevent us
from pursuing;
our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in
our industry;
additional hedging instruments may be required as a result of our indebtedness;
a high level of indebtedness may make it more likely that a reduction in our borrowing base following a periodic
redetermination could require us to repay a portion of our then‑outstanding bank borrowings; and
a high level of indebtedness may impair our ability to obtain additional financing in the future for working capital,
capital expenditures, acquisitions, general corporate or other purposes.
A high level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our
debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, risks
associated with exploring for and producing oil and natural gas, oil and natural gas prices and financial, business and other
factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to
generate sufficient cash flows to pay the interest on our indebtedness and future working capital, borrowings or equity financing
may not be available to pay or refinance such indebtedness. Factors that will affect our ability to raise cash through an offering
of our equity securities or a refinancing of our indebtedness include financial market conditions, the value of our assets and our
performance at the time we need capital.
We are a holding company and our ability to make payments on our outstanding indebtedness, including our Senior Notes
and our commercial debt facility, is dependent upon the receipt of funds from our subsidiaries by way of dividends, fees,
interest, loans or otherwise.
We are a holding company, and our subsidiaries own all of our assets and conduct all of our operations. Accordingly,
our ability to make payments of interest and principal on the Senior Notes and commercial debt facility will be dependent on
the generation of cash flow by our subsidiaries and their ability to make such cash available to us, by dividend, debt repayment
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or otherwise. Unless they are guarantors, our subsidiaries will not have any obligation to pay amounts due on the notes or to
make funds available for that purpose. Our subsidiaries may not be able to, or may not be permitted to, make distributions to
enable us to make payments in respect of the Senior Notes or the commercial debt facility. Each subsidiary is a distinct legal
entity and, under certain circumstances, legal and contractual restrictions may limit our ability to obtain cash from our
subsidiaries. The indentures governing our Senior Notes limits the ability of our subsidiaries to incur consensual encumbrances
or restrictions on their ability to pay dividends or make other intercompany payments to us, with significant qualifications and
exceptions. In addition, the terms of the commercial debt facility limit the ability of the obligors thereunder, including our
material operating subsidiaries that hold interests in our assets located offshore Ghana and Equatorial Guinea and their
intermediate parent companies to provide cash to us through dividend, debt repayment or intercompany lending. In the event
that we do not receive distributions from our subsidiaries, we may be unable to make required principal and interest payments
on our indebtedness, including the Senior Notes and commercial debt facility.
We may be subject to risks in connection with acquisitions and the integration of significant acquisitions may be difficult.
We periodically evaluate acquisitions of prospects and licenses, reserves and other strategic transactions that appear to
fit within our overall business strategy. The successful acquisition of these assets or businesses requires an assessment of
several factors, including:
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recoverable reserves;
future oil and natural gas prices and their appropriate differentials;
development and operating costs; and
potential environmental and other liabilities.
The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review
of the subject assets that we believe to be generally consistent with industry practices. Our review will not reveal all existing or
potential problems nor will it permit us to become sufficiently familiar with the assets to fully assess their deficiencies and
potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems are not
necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling
or unable to provide effective contractual protection against all or part of the problems. We may not be entitled to contractual
indemnification for environmental liabilities and could acquire assets on an “as is” basis. Significant acquisitions and other
strategic transactions may involve other risks, including:
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diversion of our management’s attention to evaluating, negotiating and integrating significant acquisitions and
strategic transactions;
the challenge and cost of integrating acquired operations, information management and other technology systems
and business cultures with those of ours while carrying on our ongoing business;
difficulty associated with coordinating geographically separate organizations; and
the challenge of attracting and retaining personnel associated with acquired operations.
The process of integrating operations could cause an interruption of, or loss of momentum in, the activities of our
business. Members of our senior management may be required to devote considerable amounts of time to this integration
process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively
manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our
business could suffer.
If we fail to realize the anticipated benefits of a significant acquisition, our results of operations may be adversely affected.
The success of a significant acquisition (such as our 2018 acquisition of DGE) will depend, in part, on our ability to
realize anticipated growth opportunities from combining the acquired assets or operations with those of ours. Even if a
combination is successful, it may not be possible to realize the full benefits we may expect in estimated proved reserves,
production volume, cost savings from operating synergies or other benefits anticipated from an acquisition or realize these
benefits within the expected time frame. Anticipated benefits of an acquisition may be offset by operating losses relating to
changes in commodity prices, increased interest expense associated with debt incurred or assumed in connection with the
transaction, adverse changes in oil and gas industry conditions, or by risks and uncertainties relating to the exploratory
prospects of the combined assets or operations, or an increase in operating or other costs or other difficulties, including the
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assumption of health, safety, and environmental or other liabilities in connection with the acquisition. If we fail to realize the
benefits we anticipate from an acquisition, our results of operations may be adversely affected.
A cyber incident, including a breach of digital security, could result in information theft, data corruption, operational
disruption, and/or financial loss.
The oil and gas industry has become increasingly dependent on digital technologies to conduct day‑to‑day operations
including certain exploration, development and production activities. For example, software programs are used to interpret
seismic data, manage drilling rigs, conduct reservoir modeling and reserves estimation, and to process and record financial and
operating data.
We depend on digital technology, including information systems and related infrastructure as well as cloud application
and services, to process and record financial and operating data, communicate with our employees and business partners,
analyze seismic and drilling information, estimate quantities of oil and gas reserves and for many other activities related to our
business. Our business partners, including vendors, service providers, co‑venturers, purchasers of our production, and financial
institutions, are also dependent on digital technology. The complexity of the technologies needed to explore for and develop oil
and gas in increasingly difficult physical environments, such as deepwater, and global competition for oil and gas resources
make certain information more attractive to thieves.
As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional
events, have also increased. A cyber‑attack could include gaining unauthorized access to digital systems for purposes of
misappropriating assets or sensitive information, corrupting data, or causing operational disruption, or result in
denial‑of‑service on websites. For example, in 2012, a wave of network attacks impacted Saudi Arabia’s oil industry and
breached financial institutions in the United States. A number of U.S. companies have also been subject to cyber-attacks in
recent years resulting in unauthorized access to sensitive information and operational disruptions. Certain countries are believed
to possess cyber warfare capabilities and are credited with attacks on American companies and government agencies.
Our technologies, systems, networks, and those of our business partners may become the target of cyber‑attacks or
information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of
proprietary and other information, or other disruption of our business operations. In addition, certain cyber incidents, such as
surveillance, may remain undetected for an extended period. A cyber incident involving our information systems and related
infrastructure, or that of our business partners, could disrupt our business plans and negatively impact our operations. Although
to date we have not experienced any significant cyber‑attacks, there can be no assurance that we will not be the target of
cyber‑attacks in the future or suffer such losses related to any cyber‑incident. As cyber threats continue to evolve, we may be
required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate
and remediate any information security vulnerabilities.
Our ability to utilize net operating loss carryforwards may be subject to certain limitations.
Our ability to use our federal and state net operating losses to offset potential future taxable income and related income
taxes that would otherwise be due is dependent upon our generation of future taxable income, including where our state losses
are subject to expiration, before such state net operating losses expire, and we cannot predict with certainty when, or whether,
we will generate sufficient taxable income to use all of our net operating losses. In addition, Section 382 of the Internal
Revenue Code of 1986, as amended (the “Code”), contains rules that impose an annual limitation on the ability of a company
with federal net operating loss carryforwards that undergoes an ownership change, which is generally any change in ownership
of more than 50% of its stock (by value) over a three-year period, to utilize its federal net operating loss carryforwards in years
after the ownership change. These rules generally operate by focusing on ownership changes among holders owning directly or
indirectly 5% or more of the shares of stock of a company or any change in ownership arising from a new issuance of shares of
stock by such company. If a company’s income in any year is less than the annual limitation prescribed by Section 382 of the
Code, the unused portion of such limitation amount may be carried forward to increase the limitation in subsequent tax years.
If we were to undergo an ownership change as a result of future transactions involving our common stock, including a
follow-on offering of our common stock or purchases or sales of common stock between 5% holders, our ability to use our
federal net operating loss carryforwards may be subject to limitation under Section 382 of the Code. If our federal net operating
losses become subject to the limitation under Section 382 of the Code, we may be unable to fully utilize our federal net
operating loss carryforwards to offset our taxable income, if any, in future years, which could have a negative impact on our
financial position and results of operations.
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In addition to the aforementioned federal income tax implications pursuant to Section 382 of the Code, most states
follow the general provisions of Section 382 of the Code, either explicitly or implicitly resulting in separate
state net operating loss limitations. Any limitation on our ability to use our state net operating loss carryforwards could also
have a negative impact on our financial position and results of operations.
Changes in the method of determining London Interbank Offered Rate (“LIBOR”), or the replacement of LIBOR with an
alternative reference rate, may adversely affect interest expense related to outstanding debt.
On July 27, 2017, the Financial Conduct Authority in the United Kingdom announced that it would no longer persuade
or compel panel banks to submit the rates required to calculate LIBOR after the end of 2023. The announcement indicates that
the continuation of LIBOR on the current basis cannot and will not be guaranteed after 2023. The continued existence of
LIBOR after 2023, therefore, remains highly uncertain. While various governmental working groups are pursuing replacement
rates, if LIBOR ceases to exist, we may need to renegotiate our Facility and Corporate Revolver and may not be able to do so
on terms that are favorable to us.
Risks Relating to Regulation
Our business, operations and financial condition may be directly and indirectly adversely affected by political, economic,
and environmental circumstances, and changes in laws and regulations, in the countries and regions in which we operate.
Oil and natural gas exploration, development and production activities are directly and indirectly subject to political,
economic, and environmental uncertainties (including but not limited to those resulting from government elections and changes
in energy policies), changes in laws and policies governing operations of companies, expropriation of property, cancellation or
modification of contract rights, revocation of consents, approvals or royalty regimes, obtaining various approvals from
regulators, foreign exchange restrictions, currency fluctuations, royalty increases, implementation of a carbon tax or cap-and-
trade program, increased laws and regulations around climate change, and other risks arising out of governmental sovereignty,
as well as risks of loss due to civil strife, acts of war, guerrilla activities, terrorism, acts of sabotage, territorial disputes and
insurrection.
For example, the Biden administration has taken a number of actions that may result in stricter environmental, health
and safety standards applicable to our operations and those of the oil and gas industry more generally. The Biden
Administration issued the “Executive Order on Tackling the Climate Crisis at Home and Abroad” on January 27, 2021 (the
“Climate Change Executive Order”). This executive order directed the Secretary of the Interior to halt indefinitely new oil and
natural gas leases on federal lands and offshore waters pending completion of a review by the Secretary of the Interior of
federal oil and gas permitting and leasing practices in light of the Biden administration’s concerns regarding the impact of these
activities on the environment and climate. The Secretary of the Interior completed its review of permitting and leasing practices
in November 2021 and issued a report recommending, among other things, an increase in royalty rates and financial assurance
requirements. However, litigation concerning the Climate Change Executive Order’s pause on new oil and gas leases is
ongoing. In June 2021, the U.S. District Court for the Western District of Louisiana issued a nationwide preliminary injunction
barring the Biden administration from implementing the pause in new federal oil and gas leases. Subsequently, in November
2021, the Biden administration resumed lease sales in the Gulf of Mexico; however, on January 27, 2022, in litigation brought
by Friends of the Earth and other plaintiffs, the U.S. District Court for the District of Columbia vacated the November 2021
lease sale and the related agency decision making process, finding that the Bureau of Ocean Energy Management (“BOEM”)
failed to consider the impact on foreign greenhouse gas emissions if the November 2021 lease sale was not held and the court
determined that this failure was a violation of the National Environmental Policy Act. Following this decision by the District
Court for the District of Columbia vacating the November 2021 lease sale, there is uncertainty surrounding whether the sale can
be revived and whether the single lease in which Kosmos was the apparent high bidder will be awarded. In addition, there is
increasing uncertainty regarding the near-term future of Gulf of Mexico lease sales. These lease sales are conducted pursuant to
Five-Year Leasing Programs under the Outer Continental Shelf Lands Act, for which the current Five-Year Program is set to
expire on June 30, 2022. No new Gulf of Mexico leases can be awarded until a new Five-Year Leasing Program is approved. In
addition, the Climate Change Executive Order, among other things, establishes climate conditions as an essential element of
U.S. foreign policy; establishes a White House office and a climate task force to coordinate and implement the Biden
Administration’s domestic climate change agenda; directs federal agencies to procure carbon pollution-free electricity and zero-
emission vehicles; eliminate fossil fuel subsidies as consistent with applicable law; identifies a goal of a carbon pollution-free
power sector by 2035 and a net-zero emissions U.S. economy by 2050; and commits to a goal of conserving at least 30 percent
of federal lands and oceans by 2030. Separately, in April 2021, President Biden announced a goal of reducing the United
States’ greenhouse gas emissions by 50-52% below 2005 levels by 2030.
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In addition, President Biden signed another executive order on January 20, 2021, titled “Executive Order on Protecting
Public Health and the Environment and Restoring Science to Tackle the Climate Crisis” (the “Health and Environment
Executive Order”), which among other things calls for a review of regulations and other executive actions promulgated, issued
or adopted during the prior Presidential administration to assess whether they are, in the view of the Biden Administration,
sufficiently protective of public health and the environment, including with respect to climate change, and consistent with
science. The order also specifically calls for consideration of new regulations regarding methane emissions in the oil and gas
sector, reassessment of decisions made by the prior administration limiting the size of certain national monuments, and
incorporation of the impact of GHG emissions (known as the “social cost of carbon”) in decision making by federal agencies.
These actions and any future changes to applicable environmental, health and safety, regulatory and legal requirements
promulgated by the current Presidential administration and Congress may restrict our access to additional acreage and new
leases in the deepwater U.S. Gulf of Mexico or lead to limitations or delays on our ability to secure additional permits to drill
and develop our acreage and leases or otherwise lead to limitations on the scope of our operations, or may lead to increases to
our compliance costs. The potential impacts these changes on our future consolidated financial condition, results of operations
or cash flows cannot be predicted.
In addition, we are subject both to uncertainties in the application of the tax laws in the countries in which we operate
and to possible changes in such tax laws (or the application thereof), each of which could result in an increase in our tax
liabilities. These risks may be higher in the developing countries in which we conduct a majority of our activities, as it is the
case in Ghana, where the GRA has disputed certain tax deductions we had claimed in prior fiscal years’ Ghanaian tax returns as
non‑allowable under the terms of the Ghanaian Petroleum Income Tax Law, as well as non‑payment of certain transactional
taxes, contractual fiscal obligations and other payments. We have faced similar tax related disputes with the Senegal Tax
Administration.
Additionally, monetary sector reform initiatives in the West African Monetary Union and the Central African
Economic and Monetary Union, such as through the implementation of Regulation 02/18/ECMAC/UMAC/CM by the Bank of
Central African States could restrict or prevent payments being made in a foreign currency; impose restrictions on offshore and
onshore foreign currency accounts; and/or restrict or prevent the repatriation of revenues and debt proceeds. The
implementation or realization of any of the foregoing could have an adverse impact on our financial condition and results of
operations.
Our operations in these areas increase our exposure to risks of war, local economic conditions, political disruption,
civil disturbance, expropriation, piracy, tribal conflicts and governmental policies that may:
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disrupt our operations;
require us to incur greater costs for security;
restrict the movement of funds or limit repatriation of profits;
lead to U.S. government or international sanctions; or
limit access to markets for periods of time.
Some countries in the geographic areas where we operate have experienced political instability in the past or are
currently experiencing instability. Disruptions may occur in the future, and losses caused by these disruptions may occur that
will not be covered by insurance. Consequently, our exploration, development and production activities may be substantially
affected by factors which could have a material adverse effect on our results of operations and financial condition. Furthermore,
in the event of a dispute arising from non‑U.S. operations, we may be subject to the exclusive jurisdiction of courts outside the
United States or may not be successful in subjecting non‑U.S. persons to the jurisdiction of courts in the United States or
international arbitration, which could adversely affect the outcome of such dispute.
Our operations may also be adversely affected by laws and policies of the jurisdictions, including the jurisdictions
where our oil and gas operating activities are located as well as the United Kingdom and the Cayman Islands and other
jurisdictions in which we do business, that affect foreign trade and taxation. Changes in any of these laws or policies or the
implementation thereof could materially and adversely affect our financial position, results of operations and cash flows.
More comprehensive and stringent regulation in the U.S. Gulf of Mexico has materially increased costs and delays in
offshore oil and natural gas exploration and production operations.
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In the U.S. Gulf of Mexico, there have been a series of regulatory initiatives developed and implemented at the federal
level to address the direct impact of the incident and to prevent similar incidents in the future. Beginning in 2010 and
continuing through the present, the Department of Interior (“DOI”) through the BOEM and the Bureau of Safety and
Environmental Enforcement (“BSEE”), has issued a variety of regulations and Notices to Lessees and Operators (“NTLs”),
intended to impose additional safety, permitting and certification requirements applicable to exploration, development and
production activities in the U.S. Gulf of Mexico. These regulatory initiatives effectively slowed down the pace of drilling and
production operations in the U.S. Gulf of Mexico as adjustments were being made in operating procedures, certification
requirements and lead times for inspections, drilling applications and permits, and exploration and production plan reviews, and
as the federal agencies evolved into their present-day bureaus. On May 15, 2019, BSEE published a final rule with an effective
date of July 15, 2019 that revises requirements for well design, well control, casing, cementing, real-time monitoring (RTM),
and subsea containment. These revisions modify regulations pertaining to offshore oil and gas drilling, completions, workovers,
and decommissioning in accordance with Executive and Secretary of the Interior's Orders. Key features of the well control
regulations include requirements for blowout preventers (BOPs), double shear rams, third-party reviews of equipment, real time
monitoring data, safe drilling margins, centralizers, inspections and other reforms related to well design and control, casing,
cementing and subsea containment. For a discussion of recent drilling and climate change executive orders signed by President
Biden, see the risk factor earlier in this 10-K titled “Our business, operations and financial condition may be directly and
indirectly adversely affected by political, economic and environmental circumstances, and changes in laws and regulations, in
the countries and regions in which we operate.”
In addition to the array of new or revised safety, permitting and certification requirements developed and implemented
by the DOI in the past few years, there have been a variety of proposals to change existing laws and regulations that could
affect offshore development and production, such as, for example, a proposal to significantly increase the minimum financial
responsibility demonstration required under the Oil Pollution Act of 1990. To the extent the existing regulatory initiatives
implemented and pursued over the past few years or any future restrictions, whether through legislative or regulatory means or
increased or broadened permitting and enforcement programs, foster uncertainties or delays in our offshore oil and natural gas
development or exploration activities, then such conditions may have a material adverse effect on our business, financial
condition and results of operations. Any other new rules, regulations or legal initiatives by BOEM or other governmental
authorities, including as a result of the current Presidential administration, that impose more stringent requirements regarding
financial assurances, moratoria on new leases or otherwise adversely affecting our offshore activities could result in increased
costs. In particular, as noted above, the current Presidential administration supports limitations on oil and gas exploration and
production on federal areas. These restrictions and similar restrictions that may be issued in the future may limit our operations
and adversely impact our future financial results.
The oil and gas industry, including the acquisition of exploratory licenses, is intensely competitive and many of our
competitors possess and employ substantially greater resources than us.
The international oil and gas industry is highly competitive in all aspects, including the exploration for, and the
development of, new license areas. We operate in a highly competitive environment for acquiring exploratory licenses and
hiring and retaining trained personnel. Many of our competitors possess and employ financial, technical and personnel
resources substantially greater than us, which can be particularly important in the areas in which we operate. These companies
may be better able to withstand the financial pressures of unsuccessful drilling efforts, sustained periods of volatility in financial
markets and generally adverse global and industry‑wide economic conditions, and may be better able to absorb the burdens
resulting from changes in relevant laws and regulations, which could adversely affect our competitive position. Our ability to
acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select
suitable licenses and to consummate transactions in a highly competitive environment. Also, there is substantial competition for
available capital for investment in the oil and gas industry. As a result of these and other factors, we may not be able to compete
successfully in an intensely competitive industry, which could cause a material adverse effect on our results of operations and
financial condition.
Participants in the oil and gas industry are subject to numerous laws, regulations, and other legislative instruments that can
affect the cost, manner or feasibility of doing business.
Exploration and production activities in the oil and gas industry are subject to local laws and regulations. We may be
required to make large expenditures to comply with governmental laws and regulations, particularly in respect of the following
matters:
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licenses for drilling operations;
tax increases, including retroactive claims;
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unitization of oil accumulations;
local content requirements (including the mandatory use of local partners and vendors); and
safety, health and environmental requirements, liabilities and obligations, including those related to remediation,
investigation or permitting.
Under these and other laws and regulations, we could be liable for personal injuries, property damage and other types
of damages. Failure to comply with these laws and regulations also may result in the suspension or termination of our
operations and subject us to administrative, civil and criminal penalties. Moreover, these laws and regulations could change, or
their interpretations could change, in ways that could substantially increase our costs. These risks may be higher in the
developing countries in which we conduct a majority of our operations, where there could be a lack of clarity or lack of
consistency in the application of these laws and regulations. Any resulting liabilities, penalties, suspensions or terminations
could have a material adverse effect on our financial condition and results of operations.
For example, Ghana’s Parliament has enacted the Petroleum Revenue Management Act, the Petroleum Commission
Act of 2011, and the 2016 Ghanaian Petroleum Law. There can be no assurance that these laws will not seek to retroactively,
either on their face or as interpreted, modify the terms of the agreements governing our license interests in Ghana, including the
WCTP and DT petroleum contracts and the Jubilee UUOA, require governmental approval for transactions that effect a direct
or indirect change of control of our license interests or otherwise affect our current and future operations in Ghana. Any such
changes may have a material adverse effect on our business. We also cannot assure you that government approval will not be
needed for direct or indirect transfers of our petroleum agreements or interests thereunder based on existing legislation.
We are subject to numerous health, safety and environmental laws and regulations which may result in material liabilities
and costs.
We are subject to various international, foreign, federal, state and local health, safety and environmental laws and
regulations governing, among other things, the emission and discharge of pollutants into the ground, air or water, the
generation, storage, handling, use, transportation and disposal of regulated materials and the health and safety of our employees,
contractors and communities in which our assets are located. We are required to obtain environmental permits from
governmental authorities for our operations, including drilling permits for our wells. We may not be at all times in complete
compliance with these permits and laws and regulations to which we are subject, and there is a risk such requirements could
change in the future or become more stringent. If we violate or fail to comply with such requirements, we could be fined or
otherwise sanctioned by regulators, including through the revocation of our permits or the suspension or termination of our
operations. If we fail to obtain, maintain or renew permits in a timely manner or at all (due to opposition from partners,
community or environmental interest groups, governmental delays or other reasons), or if we face additional requirements
imposed as a result of changes in or enactment of laws or regulations, such failure to obtain, maintain or renew permits or such
changes in or enactment of laws or regulations could impede or affect our operations, which could have a material adverse
effect on our results of operations and financial condition.
We, as an interest owner or as the designated operator of certain of our past, current and future interests, discoveries
and prospects, could be held liable for some or all health, safety and environmental costs and liabilities arising out of our
actions and omissions as well as those of our block partners, third‑party contractors, predecessors or other operators. To the
extent we do not address these costs and liabilities or if we do not otherwise satisfy our obligations, our operations could be
suspended or terminated. We have contracted with and intend to continue to hire third parties to perform services related to our
operations. There is a risk that we may contract with third parties with unsatisfactory health, safety and environmental records
or that our contractors may be unwilling or unable to cover any losses associated with their acts and omissions. Accordingly, we
could be held liable for all costs and liabilities arising out of their acts or omissions, which could have a material adverse effect
on our results of operations and financial condition.
We are not fully insured against all risks and our insurance may not cover any or all health, safety or environmental
claims that might arise from our operations or at any of our license areas. If a significant accident or other event occurs and is
not covered by insurance, such accident or event could have a material adverse effect on our results of operations and financial
condition.
Releases of regulated substances may occur and can be significant. Under certain environmental laws, we could be
held responsible for all of the costs relating to any contamination at our current or former facilities and at any third-party waste
disposal sites used by us or on our behalf. In addition, offshore oil and natural gas exploration and production involves various
hazards, including human exposure to regulated substances, which include naturally occurring radioactive, and other materials.
57
As such, we could be held liable for any and all consequences arising out of human exposure to such substances or for other
damage resulting from the release of any regulated or otherwise hazardous substances to the environment, property or to natural
resources, or affecting endangered species.
In addition, we expect continued and increasing attention to climate change issues and emissions of GHGs, including
methane (a primary component of natural gas) and carbon dioxide (a byproduct of oil and natural gas combustion). For
example, in April 2016, 195 nations, including Ghana, Mauritania, Sao Tome and Principe, Senegal and the United States,
signed and officially entered into an international climate change accord (the “Paris Agreement”). The Paris Agreement calls
for signatory countries to set their own GHG emissions targets, make these emissions targets more stringent over time and be
transparent about the GHG emissions reporting and the measures each country will use to achieve its GHG targets. A long-term
goal of the Paris Agreement is to limit global temperature increase to well below two degrees Celsius from temperatures in the
pre-industrial era. The Paris Agreement is in effect a successor to the Kyoto Protocol, an international treaty aimed at reducing
emissions of GHGs, to which various countries and regions, including Ghana, Mauritania, Sao Tome and Principe and Senegal,
are parties. In 2012, the Kyoto Protocol was extended by amendment through 2020 in the so-called Doha Amendment, which
entered into force in late December 2020 after the requisite number of parties ratified it in October 2020. In November 2021,
the international community gathered in Glasgow at the 26th Conference to the Parties on the UN Framework Convention on
Climate Change (“COP26”), during which multiple announcements were made, including a call for parties to eliminate certain
fossil fuel subsidies and pursue further action on non-carbon dioxide GHGs. It cannot be determined at this time what effect the
Paris Agreement, COP26 and any related GHG emissions targets, regulations, executive orders or other requirements, will have
on our business, results of operations and financial condition. This legislative and regulatory uncertainty, however, could result
in a disruption to our business or operations. The physical impacts of climate change in the areas in which our assets are located
or in which we otherwise operate, including through increased severity and frequency of storms, floods and other weather
events, could adversely impact our operations or disrupt transportation or other process‑related services provided by our
third‑party contractors. For a discussion of recent environmental and climate change executive orders signed by President
Biden, see the risk factor earlier in this 10-K titled “Our business, operations and financial condition may be directly and
indirectly adversely affected by political, economic and environmental circumstances, and changes in laws and regulations, in
the countries and regions in which we operate.”
Health, safety and environmental laws and regulations are complex, change frequently and have tended to become
increasingly stringent over time. Our costs of complying with current and future climate change, health, safety and
environmental laws, the actions or omissions of our block partners and third-party contractors and our liabilities arising from
releases of, or exposure to, regulated substances may adversely affect our results of operations and financial condition. See
“Item 1. Business—Environmental Matters” for more information.
We may be exposed to assertions concerning or liabilities under the U.S. Foreign Corrupt Practices Act and other
anti‑corruption laws, and any such assertions or determination that we violated the U.S. Foreign Corrupt Practices Act or
other such laws could result in significant costs to Kosmos and have a material adverse effect on our business.
We are subject to the U.S. Foreign Corrupt Practices Act (“FCPA”) and other laws that prohibit improper payments or
offers of payments to foreign government officials and political parties for the purpose of obtaining or retaining business or
otherwise securing an improper business advantage. In addition, the United Kingdom has enacted the Bribery Act of 2010, and
we may be subject to that legislation under certain circumstances. We do business and may do additional business in the future
in countries and regions in which we may face, directly or indirectly, corrupt demands by officials. We face the risk of
unauthorized payments or offers of payments by one of our employees, contractors or consultants. Our existing safeguards and
any future improvements may prove to be less than effective in preventing such unauthorized payments, and our employees and
consultants may engage in conduct for which we might be held responsible. Violations of the FCPA or other anti-corruption
laws may result in severe criminal or civil sanctions, and we may be subject to other liabilities, which could negatively affect
our business, operating results and financial condition. In addition, the U.S. government may seek to hold us liable for
successor liability for FCPA violations committed by companies in which we invest in (for example, by way of acquiring equity
interests in, participating as a joint venture partner with, acquiring the assets of, or entering into certain commercial transactions
with) or that we acquire.
While we believe we maintain a robust compliance program (including policies, procedures, and controls) and
corresponding compliance culture, from time-to-time assertions may be raised, including by media outlets or competitors,
related to our operations or assets which, notwithstanding the lack of veracity of such assertions, may attract the interest of
regulators or affect the market perception of Kosmos. On June 3, 2019, the BBC Panorama broadcast a television program,
which included various assertions concerning the Cayar Offshore Profond and Saint Louis Offshore Profond Blocks offshore
Senegal in which the Company holds interests, which we believe are inaccurate and misleading. We, BP (block operator) and
the Government of Senegal all promptly issued independent statements strongly refuting these assertions. As noted in our
statement, Kosmos conducted extensive pre-transaction due diligence, and we believe we acquired our interests in the blocks in
58
compliance with applicable laws. After the program aired, certain government agencies requested that Kosmos voluntarily
provide information related to the Senegal blocks and other blocks. We are cooperating with these requests to ensure that these
agencies have an accurate and complete understanding concerning the history of the blocks. There can be no assurance that
these or other regulatory bodies will not make further regulatory inquiries or take other actions.
Federal regulatory law could have an adverse effect on our ability to use derivatives to reduce the effect of commodity price,
interest rate and other risks associated with our business.
At times, we use derivatives, specifically cash-settled commodity options and interest rate swaps, to hedge risks
associated with our business, including commodity price and interest rate risk. The Commodity Futures Trading Commission
(“CFTC”) has jurisdiction over derivatives, including swaps and cash-settled commodity options, which are regulated as swaps
under the Commodity Exchange Act.
Of particular importance to us, the CFTC has implemented regulations that establish position limits for certain futures
and economically equivalent swaps and require exchanges to do the same. Certain bona fide hedging positions are exempt from
these position limits. As the relevant provisions of these rules for the Company are phased in over the next several years, they
may increase costs or, if we are unable to meet the specific requirements of the relevant hedging exemption, we may be subject
to certain position limits.
The CFTC has designated certain interest rate swaps for mandatory clearing and exchange trading. The CFTC has not
yet proposed rules designating any other classes of swaps, including commodity swaps, for mandatory clearing or exchange
trading. The application of the mandatory clearing and trade execution requirements may change the cost and availability of the
swaps that the Company uses for hedging.
Swap dealers that we transact with need to comply with margin and segregation requirements for uncleared swaps.
While our uncleared swaps are not directly subject to those margin requirements as a result of the fact that they are used by us
for hedging purposes, due to the increased costs to dealers for transacting uncleared swaps in general, our costs for these
transactions may increase.
The Commodity Exchange Act also requires certain of the counterparties to our derivatives instruments to be
registered with the CFTC and be subject to substantial regulation. These requirements could significantly increase the cost of
derivatives, reduce the availability of derivatives to protect against risks we encounter, and reduce our ability to monetize or
restructure our existing derivatives. If we reduce our use of derivatives as a result of these regulations, our results of operations
may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and
fund capital expenditures. Our revenues could also be adversely affected if a consequence of the legislation and regulations is to
lower commodity prices.
The European Union and other non‑U.S. jurisdictions have also implemented or are implementing similar regulations
with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions, we or our
transactions may become subject to such regulations. The impact of such regulations could be similar to those described above
with respect to U.S. rules.
Any of these consequences could have a material adverse effect on our consolidated financial position, results of
operations, or cash flows.
We are dependent on certain members of our management and technical team.
General Risk Factors
Our performance and success largely depend on the ability, expertise, judgment and discretion of our management and
the ability of our technical team to identify, discover, evaluate, develop, and produce reserves. The loss or departure of one or
more members of our management and technical team could be detrimental to our future success. Additionally, a significant
amount of shares in Kosmos held by members of our management and technical team has vested. There can be no assurance
that our management and technical team will remain in place. If any of these officers or other key personnel retires, resigns or
59
becomes unable to continue in their present roles and is not adequately replaced, our results of operations and financial
condition could be materially adversely affected. Our ability to manage our growth, if any, will require us to continue to train,
motivate and manage our employees and to attract, motivate and retain additional qualified personnel. Competition for these
types of personnel is intense, and we may not be successful in attracting, assimilating and retaining the personnel required to
grow and operate our business profitably.
We operate in a litigious environment.
Some of the jurisdictions within which we operate have proven to be litigious environments. Oil and gas companies,
such as us, can be involved in various legal proceedings, such as title or contractual disputes, in the ordinary course of business.
From time to time, we may become involved in various legal and regulatory proceedings arising in the normal course
of business. We cannot predict the occurrence or outcome of these proceedings with certainty, and if we are unsuccessful in
these disputes and any loss exceeds our available insurance, this could have a material adverse effect on our results of
operations.
Because we maintain a diversified portfolio of assets overseas, the complexity and types of legal procedures with
which we may become involved may vary, and we could incur significant legal and support expenses in different jurisdictions.
If we are not able to successfully defend ourselves, there could be a delay or even halt in our exploration, development or
production activities or other business plans, resulting in a reduction in reserves, loss of production and reduced cash flows.
Legal proceedings could result in a substantial liability and/or negative publicity about us and adversely affect the price of our
common stock. In addition, legal proceedings distract management and other personnel from their primary responsibilities.
We face various risks associated with global populism.
Globally, certain individuals and organizations are attempting to focus public attention on income distribution, wealth
distribution, and corporate taxation levels, and implement income and wealth redistribution policies. These efforts, if they gain
political traction, could result in increased taxation on individuals and/or corporations, as well as, potentially, increased
regulation on companies and financial institutions. Our need to incur costs associated with responding to these developments or
complying with any resulting new legal or regulatory requirements, as well as any potential increased tax expense, could
increase our costs of doing business, reduce our financial flexibility and otherwise have a material adverse effect on our
business, financial condition and results of our operations.
Our share price may be volatile, and purchasers of our common stock could incur substantial losses.
Our share price may be volatile. The stock market in general has experienced extreme volatility that has often been
unrelated to the operating performance of particular companies. The market price for our common stock may be influenced by
many factors, including, but not limited to:
•
•
•
•
•
•
the price of oil and natural gas;
the success of our exploration and development operations, and the marketing of any oil and natural gas we
produce;
operational incidents;
regulatory developments in the United States and foreign countries where we operate;
the recruitment or departure of key personnel;
quarterly or annual variations in our financial results or those of companies that are perceived to be similar to us;
• market conditions in the industries in which we compete and issuance of new or changed securities;
•
•
•
analysts’ reports or recommendations;
the failure of securities analysts to cover our common stock or changes in financial estimates by analysts;
the inability to meet the financial estimates of analysts who follow our common stock;
60
•
•
•
the issuance or sale of any additional securities of ours;
investor perception of our company and of the industry in which we compete; and
general economic, political and market conditions.
A substantial portion of our total issued and outstanding common stock may be sold into the market at any time. This could
cause the market price of our common stock to drop materially, even if our business is doing well.
All of the shares sold in our public offerings are freely tradable without restrictions or further registration under the
federal securities laws, unless purchased by our “affiliates” as that term is defined in Rule 144 under the Securities Act of 1933,
as amended (the “Securities Act”). Substantially all of the remaining shares of common stock are restricted securities as defined
in Rule 144 under the Securities Act (unless they have been sold pursuant to Rule 144 to date). Restricted securities may be
sold in the U.S. public market only if registered or if they qualify for an exemption from registration, including by reason of
Rule 144 or Rule 701 under the Securities Act. All of our restricted shares are eligible for sale in the public market, subject in
certain circumstances to the volume, manner of sale limitations with respect to shares held by our affiliates and other limitations
under Rule 144. Additionally, we have registered all our shares of common stock that we may issue under our employee benefit
plans. These shares can be freely sold in the public market upon issuance, unless pursuant to their terms these share awards
have transfer restrictions attached to them. Sales of a substantial number of shares of our common stock, or the perception in
the market that the holders of a large number of shares intend to sell common stock, could reduce the market price of our
common stock.
Holders of our common stock will be diluted if additional shares are issued.
We may issue additional shares of common stock, preferred shares, warrants, rights, units and debt securities for
general corporate purposes, including, but not limited to, repayment or refinancing of borrowings, working capital, capital
expenditures, investments and acquisitions. We continue to actively seek to expand our business through complementary or
strategic acquisitions, and we may issue additional shares of common stock in connection with those acquisitions. We also issue
restricted shares to our executive officers, employees and independent directors as part of their compensation. If we issue
additional shares of common stock in the future, it may have a dilutive effect on our current outstanding shareholders.
Item 1B. Unresolved Staff Comments
Not applicable.
Item 2. Properties
See “Item 1. Business.” We also have various operating leases for rental of office space, office and field equipment,
and vehicles. See “Item 8. Financial Statements and Supplementary Data—Note 15—Commitments and Contingencies” for the
future minimum rental payments. Such information is incorporated herein by reference.
Item 3. Legal Proceedings
From time to time, we may be involved in various legal and regulatory proceedings arising in the normal course of
business. While we cannot predict the occurrence or outcome of these proceedings with certainty, we do not believe that an
adverse result in any pending legal or regulatory proceeding, individually or in the aggregate, would be material to our
consolidated financial condition or cash flows; however, an unfavorable outcome could have a material adverse effect on our
results of operations for a specific interim period or year.
Item 4. Mine Safety Disclosures
Not applicable.
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PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities
Common Stock Trading Summary
Our common stock is traded on the NYSE and LSE under the symbol KOS.
As of February 24, 2022, based on information from the Company’s transfer agent, Computershare Trust Company,
N.A., the number of holders of record of Kosmos’ common stock was 112. On February 24, 2022, the last reported sale price of
Kosmos’ common stock, as reported on the NYSE, was $4.58 per share.
Kosmos does not currently pay a dividend. Any decision to pay dividends in the future is at the discretion of our Board
of Directors and depends on our financial condition, results of operations, capital requirements and other factors that our Board
of Directors deems relevant. Certain of our subsidiaries are currently restricted in their ability to pay dividends to us pursuant to
the terms of the Senior Notes, the Facility, the Corporate Revolver, and the GoM Term Loan unless we meet certain conditions,
financial and otherwise.
Issuer Purchases of Equity Securities
Under the terms of our LTIP, we have issued restricted shares to our employees. On the date that these restricted
shares vest, we provide such employees the option to sell shares to cover their tax liability, via a net exercise provision pursuant
to our applicable restricted share award agreements and the LTIP, at either the number of vested shares (based on the closing
price of our common stock on such vesting date) equal to the minimum statutory tax liability owed by such grantee or up to the
maximum statutory tax liability for such grantee. The Company may repurchase the restricted shares sold by the grantees to
settle their tax liability. The repurchased shares are reallocated to the number of shares available for issuance under the LTIP.
During 2021, there were no shares purchased.
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Share Performance Graph
The following Performance Graph and related information shall not be deemed “soliciting material” or to be “filed”
with the SEC, nor shall such information be incorporated by reference into any future filings under the Securities Act of 1933
or Securities Exchange Act of 1934, each as amended, except to the extent that the Company specifically incorporates it by
reference into such filings.
The following graph illustrates changes over the five-year period ended December 31, 2021, in cumulative total
stockholder return on our common stock as measured against the cumulative total return of the S&P 500 Index and the Dow
Jones U.S. Exploration & Production Index. The graph tracks the performance of a $100 investment in our common stock and
in each index (with the reinvestment of all dividends).
Kosmos Energy Ltd. (KOS)
S&P 500 (SPX)
December 31,
2016
2017
2018
2019
2020
2021
$ 100.00 $
97.72 $
58.06 $
83.79 $
35.14 $
51.75
100.00
121.82
116.47
153.13
181.29
233.28
Dow Jones U.S. Exploration & Production Index (DWCEXP)
100.00
100.28
80.93
89.26
59.10
101.81
63
Kosmos Energy Ltd. (KOS)S&P 500 (SPX)Dow Jones U.S. Exploration & Production Index (DWCEXP)201620172018201920202021050100150200250
Item 6. Selected Financial Data
See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8.
Financial Statements and Supplementary Data” for consolidated financial information as of and for the three years ended
December 31, 2021.
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis contains forward‑looking statements that involve risks and uncertainties. Our
actual results may differ materially from those discussed in the forward‑looking statements as a result of various factors,
including, without limitation, those set forth in “Cautionary Statement Regarding Forward‑Looking Statements” and “Item 1A.
Risk Factors.” The following discussion of our financial condition and results of operations should be read in conjunction with
our consolidated financial statements and the notes thereto included elsewhere in this annual report on Form 10‑K.
Overview
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 the U.S. Gulf of Mexico, as well as
a world-class gas development offshore Mauritania and Senegal. We also maintain a sustainable proven basin exploration
program in Equatorial Guinea, Ghana and the U.S. Gulf of Mexico.
The ongoing COVID-19 pandemic that emerged at the beginning of 2020 has resulted in travel restrictions, including
border closures, travel bans, social distancing restrictions, various quarantine measures 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
impacted demand for oil, which also resulted in significant variations in oil prices. The Company’s revenues, earnings, cash
flows, capital investments, debt capacity and, ultimately, future rate of growth are highly dependent on oil prices.
65
Recent Developments
Corporate
In March 2021, the Company issued $450.0 million of 7.500% Senior Notes due 2028 and received net proceeds of
approximately $444.4 million after deducting fees. We used the net proceeds to repay outstanding indebtedness under the
Corporate Revolver and the Facility, to pay expenses related to the issuance of the 7.500% Senior Notes and for general
corporate purposes.
In May 2021, the Company entered into an amended and restated Facility Agreement and certain ancillary documents.
As part of the amendment, Kosmos elected to lower the overall Facility size from $1.5 billion to $1.25 billion to reduce reliance
on the Facility and commitment costs following the completion of the Company’s senior notes issuance in March 2021. The
amendment includes a two-year tenor extension, with the Facility’s final maturity now in March 2027. As amended, the Facility
has an available borrowing base of approximately $1.24 billion.
In October 2021, Kosmos completed the acquisition of Anadarko WCTP Company (“Anadarko WCTP”), a subsidiary
of Occidental Petroleum Corporation, which owns a participating interest in the WCTP Block and DT Block offshore Ghana,
including an 18.0% participating interest in the Jubilee Unit Area and an 11.1% participating interest in the TEN fields. In
consideration for the acquisition, Kosmos paid $455.9 million in cash based on an initial purchase price of $550.6 million
reduced by certain purchase price adjustments totaling $94.7 million. Additionally, we incurred $9.5 million of transaction
related costs, which were capitalized as part of the purchase price. Following closing of the acquisition, Kosmos’ interest in the
Jubilee Unit Area increased from 24.1% to 42.1%, and Kosmos’ interest in the TEN fields increased from 17.0% to 28.1%.
Under the Deepwater Tano Block Joint Operating Agreement, certain joint venture partners have pre-emption rights
that, if fully exercised, could reduce our ultimate interest in the Jubilee Unit Area by 3.8% to 38.3%, and our ultimate interest in
the TEN fields by 8.3% to 19.8%. In November 2021, we received notice from certain joint venture partners that they intend to
exercise their pre-emption rights in relation to Kosmos' acquisition of additional interests in Ghana. The exercise of pre-emption
rights is subject to finalizing definitive agreements with Kosmos and requires approval from GNPC and the Ghanaian Ministry
of Energy. The initial purchase price for the pre-empted portion of transaction is approximately $150 million and is subject to
additional purchase price closing adjustments. Kosmos would anticipate using any potential proceeds to accelerate debt
repayment.
Kosmos initially funded the purchase price through the issuance of $400.0 million aggregate principal amount of
floating rate senior notes due 2022 (“Bridge Notes”) and $75.0 million of borrowings under Kosmos' Facility. Kosmos then
refinanced the Bridge Notes in full with the proceeds from the issuance of $400.0 million of 7.750% Senior Notes due 2027 and
cash on hand. Kosmos also received $136.6 million in proceeds from a public issuance of 43.1 million shares of Kosmos’
common stock with proceeds used to repay a portion of outstanding borrowings under the Facility during the fourth quarter of
2021.
Under the terms of our 2020 farm-out agreement, potential contingent consideration is payable by Shell depending on
the results of the first four exploration wells Shell drills in the purchased assets, excluding South Africa. Upon approval of the
relevant operating committee of an appraisal plan for submission to the relevant governmental authority for any of those first
four exploration wells, Shell will be required to pay Kosmos $50.0 million of consideration for each discovery for which an
appraisal plan is approved by the relevant operating committee, capped in the aggregate at a maximum of $100.0 million total.
In February 2022, there was an oil discovery announced in Namibia on the first well drilled. Under the terms of Shell’s
Petroleum Agreement with Namibia, if Shell decides to appraise the discovery, an appraisal plan is required to be submitted
within 150 days from completion of tests on the discovery well.
Ghana
During the year ended December 31, 2021, Ghana production averaged approximately 107,700 Bopd gross (26,100
Bopd net) including activity related to our acquisition of additional interests in Ghana commencing October 13, 2021, the
acquisition date. Jubilee production averaged approximately 74,900 Bopd gross (20,200 Bopd net) with consistent water
injection and gas offtake and TEN production averaged approximately 32,800 Bopd gross (5,900 Bopd net). The Ghana Jubilee
catenary anchor leg mooring (“CALM”) buoy was installed and commissioned in February 2021.
In April 2021, operations re-commenced on a multi-year development drilling program. One Jubilee producer well
started production in July 2021 and one Jubilee injector well came online in September 2021. In the fourth quarter of 2021, a
TEN gas injector well and a second Jubilee producer well were successfully completed and brought online in addition to the
66
recompletion of a Jubilee water injection well. The rig has continued drilling operations for the multi-year infill development
drilling program in 2022, which is expected to include the drilling and completion of two water-injection wells and one
producer well in Jubilee and at TEN plans are to drill three development producer wells, one of which is expected to be
completed in 2022, and complete one water-injector well in 2022.
U.S. Gulf of Mexico
During the year ended December 31, 2021, U.S. Gulf of Mexico production averaged approximately 19,700 Boepd
(net) (~82% oil). The impact of the unplanned downtime from hurricanes to our production in the U.S. Gulf of Mexico was
approximately 1,000 barrels of oil equivalent per day for the full year ended December 31, 2021 compared to our previous
production forecasts for 2021. Production returned to around pre-hurricane levels in early fourth quarter of 2021.
In April 2021, the Kodiak #3 infill well located in Mississippi Canyon Block 727 (29.1% working interest) was
brought online with one of two zones intermittently producing. During the third quarter of 2021, the well continued to
experience production issues and was shut-in. Late in the first quarter of 2022, the Company plans to commence operations to
side-track the original Kodiak #3 well, which is expected to be online in the third quarter of 2022, with insurance proceeds
expected to cover the costs incurred to return the Kodiak #3 well to normal operations.
During the second quarter of 2021, the Tornado-5 infill well located in the Green Canyon Block 281 (35.0% working
interest) was successfully drilled and completed. The Tornado-5 well was brought online in July 2021 and is performing at the
top end of expectations.
In January 2021, we announced the Winterfell-1 exploration well encountered approximately 26 meters (85 feet) of net
oil pay in two intervals. Winterfell-1 was designed to test a sub-salt Upper Miocene prospect located in Green Canyon Block
944. In January 2022, the Winterfell-2 appraisal well in Green Canyon Block 943 was drilled to evaluate the adjacent fault
block to the northwest of the original Winterfell discovery and was designed to test two horizons that were oil bearing in the
Winterfell-1 well, with an exploration tail into a deeper horizon. The well discovered approximately 40 meters (120 feet) of net
oil pay in the first and second horizons with better oil saturation and porosity than pre-drill expectations. The exploration tail
discovered an additional oil-bearing horizon in a deeper reservoir which is also prospective in the blocks immediately to the
north.
In July 2021, the Company drilled the Zora infrastructure-led exploration prospect located in DeSoto Canyon Block
266 (37.5% working interest). The well did not find hydrocarbons and was plugged and abandoned in August 2021. The well
results are being integrated into the ongoing evaluation of the surrounding area. The Company recorded approximately $14.6
million of exploration expense for the year ended December 31, 2021 related to the well.
Equatorial Guinea
Production in Equatorial Guinea averaged approximately 29,900 Bopd gross (9,700 Bopd net) for the year ended
December 31, 2021. Two of three planned infill wells in the Okume Complex were drilled and came online during the fourth
quarter of 2021. The third planned well has been deferred, as the rig was utilized to plug and abandon an existing well in
Equatorial Guinea and then mobilized to its next contract before it could complete the drilling of the last well.
Mauritania and Senegal
Greater Tortue Ahmeyim Unit
In July 2021, project partners received notice that the delivery of the Tortue FPSO is likely to be delayed due to
COVID-19 related labor shortages in China following a ramp up in activity at the shipyard. First gas from Phase 1 of the
Greater Tortue project is now expected in the third quarter of 2023, with the project making steady progress during 2021. The
following milestones were achieved through the year-end and filing date:
•
•
•
FLNG: All four mixed refrigerant compressors lifted onboard and the pipe rack installation operations commenced
FPSO: The last four of the eight process modules were successfully lifted onto the FPSO deck
Breakwater: Completed fabrication of the 21st caisson (of 21) with 16 installed
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•
Subsea: The pipe laying vessel completed its nautical trials in the North Sea in preparation for the offshore installation
campaign in the second quarter of 2022
In August 2021, BP, as the operator of the Greater Tortue project (“BP Operator”), with the consent of the Greater
Tortue Unit participants and the respective States, agreed to sell the Greater Tortue FPSO (which is currently under construction
by Technip Energies in China) to an affiliate of BP (“BP Buyer”). The Greater Tortue FPSO will be leased back to BP Operator
under a long-term lease agreement, for exclusive use in the Greater Tortue project. BP Operator will continue to manage and
supervise the construction contract with Technip Energies. Delivery of the Greater Tortue FPSO to BP Buyer will occur after
construction is complete and the Greater Tortue FPSO has been commissioned, with the lease to BP Operator becoming
effective on the same date, currently estimated to be in the third quarter of 2023.
As a result of the above transactions entered into by BP Operator, Kosmos recognized a Long-term receivable of
$200.2 million from BP Operator for our share of the consideration paid from BP Buyer to and held by BP Operator as well as a
$200.2 million FPSO Contract Liability in Other long-term liabilities related to the deferred sale of the Tortue FPSO. This
Long-term receivable will be non-cash settled against obligations payable to BP Operator. During the year ended December 31,
2021, BP Operator settled our payment obligations of $132.4 million of capital expenditures and $42.7 million of existing
Accounts Payable to BP Operator.
During the first quarter of 2021, BP, as the operator of the Cayar block offshore Senegal, provided notice to the
Government of Senegal requesting an extension of the current license phase in order to provide the block owners additional
time to evaluate the natural gas market for the natural gas discoveries at Yakaar-Teranga. In July 2021 a presidential decree was
issued extending the term of the license for up to an additional three years. In 2021, at the conclusion of the second exploration
period, Block C13 offshore Mauritania was relinquished.
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Results of Operations
All of our results, as presented in the table below, represent operations from the Jubilee and TEN fields in Ghana, the
U.S. Gulf of Mexico and Equatorial Guinea. Certain operating results and statistics for the years ended December 31, 2021,
2020 and 2019 are included in the following tables. For a discussion of the year ended December 31, 2020 compared to the year
ended December 31, 2019, please refer to Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and
Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2020.
Sales volumes:
Oil (MBbl)
Gas (MMcf)
NGL (MBbl)
Total (MBoe)
Total (Boepd)
Revenues:
Oil sales
Gas sales
NGL sales
Total revenues
Average oil sales price per Bbl
Average gas sales price per Mcf
Average NGL sales price per Bbl
Average total sales price per Boe
Costs:
Oil and gas production, excluding workovers
Oil and gas production, workovers
Total oil and gas production costs
Depletion, depreciation and amortization
Average cost per Boe:
Oil and gas production, excluding workovers
Oil and gas production, workovers
Total oil and gas production costs
Depletion, depreciation and amortization
Years ended December 31,
2021(1)
2020
2019
(In thousands, except per volume data)
18,525
4,904
508
19,850
54,384
20,531
5,867
602
22,111
60,412
23,331
6,323
548
24,933
68,309
$
1,298,577 $
786,159 $
1,475,706
18,898
14,538
11,706
6,168
15,599
8,111
1,332,013 $
804,033 $
1,499,416
70.10 $
38.29 $
3.85
28.62
67.10
2.00
10.25
36.36
63.25
2.47
14.80
60.14
332,203 $
336,662 $
13,803
1,815
346,006 $
338,477 $
370,962
31,651
402,613
467,221 $
485,862 $
563,861
$
$
$
$
$
$
16.74 $
15.23 $
0.70
17.44
23.54
0.08
15.31
21.97
14.88
1.27
16.15
22.62
38.77
Total oil and gas production costs, depletion, depreciation and amortization
$
40.98 $
37.28 $
(1)
Includes activity related to our acquisition of additional interests in Ghana commencing October 13, 2021, the
acquisition date.
69
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.
Year Ended December 31, 2021 vs. 2020
Revenues and other income:
Oil and gas revenue
Gain on sale of assets
Other income, net
Total revenues and other income
Costs and expenses:
Oil and gas production
Facilities insurance modifications, net
Exploration expenses
General and administrative
Depletion, depreciation and amortization
Impairment of long-lived assets
Interest and other financing costs, net
Derivatives, net
Other expenses, net
Total costs and expenses
Loss before income taxes
Income tax expense (benefit)
Net loss
Years Ended December 31,
2021(1)
2020
Increase
(Decrease)
(In thousands)
$
1,332,013 $
804,033 $
527,980
1,564
262
92,163
(90,599)
2
260
1,333,839
896,198
437,641
346,006
338,477
(1,586)
65,382
91,529
467,221
—
128,371
270,185
10,111
13,161
84,616
72,142
485,862
153,959
109,794
17,180
37,802
1,377,219
1,312,993
(43,380)
(416,795)
34,456
(5,209)
7,529
(14,747)
(19,234)
19,387
(18,641)
(153,959)
18,577
253,005
(27,691)
64,226
373,415
39,665
$
(77,836) $
(411,586) $
333,750
(1)
Includes activity related to our acquisition of additional interests in Ghana commencing October 13, 2021, the
acquisition date.
Oil and gas revenue. Oil and gas revenue increased by $528.0 million as a result of higher oil prices, which was
partially offset by lower sales volumes during 2021 across our portfolio. Additionally, we had two liftings after the acquisition
date related to our acquisition of additional interests in Ghana during the fourth quarter of 2021. We sold 19,850 MBoe at an
average realized price per barrel of oil equivalent of $67.10 in 2021 and 22,111 MBoe at an average realized price per barrel of
oil equivalent of $36.36 in 2020.
Gain on sale of assets. In December 2020, we closed a farm-out agreement with Shell for a portfolio of frontier
exploration assets in blocks offshore Sao Tome and Principe, Suriname, and Namibia. As part of the transaction, we received
proceeds in excess of our book basis resulting in a gain of approximately $92.1 million.
Oil and gas production. Oil and gas production costs increased by $7.5 million during the year ended December 31,
2021 as compared to the year ended December 31, 2020 as a result of two additional liftings related to our acquisition of
additional interests in Ghana during the fourth quarter of 2021 in addition to higher production costs per barrel from the TEN
fields offshore Ghana, field production mix in the U.S. Gulf of Mexico, and additional workover activity in 2021.
Facilities insurance modifications, net. Facilities insurance modifications, net decreased by $14.7 million during the
year ended December 31, 2021 as compared to the year ended December 31, 2020 as the catenary anchor leg mooring
(“CALM”) Buoy, the final phase of the long-term solution to the Jubilee turret remediation project, was installed and
commissioned in February 2021.
Exploration expenses. Exploration expenses decreased by $19.2 million during the year ended December 31, 2021, as
compared to the year ended December 31, 2020. The decrease is primarily a result of lower geological, geophysical, and
seismic costs incurred in 2021 versus the prior period related to the U.S. Gulf of Mexico business unit and other exploration
license areas sold to Shell in 2020. This decrease is partially offset by the Zora exploration well which did not find
70
hydrocarbons and was plugged and abandoned in August 2021 with $14.6 million of well costs charged to exploration expense
for the year ended December 31, 2021.
General and administrative. General and administrative costs increased by $19.4 million during the year ended
December 31, 2021, as compared to the year ended December 31, 2020 primarily as a result of no employee or officers bonuses
in 2020 as part of management’s response to COVID-19 offset by reduced employee compensation and general office expenses
in 2021.
Depletion, depreciation and amortization. Depletion, depreciation and amortization decreased $18.6 million during the
year ended December 31, 2021, as compared with the year ended December 31, 2020 due to lower production volumes during
2021, partially offset by higher depletion rates during 2021 related to a reduction of proved reserves in the fourth quarter of
2020 largely tied to lower 2020 oil prices.
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 $154.0 million during the year ended December 31,
2020 for oil and gas proved properties in the U.S. Gulf of Mexico. We did not recognize impairment of proved oil and gas
properties during the year ended December 31, 2021 as no impairment indicators were identified.
Interest and other financing costs, net. Interest and other financing costs, net increased by $18.6 million during the
year ended December 31, 2021, as compared to the year ended December 31, 2020 primarily a result of $19.6 million for loss
on extinguishment of debt related to the Facility amendment and the Bridge Notes and a $26.9 million increase in interest
expense from increased outstanding debt balance as a result of the issuance of the 7.750% Senior Notes and the 7.500% Senior
Notes during 2021. These increases were partially offset by increased interest income on long-term notes receivables with the
national oil companies of Mauritania and Senegal, as well as increased capitalized interest related to additional spend on the
Greater Tortue Ahmeyim project during 2021.
Derivatives, net. During the years ended December 31, 2021 and 2020, we recorded a loss of $270.2 million and $17.2
million, respectively, on our outstanding hedge positions. The changes recorded were a result of changes in the forward curve
of oil prices during the respective periods.
Other expenses, net. Other expenses, net decreased $27.7 million from the prior year, primarily related to $16.4 million
in restructuring charges for employee severance and related benefit costs as part of management’s response to COVID-19 and
$11.2 million of asset impairments recorded in 2020.
Income tax expense (benefit). For the year ended December 31, 2021, our overall effective tax rates were impacted by
the difference in our 21% U.S. income tax reporting rate and the 35% statutory tax rates applicable to our Ghanaian and
Equatorial Guinean operations, jurisdictions that have a 0% statutory tax rate or where we have incurred losses and have
recorded valuation allowances against the corresponding deferred tax assets and other non-deductible expenses, primarily in the
U.S. Additionally for December 31, 2020, our overall effective tax rate was impacted by a $30.9 million deferred tax expense
related to valuation allowances on U.S. deferred tax assets recognized in a prior periods, and a $4.9 million tax benefit
associated with the Coronavirus Aid, Relief and Economic Security ACT (“CARES ACT”).
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. Current commodity prices, combined with our hedging
program, and our current liquidity position support our capital program for 2022.
As such, our 2022 capital budget is based on our exploitation and production plans for Ghana, Equatorial Guinea and
the U.S. Gulf of Mexico, our infrastructure-led exploration and appraisal program in the U.S. Gulf of Mexico and Equatorial
Guinea, and our exploration, appraisal and development activities in Mauritania and Senegal.
Our future financial condition and liquidity can be impacted by, among other factors, the success of our exploitation,
exploration and appraisal drilling programs, the number of commercially viable oil and natural gas discoveries made and the
71
quantities of oil and natural gas discovered, the speed with which we can bring such discoveries to production, the reliability of
our oil and gas production facilities, our ability to continuously export oil and gas, our ability to secure and maintain partners
and their alignment with respect to capital plans, the actual cost of exploitation, exploration, appraisal and development of our
oil and natural gas assets, and coverage of any claims under our insurance policies.
In May 2021, in conjunction with the spring borrowing base redetermination, the Company agreed to an amendment
and restatement of the Facility including a reduction in the facility size to $1.25 billion (from $1.5 billion), As amended, the
Facility has an available borrowing base of $1.24 billion. During the September 2021 redetermination, the Company’s lending
syndicate approved a borrowing base capacity of $1.25 billion. The borrowing base calculation includes value related to the
Jubilee, TEN, Ceiba and Okume fields, however, excludes the additional interests in Jubilee and TEN acquired in the recent
acquisition of Anadarko WCTP.
In September 2020, the Company entered into a five-year $200.0 million senior secured term-loan credit agreement
secured against the Company's U.S. Gulf of Mexico assets with $175.0 million outstanding as of December 31, 2021.
Sources and Uses of Cash
The following table presents the sources and uses of our cash and cash equivalents for the years ended December 31,
2021, 2020 and 2019:
Sources of cash, cash equivalents and restricted cash:
Net cash provided by operating activities
Net proceeds from issuance of senior notes
Net proceeds from issuance of common stock
Borrowings under long-term debt
Advances under production prepayment agreement
Proceeds on sale of assets
Uses of cash, cash equivalents and restricted cash:
Oil and gas assets
Acquisition of oil and gas properties
Notes receivable from partners
Payments on long-term debt
Redemption of senior secured notes
Purchase of treasury stock
Dividends
Deferred financing costs
Years Ended December 31,
2021
2020
2019
(In thousands)
$
374,344 $
196,145 $
839,375
136,006
725,000
—
6,354
—
—
300,000
50,000
99,118
628,150
641,875
—
175,000
—
15,000
2,081,079
645,263
1,460,025
472,631
465,367
41,733
1,050,000
—
1,100
512
24,604
2,055,947
379,593
352,013
—
65,112
250,000
—
4,947
19,271
5,922
—
26,918
425,000
535,338
1,983
72,599
2,444
724,845
1,416,295
Increase (decrease) in cash, cash equivalents and restricted cash
$
25,132 $
(79,582) $
43,730
Net cash provided by operating activities. Net cash provided by operating activities in 2021 was $374.3 million
compared with net cash provided by operating activities of $196.1 million in 2020 and $628.2 million in 2019, respectively.
The increase in cash provided by operating activities in the year ended December 31, 2021 when compared to the same period
in 2020 is primarily a result of increased oil prices. The decrease in cash provided by operating activities in the year ended
December 31, 2020 when compared to the same period in 2019 is primarily a result of lower production across our assets and
lower oil prices stemming from the excess market supplies related to the COVID-19 pandemic.
72
The following table presents our liquidity and financial position as of December 31, 2021:
Cash and cash equivalents
Restricted cash
7.125% Senior Notes
7.750% Senior Notes
7.500% Senior Notes
Borrowings under the Facility
Borrowings under the Corporate Revolver
Borrowings under the GoM Term Loan
Net debt
Availability under the Facility
Availability under the Corporate Revolver
Available borrowings plus cash and cash equivalents
Capital Expenditures and Investments
We expect to incur capital costs as we:
December 31, 2021
(In thousands)
131,620
43,276
650,000
400,000
450,000
1,000,000
—
175,000
2,500,104
235,155
400,000
766,775
$
$
$
$
$
•
•
•
drill additional infill wells and execute exploitation and production activities in Ghana, Equatorial Guinea and
the U.S. Gulf of Mexico;
execute infrastructure-led exploration and appraisal efforts in the U.S. Gulf of Mexico and Equatorial Guinea;
and
execute appraisal and development activities in Mauritania and Senegal.
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.
2022 Capital Program
We estimate we will spend approximately $700 million of capital for the year ending December 31, 2022. This capital
expenditure budget consists of:
•
•
•
Approximately $250-$300 million related to maintenance activities across our Ghana, Equatorial Guinea and
U.S. Gulf of Mexico assets, including infill development drilling and integrity spend
Approximately $100-$150 million related to growth activities across our Ghana, Equatorial Guinea and U.S.
Gulf of Mexico assets, primarily pre-investment for infrastructure required to support production growth in
2023 and beyond
Approximately $250 million related to development of Phase 1 of GTA, net of FPSO transaction benefit
73
•
Approximately $50 million related to progressing the appraisal plans of our greater gas resource in Mauritania
and Senegal, including Phase 2 of GTA, BirAllah and Yakaar-Teranga.
Our estimated capital spend may be reduced by up to $40 million, depending on timing, if the pre-emption of our
acquisition of additional interests in Ghana discussed in “Item 8. Financial Statements and Supplementary Data—Note 3—
Acquisitions and Divestitures” is completed. The ultimate amount of capital we will spend may fluctuate materially based on
market conditions and the success of our exploitation and drilling results among other factors. Our future financial condition
and liquidity will be impacted by, among other factors, our level of production of oil and the prices we receive from the sale of
oil, our ability to effectively hedge future production volumes, the success of our multi-faceted infrastructure-led exploration
and appraisal drilling programs, the number of commercially viable oil and natural gas discoveries made and the quantities of
oil and natural gas discovered, the speed with which we can bring such discoveries to production, our partners’ alignment with
respect to capital plans, and the actual cost of exploitation, exploration, appraisal and development of our oil and natural gas
assets, and coverage of any claims under our insurance policies.
Significant Sources of Capital
Facility
The Facility supports our oil and gas exploration, appraisal and development programs and corporate activities with a
borrowing base calculation that includes value related to the Jubilee, TEN, Ceiba and Okume fields, however, the additional
interests in Jubilee and TEN acquired in the recent acquisition of Anadarko WCTP are not included in the borrowing base
calculation. In May 2021, the Company entered into an amended and restated facility agreement and certain ancillary
documents. As amended, the available borrowing base was approximately $1.24 billion. During the September 2021
redetermination, the Company’s lending syndicate approved a borrowing base capacity in excess of the facility size of $1.25
billion. As of December 31, 2021, borrowings under the Facility totaled $1.0 billion and the undrawn availability under the
Facility was $235.2 million, (limited by current commitments).
The Facility provides a revolving credit and letter of credit facility. The availability period for the revolving credit
facility expires one month prior to the final maturity date. The letter of credit facility expires on the final maturity date. The
available facility amount is subject to borrowing base constraints and, beginning on March 31, 2024, outstanding borrowings
will be constrained by an amortization schedule. The Facility has a final maturity date of March 31, 2027. As of December 31,
2021, we had no letters of credit issued under the Facility.
We have the right to cancel all the undrawn commitments under the amended and restated Facility. The amount of
funds available to be borrowed under the Facility, also known as the borrowing base amount, is determined every March and
September. The borrowing base amount is based on the sum of the net present values of net cash flows and relevant capital
expenditures reduced by certain percentages as well as value attributable to certain assets’ reserves and/or resources in Ghana
and Equatorial Guinea, however, excludes the additional interests in Jubilee and TEN acquired in the recent acquisition of
Anadarko WCTP.
If an event of default exists under the Facility, the lenders can accelerate the maturity and exercise other rights and
remedies, including the enforcement of security granted pursuant to the Facility over certain asset. We were in compliance with
the financial covenants contained in the Facility as of September 30, 2021 (the most recent assessment date). The Facility
contains customary cross default provisions.
Corporate Revolver
In August 2018, we amended and restated the Corporate Revolver maintaining the borrowing capacity at $400.0
million, extending the maturity date from November 2018 to May 2022 and lowering the margin 100 basis points to 5%. This
results in lower commitment fees on the undrawn portion of the total commitments, which is 30% per annum of the respective
margin. The Corporate Revolver is available for general corporate purposes and for oil and gas exploration, appraisal and
development programs. As of December 31, 2021, there were no outstanding borrowings under the Corporate Revolver and the
undrawn availability under the Corporate Revolver was $400.0 million.
The Corporate Revolver expires on May 31, 2022. The available amount is not subject to borrowing base constraints.
We have the right to cancel all the undrawn commitments under the Corporate Revolver. We are required to repay certain
amounts due under the Corporate Revolver with sales of certain subsidiaries or sales of certain assets. If an event of default
exists under the Corporate Revolver, the lenders can accelerate the maturity and exercise other rights and remedies, including
the enforcement of security granted pursuant to the Corporate Revolver over certain assets held by us.
74
We were in compliance with the financial covenants contained in the Corporate Revolver as of September 30, 2021
(the most recent assessment date). The Corporate Revolver contains customary cross default provisions. We intend to refinance
the Corporate Revolver in the first quarter of 2022.
The U.S. and many foreign economies continue to experience uncertainty driven by varying macroeconomic
conditions. Although some of these economies have shown signs of improvement, macroeconomic recovery remains uneven.
Uncertainty in the macroeconomic environment and associated global economic conditions have resulted in extreme volatility
in credit, equity, and foreign currency markets, including the European sovereign debt markets and volatility in various other
markets. If any of the financial institutions within our Facility or Corporate Revolver are unable to perform on their
commitments, our liquidity could be impacted. We actively monitor all of the financial institutions participating in our Facility
and Corporate Revolver. None of the financial institutions have indicated to us that they may be unable to perform on their
commitments. In addition, we periodically review our banking and financing relationships, considering the stability of the
institutions and other aspects of the relationships. Based on our monitoring activities, we currently believe our banks will be
able to perform on their commitments.
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. See Note 8 of Notes to the Consolidated Financial
Statements included in "Item 8. Financial Statements and Supplementary Data."
The 7.125% Senior Notes indenture restricts the ability of the Company and its restricted subsidiaries to, among other
things: incur or guarantee additional indebtedness, create liens, pay dividends or make distributions in respect of capital stock,
purchase or redeem capital stock, make investments or certain other restricted payments, sell assets, enter into agreements that
restrict the ability of the Company’s subsidiaries to make dividends or other payments to the Company, enter into transactions
with affiliates, or effect certain consolidations, mergers or amalgamations. These covenants are subject to a number of
important qualifications and exceptions. Certain of these covenants will be terminated if the 7.125% Senior Notes are assigned
an investment grade rating by both Standard & Poor’s Rating Services and Fitch Ratings Inc. and no default or event of default
has occurred and is continuing. The 7.125% Senior Notes contain customary cross default provisions.
7.750% Senior Notes due 2027
In October 2021, the Company issued $400.0 million of 7.750% Senior Notes and received net proceeds of
approximately $395.0 million after deducting fees. We used the net proceeds, together with cash on hand, to refinance the
Bridge Notes and to pay expenses related to the issuance of the 7.750% Senior Notes.
The 7.750% Senior Notes indenture restricts the ability of the Company and its restricted subsidiaries to, among other
things: incur or guarantee additional indebtedness, create liens, pay dividends or make distributions in respect of capital stock,
purchase or redeem capital stock, make investments or certain other restricted payments, sell assets, enter into agreements that
restrict the ability of the Company's subsidiaries to make dividends or other payments to the Company, enter into transactions
with affiliates, or effect certain consolidations, mergers or amalgamations. These covenants are subject to a number of
important qualifications and exceptions. Certain of these covenants will be terminated if the 7.750% Senior Notes are assigned
an investment grade rating by both Standard & Poor’s Rating Services and Fitch Ratings Inc. and no default or event of default
has occurred and is continuing. The 7.750% Senior Notes contain customary cross default provisions.
7.500% Senior Notes due 2028
In March 2021, the Company issued $450.0 million of 7.500% Senior Notes and received net proceeds of
approximately $444.4 million after deducting fees. We used the net proceeds to repay outstanding indebtedness under the
Corporate Revolver and the Facility, to pay expenses related to the issuance of the 7.500% Senior Notes and for general
corporate purposes.
The 7.500% Senior Notes indenture restricts the ability of the Company and its restricted subsidiaries to, among other
things: incur or guarantee additional indebtedness, create liens, pay dividends or make distributions in respect of capital stock,
purchase or redeem capital stock, make investments or certain other restricted payments, sell assets, enter into agreements that
restrict the ability of the Company's subsidiaries to make dividends or other payments to the Company, enter into transactions
with affiliates, or effect certain consolidations, mergers or amalgamations. These covenants are subject to a number of
important qualifications and exceptions. Certain of these covenants will be terminated if the 7.500% Senior Notes are assigned
an investment grade rating by both Standard & Poor’s Rating Services and Fitch Ratings Inc. and no default or event of default
has occurred. The 7.500% Senior Notes contain customary cross default provisions.
75
GoM Term Loan
In September 2020, the Company entered into a five-year $200 million senior secured term-loan credit agreement
secured against the Company's U.S. Gulf of Mexico assets with net proceeds received of $197.7 million after deducting fees
and other expenses. The GoM Term Loan also includes an accordion feature providing for incremental commitments of up to
$100 million subject to certain conditions. As of December 31, 2021, borrowings under the GoM Term Loan totaled $175
million.
The GoM Term Loan contains customary affirmative and negative covenants, including covenants that affect our
ability to incur additional indebtedness, create liens, merge, dispose of assets, and make distributions, dividends, investments or
capital expenditures, among other things. The GoM Term Loan is guaranteed on a senior, secured basis by certain subsidiaries
owning the Company's U.S. Gulf of Mexico assets.
The GoM Term Loan includes certain representations and warranties, indemnities and events of default that, subject to
certain materiality thresholds and grace periods, arise as a result of a payment default, failure to comply with covenants,
material inaccuracy of representation or warranty, and certain bankruptcy or insolvency proceedings. If there is an event of
default, all or any portion of the outstanding indebtedness may be immediately due and payable and other rights may be
exercised including against the collateral.
Contractual Obligations
The following table presents maturities by expected debt maturity dates, the weighted-average interest rates expected
to be paid on the Facility, Corporate Revolver and GoM Term Loan given current contractual terms and market conditions, and
the instrument’s estimated fair value. Weighted‑average interest rates are based on implied forward rates in the yield curve at
the reporting date. This table does not take into account amortization of deferred financing costs.
Years Ending December 31,
Asset
(Liability)
Fair Value at
December 31,
2022
2023
2024
2025
2026
Thereafter
Total(3)
2021
(In thousands, except percentages)
$ —
$
—
—
$
$
—
—
—
—
—
—
—
—
—
$ 650,000
$
—
$ 650,000 $
632,587
—
—
400,000
450,000
400,000
450,000
386,428
424,688
Fixed rate debt:
7.125% Senior Notes
7.750% Senior Notes
7.500% Senior Notes
Variable rate debt:
Weighted average interest rate
4.53 %
5.13 %
5.64 %
5.79 %
6.23 %
6.48 %
Facility(1)
GoM Term Loan
$ —
$
—
$ 307,785
$ 242,977
$ 289,350
$ 159,888
$ 1,000,000 $
1,000,000
30,000
30,000
30,000
85,000
—
—
175,000
175,000
Total principal debt repayments (1)
$ 30,000
$ 30,000
$ 337,785
$ 327,977
$ 939,350
$ 1,009,888
$ 2,675,000
Interest & commitment fees on long-
term debt
Operating leases(2)
170,073
172,256
165,724
149,057
107,500
68,763
833,373
3,974
4,077
4,148
4,219
4,290
10,874
31,582
______________________________________
(1)
(2)
(3)
The amounts included in the table represent principal maturities only. The scheduled maturities of debt related to the
Facility are based on the level of borrowings and the available borrowing base as of December 31, 2021. 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.
Primarily relates to corporate office and foreign office leases.
Does not include our share of operator’s purchase commitments for jointly owned fields and facilities where we are
not the operator and excludes commitments for exploration activities, including well commitments and seismic
obligations, in our petroleum contracts. The Company's liabilities for asset retirement obligations associated with the
76
dismantlement, abandonment and restoration costs of oil and gas properties are not included. See Note 11 of Notes to
the Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for
additional information regarding these liabilities.
We currently have a commitment to drill one exploration well in Mauritania and a $200.2 million FPSO Contract
Liability related to the deferred sale of the Greater Tortue FPSO.
In February 2019, Kosmos and BP signed Carry Advance Agreements with the national oil companies of Mauritania
and Senegal, which obligate us separately to finance the respective national oil company’s share of certain development
costs. Kosmos’ total share for the two agreements combined is currently estimated at approximately $240.0 million, of which
$145.2 million has been incurred through December 31, 2021. These amounts will be repaid through the national oil
companies’ share of future revenues.
Critical Accounting Policies
This discussion of financial condition and results of operations is based upon the information reported in our
consolidated financial statements, which have been prepared in accordance with generally accepted accounting principles in the
United States. The preparation of our financial statements requires us to make assumptions and estimates that affect the reported
amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities as of the date
the financial statements are available to be issued. These estimates could change materially if different information or
assumptions were used. We base our assumptions and estimates on historical experience and other sources that we believe to be
reasonable at the time. Actual results may vary from our estimates. Our significant accounting policies are detailed in “Item 8.
Financial Statements and Supplementary Data—Note 2—Accounting Policies.” We have outlined below certain accounting
policies that are of particular importance to the presentation of our financial position and results of operations and require the
application of significant judgment or estimates by our management.
Revenue Recognition. We recognize revenues on the volumes of hydrocarbons sold to a purchaser. The volumes sold
may be more or less than the volumes to which we are entitled based on our ownership interest in the property. These
differences result in a condition known in the industry as a production imbalance. A receivable or liability is recognized only to
the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves on such
property. As of December 31, 2021 and 2020, we had no oil and gas imbalances recorded in our consolidated financial
statements.
Our oil and gas revenues are recognized when hydrocarbons have been sold to a purchaser at a fixed or determinable
price, title has transferred and collection is probable. Certain revenues are based on provisional price contracts which contain an
embedded derivative that is required to be separated from the host contract for accounting purposes. The host contract is the
receivable from oil sales at the spot price on the date of sale. The embedded derivative, which is not designated as a hedge, is
marked to market through oil and gas revenue each period until the final settlement occurs, which generally is limited to the
month after the sale.
Exploration and Development Costs. We follow the successful efforts method of accounting for our oil and gas
properties. Acquisition costs for proved and unproved properties are capitalized when incurred. Costs of unproved properties
are transferred to proved properties when a determination that proved reserves have been found. Exploration costs, including
geological and geophysical costs and costs of carrying unproved properties, are expensed as incurred. Exploratory drilling costs
are capitalized when incurred. If exploratory wells are determined to be commercially unsuccessful or dry holes, the applicable
costs are expensed and recorded in exploration expense on the consolidated statement of operations. Costs incurred to drill and
equip development wells, including unsuccessful development wells, are capitalized. Costs incurred to operate and maintain
wells and equipment and to lift oil and natural gas to the surface are expensed as oil and gas production expense.
Income Taxes. We account for income taxes as required by the ASC 740—Income Taxes (“ASC 740”). We make
certain estimates and judgments in determining our income tax expense for financial reporting purposes. These estimates and
judgments occur in the calculation of certain tax assets and liabilities that arise from differences in the timing and recognition of
revenue and expense for tax and financial reporting purposes. Our federal, state and international tax returns are generally not
prepared or filed before the consolidated financial statements are prepared; therefore, we estimate the tax basis of our assets and
liabilities at the end of each period as well as the effects of changes in tax laws or tax rates, tax credits, and net operating loss
carryforwards. Adjustments related to these estimates are recorded in our tax provision in the period in which we file our
income tax returns. Further, we must assess the likelihood that we will be able to realize or utilize our deferred tax assets. If
realization is not more likely than not, we must record a valuation allowance against such deferred tax assets for the amount we
would not expect to recover, which would result in no benefit for the deferred tax amounts. As of December 31, 2021 and 2020,
77
we have a valuation allowance to reduce certain deferred tax assets to amounts that are more likely than not to be realized. If
our estimates and judgments regarding our ability to realize our deferred tax assets change, the benefits associated with those
deferred tax assets may increase or decrease in the period our estimates and judgments change. On a quarterly basis,
management evaluates the need for and adequacy of valuation allowances based on the expected realizability of the deferred tax
assets and adjusts the amount of such allowances, if necessary.
ASC 740 provides a more‑likely‑than‑not standard in evaluating whether a valuation allowance is necessary after
weighing all of the available evidence. When evaluating the need for a valuation allowance, we consider all available positive
and negative evidence, including the following:
• the status of our operations in the particular taxing jurisdiction, including whether we have commenced production
from a commercial discovery;
• whether a commercial discovery has resulted in significant proved reserves that have been independently verified;
• the amounts and history of taxable income or losses in a particular jurisdiction;
• projections of future income, including the sensitivity of such projections to changes in production volumes and prices;
• the existence, or lack thereof, of statutory limitations on the period that net operating losses may be carried forward in
a jurisdiction; and
• the creation and timing of future income associated with the reversal of deferred tax liabilities in excess of deferred tax
assets.
Estimates of Proved Oil and Natural Gas Reserves. Reserve quantities and the related estimates of future net cash
flows affect our periodic calculations of depletion and assessment of impairment of our oil and natural gas properties. Proved
oil and natural gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that geological and
engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under
existing economic and operating conditions. As additional proved reserves are discovered, reserve quantities and future cash
flows will be estimated by independent petroleum consultants and prepared in accordance with guidelines established by the
SEC and the FASB. The accuracy of these reserve estimates is a function of:
• the engineering and geological interpretation of available data;
• estimates of the amount and timing of future operating cost, production taxes, development cost and workover cost;
• the accuracy of various mandated economic assumptions; and
• the judgments of the persons preparing the estimates.
Asset Retirement Obligations. We account for asset retirement obligations as required by ASC 410 — Asset
Retirement and Environmental Obligations. Under these standards, the fair value of a liability for an asset retirement obligation
is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. If a reasonable estimate of
fair value cannot be made in the period the asset retirement obligation is incurred, the liability is recognized when a reasonable
estimate of fair value can be made. If a tangible long‑lived asset with an existing asset retirement obligation is acquired, a
liability for that obligation is recognized at the asset’s acquisition or in service date. In addition, a liability for the fair value of a
conditional asset retirement obligation is recorded if the fair value of the liability can be reasonably estimated. We capitalize the
asset retirement costs by increasing the carrying amount of the related long‑lived asset by the same amount as the liability. We
record increases in the discounted abandonment liability resulting from the passage of time in depletion, depreciation and
amortization in the consolidated statement of operations. Estimating the future restoration and removal costs requires
management to make estimates and judgments because most of the removal obligations are many years in the future and
contracts and regulations often have vague descriptions of what constitutes removal. Additionally, asset removal technologies
and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.
Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement
amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory,
environmental and political environments. To the extent future revisions to these assumptions impact the present value of the
existing asset retirement obligations, a corresponding adjustment is made to the oil and gas property balance.
Impairment of Long‑lived Assets. We review our long‑lived assets for impairment when changes in circumstances
indicate that the carrying amount of an asset may not be recoverable. ASC 360 — Property, Plant and Equipment requires an
78
impairment loss to be recognized if the carrying amount of a long‑lived asset is not recoverable and exceeds its fair value. The
carrying amount of a long‑lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result
from the use and eventual disposition of the asset. That assessment shall be based on the carrying amount of the asset at the date
it is tested for recoverability, whether in use or under development. Assets to be disposed of and assets not expected to provide
any future service potential to us are recorded at the lower of carrying amount or fair value. Oil and gas properties are grouped
in accordance with ASC 932 — Extractive Activities-Oil and Gas. The basis for grouping is a reasonable aggregation of
properties typically by field or by logical grouping of assets with significant shared infrastructure.
For long-lived assets whereby the carrying value exceeds the estimated future undiscounted cash flows, the carrying
amount is reduced to fair value. Fair value is generally estimated using the income approach described in the ASC 820 — Fair
Value Measurement. If applicable, we utilize prices and other relevant information generated by market transactions involving
assets and liabilities that are identical or comparable to the item being measured as the basis for determining fair value. The
expected future cash flows used for impairment reviews and related fair value measurements are typically based on judgmental
assessments of future production, pricing estimates, capital and operating costs, market-based weighted average cost of capital,
and risk adjustment factors applied to reserves. These assumptions are applied to develop future cash flow projections that are
then discounted to estimated fair value, using a market-based weighted-average cost of capital. Although we base the fair value
estimate of each asset group on assumptions we believe to be reasonable, those assumptions are inherently unpredictable and
uncertain, and actual results could differ from the estimate. Negative revisions of estimated reserve quantities, increases in
future cost estimates, divestiture of a significant component of the asset group, or sustained decreases in crude oil prices could
lead to a reduction in expected future cash flows and possibly an additional impairment of long-lived assets in future periods.
We believe the assumptions used in our analysis to test for impairment are appropriate and result in a reasonable
estimate of future cash flows and fair value. Kosmos has consistently used an average of third-party industry forecasts to
determine our pricing assumptions. Where unproved reserves exist, an appropriately risk-adjusted amount of these reserves may
be included in the evaluation.
Acquisition Accounting. The purchase price in an acquisition (business combination or asset acquisition) is allocated
to the assets acquired and liabilities assumed based on their relative fair values as of the acquisition date, which may occur
many months after the deal announcement date. Therefore, while the consideration to be paid may be fixed, the fair value of the
assets acquired, and liabilities assumed is subject to change during the period between the announcement date and the
acquisition date. The most significant estimates in the allocation typically relate to the value assigned to future recoverable oil
and natural gas reserves and unproved properties. As the allocation of the purchase price is subject to significant estimates and
subjective judgments, the accuracy of this assessment is inherently uncertain.
New Accounting Pronouncements
See “Item 8. Financial Statements and Supplementary Data—Note 2—Accounting Policies” for a discussion of recent
accounting pronouncements.
Item 7A. Qualitative and Quantitative Disclosures About Market Risk
The primary objective of the following information is to provide forward‑looking quantitative and qualitative
information about our potential exposure to market risks. The term “market risks” as it relates to our currently anticipated
transactions refers to the risk of loss arising from changes in commodity prices and interest rates. These disclosures are not
meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This
forward‑looking information provides indicators of how we view and manage ongoing market risk exposures. We enter into
market‑risk sensitive instruments for purposes other than to speculate.
We manage market and counterparty credit risk in accordance with our policies. In accordance with these policies and
guidelines, our management determines the appropriate timing and extent of derivative transactions. See “Item 8. Financial
Statements and Supplementary Data—Note 2—Accounting Policies, Note 9—Derivative Financial Instruments and Note 10—
Fair Value Measurements” for a description of the accounting procedures we follow relative to our derivative financial
instruments.
79
The following table reconciles the changes that occurred in fair values of our open derivative contracts during the year
ended December 31, 2021:
Fair value of contracts outstanding as of December 31, 2020
Changes in contract fair value
Contract maturities
Fair value of contracts outstanding as of December 31, 2021
Commodity Price Risk
Derivative Contracts
Assets (Liabilities)
Commodities
(In thousands)
$
$
(20,377)
(277,705)
231,767
(66,315)
The ongoing COVID-19 pandemic that emerged at the beginning of 2020 has resulted in travel restrictions, including
border closures, travel bans, social distancing restrictions, various quarantine measures 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
impacted demand for oil, which also resulted in significant variations in oil prices. 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 during 2021 ranged between $50.34 and $86.12 per Bbl for Dated Brent, with Heavy Louisiana
Sweet experiencing similar volatility during 2021.
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. In addition, a reduction in our ability to access
credit could reduce our ability to implement derivative contracts on commercially reasonable terms.
Commodity Price Sensitivity
The following table provides information about our oil derivative financial instruments that were sensitive to changes
in oil prices as of December 31, 2021:
Term
2022:
Type of Contract
Index
MBbl
Weighted Average Price per Bbl
Net
Deferred
Premium
Payable/
(Receivable)
Swap
Sold Put
Floor
Ceiling
Asset
(Liability)
Fair Value at
December 31,
2021(2)
(In thousands)
January — December
Three-way collars
Dated Brent
4,500
$
0.64
$
—
$
43.33
$
56.67
$
76.91
$
(26,321)
January — December
Three-way collars
NYMEX WTI
1,000
January — December
Two-way collars
January — December
Sold calls(1)
Dated Brent
Dated Brent
7,000
1,581
1.45
1.12
—
—
—
—
50.00
—
—
65.00
63.57
—
85.00
84.29
60.00
(1,301)
(10,243)
(27,596)
______________________________________
(1)
(2)
Represents call option contracts sold to counterparties to enhance other derivative positions.
Fair values are based on the average forward oil prices on December 31, 2021.
In January 2022, we entered into Dated Brent three-way collar contracts for 2.0 MMBbl from January 2023 through
December 2023 with an average sold put price of $47.50 per barrel, a floor price of $65.00 per barrel and an average ceiling
price of $95.25 per barrel.
80
At December 31, 2021, our open commodity derivative instruments were in a net liability position of $65.5 million. As
of December 31, 2021, a hypothetical 10% price increase in the commodity futures price curves would decrease future pre‑tax
earnings by approximately $63.6 million. Similarly, a hypothetical 10% price decrease would increase future pre‑tax earnings
by approximately $60.6 million.
Interest Rate Sensitivity
Changes in market interest rates affect the amount of interest we pay on certain of our borrowings. Outstanding
borrowings under the Facility, Corporate Revolver and GoM Term Loan, which as of December 31, 2021 total approximately
$1.2 billion and have a weighted average interest rate of 4.3%, are subject to variable interest rates, which expose us to the risk
of earnings or cash flow loss due to potential increases in market interest rates. If the floating market rate increased 10% at this
level of floating rate debt, we would pay an estimated additional $0.2 million interest expense per year. The commitment fees
on the undrawn availability under the Facility and the Corporate Revolver are not subject to changes in interest rates. All of our
other long-term indebtedness is fixed rate and does not expose us to the risk of cash flow loss due to changes in market interest
rates. Additionally, a change in the market interest rates could impact interest costs associated with future debt issuances or any
future borrowings.
81
Item 8. Financial Statements and Supplementary Data
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Consolidated Financial Statements of Kosmos Energy Ltd.:
Reports of Independent Registered Public Accounting Firm (PCAOB ID: 00042)
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Shareholders’ Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
Supplemental Oil and Gas Data (Unaudited)
Page
83
87
88
89
90
91
124
82
Report of Independent Registered Public Accounting Firm
To the Shareholders and the Board of Directors of Kosmos Energy Ltd.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Kosmos Energy Ltd. (the Company) as of December 31,
2021 and 2020, the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the three
years in the period ended December 31, 2021, and the related notes and financial statement schedules listed in the Index at
Item 15(a) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial
statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020,
and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in
conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
(PCAOB), the Company’s internal control over financial reporting as of December 31, 2021, based on criteria established in
Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission
(2013 framework) and our report dated February 28, 2022 expressed an unqualified opinion thereon.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company‘s management. Our responsibility is to express
an opinion on the Company‘s consolidated financial statements based on our audits. We are a public accounting firm
registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S.
federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due
to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated
financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures
include examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements.
Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as
evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable
basis for our opinion.
Critical audit matters
The critical audit matters communicated below are matters arising from the current period audit of the financial statements
that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures
that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments.
The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements,
taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the
critical audit matters or on the accounts or disclosures to which they relate.
83
Description
of the
Matter
Depletion of proved oil and natural gas properties
At December 31, 2021, the net book value of the Company’s proved oil and natural gas properties was $4.2
billion, and depletion expense was $442.3 million for the year then ended. As described in Note 2, the
Company follows the successful efforts method of accounting for its oil and natural gas properties. Proved
properties and support equipment and facilities are depleted using the unit of production method based on
estimated proved oil and natural gas reserves. Capitalized exploratory drilling costs that result in a discovery
of proved reserves and development costs are depleted using the unit-of-production method based on
estimated proved developed oil and natural gas reserves for the related field. The Company’s oil and natural
gas reserves are estimated by independent reserve engineers. Proved oil and natural gas reserves are the
estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data
demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under
existing economic and operating conditions. Significant judgment is required by the Company’s independent
reserve engineers in evaluating geological and engineering data when estimating proved oil and natural gas
reserves. Estimating reserves also requires the selection of inputs, including oil and natural gas price
assumptions and future operating and capital cost assumptions, among others. Because of the complexity
involved in estimating oil and natural gas reserves, management used independent reserve engineers to
prepare the estimate of reserve quantities as of December 31, 2021.
Auditing the Company’s depletion calculation is complex because of the use of the work of independent
reserve engineers and the evaluation of management’s determination of the inputs described above used by
the independent reserve engineers in estimating proved oil and natural gas reserves.
How We
Addressed
the Matter
in Our Audit
We obtained an understanding, evaluated the design and tested the operating effectiveness of the controls
over the Company’s process to calculate depletion, including management’s controls over the completeness
and accuracy of the financial data and inputs provided to the independent reserve engineers for use in
estimating the proved oil and natural gas reserves.
Our audit procedures included, among others, evaluating the professional qualifications and objectivity of the
independent reserve engineers used to prepare the estimate of proved oil and natural gas reserves.
Additionally, in assessing whether we can use the work of the independent reserve engineers we evaluated the
completeness and accuracy of the financial data and inputs described above used by the independent reserve
engineers in estimating proved oil and natural gas reserves by agreeing them to source documentation and we
identified and evaluated corroborative and contrary evidence. For proved undeveloped reserves, we evaluated
management’s development plan for compliance with the Securities and Exchange Commission rule that
undrilled locations are scheduled to be drilled within five years, unless specific circumstances justify a longer
time, by assessing consistency of the development projections with the Company’s drill plan and the
availability of capital relative to the drill plan. We also tested the mathematical accuracy of the depletion
calculations, including comparing the estimated proved oil and natural gas reserve amounts used to the
Company’s reserve report.
84
Asset Retirement Obligations
Description
of the
Matter
At December 31, 2021, the Company’s asset retirement obligations totaled $325.5 million. As described in
Note 2, the fair value of a liability for an asset retirement obligation is recognized in the period in which it is
incurred if a reasonable estimate of fair value can be made. If a tangible long‑lived asset with an existing asset
retirement obligation is acquired, a liability for that obligation is recognized at the asset’s acquisition or in-
service date. Because of the complexity involved in estimating the expected cash outflows, management used
a specialist to estimate the expected cash outflows for the Company’s asset retirement obligations as of
December 31, 2021.
Auditing the Company’s asset retirement obligations was complex and highly judgmental due to the
significant estimation required by management to determine the estimated present value of the amount of
dismantlement, removal, site reclamation and similar activities associated with the Company’s oil and natural
gas properties. In particular, the estimate was sensitive to significant assumptions such as the expected cash
outflows for asset retirement obligations and the ultimate productive life of the properties.
How We
Addressed
the Matter
in Our Audit
We obtained an understanding, evaluated the design and tested the operating effectiveness of the controls
over the Company’s process to estimate asset retirement obligations, including controls over management’s
review of the significant assumptions described above.
Our audit procedures included, among others, testing the significant assumptions discussed above and the
underlying data used by the Company. For example, we evaluated expected cash outflows for asset retirement
obligations by comparing to recent offshore activities and costs. We also compared the ultimate productive
life of the properties to forecasts of production based on estimates of proved oil and natural gas reserves, as
estimated by independent reserve engineers. We involved our specialists to assist in our evaluation of the
expected cash flows for asset retirement obligations.
/s/ Ernst & Young LLP
We have served as the Company’s auditor since 2004.
Dallas, Texas
February 28, 2022
85
Report of Independent Registered Public Accounting Firm
To the Shareholders and the Board of Directors of Kosmos Energy Ltd.
Opinion on Internal Control over Financial Reporting
We have audited Kosmos Energy Ltd.’s internal control over financial reporting as of December 31, 2021, based on criteria
established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission (2013 framework) (the COSO criteria). In our opinion, Kosmos Energy Ltd. (the Company) maintained, in all
material respects, effective internal control over financial reporting as of December 31, 2021, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
(PCAOB), the consolidated balance sheets of the Company as of December 31, 2021 and 2020, the related consolidated
statements of operations, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2021,
and the related notes and financial statement schedules listed in the Index at Item 15(a) and our report dated February 28, 2022
expressed an unqualified opinion thereon.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual
Report on Internal Control over Financial Reporting appearing in Item 9A. Our responsibility is to express an opinion on the
Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the
PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and
the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all
material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material
weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and
performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a
reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that
(1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions
of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of
financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the
company are being made only in accordance with authorizations of management and directors of the company; and (3) provide
reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s
assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ Ernst & Young LLP
Dallas, Texas
February 28, 2022
86
KOSMOS ENERGY LTD.
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
Assets
Current assets:
Cash and cash equivalents
Restricted cash
Receivables:
Joint interest billings, net
Oil sales
Other
Inventories
Prepaid expenses and other
Derivatives
Total current assets
Property and equipment:
Oil and gas properties, net
Other property, net
Property and equipment, net
Other assets:
Restricted cash
Long-term receivables
Deferred financing costs, net of accumulated amortization of $19,912 and $17,296 at December 31, 2021 and
December 31, 2020, respectively
Deferred tax assets
Derivatives
Other
Total assets
Liabilities and stockholders’ equity
Current liabilities:
Accounts payable
Accrued liabilities
Current maturities of long-term debt
Derivatives
Total current liabilities
Long-term liabilities:
Long-term debt, net
Derivatives
Asset retirement obligations
Deferred tax liabilities
Other long-term liabilities
Total long-term liabilities
Stockholders’ equity:
Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at December 31, 2021 and
December 31, 2020
Common stock, $0.01 par value; 2,000,000,000 authorized shares; 496,152,331 and 449,718,317 issued at
December 31, 2021 and December 31, 2020, respectively
Additional paid-in capital
Accumulated deficit
Treasury stock, at cost, 44,263,269 shares at December 31, 2021 and December 31, 2020, respectively
Total stockholders’ equity
Total liabilities and stockholders’ equity
See accompanying notes.
87
December 31,
2021
2020
$
131,620 $
149,027
42,971
195
36,908
134,004
6,614
165,247
18,899
5,689
541,952
26,002
44,491
8,320
128,972
27,870
15,414
400,291
4,177,323
6,664
4,183,987
3,310,276
10,637
3,320,913
305
191,150
1,090
—
1,026
21,141
542
117,497
3,706
—
964
23,680
$
4,940,651 $
3,867,593
$
184,403 $
250,670
30,000
65,879
530,952
2,590,495
6,298
322,237
711,038
250,394
221,430
203,260
7,500
28,009
460,199
2,103,931
8,069
244,166
573,619
37,455
3,880,462
2,967,240
—
—
4,962
2,473,674
(1,712,392)
(237,007)
529,237
4,497
2,307,220
(1,634,556)
(237,007)
440,154
$
4,940,651 $
3,867,593
KOSMOS ENERGY LTD.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
Revenues and other income:
Oil and gas revenue
Gain on sale of assets
Other income, net
Years Ended December 31,
2021
2020
2019
$
1,332,013 $
804,033 $
1,499,416
1,564
262
92,163
2
10,528
(35)
Total revenues and other income
1,333,839
896,198
1,509,909
Costs and expenses:
Oil and gas production
Facilities insurance modifications, net
Exploration expenses
General and administrative
Depletion, depreciation and amortization
Impairment of long-lived assets
Interest and other financing costs, net
Derivatives, net
Other expenses, net
346,006
338,477
(1,586)
65,382
91,529
467,221
—
128,371
270,185
10,111
13,161
84,616
72,142
485,862
153,959
109,794
17,180
37,802
402,613
(24,254)
180,955
110,010
563,861
—
155,074
71,885
24,648
Total costs and expenses
1,377,219
1,312,993
1,484,792
Income (loss) before income taxes
Income tax expense (benefit)
Net loss
Net loss per share:
Basic
Diluted
(43,380)
(416,795)
34,456
(5,209)
25,117
80,894
$
(77,836) $
(411,586) $
(55,777)
$
$
(0.19) $
(0.19) $
(1.02) $
(1.02) $
(0.14)
(0.14)
Weighted average number of shares used to compute net loss per share:
Basic
Diluted
416,943
416,943
405,212
405,212
401,368
401,368
Dividends declared per common share
$
— $
0.0452 $
0.1808
See accompanying notes.
88
KOSMOS ENERGY LTD.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
(In thousands)
Common Stock
Additional
Paid-in
Accumulated
Treasury
Shares
Amount
Capital
Deficit
Stock
Total
Balance as of December 31, 2018
442,915 $
4,429 $ 2,341,249 $ (1,167,193) $
Dividends ($0.1808 per share)
Equity-based compensation
Restricted stock awards and units
Tax withholdings on restricted stock units
Net loss
—
—
2,864
—
—
—
—
29
—
—
(74,813)
32,797
(29)
(1,983)
—
—
—
—
—
(55,777)
(237,007) $
—
—
—
—
—
Balance as of December 31, 2019
445,779
4,458
2,297,221
(1,222,970)
(237,007)
Dividends ($0.0452 per share)
Equity-based compensation
Restricted stock awards and units
Tax withholdings on restricted stock units
Net loss
Balance as of December 31, 2020
Public offering of common stock
Dividends
Equity-based compensation
Restricted stock awards and units
Tax withholdings on restricted stock units
Net loss
Balance as of December 31, 2021
941,478
(74,813)
32,797
—
(1,983)
(55,777)
841,702
(18,576)
33,561
—
(4,947)
(411,586)
440,154
136,006
227
31,786
—
(1,100)
(77,836)
—
—
3,939
—
—
449,718
43,125
—
—
3,309
—
—
—
—
39
—
—
4,497
432
—
—
33
—
—
(18,576)
33,561
(39)
(4,947)
—
—
—
—
—
(411,586)
—
—
—
—
—
2,307,220
(1,634,556)
(237,007)
135,574
227
31,786
(33)
(1,100)
—
—
—
—
—
—
(77,836)
—
—
—
—
—
—
496,152 $
4,962 $ 2,473,674 $ (1,712,392) $
(237,007) $
529,237
See accompanying notes.
89
KOSMOS ENERGY LTD.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Operating activities
Net loss
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation and amortization (including deferred financing costs)
Deferred income taxes
Unsuccessful well costs and leasehold impairments
Impairment of long-lived assets
Change in fair value of derivatives
Cash settlements on derivatives, net (including $(224.4) million and $(2.7) million
and $(36.3) million on commodity hedges during 2021, 2020, and 2019)
Equity-based compensation
Gain on sale of assets
Loss on extinguishment of debt
Other
Changes in assets and liabilities:
(Increase) decrease in receivables
Increase in inventories
Decrease in prepaid expenses and other
Increase (decrease) in accounts payable
Increase (decrease) in accrued liabilities
Net cash provided by operating activities
Investing activities
Oil and gas assets
Acquisition of oil and gas properties
Proceeds on sale of assets
Notes receivable from partners
Net cash used in investing activities
Financing activities
Borrowings under long-term debt
Payments on long-term debt
Advances under production prepayment agreement
Net proceeds from issuance of senior notes
Redemption of senior secured notes
Net proceeds from issuance of common stock
Tax withholdings on restricted stock units
Dividends
Deferred financing costs
Net cash provided by (used in) financing activities
Net increase (decrease) in cash, cash equivalents and restricted cash
Cash, cash equivalents and restricted cash at beginning of period
Cash, cash equivalents and restricted cash at end of period
Supplemental cash flow information
Cash paid for:
Interest, net of capitalized interest
Income taxes, net of refund received
Non-cash activity:
Production Prepayment Agreement converted to GoM Term Loan
See accompanying notes.
$
$
$
$
90
Years Ended December 31,
2020
2019
2021
$
(77,836) $
(411,586) $
(55,777)
477,801
(69,174)
18,819
—
277,705
(231,767)
31,651
(1,564)
19,625
(3,538)
(34,246)
(14,581)
15,218
(33,359)
(410)
374,344
(472,631)
(465,367)
6,354
(41,733)
(973,377)
725,000
(1,050,000)
—
839,375
—
136,006
(1,100)
(512)
(24,604)
624,165
495,209
(42,587)
23,157
153,959
22,800
(10,944)
32,706
(92,163)
2,902
15,922
92,093
(23,167)
7,882
71,947
(141,985)
196,145
(379,593)
—
99,118
(65,112)
(345,587)
300,000
(250,000)
50,000
—
—
—
(4,947)
(19,271)
(5,922)
69,860
25,132
149,764
174,896 $
(79,582)
229,346
149,764 $
573,118
(90,370)
87,813
—
67,436
(31,458)
32,370
(10,528)
24,794
9,069
(29,735)
(28,970)
34,586
(83,921)
129,723
628,150
(352,013)
—
15,000
(26,918)
(363,931)
175,000
(425,000)
—
641,875
(535,338)
—
(1,983)
(72,599)
(2,444)
(220,489)
43,730
185,616
229,346
91,032 $
137,421 $
103,674 $
104,061 $
99,928
43,909
— $
50,000 $
—
KOSMOS ENERGY LTD.
Notes to Consolidated Financial Statements
1. Organization
Kosmos Energy Ltd. changed our jurisdiction of incorporation from Bermuda to the State of Delaware in December
2018 as a holding company for Kosmos Energy Delaware Holdings, LLC, a Delaware limited liability company. As a holding
company, Kosmos Energy Ltd.’s management operations are conducted through a wholly-owned subsidiary, Kosmos Energy,
LLC. The terms “Kosmos,” the “Company,” “we,” “us,” “our,” “ours,” and similar terms refer to Kosmos Energy Ltd. and its
wholly-owned subsidiaries, unless the context indicates otherwise.
Kosmos is a full-cycle deepwater independent oil and gas exploration and production company focused along the
Atlantic Margins. Our key assets include production offshore Ghana, Equatorial Guinea and the U.S. Gulf of Mexico, as well as
a world-class gas development offshore Mauritania and Senegal. We also maintain a sustainable proven basin exploration
program in Equatorial Guinea, Ghana and the U.S. Gulf of Mexico. Kosmos is listed on the NYSE and LSE and is traded under
the ticker symbol KOS.
Kosmos is engaged in a single line of business, which is the exploration, development, and production of oil and
natural gas. Substantially all of our long-lived assets and all of our product sales are related to operations in four geographic
areas: Ghana, Equatorial Guinea, Mauritania/Senegal and the U.S. Gulf of Mexico.
2. Accounting Policies
Principles of Consolidation
The accompanying consolidated financial statements include the accounts of Kosmos Energy Ltd. and its wholly-
owned subsidiaries. They also include the Company’s share of the undivided interest in certain assets, liabilities, revenues and
expenses. Investments in corporate joint ventures, which we exercise significant influence over, are accounted for using the
equity method of accounting. All intercompany transactions have been eliminated.
Investments in companies that are partially owned by the Company are integral to the Company’s operations. The
other parties, who also have an equity interest in these companies, are independent third parties that share in the business results
according to their ownership. Kosmos does not invest in these companies in order to remove liabilities from its balance sheet.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United
States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues
and expenses, and the disclosures of contingent assets and liabilities. These estimates could change materially if different
information or assumptions were used. We base our assumptions and estimates on historical experience and other sources that
we believe to be reasonable at the time. Actual results could differ from these estimates.
Reclassifications
Certain prior period amounts have been reclassified to conform with the current year presentation. Such
reclassifications had no significant impact on our reported net loss, current assets, total assets, current liabilities, total liabilities,
shareholders’ equity or cash flows, except as disclosed related to the adoption of recent accounting pronouncements.
91
Cash, Cash Equivalents and Restricted Cash
Cash and cash equivalents
Restricted cash - current
Restricted cash - long-term
Total cash, cash equivalents and restricted cash shown in the
consolidated statements of cash flows
December 31,
2021
2020
2019
(In thousands)
$
131,620 $
149,027 $
224,502
42,971
305
195
542
4,302
542
$
174,896 $
149,764 $
229,346
Cash and cash equivalents includes demand deposits and funds invested in highly liquid instruments with original
maturities of three months or less at the date of purchase. When our net leverage ratio exceeds 2.50x, we are required under the
Facility to maintain a restricted cash balance that is sufficient to meet the payment of interest and fees for the next six-month
period on the 7.125% Senior Notes, the 7.750% Senior Notes, and the 7.500% Senior Notes plus the Corporate Revolver or the
Facility, whichever is greater. As of December 31, 2021, we exceeded this ratio and restricted approximately $42.9 million in
cash to meet our requirements. In the first quarter of 2022 we restricted an additional $16.2 million in cash.
Receivables
Our receivables consist of joint interest billings, oil and gas sales, related party and other receivables. Receivables
from joint interest owners are stated at amounts due, net of any allowances for doubtful accounts. As required by ASU 2016-13,
"Measurement of Credit Losses on Financial Instruments", we determine our allowance based on historical experience, current
conditions and reasonable and supportable forecasts by considering the length of time past due, future net revenues of the
debtor’s ownership interest in oil and natural gas properties we operate, and the owner’s ability to pay its obligation, among
other things. We had an allowance for doubtful accounts of $5.2 million and $5.7 million in current joint interest billings
receivables as of December 31, 2021 and 2020, respectively.
Inventories
Inventories consisted of $149.5 million and $127.5 million of materials and supplies and $15.7 million and $1.5
million of hydrocarbons as of December 31, 2021 and 2020, respectively. The Company’s materials and supplies inventory
primarily consists of casing and wellheads and is stated at the lower of cost, using the weighted average cost method, or net
realizable value. We recorded write downs of $1.2 million, $8.6 million and $4.6 million during the years ended December 31,
2021, 2020 and 2019 for materials and supplies inventories as Other expenses, net in the consolidated statements of operations
and other in the consolidated statements of cash flows.
Hydrocarbon inventory is carried at the lower of cost, using the weighted average cost method, or net realizable value.
Hydrocarbon inventory costs include expenditures and other charges incurred in bringing the inventory to its existing condition.
Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory costs.
Leases
We account for leases in accordance with ASC Topic 842, Leases, (“ASC 842”). We determine if an arrangement is a
lease at contract inception. In the normal course of business, the Company enters into various lease agreements for real estate
and equipment related to its exploration, development and production activities that are currently accounted for as operating
leases. Operating leases are included in Other assets, Accrued liabilities, and Other long-term liabilities on our consolidated
balance sheets. The lease liabilities are initially and subsequently measured at the present value of the unpaid lease payments at
the lease commencement date. We monitor for events or changes in circumstances that require a reassessment of a lease. When
a reassessment results in the re-measurement of a lease liability, a corresponding adjustment is made to the carrying amount of
the corresponding ROU asset unless doing so would reduce the carrying amount of the ROU asset to an amount less than zero.
In that case, the amount of the adjustment that would result in a negative ROU asset balance is recorded in profit or loss.
Exploration and Development Costs
The Company follows the successful efforts method of accounting for its oil and gas properties. Acquisition costs for
proved and unproved properties are capitalized when incurred. Costs of unproved properties are transferred to proved properties
when a determination that proved reserves have been found. Exploration costs, including geological and geophysical costs and
costs of carrying unproved properties, are expensed as incurred. Exploratory drilling costs are capitalized when incurred. If
92
exploratory wells are determined to be commercially unsuccessful or dry holes, the applicable costs are expensed and recorded
in exploration expense on the consolidated statement of operations. Costs incurred to drill and equip development wells,
including unsuccessful development wells, are capitalized. Costs incurred to operate and maintain wells and equipment and to
lift oil and natural gas to the surface are expensed as oil and gas production expense.
The Company evaluates unproved property periodically for impairment. The impairment assessment considers results
of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of such projects. If it is
determined that future appraisal drilling or development activities are unlikely to occur, the associated capitalized costs are
recorded as exploration expense in the consolidated statement of operations.
Depletion, Depreciation and Amortization
Proved properties and support equipment and facilities are depleted using the unit‑of‑production method based on
estimated proved oil and natural gas reserves. Capitalized exploratory drilling costs that result in a discovery of proved reserves
and development costs are depleted using the unit‑of‑production method based on estimated proved developed oil and natural
gas reserves for the related field.
Depreciation and amortization of other property is computed using the straight-line method over the assets’ estimated
useful lives (not to exceed the lease term for leasehold improvements), ranging from one to eight years.
Leasehold improvements
Office furniture, fixtures and computer equipment
Years
Depreciated
1 to 8
3 to 7
Amortization of deferred financing costs is computed using the straight‑line method over the life of the related debt.
Capitalized Interest
Interest costs from external borrowings are capitalized on major projects with an expected construction period of one
year or longer. Capitalized interest is added to the cost of the underlying asset and is depleted on the unit‑of‑production method
in the same manner as the underlying assets.
Asset Retirement Obligations
The Company accounts for asset retirement obligations as required by ASC 410—Asset Retirement and
Environmental Obligations. Under these standards, the fair value of a liability for an asset retirement obligation is recognized in
the period in which it is incurred if a reasonable estimate of fair value can be made. If a reasonable estimate of fair value cannot
be made in the period the asset retirement obligation is incurred, the liability is recognized when a reasonable estimate of fair
value can be made. If a tangible long‑lived asset with an existing asset retirement obligation is acquired, a liability for that
obligation is recognized at the asset’s acquisition or in service date. In addition, a liability for the fair value of a conditional
asset retirement obligation is recorded if the fair value of the liability can be reasonably estimated. We capitalize the asset
retirement costs by increasing the carrying amount of the related long‑lived asset by the same amount as the liability. We record
increases in the discounted abandonment liability resulting from the passage of time in depletion, depreciation and amortization
in the consolidated statement of operations. Estimating the future restoration and removal costs requires management to make
estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations
often have vague descriptions of what constitutes removal. Additionally, asset removal technologies and costs are constantly
changing, as are regulatory, political, environmental, safety and public relations considerations.
Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement
amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory,
environmental and political environments. To the extent future revisions to these assumptions impact the present value of the
existing asset retirement obligations, a corresponding adjustment is made to the oil and gas property balance.
93
Acquisition Accounting
The purchase price in an acquisition (business combination or asset acquisition) is allocated to the assets acquired and
liabilities assumed based on their relative fair values as of the acquisition date, which may occur many months after the deal
announcement date. Therefore, while the consideration to be paid may be fixed, the fair value of the assets acquired, and
liabilities assumed is subject to change during the period between the announcement date and the acquisition date. The most
significant estimates in the allocation typically relate to the value assigned to future recoverable oil and natural gas reserves and
unproved properties. As the allocation of the purchase price is subject to significant estimates and subjective judgments, the
accuracy of this assessment is inherently uncertain.
Impairment of Long‑lived Assets
We review our long‑lived assets for impairment when changes in circumstances indicate that the carrying amount of an
asset may not be recoverable. ASC 360 — Property, Plant and Equipment requires an impairment loss to be recognized if the
carrying amount of a long‑lived asset is not recoverable and exceeds its fair value. The carrying amount of a long‑lived asset is
not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of
the asset. That assessment shall be based on the carrying amount of the asset at the date it is tested for recoverability, whether in
use or under development. Assets to be disposed of and assets not expected to provide any future service potential to us are
recorded at the lower of carrying amount or fair value. Oil and gas properties are grouped in accordance with ASC 932 —
Extractive Activities-Oil and Gas. The basis for grouping is a reasonable aggregation of properties typically by field or by
logical grouping of assets with significant shared infrastructure.
For long-lived assets whereby the carrying value exceeds the estimated future undiscounted cash flows, the carrying
amount is reduced to fair value. Fair value is generally estimated using the income approach described in the ASC 820 — Fair
Value Measurement. If applicable, we utilize prices and other relevant information generated by market transactions involving
assets and liabilities that are identical or comparable to the item being measured as the basis for determining fair value. The
expected future cash flows used for impairment reviews and related fair value measurements are typically based on judgmental
assessments of future production, pricing estimates, capital and operating costs, market-based weighted average cost of capital,
and risk adjustment factors applied to reserves. These assumptions are applied to develop future cash flow projections that are
then discounted to estimated fair value, using a market-based weighted-average cost of capital. Although we base the fair value
estimate of each asset group on assumptions we believe to be reasonable, those assumptions are inherently unpredictable and
uncertain, and actual results could differ from the estimate. Negative revisions of estimated reserve quantities, increases in
future cost estimates, divestiture of a significant component of the asset group, or sustained decreases in crude oil prices could
lead to a reduction in expected future cash flows and possibly an additional impairment of long-lived assets in future periods.
We believe the assumptions used in our analysis to test for impairment are appropriate and result in a reasonable
estimate of future cash flows and fair value. Kosmos has consistently used an average of third-party industry forecasts to
determine our pricing assumptions. Where unproved reserves exist, an appropriately risk-adjusted amount of these reserves may
be included in the evaluation.
Derivative Instruments and Hedging Activities
We utilize oil derivative contracts to mitigate our exposure to commodity price risk associated with our anticipated
future oil production. These derivative contracts consist of collars, put options, call options and swaps. We also have used
interest rate derivative contracts to mitigate our exposure to interest rate fluctuations related to our long‑term debt. Our
derivative financial instruments are recorded on the balance sheet as either assets or liabilities and are measured at fair value.
We do not apply hedge accounting to our derivative contracts. See Note 9—Derivative Financial Instruments.
Estimates of Proved Oil and Natural Gas Reserves
Reserve quantities and the related estimates of future net cash flows affect our periodic calculations of depletion and
assessment of impairment of our oil and natural gas properties. Proved oil and natural gas reserves are the estimated quantities
of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be
recoverable in future periods from known reservoirs under existing economic and operating conditions. As additional proved
reserves are discovered, reserve quantities and future cash flows will be estimated by independent petroleum consultants and
prepared in accordance with guidelines established by the SEC and the FASB. The accuracy of these reserve estimates is a
function of:
• the engineering and geological interpretation of available data;
• estimates of the amount and timing of future operating cost, production taxes, development cost and workover cost;
94
• the accuracy of various mandated economic assumptions; and
• the judgments of the persons preparing the estimates.
Revenue Recognition
We recognize revenues on the volumes of hydrocarbons sold to a purchaser. The volumes sold may be more or less
than the volumes to which we are entitled based on our ownership interest in the property. These differences result in a
condition known in the industry as a production imbalance. A receivable or liability is recognized only to the extent that we
have an imbalance on a specific property greater than the expected remaining proved reserves on such property. As of
December 31, 2021 and 2020, we had no oil and gas imbalances recorded in our consolidated financial statements.
Our oil and gas revenues are recognized when hydrocarbons have been sold to a purchaser at a fixed or determinable
price, title has transferred and collection is probable. Certain revenues are based on provisional price contracts which contain an
embedded derivative that is required to be separated from the host contract for accounting purposes. The host contract is the
receivable from oil sales at the spot price on the date of sale. The embedded derivative, which is not designated as a hedge, is
marked to market through oil and gas revenue each period until the final settlement occurs, which generally is limited to the
month after the sale.
Oil and gas revenue is composed of the following:
Years Ended December 31,
2021
2020
2019
(In thousands)
Revenues from contract with customer - Equatorial Guinea
$
257,628 $
149,033 $
654,644
427,261
375,603
285,017
(7,520)
(5,620)
297,831
740,464
459,960
1,161
$
1,332,013 $
804,033 $
1,499,416
Revenues from contract with customer - Ghana
Revenues from contract with customers - U.S. Gulf of Mexico
Provisional oil sales contracts
Oil and gas revenue
Equity‑based Compensation
For equity‑based compensation awards, compensation expense is recognized in the Company’s financial statements
over the awards’ vesting periods based on their grant date fair value. The Company utilizes (i) the closing stock price on the
date of grant to determine the fair value of service vesting restricted stock units and (ii) a Monte Carlo simulation to determine
the fair value of restricted stock units with a combination of market and service vesting criteria. Forfeitures are recognized in
the period in which they occur.
Restructuring Charges
The Company accounts for restructuring charges and related termination benefits in accordance with ASC 712-
Compensation-Nonretirement Postemployment Benefits. Under this standard, the costs associated with termination benefits are
recorded during the period in which the liability is incurred. During the years ended December 31, 2021, 2020 and 2019, we
recognized $2.6 million, $16.5 million and $11.5 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.
Income Taxes
The Company accounts for income taxes as required by ASC 740—Income Taxes. Under this method, deferred
income taxes are determined based on the difference between the financial statement and tax basis of assets and liabilities using
enacted tax rates in effect for the year in which the differences are expected to reverse. Valuation allowances are established
when necessary to reduce deferred tax assets to the amounts expected to be realized. On a quarterly basis, management
evaluates the need for and adequacy of valuation allowances based on the expected realizability of the deferred tax assets and
adjusts the amount of such allowances, if necessary.
95
We recognize tax benefits from uncertain tax positions only if it is more likely than not that the tax position will be
sustained upon examination by the tax authorities, based on the technical merits of the position. Accordingly, we measure tax
benefits from such positions based on the most likely outcome to be realized.
Foreign Currency Translation
The U.S. dollar is the functional currency for all of the Company’s material foreign operations. Foreign currency
transaction gains and losses and adjustments resulting from translating monetary assets and liabilities denominated in foreign
currencies are included in other expenses. Cash balances held in foreign currencies are not significant, and as such, the effect of
exchange rate changes is not material to any reporting period.
Concentration of Credit Risk
Our revenue can be materially affected by current economic conditions and the price of oil and natural gas. However,
based on the current demand for crude oil and natural gas and the fact that alternative purchasers are readily available, we
believe that the loss of our marketing agents and/or any of the purchasers identified by our marketing agents would not have a
long‑term material adverse effect on our financial position or results of international 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.
Recent Accounting Standards
Recently Adopted
In December 2019, the FASB issued ASU 2019-12, “Simplifying the Accounting for Income Taxes”. Our adoption of
ASU 2019-12 on January 1, 2021, did not have a material impact on our income tax expense.
Not Yet Adopted
In March 2020, the FASB issued ASU 2020-04, “Reference Rate Reform (Topic 848),” which provides optional
expedients and exceptions for applying U.S. GAAP to contracts, hedging relationships and other transactions affected by the
cessation of the LIBOR. The guidance was effective beginning March 12, 2020 and can be applied prospectively through
December 31, 2022. As we implement the cessation of LIBOR into our current contracts and hedging relationships, the
Company is evaluating whether to apply any of these expedients and, if elected, will adopt these standards when LIBOR is
discontinued.
3. Acquisitions and Divestitures
2021 Transactions
In October 2021, Kosmos completed the acquisition of Anadarko WCTP Company (“Anadarko WCTP”), a subsidiary
of Occidental Petroleum Corporation, which owns a participating interest in the WCTP Block and DT Block offshore Ghana,
including an 18.0% participating interest in the Jubilee Unit Area and an 11.1% participating interest in the TEN fields. In
consideration for the acquisition, Kosmos paid $455.9 million in cash based on an initial purchase price of $550.6 million
reduced by certain purchase price adjustments totaling $94.7 million. Additionally, we incurred $9.5 million of transaction
related costs, which were capitalized as part of the purchase price. Following closing of the acquisition, Kosmos’ interest in the
Jubilee Unit Area increased from 24.1% to 42.1%, and Kosmos’ interest in the TEN fields increased from 17.0% to 28.1%.
Under the Deepwater Tano Block Joint Operating Agreement, certain joint venture partners have pre-emption rights
that, if fully exercised, could reduce our ultimate interest in the Jubilee Unit Area by 3.8% to 38.3%, and our ultimate interest in
the TEN fields by 8.3% to 19.8%. In November 2021, we received notice from certain joint venture partners that they intend to
exercise their pre-emption rights in relation to Kosmos' acquisition of Anadarko WCTP. The exercise of pre-emption rights is
subject to finalizing definitive agreements with Kosmos and requires approval from GNPC and the Ghanaian Ministry of
Energy. The initial purchase price for the pre-empted portion of transaction is approximately $150 million and is subject to
certain closing adjustments. Kosmos would anticipate using any potential proceeds to accelerate debt repayment.
Kosmos initially funded the purchase price through the issuance of $400.0 million aggregate principal amount of
floating rate senior notes due 2022 (“Bridge Notes”) and $75.0 million of borrowings under Kosmos' Facility. Kosmos then
refinanced the Bridge Notes in full with the proceeds from the issuance of $400.0 million of 7.750% Senior Notes due 2027 and
cash on hand. Kosmos also received $136.6 million in proceeds from a public issuance of 43.1 million shares of Kosmos’
96
common stock with proceeds used to repay a portion of outstanding borrowings under the Facility during the fourth quarter of
2021. The purchase price allocation was based on the estimated fair value of identifiable assets acquired and liabilities assumed.
The estimated fair value measurements of oil and gas assets acquired and asset retirement obligations liabilities
assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair value of oil
and gas properties and asset retirement obligations were measured using the discounted cash flow technique of valuation.
Significant inputs to the valuation of oil and gas properties include estimates of: (i) reserves, (ii) future operating and
development costs, (iii) future commodity prices, (iv) future plugging and abandonment costs, (v) estimated future cash flows,
and (vi) a market-based weighted average cost of capital rate.
Fair value of assets acquired:
Proved oil and gas properties
Accounts receivable and other
Total assets acquired
Fair value of liabilities assumed:
Asset retirement obligations
Accounts payable and accrued liabilities
Deferred tax liabilities
Total liabilities assumed
Purchase price:
Cash consideration paid
Transaction related costs
Total purchase price
Purchase Price Allocation
(in thousands)
$
$
$
$
$
$
718,159
95,847
814,006
28,342
113,704
206,593
348,639
455,886
9,481
465,367
As a result of the acquisition of Anadarko WCTP, we have included $104.4 million of revenues and $10.3 million of
direct operating expenses in our consolidated statements of operations for the period from October 13, 2021 to December 31,
2021.
In 2021, at the conclusion of the second exploration period, Block C13 offshore Mauritania was relinquished.
2020 Transactions
During the third quarter of 2020, Kosmos entered into an agreement with Shell to farm down interests in a portfolio of
frontier exploration assets for cash consideration of $96.0 million and future contingent consideration of up to $100.0 million.
Under the terms of the agreement, Shell acquired Kosmos' participating interest in blocks offshore Sao Tome and Principe
(excluding Block 5 offshore Sao Tome and Principe), Suriname, Namibia and South Africa. Kosmos received proceeds totaling
$95.0 million during the fourth quarter of 2020 resulting in gain on sale of assets of $92.1 million. The remaining proceeds of
$1.0 million related to Kosmos' participating interest in South Africa were received during the third quarter of 2021. The
potential contingent consideration is payable by Shell depending on the results of the first four exploration wells drilled by
Shell in the purchased assets, excluding South Africa. Upon approval of the relevant operating committee of an appraisal plan
for submission to the relevant governmental authority under the relevant host government contract for any of the first four
exploration wells, Shell will be required to pay Kosmos $50.0 million of consideration for each discovery for which an
appraisal plan is approved by the relevant operating committee, capped in the aggregate at a maximum of $100.0 million. In
February 2022, there was an oil discovery announced in Namibia on the first well drilled. Under the terms of Shell’s Petroleum
Agreement with Namibia, if Shell decides to appraise the discovery, an appraisal plan is required to be submitted within 150
days from completion of tests on the discovery well.
In October 2020, Kosmos withdrew from Block C6 offshore Mauritania.
In May 2020, a withdrawal notice for our blocks offshore Cote d'Ivoire was issued to partners and the Government of
Cote d’Ivoire.
97
In July 2020, we provided notice that we declined to enter the final exploration phase of the Suriname Block 45
petroleum agreement.
2019 Transactions
In March 2019, we completed an agreement to acquire Ophir's remaining interest in Block EG-24, offshore Equatorial
Guinea, which increased our participating interest to 80% and named Kosmos as operator. The Equatorial Guinean national oil
company, GEPetrol, has a 20% carried interest during the exploration period. Should a commercial discovery be made,
GEPetrol's 20% carried interest will convert to a 20% participating interest.
In November 2019, we completed a farm-out agreement with Shell Sao Tome and Principe B.V. to farm-out a 20%
participating interest in Block 6 and a 30% participating interest in Block 11, offshore Sao Tome and Principe, resulting in our
participating interests in Blocks 6 and 11 being 25% and 35%, respectively. During the year ended December 31, 2019, we
recognized a $10.5 million gain related to the farm-out of Blocks 6 and 11 offshore Sao Tome and Principe.
4. Joint Interest Billings and Long-term Receivables
Joint Interest Billings
The Company’s joint interest billings consist of receivables from partners with interests in common oil and gas
properties operated by the Company for shared costs. Joint interest billings are classified on the face of the consolidated balance
sheets as current and long-term receivables based on when collection is expected to occur.
In Ghana, the foreign contractor group funded GNPC’s 5% share of TEN development costs. The foreign contractor
group is being reimbursed for such costs plus interest out of a portion of GNPC’s TEN production revenues. As of December
31, 2021 and 2020, the current portion of the joint interest billing receivables due from GNPC for the TEN fields' development
costs were $7.9 million and $5.8 million, respectively, and the long-term portion were $20.9 million and $21.2 million.
Notes Receivables
In February 2019, Kosmos signed Carry Advance Agreements with the national oil companies of Mauritania and
Senegal obligating us to finance a portion of the respective national oil company’s share of certain development costs incurred
through first gas production for Greater Tortue Ahmeyim Phase 1, currently projected in the third quarter of 2023. Kosmos’
share for the two agreements combined is currently estimated at approximately $240.0 million, which is to be repaid with
interest through the national oil companies’ share of future revenues. As of December 31, 2021 and 2020, the balance due from
the national oil companies was $145.2 million, and $96.3 million, respectively, which is classified as Long-term receivables in
our consolidated balance sheets. Interest income on the long-term notes receivable was $7.1 million, $3.8 million and
$0.5 million for the years ended December 31, 2021, 2020 and 2019, respectively.
Other Long-term Receivables
In August 2021, BP, as the operator of the Greater Tortue project (“BP Operator”), with the consent of the Greater
Tortue Unit participants and the respective States, agreed to sell the Greater Tortue FPSO (which is currently under construction
by Technip Energies in China) to an affiliate of BP (“BP Buyer”). The Greater Tortue FPSO will be leased back to BP Operator
under a long-term lease agreement, for exclusive use in the Greater Tortue project. BP Operator will continue to manage and
supervise the construction contract with Technip Energies. Delivery of the Greater Tortue FPSO to BP Buyer will occur after
construction is complete and the Greater Tortue FPSO has been commissioned, with the lease to BP Operator becoming
effective on the same date, currently estimated to be in the third quarter of 2023.
As a result of the above transactions entered into by BP Operator, Kosmos has recognized a Long-term receivable of
$200.2 million from BP Operator for our share of the consideration paid from BP Buyer to and held by BP Operator as well as a
$200.2 million FPSO Contract Liability in Other long-term liabilities related to the deferred sale of the Tortue FPSO. This
Long-term receivable will be non-cash settled against future obligations payable to BP Operator. During the year ended
December 31, 2021, BP Operator settled our payment obligations of $132.4 million of capital expenditures and $42.7 million of
existing Accounts Payable to BP Operator, these non-cash impacts are excluded from the statement of cash flows.
98
5. Property and Equipment
Property and equipment is stated at cost and consisted of the following:
Oil and gas properties:
Proved properties
Unproved properties
Total oil and gas properties
Accumulated depletion
Oil and gas properties, net
Other property
Accumulated depreciation
Other property, net
Property and equipment, net
December 31,
2021
2020
(In thousands)
$
6,725,453 $
451,454
7,176,907
(2,999,584)
4,177,323
5,369,737
495,390
5,865,127
(2,554,851)
3,310,276
58,598
(51,934)
6,664
59,949
(49,312)
10,637
$
4,183,987 $
3,320,913
We recorded depletion expense of $442.3 million, $460.9 million and $542.9 million and depreciation expense of $3.9
million, $5.5 million and $6.9 million for the years ended December 31, 2021, 2020 and 2019, respectively. During the years
ended December 31, 2021, 2020 and 2019, we recorded asset impairments totaling zero, $154.0 million and zero, respectively,
in our consolidated statement of operations in connection with fair value assessments for oil and gas proved properties.
6. Suspended Well Costs
The Company capitalizes exploratory well costs as unproved properties within oil and gas properties until a
determination is made that the well has either found proved reserves or is impaired. If proved reserves are found, the capitalized
exploratory well costs are reclassified to proved properties. Well costs are charged to exploration expense if the exploratory
well is determined to be impaired.
The following table reflects the Company’s capitalized exploratory well costs on drilled wells as of and during the
years ended December 31, 2021, 2020 and 2019.
Beginning balance
Additions to capitalized exploratory well costs pending the determination
of proved reserves
Reclassification due to determination of proved reserves(1)
Capitalized exploratory well costs charged to expense
Ending balance
______________________________________
Years Ended December 31,
2021
2020
2019
(In thousands)
$
186,289 $
445,790 $
367,665
31,891
—
—
218,180 $
4,001
(263,502)
—
186,289 $
78,125
—
—
445,790
$
(1)
Represents the reclassification of exploratory well costs associated with the Greater Tortue Ahmeyim Unit as a result
of the execution of the Tortue Phase 1 SPA in February 2020.
The following table provides aging of capitalized exploratory well costs based on the date drilling was completed and
the number of projects for which exploratory well costs have been capitalized for more than one year since the completion of
drilling:
99
Exploratory well costs capitalized for a period of one year or less
Exploratory well costs capitalized for a period of one to three years
Exploratory well costs capitalized for a period of four to six years
Ending balance
Number of projects that have exploratory well costs that have been
capitalized for a period greater than one year
Years Ended December 31,
2021
2020
2019
(In thousands, except well counts)
$
$
20,903 $
30,389
166,888
218,180 $
— $
66,573
119,716
186,289 $
40,313
279,861
125,616
445,790
3
3
3
As of December 31, 2021, 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, the Yakaar and Teranga discoveries in the Cayar Offshore Profond block offshore Senegal, and the Asam discovery
in Block S offshore Equatorial Guinea.
BirAllah Discovery — In November 2015, we completed the Marsouin-1 exploration well in the northern part of
Block C8 offshore Mauritania, which encountered hydrocarbon pay. Following additional evaluation, a decision regarding
commerciality is expected be made. During the fourth quarter of 2019, we completed the nearby Orca-1 exploration well which
encountered hydrocarbon pay. Following additional evaluation, a decision regarding commerciality is expected to be made. The
BirAllah and Orca discoveries are being analyzed as a joint development. In 2021, we continued progressing appraisal studies
and maturing concept design. We are currently in discussions with the government of Mauritania to extend the exploration
phase of Block C8 which is currently set to expire in June 2022. As of December 31, 2021, capitalized costs related to BirAllah
and Orca discoveries approximates $62.0 million
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. In 2021, we continued progressing
appraisal studies and maturing concept design.
Asam Discovery - In October 2019, we completed the S-5 exploration well offshore Equatorial Guinea, which
encountered hydrocarbon pay. In July 2020, an appraisal plan was approved by the government of Equatorial Guinea. The well
is located within tieback range of the Ceiba FPSO and work is currently ongoing to integrate all available data into models to
establish the scale of the discovered resource. Additionally, in 2021 engineering continues to progress concepts around required
subsea infrastructure necessary for a subsea tieback. Once the appraisal plan involving this work is complete, a decision
regarding commerciality will be made.
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 years ended December 31, 2021 and 2020 is as follows:
Operating lease cost
Variable lease cost
Short-term lease cost(1)
Total lease cost
__________________________________
December 31,
2021
2020
(In thousands)
3,971 $
1,780
10,790
16,541 $
4,076
1,793
13,705
19,574
$
$
(1)
Includes $9.4 million and $12.6 million during the years ended December 31, 2021 and 2020, respectively, of costs
associated with short-term drilling contracts.
100
Other information related to operating leases at December 31, 2021 and 2020, is as follows:
Balance sheet classifications
Other assets (right-of-use assets)
Accrued liabilities (current maturities of leases)
Other long-term liabilities (non-current maturities of leases)
December 31
2021
2020
(In thousands, except lease term and discount rate)
$
17,578
$
1,905
20,351
19,799
1,405
22,771
Weighted average remaining lease term
7.5 years
8.4 years
Weighted average discount rate
9.8 %
9.8 %
The table below presents supplemental cash flow information related to leases during the years ended December 31,
2021 and 2020:
Operating cash flows for operating leases
Investing cash flows for operating leases(1)
__________________________________
(1)
Represents costs associated with short-term drilling contracts.
December 31,
2021
2020
$
(In thousands)
6,460 $
9,350
5,225
12,586
Future minimum rental commitments under our leases at December 31, 2021, are as follows:
2022
2023
2024
2025
2026
Thereafter
Total undiscounted lease payments
Less: Imputed interest
Total lease liabilities
__________________________________
Operating Leases(1)
(In thousands)
$
$
$
3,974
4,077
4,148
4,219
4,290
10,874
31,582
(9,326)
22,256
(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.
101
8. Debt
Outstanding debt principal balances:
Facility
Corporate Revolver
7.125% Senior Notes
7.750% Senior Notes
7.500% Senior Notes
GoM Term Loan
Total
Unamortized deferred financing costs and discounts(1)
Total debt, net
Less: Current maturities of long-term debt
Long-term debt, net
________________________________________
December 31,
2021
2020
(In thousands)
$
1,000,000 $
—
650,000
400,000
450,000
175,000
2,675,000
(54,505)
2,620,495
(30,000)
2,590,495 $
$
1,200,000
100,000
650,000
—
—
200,000
2,150,000
(38,569)
2,111,431
(7,500)
2,103,931
(1)
Includes $31.0 million and $25.6 million of unamortized deferred financing costs related to the Facility; $20.2 million
and $8.4 million of unamortized deferred financing costs and discounts related to the Senior Notes; and $3.3 million and
$4.6 million of unamortized deferred financing costs related to the GoM Term Loan as of December 31, 2021 and
December 31, 2020, respectively.
Facility
The Facility supports our oil and gas exploration, appraisal and development programs and corporate activities with a
borrowing base calculation that includes value related to the Jubilee, TEN, Ceiba and Okume fields, however, the additional
interests in Jubilee and TEN acquired in the recent acquisition of Anadarko WCTP are not included in the borrowing base
calculation. In May 2021, the Company entered into an amended and restated facility agreement and certain ancillary
documents. The amendments to the terms of the Facility included the following:
•
•
•
•
•
•
•
the extension of the maturity date by two years (final maturity date now occurs on March 31, 2027),
the extension of the amortization schedule such that amortization of principal is to commence on March 31, 2024 and
continue in equal amounts every six months thereafter until the maturity date,
an increase in the interest margin by 0.5% (applicable interest margin for the first three years is now LIBOR +3.75%),
the incorporation of a mechanism for two ESG key performance indicators (“KPIs”) to impact the interest margin
either positively or negatively based upon delivering emissions targets and achieving certain third-party ESG ratings,
an increase in the Loan Life Coverage Ratio from 1.10x to 1.30x after March 31, 2024,
the removal of Kosmos Energy Investments Senegal Limited, Kosmos Energy Senegal and Kosmos Energy
Mauritania as borrowers, guarantors and pledged subsidiaries, and
a reduction in the Facility size to $1.25 billion (from $1.5 billion).
As amended, the available borrowing base was approximately $1.24 billion. As part of the amendment, the Company
incurred $15.2 million for loss on extinguishment of debt during the year ended December 31, 2021. The Facility amendment
contains other customary representations and warranties, covenants and informational undertakings, in each case, subject to
certain exceptions and conditions. The Facility amendment also provides for certain customary events of default, including,
among other things, payment defaults, breach of representations and warranties, covenant defaults, cross-defaults to certain
indebtedness, certain events of insolvency, judgment defaults, and repudiation or rescission of certain documents supporting the
amendment. If such an event of default occurs, the agents under such amendment are entitled to take various actions, including
102
the cancellation of any outstanding commitments, acceleration of amounts due thereunder and taking certain permitted
enforcement actions under the ancillary security documents, subject in each case to the terms of the Facility amendment and
such security documents.
During the September 2021 redetermination, the Company’s lending syndicate approved a borrowing base capacity in
excess of the facility size of $1.25 billion. As of December 31, 2021, borrowings under the Facility totaled $1.0 billion and the
undrawn availability under the Facility was $235.2 million, (limited by current commitments).
When our net leverage ratio exceeds 2.50x, we are required under the Facility to maintain a restricted cash balance that
is sufficient to meet the payment of interest and fees for the next six-month period on the 7.125% Senior Notes, the 7.750%
Senior Notes and the 7.500% Senior Notes plus the Corporate Revolver or the Facility, whichever is greater. As of December
31, 2021, we exceeded this ratio and restricted approximately $42.9 million in cash to meet our requirements. In the first quarter
of 2022 we restricted an additional $16.2 million in cash.
Interest on the Facility is the aggregate of the applicable margin (3.75% to 5.00%, depending on the length of time that
has passed from the date the Facility was entered into) and LIBOR. Interest is payable on the last day of each interest period
(and, if the interest period is longer than six months, on the dates falling at six-month intervals after the first day of the interest
period). We pay commitment fees on the undrawn and unavailable portion of the total commitments, if any. Commitment fees
are equal to 30% per annum of the then-applicable respective margin when a commitment is available for utilization and, equal
to 20% per annum of the then-applicable respective margin when a commitment is not available for utilization. We recognize
interest expense in accordance with ASC 835—Interest, which requires interest expense to be recognized using the effective
interest method. We determined the effective interest rate based on the estimated level of borrowings under the Facility.
The Facility provides a revolving credit and letter of credit facility. The availability period for the revolving credit
facility expires one month prior to the final maturity date. The letter of credit facility expires on the final maturity date. The
available facility amount is subject to borrowing base constraints and, beginning on March 31, 2024, outstanding borrowings
will be constrained by an amortization schedule. The Facility has a final maturity date of March 31, 2027. As of December 31,
2021, we had no letters of credit issued under the Facility.
We have the right to cancel all the undrawn commitments under the amended and restated Facility. The amount of
funds available to be borrowed under the Facility, also known as the borrowing base amount, is determined every March and
September. The borrowing base amount is based on the sum of the net present values of net cash flows and relevant capital
expenditures reduced by certain percentages as well as value attributable to certain assets’ reserves and/or resources in Ghana
and Equatorial Guinea, however, the additional interests in Jubilee and TEN acquired in the recent acquisition of Anadarko
WCTP are not included in the borrowing base calculation.
If an event of default exists under the Facility, the lenders can accelerate the maturity and exercise other rights and
remedies, including the enforcement of security granted pursuant to the Facility over certain assets held by our subsidiaries. We
were in compliance with the financial covenants below contained in the Facility as of September 30, 2021 (the most recent
assessment date), which requires the maintenance of:
•
•
•
•
the field life cover ratio (as defined in the glossary), not less than 1.30x; and
the loan life cover ratio (as defined in the glossary), not less than 1.10x; and
the interest cover ratio (as defined in the glossary), not less than 2.25x; and
the debt cover ratio (as defined in the glossary), not more than 4.0x as amended.
The Facility contains customary cross default provisions.
Corporate Revolver
In August 2018, we amended and restated the Corporate Revolver maintaining the borrowing capacity at $400.0
million, extending the maturity date from November 2018 to May 2022 and lowering the margin 100 basis points to 5%. This
results in lower commitment fees on the undrawn portion of the total commitments, which is 30% per annum of the respective
margin. The Corporate Revolver is available for general corporate purposes and for oil and gas exploration, appraisal and
development programs. As of December 31, 2021, we have $1.1 million of net deferred financing costs related to the Corporate
Revolver, which will be amortized over the remaining term. These deferred financing costs are included in the Other assets
section of our consolidated balance sheets.
103
As of December 31, 2021, there were no outstanding borrowings under the Corporate Revolver and the undrawn
availability under the Corporate Revolver was $400.0 million.
Interest is the aggregate of the applicable margin (5.0%); LIBOR; and mandatory cost (if any, as defined in the
Corporate Revolver). Interest is payable on the last day of each interest period (and, if the interest period is longer than six
months, on the dates falling at six‑month intervals after the first day of the interest period). We pay commitment fees on the
undrawn portion of the total commitments. Commitment fees for the lenders are equal to 30% per annum of the respective
margin when a commitment is available for utilization.
The Corporate Revolver expires on May 31, 2022. The available amount is not subject to borrowing base constraints.
we have the right to cancel all the undrawn commitments under the Corporate Revolver. We are required to repay certain
amounts due under the Corporate Revolver with sales of certain subsidiaries or sales of certain assets. If an event of default
exists under the Corporate Revolver, the lenders can accelerate the maturity and exercise other rights and remedies, including
the enforcement of security granted pursuant to the Corporate Revolver over certain assets held by us.
We were in compliance with the financial covenants below contained in the Corporate Revolver as of September 30,
2021 (the most recent assessment date), which requires the maintenance of:
•
•
the interest cover ratio (as defined in the glossary), not less than 2.25x; and
the debt cover ratio (as defined in the glossary), not more than 4.0x as amended.
The Corporate Revolver contains customary cross default provisions.
7.875% Senior Secured Notes due 2021
In April 2019, all of the 7.875% Senior Secured Notes were redeemed for $543.8 million, including accrued interest
and the early redemption premium. The redemption resulted in a $22.9 million loss on extinguishment of debt, which is
included in Interest and other financing costs, net on the consolidated statement of operations for the year ended December 31,
2019.
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
7.875% 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 7.125% Senior Notes.
The 7.125% Senior Notes mature on April 4, 2026. We will pay interest in arrears on the 7.125% Senior Notes each
April 4 and October 4, commencing on October 4, 2019. The 7.125% Senior Notes are senior, unsecured obligations of Kosmos
Energy Ltd. and rank equal in right of payment with all of its existing and future senior indebtedness (including all borrowings
under the Corporate Revolver, the 7.750% Senior Notes and the 7.500% Senior Notes ) and rank effectively junior in right of
payment to all of its existing and future secured indebtedness (including all borrowings under the Facility) and all borrowings
under the GoM Term Loan. The 7.125% Senior Notes are guaranteed on a senior, unsecured basis by certain subsidiaries
owning the Company's U.S. Gulf of Mexico assets and the interests acquired in the Anadarko WCTP acquisition, and on a
subordinated, unsecured basis by certain subsidiaries that borrow under, or guarantee, the Facility and that guarantee the
Corporate Revolver, the 7.750% Senior Notes and the 7.500% Senior Notes.
104
At any time prior to April 4, 2022, and subject to certain conditions, the Company may, on one or more occasions,
redeem up to 40% of the original principal amount of the 7.125% Senior Notes with an amount not to exceed the net cash
proceeds of certain equity offerings at a redemption price of 107.125% of the outstanding principal amount of the 7.125%
Senior Notes, together with accrued and unpaid interest and premium, if any, to, but excluding, the date of redemption.
Additionally, at any time prior to April 4, 2022 the Company may, on any one or more occasions, redeem all or a part of the
7.125% Senior Notes at a redemption price equal to 100%, plus any accrued and unpaid interest, and plus a “make-whole”
premium. On or after April 4, 2022, the Company may redeem all or a part of the 7.125% Senior Notes at the redemption prices
(expressed as percentages of principal amount) set forth below plus accrued and unpaid interest:
Year
On or after April 4, 2022
On or after April 4, 2023
On or after April 4, 2024
Percentage
103.563 %
101.781 %
100.000 %
We may also redeem the 7.125% Senior Notes in whole, but not in part, at any time if changes in tax laws impose
certain withholding taxes on amounts payable on the 7.125% Senior Notes at a price equal to the principal amount of the
7.125% Senior Notes plus accrued interest and additional amounts, if any, as may be necessary so that the net amount received
by each holder after any withholding or deduction on payments of the 7.125% Senior Notes will not be less than the amount
such holder would have received if such taxes had not been withheld or deducted.
Upon the occurrence of a change of control triggering event as defined under the 7.125% Senior Notes indenture, the
Company will be required to make an offer to repurchase the 7.125% Senior Notes at a repurchase price equal to 101% of the
principal amount, plus accrued and unpaid interest to, but excluding, the date of repurchase.
If we sell assets, under certain circumstances outlined in the 7.125% Senior Notes indenture, we will be required to use
the net proceeds to make an offer to purchase the 7.125% Senior Notes at an offer price in cash in an amount equal to 100% of
the principal amount of the 7.125% Senior Notes, plus accrued and unpaid interest to, but excluding, the repurchase date.
The 7.125% Senior Notes indenture restricts the ability of the Company and its restricted subsidiaries to, among other
things: incur or guarantee additional indebtedness, create liens, pay dividends or make distributions in respect of capital stock,
purchase or redeem capital stock, make investments or certain other restricted payments, sell assets, enter into agreements that
restrict the ability of the Company’s subsidiaries to make dividends or other payments to the Company, enter into transactions
with affiliates, or effect certain consolidations, mergers or amalgamations. These covenants are subject to a number of
important qualifications and exceptions. Certain of these covenants will be terminated if the 7.125% Senior Notes are assigned
an investment grade rating by both Standard & Poor’s Rating Services and Fitch Ratings Inc. and no default or event of default
has occurred and is continuing. The 7.125% Senior Notes contain customary cross default provisions.
7.750% Senior Notes due 2027
In October 2021, the Company issued $400.0 million of 7.750% Senior Notes and received net proceeds of
approximately $395.0 million after deducting fees. We used the net proceeds, together with cash on hand, to refinance the
Bridge Notes and to pay expenses related to the issuance of the 7.750% Senior Notes.
The 7.750% Senior Notes mature on May 1, 2027. Interest is payable in arrears each May 1 and November 1,
commencing on May 1, 2022. The 7.750% Senior Notes are senior, unsecured obligations of Kosmos Energy Ltd. and rank
equal in right of payment with all of its existing and future senior indebtedness (including all borrowings under the Corporate
Revolver, the 7.125% Senior Notes and the 7.500% Senior Notes) and rank effectively junior in right of payment to all of its
existing and future secured indebtedness (including all borrowings under the Facility) and all borrowings under the GoM Term
Loan. The 7.750% Senior Notes are guaranteed on a senior, unsecured basis by certain subsidiaries owning the Company's U.S.
Gulf of Mexico assets and the interests acquired in the Anadarko WCTP acquisition, and on a subordinated, unsecured basis by
certain subsidiaries that borrow under, or guarantee, the Facility and that guarantee the Corporate Revolver, the 7.125% Senior
Notes and the 7.500% Senior Notes.
105
At any time prior to November 1, 2023, and subject to certain conditions, the Company may, on one or more
occasions, redeem up to 40% of the original principal amount of the 7.750% Senior Notes with an amount not to exceed the net
cash proceeds of certain equity offerings at a redemption price of 107.750% of the outstanding principal amount of the 7.750%
Senior Notes, together with accrued and unpaid interest and premium, if any, to, but excluding, the date of redemption.
Additionally, at any time prior to November 1, 2023 the Company may, on any one or more occasions, redeem all or a part of
the 7.750% Senior Notes at a redemption price equal to 100%, plus any accrued and unpaid interest, and plus a “make-whole”
premium. On or after November 1, 2023, the Company may redeem all or a part of the 7.750% Senior Notes at the redemption
prices (expressed as percentages of principal amount) set forth below plus accrued and unpaid interest:
Year
On or after November 1, 2023
On or after November 1, 2024
On or after November 1, 2025
Percentage
103.875 %
101.938 %
100.000 %
We may also redeem the 7.750% Senior Notes in whole, but not in part, at any time if changes in tax laws impose
certain withholding taxes on amounts payable on the 7.750% Senior Notes at a price equal to the principal amount of the
7.750% Senior Notes plus accrued interest and additional amounts, if any, as may be necessary so that the net amount received
by each holder after any withholding or deduction on payments of the 7.750% Senior Notes will not be less than the amount
such holder would have received if such taxes had not been withheld or deducted.
Upon the occurrence of a change of control triggering event as defined under the 7.750% Senior Notes indenture, the
Company will be required to make an offer to repurchase the 7.750% Senior Notes at a repurchase price equal to 101% of the
principal amount, plus accrued and unpaid interest to, but excluding, the date of repurchase.
If we sell assets, under certain circumstances outlined in the 7.750% Senior Notes indenture, we will be required to use
the net proceeds to make an offer to purchase the 7.750% Senior Notes at an offer price in cash in an amount equal to 100% of
the principal amount of the 7.750% Senior Notes, plus accrued and unpaid interest to, but excluding, the repurchase date.
The 7.750% Senior Notes indenture restricts the ability of the Company and its restricted subsidiaries to, among other
things: incur or guarantee additional indebtedness, create liens, pay dividends or make distributions in respect of capital stock,
purchase or redeem capital stock, make investments or certain other restricted payments, sell assets, enter into agreements that
restrict the ability of the Company's subsidiaries to make dividends or other payments to the Company, enter into transactions
with affiliates, or effect certain consolidations, mergers or amalgamations. These covenants are subject to a number of
important qualifications and exceptions. Certain of these covenants will be terminated if the 7.750% Senior Notes are assigned
an investment grade rating by both Standard & Poor’s Rating Services and Fitch Ratings Inc. and no default or event of default
has occurred and is continuing. The 7.750% Senior Notes contain customary cross default provisions.
7.500% Senior Notes due 2028
In March 2021, the Company issued $450.0 million of 7.500% Senior Notes and received net proceeds of
approximately $444.4 million after deducting fees. We used the net proceeds to repay outstanding indebtedness under the
Corporate Revolver and the Facility, to pay expenses related to the issuance of the 7.500% Senior Notes and for general
corporate purposes.
The 7.500% Senior Notes mature on March 1, 2028. Interest is payable in arrears each March 1 and September 1,
commencing on September 1, 2021. The 7.500% Senior Notes are senior, unsecured obligations of Kosmos Energy Ltd. and
rank equal in right of payment with all of its existing and future senior indebtedness (including all borrowings under the
Corporate Revolver, the 7.125% Senior Notes and the 7.750% Senior Notes) and rank effectively junior in right of payment to
all of its existing and future secured indebtedness (including all borrowings under the Facility) and all borrowings under the
GoM Term Loan. The 7.500% Senior Notes are guaranteed on a senior, unsecured basis by certain subsidiaries owning the
Company's U.S. Gulf of Mexico assets and the interests acquired in the Anadarko WCTP acquisition, and on a subordinated,
unsecured basis by certain subsidiaries that borrow under, or guarantee, the Facility and that guarantee the Corporate Revolver,
the 7.125% Senior Notes and the 7.750% Senior Notes.
106
At any time prior to March 1, 2024, and subject to certain conditions, the Company may, on one or more occasions,
redeem up to 40% of the original principal amount of the 7.500% Senior Notes with an amount not to exceed the net cash
proceeds of certain equity offerings at a redemption price of 107.500% of the outstanding principal amount of the 7.500%
Senior Notes, together with accrued and unpaid interest and premium, if any, to, but excluding, the date of redemption.
Additionally, at any time prior to March 1, 2024 the Company may, on any one or more occasions, redeem all or a part of the
7.500% Senior Notes at a redemption price equal to 100%, plus any accrued and unpaid interest, and plus a “make-whole”
premium. On or after March 1, 2024, the Company may redeem all or a part of the 7.500% Senior Notes at the redemption
prices (expressed as percentages of principal amount) set forth below plus accrued and unpaid interest:
Year
On or after March 1, 2024
On or after March 1, 2025
On or after March 1, 2026
Percentage
103.750 %
101.875 %
100.000 %
We may also redeem the 7.500% Senior Notes in whole, but not in part, at any time if changes in tax laws impose
certain withholding taxes on amounts payable on the 7.500% Senior Notes at a price equal to the principal amount of the
7.500% Senior Notes plus accrued interest and additional amounts, if any, as may be necessary so that the net amount received
by each holder after any withholding or deduction on payments of the 7.500% Senior Notes will not be less than the amount
such holder would have received if such taxes had not been withheld or deducted.
Upon the occurrence of a change of control triggering event as defined under the 7.500% Senior Notes indenture, the
Company will be required to make an offer to repurchase the 7.500% Senior Notes at a repurchase price equal to 101% of the
principal amount, plus accrued and unpaid interest to, but excluding, the date of repurchase.
If we sell assets, under certain circumstances outlined in the 7.500% Senior Notes indenture, we will be required to use
the net proceeds to make an offer to purchase the 7.500% Senior Notes at an offer price in cash in an amount equal to 100% of
the principal amount of the 7.500% Senior Notes, plus accrued and unpaid interest to, but excluding, the repurchase date.
The 7.500% Senior Notes indenture restricts the ability of the Company and its restricted subsidiaries to, among other
things: incur or guarantee additional indebtedness, create liens, pay dividends or make distributions in respect of capital stock,
purchase or redeem capital stock, make investments or certain other restricted payments, sell assets, enter into agreements that
restrict the ability of the Company’s subsidiaries to make dividends or other payments to the Company, enter into transactions
with affiliates, or effect certain consolidations, mergers or amalgamations. These covenants are subject to a number of
important qualifications and exceptions. Certain of these covenants will be terminated if the 7.500% Senior Notes are assigned
an investment grade rating by both Standard & Poor’s Rating Services and Fitch Ratings Inc. and no default or event of default
has occurred and is continuing. The 7.500% Senior Notes contain customary cross default provisions.
Bridge Notes
In connection with the completion of the acquisition of additional interests in Ghana, the Company issued $400 million
aggregate principal amount of floating rate senior notes due 2022 (the “Bridge Notes”) in a private placement to Barclays Bank
PLC and Standard Chartered Bank. In October 2021, the Company refinanced the Bridge Notes with the 7.750% Senior Notes.
As a result, the Company incurred a $4.4 million loss on extinguishment of debt, which is included in Interest and other
financing costs, net on the consolidated statement of operations for the year ended December 31, 2021.
Production Prepayment Agreement, net
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 Company has terminated
the Production Prepayment Agreement and the initial prepayment of $50 million advanced under the Production Prepayment
Agreement by Trafigura in the second quarter of 2020 has been extinguished and converted into the GoM Term Loan as of
September 30, 2020.
GoM Term Loan
In September 2020, the Company entered into a five-year $200 million senior secured term-loan credit agreement
secured against the Company's U.S. Gulf of Mexico assets with net proceeds received of $197.7 million after deducting fees
and other expenses. The GoM Term Loan also includes an accordion feature providing for incremental commitments of up to
$100 million subject to certain conditions. The net proceeds were used to pay down a portion of the Facility and to fund U.S.
Gulf of Mexico working capital and general operating expenses. The $50 million advanced under the Production Prepayment
Agreement with Trafigura in the second quarter of 2020 has been extinguished and converted as part of the GoM Term Loan.
107
The GoM Term Loan bears interest at an effective rate of approximately 6% per annum and matures in 2025, with principal
repayments beginning in the fourth quarter of 2021. During the fourth quarter of 2021, the Company made principal repayments
totaling $25 million on the GoM Term Loan, of which $7.5 million was regular scheduled maturity and $17.5 million as a
voluntary early repayment. As of December 31, 2021, borrowings under the GoM Term Loan totaled $175 million.
The GoM Term Loan contains customary affirmative and negative covenants, including covenants that affect our
ability to incur additional indebtedness, create liens, merge, dispose of assets, and make distributions, dividends, investments or
capital expenditures, among other things. The GoM Term Loan is guaranteed on a senior, secured basis by certain subsidiaries
owning the Company's U.S. Gulf of Mexico assets.
The GoM Term Loan includes certain representations and warranties, indemnities and events of default that, subject to
certain materiality thresholds and grace periods, arise as a result of a payment default, failure to comply with covenants,
material inaccuracy of representation or warranty, and certain bankruptcy or insolvency proceedings. If there is an event of
default, all or any portion of the outstanding indebtedness may be immediately due and payable and other rights may be
exercised including against the collateral.
At December 31, 2021, the estimated repayments of debt during the five years and thereafter are as follows:
Total
2022
2023
2024
2025
2026
Thereafter
Payments Due by Year
(In thousands)
Principal debt
repayments(1)
$ 2,675,000 $
30,000 $
30,000 $ 337,785 $ 327,977 $ 939,350 $ 1,009,888
_______________________________________
(1)
Includes the scheduled maturities for outstanding principal debt balances. The scheduled maturities of debt related to the
Facility as of December 31, 2021 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.
Interest and other financing costs, net
Interest and other financing costs, net incurred during the period comprised of the following:
Interest expense
Amortization—deferred financing costs
Loss on extinguishment of debt
Capitalized interest
Deferred interest
Interest income
Other, net
Years Ended December 31,
2021
2020
2019
(In thousands)
$
146,706 $
119,857 $
145,507
10,580
19,625
9,347
2,902
9,257
24,794
(46,098)
(25,013)
(28,077)
(3,401)
(10,257)
11,216
2,402
(4,773)
5,072
1,919
(3,692)
5,366
Interest and other financing costs, net
$
128,371 $
109,794 $
155,074
Capitalized interest for the years ended December 31, 2021, 2020 and 2019 was $46.1 million, $25.0 million and
$28.1 million, respectively, primarily related to spend on the Greater Tortue Ahmeyim project.
9. Derivative Financial Instruments
We use financial derivative contracts to manage exposures to commodity price and interest rate fluctuations. We do
not hold or issue derivative financial instruments for trading purposes.
We manage market and counterparty credit risk in accordance with our policies and guidelines. In accordance with
these policies and guidelines, our management determines the appropriate timing and extent of derivative transactions. We have
108
included an estimate of non-performance risk in the fair value measurement of our derivative contracts as required by ASC 820
—Fair Value Measurements and Disclosures.
Oil Derivative Contracts
The following table sets forth the volumes in barrels underlying the Company’s outstanding oil derivative contracts
and the weighted average prices per Bbl for those contracts as of December 31, 2021. Volumes and weighted average prices are
net of any offsetting derivative contracts entered into.
Term
2022:
Type of Contract
Index
MBbl
Weighted Average Price per Bbl
Net Deferred
Premium
Payable/
(Receivable)
Swap
Sold Put
Floor
Ceiling
January — December
Three-way collars
Dated Brent
4,500 $
0.64 $ — $ 43.33 $ 56.67 $ 76.91
January — December
Three-way collars
NYMEX WTI
January — December
Two-way collars
January — December
Sold calls(1)
Dated Brent
Dated Brent
1,000
7,000
1,581
1.45
1.12
—
—
—
—
50.00
—
—
65.00
63.57
—
85.00
84.29
60.00
______________________________________
(1)
Represents call option contracts sold to counterparties to enhance other derivative positions.
In January 2022, we entered into Dated Brent three-way collar contracts for 2.0 MMBbl from January 2023 through
December 2023 with an average sold put price of $47.50 per barrel, a floor price of $65.00 per barrel and an average ceiling
price of $95.25 per barrel.
See Note 10—Fair Value Measurements for additional information regarding the Company’s derivative instruments.
The following tables disclose the Company’s derivative instruments as of December 31, 2021 and 2020 and gain/(loss)
from derivatives during the years ended December 31, 2021, 2020 and 2019.
Type of Contract
Balance Sheet Location
2021
2020
(In thousands)
Derivatives not designated as hedging instruments:
Estimated Fair Value
Asset (Liability)
December 31,
Derivative assets:
Commodity
Provisional oil sales
Commodity
Derivative liabilities:
Commodity
Commodity
Derivatives assets—current
$
5,689 $
15,414
Receivables: Oil sales
Derivatives assets—long-term
(853)
1,026
(677)
964
Derivatives liabilities—current
(65,879)
(28,009)
Derivatives liabilities—long-term
(6,298)
(8,069)
Total derivatives not designated as hedging instruments
$
(66,315) $
(20,377)
109
Amount of Gain/(Loss)
Years Ended December 31,
Type of Contract
Location of Gain/(Loss)
2021
2020
2019
(In thousands)
Derivatives not designated as hedging instruments:
Commodity(1)
Commodity
Oil and gas revenue
$
(7,520) $
(5,620) $
1,161
Derivatives, net
(270,185)
(17,180)
(71,885)
Total derivatives not designated
as hedging instruments
______________________________________
$
(277,705) $
(22,800) $
(70,724)
(1)
Amounts represent the change in fair value of our provisional oil sales contracts.
Offsetting of Derivative Assets and Derivative Liabilities
Our derivative instruments which are subject to master netting arrangements with our counterparties only have the
right of offset when there is an event of default. As of December 31, 2021 and 2020, there was not an event of default and,
therefore, the associated gross asset or gross liability amounts related to these arrangements are presented on the consolidated
balance sheets.
10. Fair Value Measurements
In accordance with ASC 820—Fair Value Measurements, fair value measurements are based upon inputs that market
participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable
inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a
company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and
effort. We prioritize the inputs used in measuring fair value into the following fair value hierarchy:
•
•
•
Level 1—quoted prices for identical assets or liabilities in active markets.
Level 2—quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or
liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and
inputs derived principally from or corroborated by observable market data by correlation or other means.
Level 3—unobservable inputs for the asset or liability. The fair value input hierarchy level to which an asset or
liability measurement in its entirety falls is determined based on the lowest level input that is significant to the
measurement in its entirety.
The following tables present the Company’s assets and liabilities that are measured at fair value on a recurring basis as
of December 31, 2021 and 2020, for each fair value hierarchy level:
110
December 31, 2021
Assets:
Commodity derivatives
Provisional oil sales
Liabilities:
Commodity derivatives
Total
December 31, 2020
Assets:
Commodity derivatives
Provisional oil sales
Liabilities:
Commodity derivatives
Total
Fair Value Measurements Using:
Quoted Prices in
Active Markets for
Identical Assets
Significant Other
Observable Inputs
Significant
Unobservable
Inputs
(Level 1)
(Level 2)
(Level 3)
Total
(In thousands)
$
$
$
$
— $
—
—
6,715 $
(853)
(72,177)
— $
—
—
— $
(66,315) $
— $
6,715
(853)
(72,177)
(66,315)
— $
16,378 $
— $
16,378
—
—
(677)
(36,078)
—
—
— $
(20,377) $
— $
(677)
(36,078)
(20,377)
The book values of cash and cash equivalents and restricted cash approximate fair value based on Level 1 inputs. Joint
interest billings, oil sales and other receivables, and accounts payable and accrued liabilities approximate fair value due to the
short‑term nature of these instruments. Our long‑term receivables, after any allowances for doubtful accounts, and other long-
term assets approximate fair value. The estimates of fair value of these items are based on Level 2 inputs.
Commodity Derivatives
Our commodity derivatives represent crude oil collars, put options, call options and swaps for notional barrels of oil at
fixed Dated Brent, NYMEX WTI or Argus LLS oil prices. The values attributable to our oil derivatives are based on (i) the
contracted notional volumes, (ii) independent active futures price quotes for the respective index, (iii) a credit‑adjusted yield
curve applicable to each counterparty by reference to the credit default swap (“CDS”) market and (iv) an independently sourced
estimate of volatility for the respective index. The volatility estimate was provided by certain independent brokers who are
active in buying and selling oil options and was corroborated by market‑quoted volatility factors. The deferred premium is
included in the fair market value of the commodity derivatives. See Note 9—Derivative Financial Instruments for additional
information regarding the Company’s derivative instruments.
Provisional Oil Sales
The value attributable to the provisional oil sales derivative is based on (i) the sales volumes and (ii) the difference in
the independent active futures price quotes for the respective index over the term of the pricing period designated in the sales
contract and the spot price on the lifting date.
111
Debt
The following table presents the carrying values and fair values at December 31, 2021 and 2020:
7.125% Senior Notes
7.750% Senior Notes
7.500% Senior Notes
GoM Term Loan
Corporate Revolver
Facility
Total
December 31, 2021
December 31, 2020
Carrying Value
Fair Value
Carrying Value
Fair Value
(In thousands)
$
$
644,572 $
395,131
444,892
175,000
—
1,000,000
2,659,595 $
632,587 $
386,428
424,688
175,000
—
1,000,000
2,618,703 $
643,524 $
—
—
200,000
100,000
1,200,000
2,143,524 $
613,412
—
—
200,000
100,000
1,200,000
2,113,412
The carrying values of our 7.125% Senior Notes, 7.750% Senior Notes and 7.500% Senior Notes represent the
principal amounts outstanding less unamortized discounts. The fair values of our 7.125% Senior Notes, 7.750% Senior Notes
and 7.500% Senior Notes are based on quoted market prices, which results in a Level 1 fair value measurement. The carrying
values of the GoM Term Loan, Corporate Revolver and Facility approximate fair value since they are subject to short-term
floating interest rates that approximate the rates available to us for those periods.
Nonrecurring Fair Value Measurements - Long-lived assets
Certain long-lived assets are reported at fair value on a non-recurring basis on the Company's consolidated balance
sheet. These long-lived assets are not measured at fair value on an ongoing basis but are subject to fair value adjustments in
certain circumstances. Our long-lived assets are reviewed for impairment when changes in circumstances indicate that the
carrying amount of an asset may not be recoverable.
The Company calculates the estimated fair values of its long-lived assets using the income approach described in the
ASC 820 — Fair Value Measurements. Significant inputs associated with the calculation of estimated discounted future net
cash flows include anticipated future production, pricing estimates, capital and operating costs, market-based weighted average
cost of capital, and risk adjustment factors applied to reserves. These are classified as Level 3 fair value assumptions. The
Company utilizes an average of third-party industry forecasts of Dated Brent, adjusted for location and quality differentials, to
determine our pricing assumptions. In order to evaluate the sensitivity of the assumptions, we analyze sensitivities to prices,
production, and risk adjustment factors.
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 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.
During the fourth quarter of 2020 the Company recorded additional impairment charges totaling approximately
$3.2 million resulting in impairment charges totaling $154.0 million for the year ended December 31, 2020. During the year
ended December 31, 2021, the company did not recognize impairment of proved oil and gas properties as no impairment
indicators were identified. If we experience material declines in oil pricing expectations, 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.
112
11. Asset Retirement Obligations
The following table summarizes the changes in the Company’s asset retirement obligations:
Asset retirement obligations:
Beginning asset retirement obligations
Liabilities incurred during period
Liabilities settled during period
Revisions in estimated retirement obligations
Accretion expense
Ending asset retirement obligations
December 31,
2021
2020
(In thousands)
$
$
251,421 $
38,967
(8,705)
22,744
21,032
325,459 $
235,053
3,436
(2,782)
(3,736)
19,450
251,421
The asset retirement obligations reflect the estimated present value of the amount of dismantlement, removal, site
reclamation, and similar activities associated with our oil and gas properties. The Company utilizes current cost experience to
estimate the expected cash outflows for retirement obligations. The Company estimates the ultimate productive life of the
properties, a risk-adjusted discount rate, and an inflation factor in order to determine the current present value of this obligation.
To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation, a
corresponding adjustment is made to the oil and gas property balance. The liabilities incurred during the period include
$28.3 million associated with our acquisition of additional interests in Ghana. The revisions in estimated retirement obligations
during 2021 and 2020 are related to changes in the estimated timing, scopes of work and costs.
12. Equity‑based Compensation
Restricted Stock Awards and Restricted Stock Units
Our Long-Term Incentive Plan (“LTIP”) provides for the granting of incentive awards in the form of stock options,
stock appreciation rights, restricted stock awards, restricted stock units, among other award types. In April 2021, the board of
directors approved amendments to the LTIP which added 11.0 million shares to the LTIP which were approved at the
corresponding Annual Stockholders Meeting. The LTIP as amended provides for the issuance of 61.5 million shares pursuant to
awards under the LTIP. As of December 31, 2021, the Company had approximately 11.0 million shares that remain available
for issuance under the LTIP.
The Company granted restricted stock units with service vesting criteria and with a combination of market and service
vesting criteria under the LTIP. Substantially, all of these awards vest over a three year period. Upon vesting, restricted stock
units become issued and outstanding stock.
113
The following table reflects the outstanding restricted stock units as of December 31, 2021:
Outstanding at December 31, 2018:
Granted
Forfeited
Vested
Outstanding at December 31, 2019:
Granted
Forfeited
Vested
Outstanding at December 31, 2020:
Granted
Forfeited
Vested
Outstanding at December 31, 2021:
Service Vesting
Restricted Stock
Units
(In thousands)
Weighted-
Average Grant-
Date Fair Value
Market / Service
Vesting
Restricted Stock
Units
(In thousands)
Weighted-
Average Grant-
Date Fair Value
4,115 $
3,228
(591)
(2,021)
4,731
3,481
(1,187)
(2,185)
4,840
2,905
(649)
(2,400)
4,696
6.42
5.01
5.90
5.95
5.71
5.48
6.12
5.91
5.34
2.57
4.05
5.19
3.88
6,716 $
3,195
(813)
(1,300)
7,798
3,394
(726)
(2,607)
7,859
6,744
(1,998)
(1,372)
11,233
9.02
6.02
7.93
6.32
8.42
8.37
8.03
9.47
8.11
3.91
5.50
9.95
5.28
As of December 31, 2021, total equity‑based compensation to be recognized on unvested restricted stock units is $18.9
million over a weighted average period of 1.6 years.
For restricted stock units with a combination of market and service vesting criteria, the number of shares of common
stock to be issued is determined by comparing the Company’s total shareholder return with the total shareholder return of a
predetermined group of peer companies over the performance period and can vest up to 200% of the awards granted. The grant
date fair value ranged from $1.06 to $9.52 per award. The Monte Carlo simulation model utilizes multiple input variables that
determine the probability of satisfying the market condition stipulated in the award grant and calculates the fair value of the
award. The expected volatility utilized in the model was estimated using our historical volatility and the historical volatilities of
our peer companies and ranged from 50.0% to 52.0%. The risk‑free interest rate was based on the U.S. treasury rate for a term
commensurate with the expected life of the grant ranged from 0.2% to 2.5% for restricted stock units. The expected quarterly
dividends ranged from $0.000 to $0.050 commensurate with our current dividend experience.
In January 2022, we granted 2.5 million service vesting restricted stock units and 3.3 million market and service
vesting restricted stock units to our employees under our long-term incentive plan. We expect to recognize approximately
$34.2 million of non-cash compensation expense related to these grants over the next three years.
We record equity-based compensation expense equal to the grant date fair value of share‑based payments over the
vesting periods of the LTIP awards. The following table summarizes certain information related to our share-based payments:
Share-based compensation expense
$
31,651 $
32,706 $
32,370
Total tax benefit
Net tax shortfall (windfall)
Fair value of awards vested
5,786
6,307
9,435
4,694
1,175
26,039
4,898
1,224
20,253
Years Ended December 31,
2021
2020
2019
(In thousands)
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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.
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.
The components of loss before income taxes were as follows:
United States
Foreign
Income (loss) before income taxes
Years Ended December 31,
2021
2020
2019
(In thousands)
$
$
(75,948) $
32,568
(43,380) $
(338,746) $
(78,049)
(416,795) $
(149,919)
175,036
25,117
The components of the provision for income taxes attributable to our income (loss) before income taxes consist of the
following:
Current:
United States
Foreign
Total current
Deferred:
United States
Foreign
Total deferred
Income tax expense (benefit)
Years Ended December 31,
2021
2020
2019
(In thousands)
$
282 $
103,348
103,630
(12,208) $
49,586
37,378
185
171,079
171,264
1,202
(70,376)
(69,174)
34,456 $
34,831
(77,418)
(42,587)
(5,209) $
(18,776)
(71,594)
(90,370)
80,894
$
115
Our reconciliation of income tax expense (benefit) computed by applying our statutory rate and the reported effective
tax rate on income or (loss) from continuing operations is as follows:
Tax at statutory rate
Foreign income (loss) taxed at different rates
Net non-taxable expense / insurance recoveries
Non-deductible insurance premiums
Non-deductible compensation
Non-deductible and other items
Tax shortfall (windfall) on equity-based compensation, net
Change in valuation allowance
U.S. tax loss carryback rate differential
Total tax expense
Effective tax rate(1)
______________________________________
Years Ended December 31,
2021
2020
2019
$
$
(9,110)
17,344
—
—
2,775
1,719
6,307
15,421
—
34,456
$
(In thousands)
(87,527)
(1,771)
—
$
5,275
32,690
(13,352)
—
890
387
1,175
86,539
(4,902)
(5,209)
$
2,625
3,545
3,998
1,224
44,889
—
80,894
$
79 %
1 %
322 %
(1)
The effective tax rate during the years ended December 31, 2021, 2020 and 2019, were impacted by (gains) and losses
of $61.6 million, $(2.9) million and $132.1 million, respectively, incurred in jurisdictions in which we are not subject
to taxes and therefore do not generate any income tax benefits or where there are valuation allowances offsetting the
corresponding deferred tax assets.
The effective tax rate for the United States is approximately 2%, 7% and 12% for the years ended December 31, 2021,
2020 and 2019, respectively. The effective tax rate in the United States is impacted by the effect of non-deductible expenditures
and equity-based compensation tax shortfalls and tax windfalls equal to the difference between the income tax benefit
recognized for financial statement reporting purposes compared to the income tax benefit realized for tax return purposes. For
the years ended December 31, 2021, 2020 and 2019, our effective tax rate in the United States is impacted by valuation
allowances on a portion of our deferred tax assets totaling $6.6 million, $96.6 million and $6.8 million, respectively.
The effective tax rate for Ghana is approximately 35%, 35% and 29% for the years ended December 31, 2021, 2020
and 2019, respectively. The effective tax rate in Ghana is impacted by non-deductible expenditures. The effective tax rate for
the year ended December 31, 2019 was impacted by amounts associated with damage to the turret bearing, which we expect to
recover from insurance proceeds. Any such insurance recoveries would not be subject to income tax.
The effective tax rate for Equatorial Guinea is approximately 35%, 34% and 37% for the years ended December 31,
2021, 2020 and 2019, respectively, and is impacted by non-deductible expenditures.
Our operations in other foreign jurisdictions have a 0% effective tax rate because they reside in countries with a 0%
statutory rate or we have incurred losses in those countries and have full valuation allowances against the corresponding net
deferred tax assets.
Deferred tax assets and liabilities, which are computed on the estimated income tax effect of temporary differences
between financial and tax bases in assets and liabilities, are determined using the tax rates expected to be in effect when taxes
are actually paid or recovered. In assessing the realizability of deferred tax assets, management considers whether it is more
likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax
assets is dependent upon the generation of future taxable income during the periods in which those temporary differences
become deductible. The tax effects of significant temporary differences giving rise to deferred tax assets and liabilities are as
follows:
116
Deferred tax assets:
Foreign capitalized operating expenses
Foreign net operating losses
United States net operating losses
United States deferred interest expense
Equity compensation
Unrealized derivative losses
Asset retirement obligation and other
Total deferred tax assets
Valuation allowance
Total deferred tax assets, net
Deferred tax liabilities:
Depletion, depreciation and amortization related to property and equipment
Total deferred tax liabilities
Net deferred tax liability
December 31,
2021
2020
(In thousands)
$
172,836 $
152,106
35,518
109,094
6,725
12,424
21,710
55,859
32,762
113,427
—
14,089
3,482
41,759
414,166
357,625
(318,343)
(288,288)
95,823
69,337
(806,861)
(806,861)
(642,956)
(642,956)
$
(711,038) $
(573,619)
The Company has foreign net operating loss carryforwards of $95.2 million. Of these losses, we expect $0.5 million,
$0.6 million, $0.7 million, and $43.3 million to expire in 2022, 2023, 2024, and 2027 respectively, and $50.1 million do not
expire. All of these losses currently have offsetting valuation allowances. The Company has $519.5 million of United States net
operating loss that will not expire.
The Company is open to tax examinations in the United States for federal income tax return years 2018 through 2020
in Ghana to federal income tax return years 2018 through 2020, and in Equatorial Guinea to federal income tax return years
2019-2020.
As of December 31, 2021, 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.
14. Net Income (Loss) Per Share
In the calculation of basic net income per share, participating securities are allocated earnings based on actual dividend
distributions received plus a proportionate share of undistributed net income, if any. We calculate basic net income per share
under the two‑class method. Diluted net income (loss) per share is calculated under both the two-class method and the treasury
stock method and the more dilutive of the two calculations is presented. The computation of diluted net income (loss) per share
reflects the potential dilution that could occur if all outstanding awards under our LTIP were converted into shares of common
stock or resulted in the issuance of shares of common stock that would then share in the earnings of the Company. During
periods in which the Company realizes a loss from continuing operations securities would not be dilutive to net loss per share
and conversion into shares of common stock is assumed not to occur.
Basic net income (loss) per share is computed as (i) net income (loss), (ii) less income allocable to participating
securities (iii) divided by weighted average basic shares outstanding. The Company’s diluted net income (loss) per share is
computed as (i) basic net income (loss), (ii) plus diluted adjustments to income allocable to participating securities (iii) divided
by weighted average diluted shares outstanding.
117
Numerator:
Net loss allocable to common stockholders
$
(77,836) $
(411,586) $
(55,777)
Years Ended
December 31,
2021
2020
2019
(In thousands, except per share data)
Denominator:
Weighted average number of shares outstanding:
Basic
Restricted stock units(1)(2)
Diluted
Net loss per share:
Basic
Diluted
______________________________________
416,943
405,212
401,368
—
—
—
416,943
405,212
401,368
$
$
(0.19) $
(0.19) $
(1.02) $
(1.02) $
(0.14)
(0.14)
(1)
(2)
Our restricted stock units are not considered to be participating securities and, therefore, are excluded from the basic
net income (loss) per share calculation.
For the years ended December 31, 2021, 2020 and 2019, we excluded 19.0 million, 6.1 million and 15.3 million
outstanding restricted stock units, respectively, from the computations of diluted net income 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.
The Jubilee Field in Ghana covers an area within both the WCTP and DT petroleum contract areas. It was agreed the
Jubilee Field would be unitized for optimal resource recovery. Kosmos and its partners executed a comprehensive unitization
and unit operating agreement, the Jubilee UUOA, to unitize the Jubilee Field and govern each party’s respective rights and
duties in the Jubilee Unit, which was effective July 16, 2009. Pursuant to the terms of the Jubilee UUOA, the tract
participations are subject to a process of redetermination. The initial redetermination process was completed on October 14,
2011. As a result of the initial redetermination process, our Unit Interest is 24.1%. Following the acquisition of Anadarko
WCTP, which owned a participating interest in the WCTP Block and DT Block, our Unit Interest (participating interest in the
Jubilee Unit) has since increased from 24.1% to 42.1%. These consolidated financial statements are based on these
redetermined tract participations. Our unit interest may change in the future should another redetermination occur.
Under the Deepwater Tano Block Joint Operating Agreement, certain joint venture partners have pre-emption rights
that, if fully exercised and approved by the Government of Ghana, could reduce our ultimate interest in the Jubilee Unit Area
by 3.8% to 38.3%. In November 2021, we received notice from certain joint venture partners that they intend to exercise their
pre-emption rights in relation to Kosmos' acquisition of Anadarko WCTP. The exercise of pre-emption rights is subject to
finalizing definitive agreements with Kosmos and requires approval from GNPC and the Ghanaian Ministry of Energy.
The Greater Tortue Ahmeyim Unit, which includes the Ahmeyim discovery in Mauritania Block C8 and the Guembeul
discovery in the Senegal Saint Louis Offshore Profond Block, straddles the border between Mauritania and Senegal. To
optimize resource recovery in this field, we entered into the GTA UUOA in February 2019 with the governments of Mauritania
and Senegal. The GTA UUOA governs interests in and development of the Greater Tortue Ahmeyim Field and created the
Greater Tortue Ahmeyim Unit from portions of the Mauritania Block C8 and the Senegal Saint Louis Offshore Profond Block
areas. These interest percentages are subject to redetermination of the participating interests in the Greater Tortue Ahmeyim
Field pursuant to the terms of the GTA UUOA. These consolidated financial statements are based our current payment interest
on development activities in the Greater Tortue Ahmeyim Unit of 26.7%. Our unit interest may change in the future should a
redetermination occur.
118
We currently have a commitment to drill one exploration well in Mauritania and a $200.2 million FPSO Contract
Liability related to the deferred sale of the Greater Tortue FPSO.
Performance Obligations
As of December 31, 2021 and 2020, the Company had performance bonds totaling $195.5 million and $195.5 million,
respectively, for our supplemental bonding requirements stipulated by the BOEM and $3.5 million and $7.1 million,
respectively, to third parties related to costs anticipated for the plugging and abandonment of certain wells and the removal of
certain facilities in our U.S. Gulf of Mexico fields.
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. During the year ended December 31, 2019 we declared and
issued cash dividends to stockholders totaling $0.1808 per common share.
16. Additional Financial Information
Accrued Liabilities
Accrued liabilities consisted of the following:
Accrued liabilities:
Exploration, development and production
Revenue payable
Current asset retirement obligations
General and administrative expenses
Interest
Income taxes
Taxes other than income
Derivatives
Other
December 31,
2021
2020
(In thousands)
$
61,881 $
31,986
3,222
27,980
31,117
69,392
2,854
19,302
2,936
89,162
15,079
7,255
4,988
23,725
37,344
2,815
17,475
5,417
$
250,670 $
203,260
Gain on sale of assets
During the year ended December 31, 2020, we recognized a $92.1 million gain related to the farm down of interests in
blocks offshore Sao Tome & Principe, Suriname and Namibia to Shell.
During the year ended December 31, 2019, we recognized a $10.5 million gain related to the farm-out of Blocks 6 and
11 offshore Sao Tome and Principe.
Facilities Insurance Modifications, net
Facilities insurance modifications, net consists of costs associated with the long-term solution to convert the Jubilee
FPSO to a permanently spread moored facility, net of any insurance reimbursements.
Other Expenses, net
Other expenses, net incurred during the period is comprised of the following:
119
Loss on disposal of inventory
Gain on insurance settlements
Loss on asset retirement obligations liability settlements
Restructuring charges
Other, net
Other expenses, net
Years Ended December 31,
2021
2020
2019
(In thousands)
$
$
1,239 $
—
6,351
2,584
(63)
10,111 $
8,607 $
—
1,966
16,474
10,755
37,802 $
4,590
(3,509)
193
11,528
11,846
24,648
The restructuring charges are for employee severance and related benefit costs incurred as part of a corporate
reorganization.
120
17. Business Segment Information
Kosmos is engaged in a single line of business, which is the exploration and development of oil and gas.
At December 31, 2021, the Company had operations in four geographic reporting segments: Ghana, Equatorial Guinea,
Mauritania/Senegal and the U.S. Gulf of Mexico. To assess performance of the reporting segments, the Chief Operating
Decision Maker reviews capital expenditures. Capital expenditures, as defined by the Company, may not be comparable to
similarly titled measures used by other companies and should be considered in conjunction with our consolidated financial
statements and notes thereto. Financial information for each area is presented below:
Ghana(2)
Equatorial
Guinea
Mauritania
/ Senegal
U.S. Gulf
of Mexico
Corporate &
Other
Eliminations
Total
(in thousands)
$ 644,232
$ 260,520 $
— $ 427,261 $
— $
— $ 1,332,013
Years ended December 31, 2021
Revenues and other income:
Oil and gas revenue
Gain on sale of assets
Other income, net
—
6
—
—
Total revenues and other income
644,238
260,520
Costs and expenses:
Oil and gas production
151,079
93,032
Facilities insurance modifications, net
Exploration expenses
General and administrative
(1,586)
1,527
12,179
—
5,700
4,343
Depletion, depreciation and amortization
240,901
56,468
Impairment of long-lived assets
—
—
—
—
—
—
—
10,639
8,601
61
—
—
1,279
428,540
101,895
—
41,230
17,665
168,142
—
Interest and other financing costs, net(1)
51,279
(1,661)
(44,831)
15,875
Derivatives, net
Other expenses, net
—
—
—
—
206,466
41,891
(2,189)
30,118
1,564
395,073
396,637
—
—
6,286
172,869
1,649
—
109,493
270,185
4,010
—
(396,096)
1,564
262
(396,096)
1,333,839
—
—
—
(124,128)
—
—
346,006
(1,586)
65,382
91,529
467,221
—
(1,784)
128,371
—
270,185
(270,185)
10,111
Total costs and expenses
661,845
199,773
(27,719)
374,925
564,492
(396,097)
1,377,219
Income (loss) before income taxes
Income tax expense (benefit)
(17,607)
(4,290)
60,747
37,487
27,719
53,615
(167,855)
—
(4,958)
6,217
1
—
(43,380)
34,456
Net income (loss)
$
(13,317) $
23,260 $
27,719 $
58,573 $
(174,072) $
1 $
(77,836)
Consolidated capital expenditures
$ 575,472
$
77,364 $
170,690 $
96,897 $
3,791 $
— $ 924,214
As of December 31, 2021
Property and equipment, net
$ 1,885,116
$ 460,975 $
918,683 $ 901,392 $
17,821 $
— $ 4,183,987
Total assets
$ 3,125,835
$ 911,159 $ 1,346,622 $ 3,258,264 $ 17,108,138 $
(20,809,367) $ 4,940,651
______________________________________
(1)
(2)
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.
Includes activity related to our acquisition of additional interests in Ghana commencing October 13, 2021, the
acquisition date. Additionally, the acquisition purchase price of $465.4 million is included in Consolidated capital
expenditures.
121
Year ended December 31, 2020
Revenues and other income:
Oil and gas revenue
Gain on sale of assets
Other income, net
—
2
—
—
Total revenues and other income
366,517
152,501
Costs and expenses:
Oil and gas production
169,357
80,813
Facilities insurance modifications, net
Exploration expenses
General and administrative
13,161
182
13,506
—
8,290
4,865
Depletion, depreciation and amortization
235,772
64,786
Impairment of long-lived assets
—
—
Ghana
Equatorial
Guinea
Mauritania
/ Senegal
U.S. Gulf of
Mexico
Corporate &
Other
Eliminations
Total
(in thousands)
$ 366,515 $ 152,501 $
— $
285,017 $
— $
— $ 804,033
—
—
—
—
—
8,189
7,464
61
—
84
280
285,381
88,307
—
26,792
12,607
181,898
153,959
92,079
120,135
212,214
—
—
41,163
129,801
3,345
—
73,612
17,180
21,312
—
92,163
(120,415)
2
(120,415)
896,198
—
—
—
338,477
13,161
84,616
(96,101)
72,142
—
485,862
153,959
(7,134)
109,794
—
17,180
(17,180)
37,802
Interest and other financing costs, net(1)
54,530
(1,248)
(27,339)
17,373
Derivatives, net
Other expenses, net
—
—
—
—
(27,925)
2,281
4,829
54,485
Total costs and expenses
458,583
159,787
(6,796)
535,421
286,413
(120,415)
1,312,993
Income (loss) before income taxes
(92,066)
(7,286)
6,796
(250,040)
(74,199)
Income tax expense (benefit)
(30,486)
2,428
—
26,061
(3,212)
—
—
(416,795)
(5,209)
Net income (loss)
$
(61,580) $
(9,714) $
6,796 $
(276,101) $
(70,987) $
— $ (411,586)
Consolidated capital expenditures
$
44,146 $
38,126 $
126,803 $
123,197 $
(58,293) $
— $ 273,979
As of December 31, 2020
Property and equipment, net
$ 1,293,372 $ 426,365 $
580,920 $
998,204 $
22,052 $
— $ 3,320,913
Total assets
$ 1,397,802 $ 689,222 $
823,411 $ 3,171,851 $ 12,654,827 $
(14,869,520) $ 3,867,593
______________________________________
(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.
122
Year ended December 31, 2019
Revenues and other income:
Oil and gas revenue
Gain on sale of assets
Other income, net
—
5
—
—
Total revenues and other income
738,914
300,547
Costs and expenses:
Oil and gas production
188,207
90,607
Facilities insurance modifications, net
(24,254)
—
Ghana
Equatorial
Guinea
Mauritania
/ Senegal
U.S. Gulf
of Mexico
Corporate &
Other
Eliminations
Total
(in thousands)
$ 738,909 $ 300,547 $
— $ 459,960 $
— $
— $ 1,499,416
—
—
—
—
—
—
1,194
461,154
123,799
—
10,528
155,866
166,394
—
—
—
10,528
(157,100)
(35)
(157,100)
1,509,909
—
—
—
402,613
(24,254)
180,955
Exploration expenses
204
13,350
11,181
115,765
40,455
General and administrative
18,618
6,643
8,222
25,456
159,539
(108,468)
110,010
Depletion, depreciation and amortization
268,866
75,565
62
214,592
Interest and other financing costs, net(1)
72,226
(634)
(26,537)
Derivatives, net
Other expenses, net
—
—
—
40,382
(563)
12,056
21,266
30,387
2,691
4,776
95,887
41,498
11,580
—
563,861
(7,134)
155,074
—
(41,498)
71,885
24,648
Total costs and expenses
564,249
184,968
4,984
533,956
353,735
(157,100)
1,484,792
Income (loss) before income taxes
174,665
115,579
(4,984)
(72,802)
(187,341)
Income tax expense (benefit)
50,293
49,192
—
(8,419)
(10,172)
—
—
25,117
80,894
Net income (loss)
$ 124,372 $
66,387 $
(4,984) $
(64,383) $
(177,169) $
— $
(55,777)
Consolidated capital expenditures
$
98,285 $
63,798 $
12,556 $ 232,891 $
33,206 $
— $ 440,736
As of December 31, 2019
Property and equipment, net
$ 1,487,114 $ 464,420 $
438,800 $ 1,216,453 $
35,545 $
— $ 3,642,332
Total assets
$ 1,654,266 $ 650,607 $
581,317 $ 3,251,420 $ 12,144,312 $
(13,964,690) $ 4,317,232
______________________________________
(1)
Interest expense is recorded based on actual third-party and intercompany debt agreements. Capitalized interest is
recorded on the business unit where the assets reside.
123
Consolidated capital expenditures:
Consolidated Statements of Cash Flows - Investing activities:
Oil and gas assets
Acquisition of oil and gas properties
Adjustments:
Changes in capital accruals
Exploration expense, excluding unsuccessful well costs and leasehold
impairments(1)
Capitalized interest
Proceeds on sale of assets
Other
Total consolidated capital expenditures
______________________________________
Years Ended December 31,
2021
2020
2019
(In thousands)
$
472,631 $
465,367
379,593 $
—
352,013
—
(18,534)
(42,315)
33,717
46,563
(46,098)
(4,422)
8,707
924,214 $
61,459
(25,013)
(99,337)
(408)
273,979 $
93,142
(28,077)
(16,713)
6,654
440,736
$
(1)
Unsuccessful well costs are included in oil and gas assets when incurred.
KOSMOS ENERGY LTD.
Supplemental Oil and Gas Data (Unaudited)
Net proved oil and gas reserve estimates presented were prepared by Ryder Scott Company, L.P. (“RSC”) for the years
ended December 31, 2021, 2020 and 2019. RSC are independent petroleum engineers located in Houston, Texas. RSC has
prepared the reserve estimates presented herein and meet the requirements regarding qualifications, independence, objectivity
and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information
promulgated by the Society of Petroleum Engineers. We maintain an internal staff of petroleum engineers and geoscience
professionals who work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of data
furnished to independent reserve engineers for their reserves estimation process.
124
Net Proved Developed and Undeveloped Reserves
The following table is a summary of net proved developed and undeveloped oil and gas reserves to Kosmos’ interest in
the Jubilee and TEN fields in Ghana, Equatorial Guinea, Mauritania, Senegal and the U.S. Gulf of Mexico.
Ghana
Equatorial
Guinea
Mauritania
/ Senegal
U.S.
Gulf of
Mexico
Total
Oil
Ghana
Equatorial
Guinea
Mauritania
/ Senegal
U.S.
Gulf of
Mexico
Total
Gas
Kosmos
Total
Oil, Condensate, NGLs (MMBbls)
Natural Gas (Bcf)
Equity
Method
Investment-
Equatorial
Guinea
(MMBoe)
Total
Net proved developed and
undeveloped reserves at
December 31, 2018(1)
Extensions and
discoveries
Production
Revision in estimate
Purchases of minerals-in-
place(3)
Net proved developed and
undeveloped reserves at
December 31, 2019(1)
Extensions and
discoveries
Production
Revision in estimate
Purchases of minerals-in-
place
Net proved developed and
undeveloped reserves at
December 31, 2020(1)
Extensions and
discoveries
Production
Revision in estimate(2)
Purchases of minerals-in-
place
Net proved developed and
undeveloped reserves at
December 31, 2021(1)
Proved developed reserves(1)
December 31, 2018
December 31, 2019
December 31, 2020
December 31, 2021
Proved undeveloped
reserves(1)
December 31, 2018
December 31, 2019
December 31, 2020
December 31, 2021
82
—
(11)
17
88
—
(10)
(10)
68
—
(10)
10
52
120
48
47
26
52
33
41
42
68
—
—
(4)
6
24
26
—
(4)
2
—
24
—
(4)
4
—
24
—
23
21
20
—
3
4
5
2
(6)
(14)
(1)
(600)
(2) (617)
(109)
—
45
127
47
—
—
—
—
—
—
—
(8)
(23)
3
26
(1)
(1)
24
—
40
154
45
—
—
—
—
(7)
(21)
—
—
—
—
—
—
—
8
—
34
127
31
—
—
(6)
(20)
—
4
26
10
27
—
—
52
8
32
185
68
—
—
—
—
—
—
—
8
33
81
34
104
32
79
28
100
12
6
2
4
45
50
48
85
33
31
23
56
14
14
8
12
—
—
—
(2)
14
12
—
—
—
38
85
141
26
166
—
—
—
—
—
—
(6)
(7)
3
—
14
—
(24)
26
26
—
—
—
—
(24)
26
(26) —
—
35
92
169
—
169
600
—
600
—
(6)
(6)
100
(22)
—
100
—
(22)
—
(109)
—
11
—
—
—
—
11
—
12
11
11
—
—
—
—
—
—
—
—
—
—
27
69
139
—
139
—
—
—
—
590
(5)
(5)
5
605
—
(21)
127
—
—
—
(21)
—
127
—
—
27
57
—
57
590
27
695
301
—
301
—
—
—
—
—
—
—
590
24
28
25
20
13
7
2
6
57
71
60
87
28
21
10
91
116
89
115
50
53
50
25
116
—
116
—
89
—
115
1
—
—
51
53
50
608
186
—
186
______________________________________
125
(1)
(2)
(3)
The sum of proved developed reserves and proved undeveloped reserves may not add to net proved developed and
undeveloped reserves as a result of rounding.
The increase in proved reserves is a result of an increase of 9.2 MMBbl in Greater Jubilee related to field performance,
positive drilling results and optimization of future development plans. Changes at TEN include a positive revision of
2.0 MMBoe related to increase in estimated associated gas sales. Changes at Equatorial Guinea include an increase of
3.6 MMBbl related to Okume Complex performance and drilling results. Changes at Mauritania/Senegal are related to
the economic status of the Greater Tortue Ahmeyim project due to project progress and improved oil price (+106.5
MMBoe). Changes at the U.S. Gulf of Mexico include an increase of 4.4 MMBoe related to strong performance of
certain fields.
We disclosed our share of reserves that were accounted for by the equity method. Effective of January 1, 2019, our
outstanding shares in KTIPI were transferred to Trident in exchange for a 40.4% undivided participating interest in the
Ceiba Field and Okume Complex. As a result, our interest in the Ceiba Field and Okume Complex is accounted for
under the proportionate consolidation method of accounting going forward.
Net proved reserves were calculated utilizing
the
the
first‑day‑of‑the‑month oil price for each month based on the respective benchmark price in the period January through
December 2021. The average price is adjusted for crude handling, transportation fees, quality, and a regional price differential.
twelve month unweighted arithmetic average of
Proved oil and gas reserves are defined by the SEC Rule 4.10(a) of Regulation S‑X as those quantities of oil and gas,
which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recovered
under current economic conditions, operating methods, and government regulations. Inherent uncertainties exist in estimating
proved reserve quantities, projecting future production rates and timing of development expenditures.
Capitalized Costs Related to Oil and Gas Activities
The following table presents aggregate capitalized costs related to oil and gas activities:
Ghana
Equatorial
Guinea
Mauritania /
Senegal
U.S. Gulf of
Mexico
Other
Kosmos Total
As of December 31, 2021
Unproved properties
Proved properties
Accumulated depletion
Net capitalized costs
As of December 31, 2020
Unproved properties
Proved properties
Accumulated depletion
Net capitalized costs
$
$
$
$
— $
4,116
4,116
(2,231)
1,885 $
— $
3,288
3,288
(1,995)
1,293 $
86 $
545
631
(170)
461 $
125 $
421
546
(120)
426 $
(In millions)
167 $
752
919
—
919 $
160 $
421
581
—
581 $
185 $
1,313
1,498
(599)
899 $
196 $
1,240
1,436
(440)
996 $
13 $
—
13
—
13 $
14 $
—
14
—
14 $
451
6,726
7,177
(3,000)
4,177
495
5,370
5,865
(2,555)
3,310
126
Costs Incurred in Oil and Gas Activities
The following tables reflects total costs incurred, both capitalized and expensed, for oil and gas property acquisition,
exploration, and development activities for the year.
Year ended December 31, 2021
Property acquisition:
Unproved
Proved(2)
Exploration
Development(3)
Total costs incurred
Year ended December 31, 2020
Property acquisition:
Unproved
Proved
Exploration
Development
Total costs incurred
Year ended December 31, 2019
Property acquisition:
Unproved
Proved
Exploration
Development
Total costs incurred
Ghana
Equatorial
Guinea
Mauritania
/ Senegal
U.S. Gulf
of Mexico Other(1)
Kosmos
Total
(In millions)
$ — $
718
—
112
830 $
$
1 $
1
8
79
89 $
— $
—
16
333
349 $
(2) $
—
60
46
104 $
(1) $
(2)
—
719
6
90
570
—
5 $ 1,377
$ — $ — $
(2)
7
20
25 $
—
—
39
39 $
$
— $
—
21
129
150 $
5 $
—
34
99
138 $
(1) $
—
34
—
33 $
4
(2)
96
287
385
$ — $
—
—
59
59 $
$
11 $
—
41
126
178 $
2 $
—
26
11
39 $
15 $ — $
—
122
91
228 $
—
38
—
38 $
28
—
227
287
542
______________________________________
(1)
(2)
(3)
Includes Africa (excluding Ghana, Equatorial Guinea, Mauritania and Senegal), Europe and South America.
Includes $718.2 million of oil and gas properties acquired as a result of the purchase price allocation of the estimated
fair value of identifiable assets acquired and liabilities assumed in the acquisition of additional interests in Ghana
discussed in “Note 3—Acquisitions and Divestitures.”
Includes $132.4 million of capitalized oil and gas properties settled against our Long-term receivable from BP
Operator in Mauritania and Senegal discussed in “Note 4—Joint Interest Billings and Long-term Receivables.”
Standardized Measure for Discounted Future Net Cash Flows
The following table provides projected future net cash flows based on the twelve month unweighted arithmetic average
of the first‑day‑of‑the‑month oil price for Brent crude in the period January through December 2021. The average price is
adjusted for crude handling, transportation fees, quality, and a regional price differential.
Because prices used in the calculation are average prices for that year, the standardized measure could vary
significantly from year to year based on market conditions that occur.
The projection should not be interpreted as representing the current value to Kosmos. Material revisions to estimates of
proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed;
actual prices realized are expected to vary significantly from those used; and actual costs may vary. Kosmos’ investment and
operating decisions are not based on the information presented, but on a wide range of reserve estimates that include probable
as well as proved reserves and on a wide range of different price and cost assumptions.
127
The standardized measure is intended to provide a better means to compare the value of Kosmos’ proved reserves at a
given time with those of other oil producing companies than is provided by comparing raw proved reserve quantities.
At December 31, 2021
Future cash inflows
Future production costs
Future development costs
Future tax expenses
Future net cash flows
10% annual discount for estimated timing of cash flows
Standardized measure of discounted future net cash flows
At December 31, 2020
Future cash inflows
Future production costs
Future development costs
Future tax expenses
Future net cash flows
10% annual discount for estimated timing of cash flows
Standardized measure of discounted future net cash flows
At December 31, 2019
Future cash inflows
Future production costs
Future development costs
Future tax expenses
Future net cash flows
10% annual discount for estimated timing of cash flows
Ghana
Equatorial
Guinea
Mauritania
/ Senegal
U.S. Gulf
of
Mexico
Total
(In millions)
$ 8,308 $ 1,661 $ 4,314 $ 1,981 $ 16,264
(2,079)
(621)
(2,853)
(334) (5,887)
(1,640)
(1,546)
3,043
(983)
(478)
(307)
255
37
(822)
(284) (3,224)
(43)
(117) (2,013)
596
1,246
5,140
(671)
(262) (1,879)
$ 2,060 $
292 $
(75) $ 984 $ 3,261
$ 2,791 $
986 $
— $ 1,244 $ 5,021
(1,197)
(765)
(251)
578
(577)
(352)
(131)
(74)
(214)
101
—
—
—
—
—
(249) (2,023)
(306) (1,423)
(7)
(389)
682
1,186
(109)
(222)
$ 364 $
27 $
— $ 573 $ 964
$ 5,546 $ 1,650 $
— $ 2,205 $ 9,401
(1,683)
(736)
(1,026)
2,101
(675)
(675)
(400)
(317)
258
36
—
—
—
—
—
(312) (2,670)
(393) (1,529)
(123) (1,466)
1,377
3,736
(278)
(917)
Standardized measure of discounted future net cash flows
$ 1,426 $
294 $
— $ 1,099 $ 2,819
128
Changes in the Standardized Measure for Discounted Cash Flows
Ghana
Equatorial
Guinea
Mauritania /
Senegal
U.S. Gulf
of Mexico
(In millions)
Equity
Method
Investment-
Equatorial
Guinea
Total
$ 1,540 $
— $
— $ 1,370 $
391 $
3,301
—
391
(568)
(210)
—
—
(352)
(151)
97
44
474
(23)
224
(10)
11
(57)
187
11
69
43
—
—
—
—
—
—
—
—
—
—
—
(391)
—
(336)
(14)
(401)
109
(43)
109
231
167
(93)
—
—
—
—
—
—
—
—
—
(1,114)
(14)
(904)
217
(56)
770
219
460
(60)
$ 1,426 $
294 $
— $ 1,099 $
— $
2,819
—
—
(197)
(72)
—
—
—
—
80
—
(197)
—
(1,292)
(390)
(80)
(633)
44
(65)
(95)
440
212
(109)
33
(19)
27
88
52
14
—
—
—
—
—
—
$
364 $
27 $
— $
981
—
(493)
(167)
—
1,232
91
—
479
73
(187)
(124)
367
128
(421)
(146)
53
73
12
10
—
—
—
(75)
—
—
—
—
—
—
126
(57)
44
81
118
(8)
573
—
(325)
—
602
42
(38)
153
(74)
58
(7)
$
—
(466)
80
(2,395)
203
(141)
(24)
609
382
(103)
964
981
(985)
—
2,238
206
(349)
648
(641)
123
76
$ 2,060 $
292 $
(75) $
984
$
3,261
Balance at December 31, 2018
Purchase of minerals in place(1)
Sales and transfers 2019
Extensions and discoveries
Net changes in prices and costs
Previously estimated development costs incurred
during the period
Net changes in development costs
Revisions of previous quantity estimates
Net changes in tax expenses
Accretion of discount
Changes in timing and other
Balance at December 31, 2019
Purchase of minerals in place
Sales and transfers 2020
Extensions and discoveries
Net changes in prices and costs
Previously estimated development costs incurred
during the period
Net changes in development costs
Revisions of previous quantity estimates
Net changes in tax expenses
Accretion of discount
Changes in timing and other
Balance at December 31, 2020
Purchase of minerals in place
Sales and transfers 2021
Extensions and discoveries
Net changes in prices and costs
Previously estimated development costs incurred
during the period
Net changes in development costs
Revisions of previous quantity estimates
Net changes in tax expenses
Accretion of discount
Changes in timing and other
Balance at December 31, 2021
______________________________________
(1)
We disclosed our share of reserves that were accounted for by the equity method. Effective of January 1, 2019, our
outstanding shares in KTIPI were transferred to Trident in exchange for a 40.4% undivided participating interest in the
Ceiba Field and Okume Complex. As a result, our interest in the Ceiba Field and Okume Complex is accounted for
under the proportionate consolidation method of accounting going forward.
129
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. 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 December 31, 2021, 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.
Management’s Annual Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Our
internal control has been designed to provide reasonable assurance regarding the reliability of financial reporting and the
preparation of our financial statements for external purposes in accordance with U.S. generally accepted accounting principles.
All internal control systems have inherent limitations, including the possibility of human error and the possible circumvention
of or overriding of controls. The design of an internal control system is also based in part upon assumptions and judgments
made by management. As a result, even an effective system of internal controls can provide no more than reasonable assurance
with respect to the fair presentation of financial statements and the processes under which they were prepared. Also, projections
of any evaluation of effectiveness to future periods are subject to the risk that internal control may become inadequate because
of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Under the supervision and with the participation of management, including our Chief Executive Officer and our Chief
Financial Officer, we assessed the effectiveness of our internal control over financial reporting as of the end of the period
covered by this report based on the framework in “Internal Control—Integrated Framework (2013)” issued by the Committee of
Sponsoring Organizations of the Treadway Commission. Based on the assessment, our Chief Executive Officer and our Chief
Financial Officer concluded that our internal control over financial reporting was effective to provide reasonable assurance
regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in
accordance with U.S. generally accepted accounting principles.
Ernst & Young LLP, the independent registered public accounting firm that audited our consolidated financial
statements included in this annual report on Form 10‑K, has issued an attestation report on the effectiveness of internal control
over financial reporting as of December 31, 2021 which is included in “Item 8. Financial Statements and Supplementary Data.”
Item 9B. Other Information
Disclosures Required Pursuant to Section 13(r) of the Securities Exchange Act of 1934
Not applicable.
130
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
Not applicable.
PART III
Item 10. Directors, Executive Officers and Corporate Governance
The information required by this item is incorporated herein by reference to the 2022 Proxy Statement, which will be
filed with the SEC not later than 120 days subsequent to December 31, 2021.
Item 11. Executive Compensation
The information required by this item is incorporated herein by reference to the 2022 Proxy Statement, which will be
filed with the SEC not later than 120 days subsequent to December 31, 2021.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information required by this item is incorporated herein by reference to the 2022 Proxy Statement, which will be
filed with the SEC not later than 120 days subsequent to December 31, 2021.
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required by this item is incorporated herein by reference to the 2022 Proxy Statement, which will be
filed with the SEC not later than 120 days subsequent to December 31, 2021.
Item 14. Principal Accounting Fees and Services
The information required by this item is incorporated herein by reference to the 2022 Proxy Statement, which will be
filed with the SEC not later than 120 days subsequent to December 31, 2021.
PART IV
Item 15. Exhibits, Financial Statement Schedules
(a) The following documents are filed as part of this report:
(1)
Financial statements
The financial statements filed as part of the Annual Report on Form 10‑K are listed in the accompanying index to
consolidated financial statements in Item 8, Financial Statements and Supplementary Data.
(2)
Financial statement schedules
Schedule I—Condensed Parent Company Financial Statements
Under the terms of agreements governing the indebtedness of subsidiaries of Kosmos Energy Ltd. for 2021, 2020 and
2019 (collectively “KEL,” the “Parent Company”), such subsidiaries may be restricted from making dividend payments, loans
or advances to KEL. Schedule I of Article 5‑04 of Regulation S‑X requires the condensed financial information of the Parent
Company to be filed when the restricted net assets of consolidated subsidiaries exceed 25 percent of consolidated net assets as
of the end of the most recently completed fiscal year.
The following condensed parent‑only financial statements of KEL have been prepared in accordance with Rule 12‑04,
Schedule I of Regulation S‑X and included herein. The Parent Company’s 100% investment in its subsidiaries has been
recorded using the equity basis of accounting in the accompanying condensed parent‑only financial statements. The condensed
financial statements should be read in conjunction with the consolidated financial statements of Kosmos Energy Ltd. and
subsidiaries and notes thereto.
131
The terms “Kosmos,” the “Company,” and similar terms refer to Kosmos Energy Ltd. and its wholly-owned
subsidiaries, unless the context indicates otherwise. Certain prior period amounts have been reclassified to conform with the
current year presentation. Such reclassifications had no impact on our reported net income, current assets, total assets, current
liabilities, total liabilities or shareholders equity.
132
KOSMOS ENERGY LTD.
CONDENSED PARENT COMPANY BALANCE SHEETS
(In thousands, except share data)
$
$
$
December 31,
2021
2020
6,693 $
1,474
957
5,689
1,217
16,030
2,092,915
—
1,090
1,026
84
305
18,687
2,130,137 $
242 $
80,595
32,239
1,217
5,689
119,982
1,479,808
84
1,026
—
1,166
—
908
—
2,502
4,576
1,034,226
176,540
3,706
—
140
305
18,687
1,238,180
153
38,558
14,157
2,502
—
55,370
741,606
140
—
910
—
—
4,962
2,473,674
(1,712,392)
(237,007)
529,237
2,130,137 $
4,497
2,307,220
(1,634,556)
(237,007)
440,154
1,238,180
$
Assets
Current assets:
Cash and cash equivalents
Derivatives receivable - related party
Prepaid expenses and other
Derivatives
Derivatives—related party
Total current assets
Investment in subsidiaries at equity
Long-term note receivable from subsidiary
Deferred financing costs, net of accumulated amortization of $19,912 and $17,296 at
December 31, 2021 and December 31, 2020, respectively
Derivatives
Derivatives—related party
Restricted cash
Long-term deferred tax asset
Total assets
Liabilities and shareholders’ equity
Current liabilities:
Accounts payable
Accounts payable to subsidiaries
Accrued liabilities
Derivatives
Derivatives - related party
Total current liabilities
Long-term debt, net
Derivatives
Derivatives - related party
Other long-term liabilities
Shareholders’ equity:
Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at
December 31, 2021 and December 31, 2020
Common stock, $0.01 par value; 2,000,000,000 authorized shares; 496,152,331 and
449,718,317 issued at December 31, 2021 and December 31, 2020, respectively
Additional paid-in capital
Accumulated deficit
Treasury stock, at cost, 44,263,269 shares at December 31, 2021 and 2020, respectively
Total shareholders’ equity
Total liabilities and shareholders’ equity
133
KOSMOS ENERGY LTD.
CONDENSED PARENT COMPANY STATEMENTS OF OPERATIONS
(In thousands)
Years Ended December 31,
2021
2020
2019
Revenues and other income:
Oil and gas revenue
Other income—related party
Total revenues and other income
Costs and expenses:
General and administrative
General and administrative recoveries—related party
Interest and other financing costs, net
Interest and other financing costs, net—related party
Derivatives, net
Other expenses, net
Equity in (earnings) losses of subsidiaries
Total costs and expenses
Loss before income taxes
Income tax expense
Net loss
Dividends declared per common share
$
— $
— $
20,307
20,307
2,642
2,642
38,810
79
98,649
(2,446)
20,307
(61)
(57,195)
98,143
(77,836)
—
(77,836) $
40,162
4,112
59,200
(5,889)
2,642
—
315,423
415,650
(413,008)
(1,422)
(411,586) $
—
—
—
40,840
(30,822)
86,104
(7,144)
—
10
(15,064)
73,924
(73,924)
(18,147)
(55,777)
— $
0.0452 $
0.1808
$
$
134
KOSMOS ENERGY LTD.
CONDENSED PARENT COMPANY STATEMENTS OF CASH FLOWS
(In thousands)
Operating activities
Net loss
Adjustments to reconcile net income (loss) to net cash provided by (used
in) operating activities:
Equity in (earnings) losses of subsidiaries
Equity-based compensation
Depreciation and amortization
Deferred income taxes
Other income—related party
Change in fair value on derivatives
Cash settlements on derivatives
Loss on extinguishment of debt
Changes in assets and liabilities:
Decrease in receivables
(Increase) decrease in prepaid expenses and other
Decrease due to/from related party
Increase (decrease) in accounts payable and accrued liabilities
Net cash provided by (used in) operating activities
Investing activities
Investment in subsidiaries
Net cash provided by (used in) investing activities
Financing activities
Borrowings under long-term debt
Payments on long-term debt
Net proceeds from issuance of senior notes
Redemption of senior secured notes
Net proceeds from issuance of common stock
Tax withholdings on restricted stock units
Dividends
Deferred financing costs
Net cash provided by (used in) financing activities
Net increase (decrease) in cash and cash equivalents
Cash, cash equivalents and restricted cash at beginning of period
Cash, cash equivalents and restricted cash at end of period
Years Ended December 31,
2021
2020
2019
$
(77,836) $
(411,586) $
(55,777)
(57,195)
31,651
5,638
—
6,582
20,307
(28,363)
4,403
315,423
32,706
8,644
(1,422)
(2,642)
2,642
—
—
134
(49)
856
(480)
218,008
18,003
141,283
162,897
2,509
109,547
(15,064)
32,370
5,039
(18,397)
—
—
—
22,913
427
(115)
43,974
(8,754)
6,616
(1,001,494)
(1,001,494)
(190,089)
(190,089)
287,972
287,972
100,000
(200,000)
839,375
—
136,006
(1,100)
(512)
(8,031)
865,738
5,527
1,471
6,998 $
100,000
—
—
—
—
(4,947)
(19,271)
(496)
75,286
(5,256)
6,727
1,471 $
—
(325,000)
641,875
(535,338)
—
(1,983)
(72,599)
(1,897)
(294,942)
(354)
7,081
6,727
$
135
Kosmos Energy Ltd.
Valuation and Qualifying Accounts
For the Years Ended December 31, 2021, 2020 and 2019
Additions
Schedule II
Description
2021
Allowance for credit losses
Allowance for deferred tax assets
2020
Allowance for credit losses
Allowance for deferred tax assets
2019
Allowance for doubtful receivables
Allowance for deferred tax assets
Balance
January 1,
Charged to
Costs and
Expenses
Charged To
Other
Accounts
Deductions
From Reserves
Balance
December 31,
$
$
$
$
$
$
5,675 $
1,019 $
(1,505) $
— $
5,189
288,288 $
30,055 $
— $
— $
318,343
2,748 $
1,800 $
1,127 $
— $
5,675
201,749 $
86,539 $
— $
— $
288,288
1,211 $
1,324 $
156,860 $
44,889 $
228 $
— $
(15) $
2,748
— $
201,749
Schedules other than Schedule I and Schedule II have been omitted because they are not applicable or the required
information is presented in the consolidated financial statements or the notes to consolidated financial statements.
(3)
Exhibits
See “Index to Exhibits” on page 139 for a description of the exhibits filed as part of this report.
Item 16. Form 10-K Summary
None
136
Pursuant to the requirements of Section 13 or 15(d) 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.
SIGNATURES
Date: February 28, 2022
KOSMOS ENERGY LTD.
By:
/s/ NEAL D. SHAH
Neal D. Shah
Senior Vice President and Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the
following persons on behalf of the Registrant and in the capacities and on the dates indicated.
Signature
Title
Date
/s/ ANDREW G. INGLIS
Andrew G. Inglis
Chairman of the Board of Directors and Chief
Executive Officer (Principal Executive Officer)
February 28, 2022
/s/ NEAL D. SHAH
Neal D. Shah
Senior Vice President and Chief Financial
Officer (Principal Financial Officer)
February 28, 2022
/s/ RONALD W. GLASS
Ronald W. Glass
Vice President and Chief Accounting Officer
(Principal Accounting Officer)
February 28, 2022
/s/ LISA A. DAVIS
Lisa A. Davis
/s/ SIR RICHARD B. DEARLOVE
Sir Richard B. Dearlove
/s/ ROY A. FRANKLIN
Roy A. Franklin
/s/ DEANNA L. GOODWIN
Deanna L. Goodwin
/s/ ADEBAYO O. OGUNLESI
Adebayo O. Ogunlesi
/s/ STEVEN M. STERIN
Steven M. Sterin
Director
February 28, 2022
Director
February 28, 2022
Director
February 28, 2022
Director
February 28, 2022
Director
February 28, 2022
Director
February 28, 2022
137
Exhibit
Number
Governing Documents
INDEX OF EXHIBITS
Description of Document
3.1 Certificate of Incorporation of the Company (filed as Exhibit 3.1 to the Company’s Form 8-K12g-3 filed
December 28, 2018 (File No. 000‑56014), and incorporated herein by reference).
3.2 Bylaws of the Company (filed as Exhibit 3.2 to the Company’s Form 8-K12g-3 filed December 31, 2018
(File No. 000‑56014), and incorporated herein by reference).
4.1 Form of Common Stock Certificate (filed as Exhibit 4.1 to the Company’s Form 8‑K12g-3 filed December
28, 2018 (File No. 000‑56014), and incorporated herein by reference).
4.2 Description of the Company's Capital Stock (filed as Exhibit 4.2 to the Company's Annual Report on Form
10-K for the year ended December 31, 2019, and incorporated herein by reference.)
Operating Agreements
Certain of the agreements listed below have been filed pursuant to the Company’s voluntary compliance with
international transparency standards and are not material contracts as such term is used in Item 601(b)(10)
of Regulation S-K.
Ghana
10.1 Petroleum Agreement in respect of West Cape Three Points Block Offshore Ghana dated July 22, 2004
among the GNPC, Kosmos Ghana and the E.O. Group (filed as Exhibit 10.1 to the Company’s Registration
Statement on Form S‑1/A filed March 3, 2011 (File No. 333‑171700), and incorporated herein by reference).
Joint Operating Agreement in respect of West Cape Three Points Block Offshore Ghana dated July 27, 2004
between Kosmos Ghana and E.O. Group (filed as Exhibit 10.2 to the Company’s Registration Statement on
Form S‑1/A filed March 3, 2011 (File No. 333‑171700), and incorporated herein by reference).
10.2
10.3 Petroleum Agreement in respect of the Deepwater Tano Contract Area dated March 10, 2006 among GNPC,
Tullow Ghana, Sabre and Kosmos Ghana (filed as Exhibit 10.3 to the Company’s Registration Statement on
Form S‑1/A filed March 3, 2011 (File No. 333‑171700), and incorporated herein by reference).
Joint Operating Agreement in respect of the Deepwater Tano Contract Area, Offshore Ghana dated
August 14, 2006, among Tullow Ghana, Sabre Oil and Gas Limited, and Kosmos Ghana (filed as
Exhibit 10.4 to the Company’s Registration Statement on Form S‑1/A filed March 3, 2011 (File
No. 333‑171700), and incorporated herein by reference).
10.4
10.5 Unitization and Unit Operating Agreement covering the Jubilee Field Unit located offshore the Republic of
Ghana dated July 13, 2009, among GNPC, Tullow, Kosmos Ghana, Anadarko WCTP, Sabre and E.O. Group
(filed as Exhibit 10.6 to the Company’s Registration Statement on Form S‑1/A filed March 3, 2011 (File
No. 333‑171700), and incorporated herein by reference).
10.6 Settlement Agreement, dated December 18, 2010 among Kosmos Ghana, Ghana National Petroleum
Corporation and the Government of the Republic of Ghana (filed as Exhibit 10.32 to the Company’s
Registration Statement on Form S‑1/A filed April 14, 2011 (File No. 333‑171700), and incorporated herein
by reference).
Sao Tome and Principe
10.7 Production Sharing Contract relating to Block 5 Offshore Sao Tome between the Democratic Republic of
Sao Tome and Principe and Equator Exploration STP Block 5 Limited dated April 18, 2012 (filed as
Exhibit 10.1 to the Company’s Quarterly Report on Form 10‑Q for the quarter ended March 31, 2016, and
incorporated herein by reference).
10.8 Amendment No. 1, dated November 24, 2014, to the Production Sharing Contract relating to Block 5
Offshore Sao Tome between the Democratic Republic of Sao Tome and Principe and Equator Exploration
STP Block 5 Limited dated April 18, 2012 (filed as Exhibit 10.2 to the Company’s Quarterly Report on Form
10-Q for the quarter ended March 31, 2016, and incorporated herein by reference).
10.9 Amendment No. 2, dated September 15, 2015, to the Production Sharing Contract relating to Block 5
Offshore Sao Tome between the Democratic Republic of Sao Tome and Principe and Equator Exploration
STP Block 5 Limited dated April 18, 2012 (filed as Exhibit 10.3 to the Company’s Quarterly Report on Form
10-Q for the quarter ended March 31, 2016, and incorporated herein by reference).
10.10 Amendment No. 3, dated February 19, 2016, to the Production Sharing Contract relating to Block 5 Offshore
Sao Tome between the Democratic Republic of Sao Tome and Principe, Equator Exploration STP Block 5
Limited and Kosmos Energy Sao Tome and Principe dated April 18, 2012 (filed as Exhibit 10.5 to the
Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2016, and incorporated herein
by reference).
138
Exhibit
Number
Description of Document
10.11 Production Sharing Contract relating to Block 6 Offshore Sao Tome between the Democratic Republic of
Sao Tome and Principe and Galp Energia São Tomé e Príncipe, Unipessoal, LDA dated October 26, 2015
(filed as Exhibit 10.6 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31,
2016, and incorporated herein by reference).
10.12 Addendum, dated November 9, 2015, to the Production Sharing Contract relating to Block 6 Offshore Sao
Tome between the Democratic Republic of Sao Tome and Principe and Galp Energia São Tomé e Príncipe,
Unipessoal, LDA dated October 26, 2015 (filed as Exhibit 10.7 to the Company’s Quarterly Report on Form
10-Q for the quarter ended March 31, 2016, and incorporated herein by reference).
10.13 Production Sharing Contract relating to Block 10 Offshore Sao Tome between the Democratic Republic of
Sao Tome and Principe, BP Exploration (STP) Limited and Kosmos Energy Sao Tome and Principe dated
March 9, 2018 (filed as Exhibit 10.8 to the Company's Quarterly Report on Form 10-Q for the quarter ended
March 31, 2018, and incorporated herein by reference).
10.14 First Addendum, dated December 17, 2015, to the Production Sharing Contract relating to Block 11 Offshore
Sao Tome between the Democratic Republic of Sao Tome and Kosmos Energy Sao Tome and Principe dated
July 23, 2014 (filed as Exhibit 10.11 to the Company’s Quarterly Report on Form 10-Q for the quarter ended
March 31, 2016, and incorporated herein by reference).
10.15 Production Sharing Contract relating to Block 12 Offshore Sao Tome between the Democratic Republic of
Sao Tome and Principe and Equator Exploration STP Block 12 Limited dated February 19, 2016 (filed as
Exhibit 10.12 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2016, and
incorporated herein by reference).
10.16 First Amendment, dated March 31, 2016, to the Production Sharing Contract between the Democratic
Republic of Sao Tome and Principe, Equator Exploration STP Block 12 Limited and Kosmos Energy Sao
Tome and Principe dated February 19, 2016 (filed as Exhibit 10.14 to the Company’s Quarterly Report on
Form 10-Q for the quarter ended March 31, 2016, and incorporated herein by reference).
10.17 Production Sharing Contract relating to Block 13 Offshore Sao Tome between the Democratic Republic of
Sao Tome and Principe, BP Exploration (STP) Limited and Kosmos Energy Sao Tome and Principe dated
March 9, 2018 (filed as Exhibit 10.9 to the Company’s Quarterly Report on Form 10-Q for the quarter ended
March 31, 2018, and incorporated herein by reference).
Senegal
10.18 Hydrocarbon Exploration and Production Sharing Contract for the Cayar Offshore Profond between the
Republic of Senegal and Petro‑Tim Limited and Societe des Petroles du Senegal dated January 17, 2012
(filed as Exhibit 10.1 to the Company’s Quarterly Report on Form 10‑Q for the quarter ended September 30,
2014, and incorporated herein by reference).
10.19 Hydrocarbon Exploration and Production Sharing Contract for the Saint Louis Offshore Profond between the
Republic of Senegal and Petro‑Tim Limited and Societe des Petroles du Senegal dated January 17, 2012
(filed as Exhibit 10.2 to the Company’s Quarterly Report on Form 10‑Q for the quarter ended September 30,
2014, and incorporated herein by reference).
10.20 Sale and Purchase Agreement relating to the sale and purchase of shares in Kosmos BP Senegal Limited
(formerly Normandy Ventures Limited) between BP Indonesia Oil Terminal Investment Limited and
Kosmos Energy Senegal dated December 15, 2016 (filed as Exhibit 10.31 to the Company's Annual Report
on Form 10-K of the year ended December 31, 2016, and incorporated herein by reference).
Suriname
10.21 Production Sharing Contract for Petroleum Exploration, Development and Production relating to Block 42
Offshore Suriname between Staatsolie Maatshappij Suriname N.V. and Kosmos Energy Suriname dated
December 13, 2011 (filed as Exhibit 10.20 to the Company’s Quarterly Report on Form 10‑Q for the quarter
ended September 30, 2013, and incorporated herein by reference).
10.22 Production Sharing Contract for Petroleum Exploration, Development and Production relating to Block 45
Offshore Suriname between Staatsolie Maatshappij Suriname N.V. and Kosmos Energy Suriname dated
December 13, 2011 (filed as Exhibit 10.21 to the Company’s Quarterly Report on Form 10‑Q for the quarter
ended September 30, 2013, and incorporated herein by reference).
Mauritania
10.23 Exploration and Production Contract between The Islamic Republic of Mauritania and Kosmos Energy
Mauritania (Bloc C8) dated April 5, 2012 (filed as Exhibit 10.17 to the Company’s Quarterly Report on
Form 10‑Q for the quarter ended September 30, 2013, and incorporated herein by reference).
10.24 Exploration and Production Contract between The Islamic Republic of Mauritania and Kosmos Energy
Mauritania (Bloc C12) dated April 5, 2012 (filed as Exhibit 10.18 to the Company’s Quarterly Report on
Form 10‑Q for the quarter ended September 30, 2013, and incorporated herein by reference).
139
Exhibit
Number
Description of Document
10.25 Exploration and Production Contract between The Islamic Republic of Mauritania and Kosmos Energy
Mauritania (Bloc C13) dated April 5, 2012 (filed as Exhibit 10.19 to the Company’s Quarterly Report on
Form 10‑Q for the quarter ended September 30, 2013, and incorporated herein by reference).
10.26 Exploration and Production Contract between The Islamic Republic of Mauritania and Kosmos Energy
Mauritania (Bloc C6) dated October 11, 2016 (filed as Exhibit 10.41 to the Company's Annual Report on
Form 10-K for the year ended December 31, 2016, and incorporated herein by reference).
10.27 Exploration and Production Contract between The Islamic Republic of Mauritania and Tullow Mauritania
Limited (Bloc C18) dated May 17, 2012 (filed as Exhibit 10.42 to the Company's Annual Report on Form
10-K of the year ended December 31, 2017, and incorporated herein by reference).
Equatorial Guinea
10.28 Share Sale and Purchase Agreement relating to the sale and purchase of shares in Hess International
Petroleum, Inc. between Hess Equatorial Guinea Investments Limited, Hess Corporation, Kosmos Energy
Equatorial Guinea, Kosmos Energy Operating and Trident Energy E.G. Operations, Ltd. dated October 23,
2017 (filed as Exhibit 10.43 to the Company's Annual Report on Form 10-K of the year ended December 31,
2017, and incorporated herein by reference).
10.29 Production Sharing Contract relating to Block G Offshore Republic of Equatorial Guinea between the
Republic of Equatorial Guinea and Triton Equatorial Guinea, Inc. dated March 26, 1997 (filed as Exhibit
10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2018, and
incorporated herein by reference).
10.30 Amendment No. 1, dated January 1, 2000, to the Production Sharing Contract relating to Block G Offshore
Republic of Equatorial Guinea between Triton Equatorial Guinea, Inc., Energy Africa Equatorial Guinea
Limited, and the Republic of Equatorial Guinea represented by the Ministry of Mines and Energy (filed as
Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2018, and
incorporated herein by reference).
10.31 Amendment No. 2, dated December 15, 2005, to the Production Sharing Contract relating to Block G
Offshore Republic of Equatorial Guinea between Amerada Hess Equatorial Guinea, Energy Africa
Equatorial Guinea Limited, and the Republic of Equatorial Guinea represented by the Ministry of Mines,
Industry and Energy (filed as Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q for the quarter
ended March 31, 2018, and incorporated herein by reference).
10.32 Amendment No. 3, dated October 22, 2017, to the Production Sharing Contract relating to Block G Offshore
Republic of Equatorial Guinea between Hess Equatorial Guinea, Tullow Equatorial Guinea Limited, and the
Republic of Equatorial Guinea represented by the Ministry of Mines and Hydrocarbons (filed as Exhibit10.4
to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2018, and incorporated
herein by reference).
10.33 Production Sharing Contract relating to Block EG-21 Offshore Republic of Equatorial Guinea between the
Republic of Equatorial Guinea, Guinea Ecuatorial de Petroleos and Kosmos Energy Equatorial Guinea dated
October 10, 2017 (filed as Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q for the quarter
ended March 31, 2018, and incorporated herein by reference).
10.34 Production Sharing Contract relating to Block S Offshore Republic of Equatorial Guinea between the
Republic of Equatorial Guinea, Guinea Ecuatorial de Petroleos and Kosmos Energy Equatorial Guinea dated
October 10, 2017 (filed as Exhibit 10.6 to the Company’s Quarterly Report on Form 10-Q for the quarter
ended March 31, 2018, and incorporated herein by reference).
10.35 Production Sharing Contract relating to Block W Offshore Republic of Equatorial Guinea between the
Republic of Equatorial Guinea, Guinea Ecuatorial de Petroleos and Kosmos Energy Equatorial Guinea dated
October 10, 2017 (filed as Exhibit 10.7 to the Company’s Quarterly Report on Form 10-Q for the quarter
ended March 31, 2018, and incorporated herein by reference).
10.36 Production Sharing Contract relating to Block EG-24 Offshore Equatorial Guinea between the Republic of
Equatorial Guinea, Guinea Ecuatorial de Petroleos and Ophir Equatorial Guinea (EG-24) Limited dated
October 2017 (filed as Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended
June 30, 2018, and incorporated herein by reference).
Cote d'Ivoire
10.37 Hydrocarbons Production Sharing Agreement between The Republic of Cote d'Ivoire, BP Exploration
Operating Company Limited and Kosmos Energy Cote d'Ivoire (Block CI-526) dated December 21, 2017
(filed as Exhibit 10.44 to the Company's Annual Report on Form 10-K of the year ended December 31, 2017,
and incorporated herein by reference).
10.38 Hydrocarbons Production Sharing Agreement between The Republic of Cote d'Ivoire, BP Exploration
Operating Company Limited and Kosmos Energy Cote d'Ivoire (Block CI-602) dated December 21, 2017
(filed as Exhibit 10.45 to the Company's Annual Report on Form 10-K of the year ended December 31, 2017,
and incorporated herein by reference).
140
Exhibit
Number
Description of Document
10.39 Hydrocarbons Production Sharing Agreement between The Republic of Cote d'Ivoire, BP Exploration
Operating Company Limited and Kosmos Energy Cote d'Ivoire (Block CI-603) dated December 21, 2017
(filed as Exhibit 10.46 to the Company's Annual Report on Form 10-K of the year ended December 31, 2017,
and incorporated herein by reference).
10.40 Hydrocarbons Production Sharing Agreement between The Republic of Cote d'Ivoire, BP Exploration
Operating Company Limited and Kosmos Energy Cote d'Ivoire (Block CI-707) dated December 21, 2017
(filed as Exhibit 10.47 to the Company's Annual Report on Form 10-K of the year ended December 31, 2017,
and incorporated herein by reference).
10.41 Hydrocarbons Production Sharing Agreement between The Republic of Cote d'Ivoire, BP Exploration
Operating Company Limited and Kosmos Energy Cote d'Ivoire (Block CI-708) dated December 21, 2017
(filed as Exhibit 10.48 to the Company's Annual Report on Form 10-K of the year ended December 31, 2017,
and incorporated herein by reference).
Namibia
10.42 Petroleum Agreement between the Government of the Republic of Namibia and Signet Petroleum Limited
Cricket Investments (PTY) LTD National Petroleum Corporation of Namibia (Block 2914B) dated June
2011 (filed as Exhibit 10.42 to the Company's Annual Report on Form 10-K of the year ended December 31,
2018, and incorporated herein by reference).
10.43 Addendum to Petroleum Agreement between The Government of the Republic of Namibia and Shell
Namibia Upstream B.V. and National Petroleum Corporation of Namibia dated June 17, 2011 (filed as
Exhibit 10.43 to the Company's Annual Report on Form 10-K of the year ended December 31, 2018, and
incorporated herein by reference).
10.44 Addendum II to Petroleum Agreement between The Government of the Republic of Namibia and Shell
Namibia Upstream B.V. and National Petroleum Corporation of Namibia dated June 17, 2011 (filed as
Exhibit 10.44 to the Company's Annual Report on Form 10-K of the year ended December 31, 2018, and
incorporated herein by reference).
South Africa
10.45 Exploration Right Contract relating to the Northern Cape Ultra Deep Block Offshore South Africa between
the Republic of South Africa and OK Energy Limited dated January 10, 2019 (filed as Exhibit 10.1 to the
Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2019, and incorporated
herein by reference).
Greater Tortue Ahmeyim
10.46† † Agreement for a Long Term Sale and Purchase of LNG, dated February 11, 2020, between LA Societe
Mauritanienne des Hydrocarbures et de Patrimoine Minier, BP Mauritania Investments Limited, Kosmos
Energy Investments Limited, La Societe des Petroles du Senegal, BP Senegal Investments Limited, Kosmos
Energy Investments Senegal Limited and BP Gas Marketing Limited (filed as Exhibit 10.46 to the
Company's Annual Report on Form 10-K for the year ended December 31, 2019, and incorporated herein by
reference).
Financing Agreements
10.47
Indenture, dated as of April 4, 2019, among the Company, the guarantors names therein, Wilmington Trust,
National Association, as trustee, transfer agent, registrar and paying agent and Banque Internationale à
Luxembourg S.A., as Luxembourg listing agent, transfer agent and paying agent (including the Form of
Notes) (filed as Exhibit 4.1 to the Company’s Current Report on Form 8‑K filed April 4, 2019 (File
No. 001‑35167), and incorporated herein by reference).
10.48 Deed of Amendment and Restatement relating to the Facility Agreement, dated February 5, 2018 among
Kosmos Energy Finance International, Kosmos Energy Operating, Kosmos Energy International, Kosmos
Energy Development, Kosmos Energy Ghana HC, Kosmos Energy Senegal, Kosmos Energy Mauritania,
Kosmos Energy Equatorial Guinea, Kosmos Energy Investments Senegal Limited, BNP Paribas and
Standard Chartered Bank (filed as Exhibit 10.10 to the Company’s Quarterly Report on Form 10-Q for the
quarter ended March 31, 2018, and incorporated herein by reference).
10.49 Amended and Restated Revolving Credit Facility Agreement, dated August 6, 2018, among Kosmos Energy
Ltd., as Original Borrower, certain of its subsidiaries listed therein, as Guarantors, ING Bank N.V., as
Facility Agent, Crédit Agricole Corporate and Investment Bank, as Security and Intercreditor Agent, and the
financial institutions listed therein, as Lenders (filed as Exhibit 1.1 to the Company’s Current Report on
Form 8-K filed August 7, 2018 (File No. 001-35167), and incorporated herein by reference).
10.50†† Prepayment Agreement dated June 26, 2020 between Kosmos Energy Gulf of Mexico Operations, LLC and
Trafigura Trading LLC (filed as Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q for the
quarter ended June 30, 2020, and incorporated herein by reference).
141
Exhibit
Number
Description of Document
10.51† † Senior Secured Term Loan Credit Agreement, dated September 30, 2020, among Kosmos Energy Ltd.,
Kosmos Energy GoM Holdings, LLC, Kosmos Energy Gulf of Mexico Operations, LLC, the Other
Guarantors named therein, the Initial Lenders named therein and CLMG CORP, as Term Loan Collateral
Agent and Administrative Agent (filed as Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q for
the quarter ended September 30, 2020, and incorporated herein by reference).
10.52 Indenture dated March 4, 2021 among the Company, the guarantors named therein, Wilmington Trust,
National Association, as trustee, paying agent, transfer agent and registrar, and Banque Internationale à
Luxembourg S.A., as Luxembourg listing agent, Luxembourg paying agent and Luxembourg transfer agent.
(filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K filed March 4, 2021 (File No.
001-35167), and incorporated herein by reference).
10.53 Amended and Restated Facility Agreement, effective May 12, 2021 among Kosmos Energy Finance
International, Kosmos Energy Operating, Kosmos Energy International, Kosmos Energy Development,
Kosmos Energy Ghana HC, Kosmos Energy Equatorial Guinea, ABSA Bank Limited, Credit Agricole
Corporate and Investment Bank, ING Belgium SA/NV, Natixis, N.B.S.A Limited, Societe Generale, London
Branch, The Standard Bank of South Africa Limited, Isle of Man Branch, Standard Chartered Bank, and
SMBC Bank International PLC (filed as Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for
the quarter ended June 30, 2021, and incorporated herein by reference).
10.54 Indenture dated October 13, 2021 among Kosmos Energy Ltd., the guarantors named therein and
Wilmington Trust, National Association, as trustee, paying agent, transfer agent and registrar (filed as
Exhibit 1.1 to the Company's Current Report on Form 8-K filed October 13, 2021 (File No. 001-35167), and
incorporated herein by reference).
10.55 Indenture dated October 26, 2021 among Kosmos Energy Ltd., the guarantors named therein, Wilmington
Trust, National Association, as trustee, paying agent, transfer agent and registrar, and Banque Internationale
à Luxembourg S.A., as Luxembourg listing agent, Luxembourg paying agent and Luxembourg transfer agent
(filed as Exhibit 4.1 to the Company's Current Report on Form 8-K filed October 26, 2021 (File No.
001-35167), and incorporated herein by reference).
10.56* Supplemental Indenture dated February 25, 2022 among Kosmos Energy Ltd., the guarantors named therein
and, Wilmington Trust, National Association, as trustee, paying agent, transfer agent and registrar.
Agreements with Shareholders and Directors
10.57 Form of Director Indemnification Agreement (filed as Exhibit 10.27 to the Company’s Registration
Statement on Form S‑1/A filed April 14, 2011 (File No. 333‑171700), and incorporated herein by reference).
10.58 Shareholders Agreement, dated as of May 10, 2011, among Kosmos Energy Ltd. and the other parties
signatory thereto (filed as Exhibit 9.1 to the Company’s Annual Report on Form 10‑K for the year ended
December 31, 2012, and incorporated herein by reference) (the "Shareholders Agreement").
10.59 Amended and Restated Registration Rights Agreement, dated as of October 7, 2009, among Kosmos Energy
Holdings and the other parties signatory thereto (filed as Exhibit 10.32 to the Company’s Annual Report on
Form 10‑K for the year ended December 31, 2012, and incorporated herein by reference).
Joinder Agreement to the Registration Rights Agreement, dated as of May 10, 2011, among Kosmos
Energy Ltd. and the other parties signatory thereto (filed as Exhibit 10.33 to the Company’s Annual Report
on Form 10‑K for the year ended December 31, 2012, and incorporated herein by reference).
10.60
10.61 Amendment No. 1 to the Registration Rights Agreement, dated as of February 8, 2013, among Kosmos
Energy Ltd. and the other parties signatory thereto (filed as Exhibit 10.34 to the Company’s Annual Report
on Form 10‑K for the year ended December 31, 2012, and incorporated herein by reference).
Management Contracts/Compensatory Plans or Arrangements
10.62† Long Term Incentive Plan (filed as Exhibit 99.1 to the Company’s Registration Statement on Form S‑8 filed
May 16, 2011 (File No. 333‑174234), and incorporated herein by reference).
10.63† Long Term Incentive Plan (amended and restated as of January 23, 2015) (filed as Exhibit 99 to the
Company’s Registration Statement on Form S-8 filed October 2, 2015 (File No. 333-207259), and
incorporated herein by reference).
10.64† Long Term Incentive Plan (amended and restated as of January 23, 2017) (filed as Exhibit 10.64 to the
Company's Annual Report on Form 10-K for the year ended December 31, 2016, and incorporated herein by
reference).
10.65† Long Term Incentive Plan (amended and restated as of March 27, 2018) (filed as Exhibit 99 to the
Company’s Registration Statement on Form S-8 filed November 15, 2018 (File No. 333-207259), and
incorporated herein by reference).
10.66† Long Term Incentive Plan (amended and restated as of April 20, 2021) (filed as Exhibit 99 to the Company’s
Registration Statement on Form S-8 filed June 9, 2021 (File No. 333-256933), and incorporated herein by
reference).
142
Exhibit
Number
Description of Document
10.67† Annual Incentive Plan (filed as Exhibit 10.22 to the Company’s Registration Statement on Form S‑1/A filed
March 30, 2011 (File No. 333‑171700), and incorporated herein by reference).
10.68† Form of Restricted Stock Award Agreement (Service-Vesting) (filed as Exhibit 10.50 to the Company’s
Annual Report on Form 10-K for the year ended December 31, 2014, and incorporated herein by reference).
10.69† Form of Restricted Stock Award Agreement (Performance-Vesting) (filed as Exhibit 10.51 to the Company’s
Annual Report on Form 10-K for the year ended December 31, 2014, and incorporated herein by reference).
10.70† Form of RSU Award Agreement (Service-Vesting) (filed as Exhibit 10.52 to the Company’s Annual Report
on Form 10-K for the year ended December 31, 2014, and incorporated herein by reference).
10.71† Form of RSU Award Agreement (Performance-Vesting) (filed as Exhibit 10.13 to the Company’s Quarterly
Report on Form 10-Q for the quarter ended March 31, 2015, and incorporated herein by reference).
10.72† Form of Directors RSU Award Agreement (Service-Vesting) (filed as Exhibit 10.54 to the Company’s
Annual Report on Form 10-K for the year ended December 31, 2014, and incorporated herein by reference).
10.73*† Form of Directors Award Agreement (Elective Shares).
10.74† Offer Letter, dated September 1, 2011, between Kosmos Energy, LLC and Jason Doughty (filed as
Exhibit 10.1 to the Company’s Quarterly Report on Form 10‑Q for the quarter ended June 30, 2014, and
incorporated herein by reference).
10.75† Offer Letter, dated May 22, 2013, between Kosmos Energy, LLC and Christopher Ball (filed as Exhibit 10.2
to the Company’s Quarterly Report on Form 10‑Q for the quarter ended June 30, 2014, and incorporated
herein by reference).
10.76† Offer Letter, dated January 10, 2014, between Kosmos Energy, LLC and Andrew Inglis (filed as
Exhibit 10.58 to the Company’s Annual Report on Form 10‑K for the year ended December 31, 2013, and
incorporated herein by reference).
10.77† Assignment Agreement, dated April 16, 2014, between Kosmos Energy, LLC and Brian F. Maxted (filed as
Exhibit 10.3 to the Company’s Quarterly Report on Form 10‑Q for the quarter ended June 30, 2014, and
incorporated herein by reference).
10.78† Exit Agreement between Kosmos Energy, LLC and Brian F. Maxted dated March 1, 2019 (filed as Exhibit
10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2019, and
incorporated herein by reference).
10.79† Offer Letter between Kosmos Energy Gulf of Mexico, LLC and Richard R. Clark dated August 3, 2018
(filed as Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31,
2019, and incorporated herein by reference).
10.80† Offer Letter, dated October 16, 2014, between Kosmos Energy, LLC and Thomas P. Chambers (filed as
Exhibit 10.60 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2014, and
incorporated herein by reference).
10.81*† Kosmos Energy Ltd. Change in Control Severance Policy for U.S. Employees (amended and restated as of
January 19, 2022).
10.82† Offer Letter, dated November 12, 2019, between Kosmos Energy, LLC and Ronald Glass (filed as Exhibit
10.73 to the Company's Annual Report on Form 10-K for the year ended December 31, 2019, and
incorporated herein by reference).
10.83† Offer Letter, dated November 12, 2019, between Kosmos Energy, LLC and Neal D. Shah (filed as Exhibit
10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2020, and incorporated
herein by reference).
10.84† Kosmos Energy Deferred Compensation Plan (effective February 1, 2017) (filed as Exhibit 10.2 to the
Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2017, and incorporated herein by
reference).
Exit Agreement between Kosmos Energy, LLC and Thomas P. Chambers dated January 4, 2021 (filed as
Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2021, and
incorporated herein by reference).
DGE Acquisition
10.85
10.86 Securities Purchase Agreement by and among DGE Group Series Holdco, LLC, and each of its three
designated series, DGE Group Series Holdco, LLC, Series I, DGE Group Series Holdco, LLC, Series, II,
DGE Group Series Holdco, LLC, Series III, and Kosmos Energy Gulf of Mexico, LLC dated August 3, 2018
(filed as Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q filed November 5, 2018 (File No.
001-35167), and incorporated herein by reference).
Anadarko WCTP Acquisition
143
Exhibit
Number
Description of Document
10.87 Share Purchase Agreement dated October 13, 2021 between Kosmos Energy Ghana Holdings Limited and
Anadarko Offshore Holding Company, LLC (filed as Exhibit 2.1 to the Company's Current Report on Form
8-K filed October 13, 2021 (File No. 001-35167), and incorporated herein by reference).
Other Exhibits
10.88†† Asset Sale Agreement related to Blocks 3013 and 3113 (North Cape Ultra Deep) offshore South Africa,
dated September 8, 2020, between Shell Offshore Upstream South Africa B.V. and Kosmos Energy South
Africa Limited (filed as Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended
September 30, 2020, and incorporated herein by reference).
10.89†† Share Sale and Purchase Agreement related to the sale and purchase of shares of KE Namibia Company, KE
STP Company, and KE Suriname Company, dated September 8, 2020, between Kosmos Energy Operating,
Kosmos Energy Holdings and B.V. Dordtsche Petroleum Maatschappij (filed as Exhibit 10.2 to the
Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2020, and incorporated
herein by reference).
10.90†† Portfolio Agreement, dated September 8, 2020, between Kosmos Energy Operating and B.V. Dordtsche
Petroleum Maatschappij (filed as Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q for the
quarter ended September 30, 2020, and incorporated herein by reference).
10.91 Parent Guarantee Agreement, dated September 30, 2020, between Kosmos Energy Ltd. and CLMG CORP.
related to the Senior Secured Term Loan Credit Agreement, dated September 30, 2020, among Kosmos
Energy Ltd., Kosmos Energy GoM Holdings, LLC, Kosmos Energy Gulf of Mexico Operations, LLC and
CLMG CORP (filed as Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q for the quarter ended
September 30, 2020, and incorporated herein by reference).
14.1 Code of Business Conduct and Ethics (filed as Exhibit 14.1 to the Company’s Annual Report on Form 10‑K
for the year ended December 31, 2011, and incorporated herein by reference).
21.1* List of Subsidiaries.
23.1* Consent of Ernst & Young LLP.
23.2* Consent of Ryder Scott Company, L.P.
31.1* Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes‑Oxley Act of 2002.
31.2* Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes‑Oxley Act of 2002.
32.1** Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes‑Oxley Act of 2002.
32.2** Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes‑Oxley Act of 2002.
99.1* Report of Ryder Scott Company, L.P.
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.
___________________________________
* Filed herewith.
** Furnished herewith.
† Management contract or compensatory plan or arrangement.
† † 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.
144
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BR500688-0322-10K Corporate Leadership & Information
BOAR D OF DIREC TORS
SENIOR LE ADERSHIP
CORPORATE INFORMATI ON
ANDREW G. INGLIS
Chairman of the Board of Directors
Chief Executive Officer
ANDREW G. INGLIS
Chairman of the Board of Directors
Chief Executive Officer
SIR RICHARD B. DEARLOVE
Retired Head of the British Secret
Intelligence Service (MI6)
CHRISTOPHER J. BALL
Senior Vice President and Chief
Commercial Officer
ADEBAYO O. OGUNLESI
Chairman and Managing Partner,
Global Infrastructure Partners
NEAL D. SHAH
Senior Vice President and Chief
Financial Officer
RICHARD R. CLARK
Senior Vice President and Head of
Gulf of Mexico Business Unit
JASON E. DOUGHTY
Senior Vice President and General
Counsel
RONALD GLASS
Vice President and Chief Accounting
Officer
DEANNA L. GOODWIN
Director, Arcadis NV
Director, Oceaneering
International, Inc.
LISA DAVIS
Director, Air Products and
Chemicals, Inc.
Director, C3.ai, Inc.
Director, Penske Automotive
Group, Inc.
Director, Phillips 66
STEVEN M. STERIN
Director, DuPont de Nemours, Inc.
Co-Founder & President of G&S
Energy Holdings, LLC.
ROY A. FRANKLIN
Chairman, John Wood Group PLC
Director, Energean plc
PRIMARY OFFICE
Kosmos Energy Ltd.
8176 Park Lane
Suite 500
Dallas, TX 75231
REGISTERED OFFICE
Kosmos Energy Ltd.
Corporation Trust Center
1209 Orange Street
Wilmington, DE 19801
WEBSITE
www.kosmosenergy.com
STOCK EXCHANGE LISTING
New York Stock Exchange
London Stock Exchange
Symbol: KOS
ANNUAL MEETING
June 9, 2022
8:00 a.m. Central Daylight Time
Virtual-Only Format:
www.virtualshareholdermeeting.com/
KOS2022
FORM 10-K
Copies of the corporation’s 10-K
are available on our website at
www.kosmosenergy.com
AUDITORS
Ernst & Young
Dallas, TX
SHAREHOLDER SERVICES
Computershare
250 Royall Street
Canton, MA 02021
1-800-962-4284 (Toll-Free)
1-781-575-3120 (International)
INVESTOR RELATIONS
Additional corporate information
is available on our website at
www.kosmosenergy.com
FORWARD-LOOK ING
STATEMENTS
CAUTIONARY STATEME NTS
REGARDI NG OIL AND GAS
QUANTITIE S
NON-GAAP FI NANCIAL
ME ASURE S
EBITDAX and net debt are supplemental
non-GAAP financial measures used
by management and external users of
the Company’s consolidated financial
statements, such as industry analysts,
investors, lenders and rating agencies. The
Company defines EBITDAX as 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 Company defines net debt as
the sum of notes outstanding issued at
par and borrowings on the RBL Facility,
Corporate revolver, and Gulf of Mexico
Term Loan less cash and cash equivalents
and restricted cash.
We believe that EBITDAX, net debt and
other similar measures are useful to
investors because they are frequently
used by securities analysts, investors and
other interested parties in the evaluation
of companies in the oil and gas sector and
will provide investors with a useful tool
for assessing the comparability between
periods, among securities analysts, as well
as company by company. Because EBITDAX
excludes some, but not all, items that affect
net income, these measures as presented by
us may not be comparable to similarly titled
measures of other companies.
This annual report contains forward-looking
statements within the meaning of Section
27A of the Securities Act of 1933 and
Section 21E of the Securities Exchange
Act of 1934. All statements, other than
statements of historical facts, included in
this report that address activities, events
or developments that Kosmos Energy Ltd.
(“Kosmos” or the “Company”) expects,
believes or anticipates will or may occur in
the future are forward-looking statements.
Without limiting the generality of the
foregoing, forward-looking statements
contained in this report specifically include
the expectations of management regarding
plans, strategies, objectives, anticipated
financial and operating results of the
The SEC permits oil and gas companies,
in their filings with the SEC, to disclose
only proved, probable and possible reserves
that meet the SEC’s definitions for such
terms, and price and cost sensitivities for
such reserves, and prohibits disclosure
of resources that do not constitute such
reserves. The Company uses terms in this
report, such as “discovered resources,”
“potential,” “significant resource upside,”
“resource,” “net resources,” “recoverable
resources,” “discovered resource,” “world-
class discovered resource,” “significant
defined resource,” “gross unrisked resource
potential,” “defined growth resources,”
Company, including as to estimated oil and
“recovery potential” and similar terms or
gas in place and recoverability of the oil
and gas, estimated reserves and drilling
other descriptions of volumes of reserves
potentially recoverable that the SEC’s
locations, capital expenditures, typical well
guidelines strictly prohibit the Company
results and well profiles and production
from including in filings with the SEC.
and operating expenses guidance included
These estimates are by their nature more
in the report. The Company’s estimates
speculative than estimates of proved,
and forward-looking statements are mainly
probable and possible reserves and
based on its current expectations and
accordingly are subject to substantially
estimates of future events and trends, which
greater risk of being actually realized.
affect or may affect its businesses and
Investors are urged to consider closely
operations. Although the Company believes
the disclosures and risk factors in the
that these estimates and forward-looking
Company’s SEC filings, available on the
statements are based upon reasonable
assumptions, they are subject to several
risks and uncertainties and are made in
light of information currently available to
the Company. When used in this report,
Company’s website at www.kosmosenergy.
com. Potential drilling locations and
resource potential estimates have not been
risked by the Company. Actual locations
drilled and quantities that may be ultimately
the words “anticipate,” “believe,” “intend,”
recovered from the Company’s interest may
“expect,” “plan,” “will” or other similar words
differ substantially from these estimates.
are intended to identify forward-looking
statements. Such statements are subject
to a number of assumptions, risks and
uncertainties, many of which are beyond
the control of the Company including, but
not limited to, the impact of the COVID-19
pandemic, which may cause actual results
to differ materially from those implied
or expressed by the forward-looking
statements. Further information on such
assumptions, risks and uncertainties is
There is no commitment by the Company
to drill all of the drilling locations that have
been attributed these quantities. Factors
affecting ultimate recovery include the
scope of the Company’s ongoing drilling
program, which will be directly affected
by the availability of capital, drilling and
production costs, availability of drilling and
completion services and equipment, drilling
results, agreement terminations, regulatory
approval and actual drilling results, including
available in the Company’s Securities and
geological and mechanical factors affecting
Exchange Commission (“SEC”) filings. The
recovery rates. Estimates of reserves and
Company’s SEC filings are available on the
resource potential may change significantly
Company’s website at www.kosmosenergy.
as development of the Company’s oil and
com. Kosmos undertakes no obligation and
gas assets provides additional data.
does not intend to update or correct these
forward-looking statements to reflect events
or circumstances occurring after the date
of this report, whether as a result of new
information, future events or otherwise,
except as required by applicable law. You
are cautioned not to place undue reliance
on these forward-looking statements, which
speak only as of the date of this report. All
forward-looking statements are qualified in
their entirety by this cautionary statement.
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