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2022
ANNUAL
REPORT
KOSMOS ENERGY is a full-cycle deepwater
exploration and production company focused
on meeting the world’s growing demand for
secure, affordable and cleaner energy.
We have 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
natural gas and LNG development projects
offshore Mauritania and Senegal.
We are working to supply the energy
the world needs today, find and develop
cleaner energy for the future, and be a
force for good in our host countries.
ANDREW G. INGLIS
Chairman of the Board of Directors
and Chief Executive Officer
Fellow Shareholders,
As the world grapples with the need for affordable,
secure, and cleaner energy – particularly in the
wake of Russia’s war in Ukraine – I am confident that
Kosmos has the right strategy and portfolio to be a
part of the solution.
Kosmos has a strong oil-weighted portfolio that can
supply more of the energy the world needs today.
We are investing in growing oil supply at each of our
core production hubs, with an emphasis on high-
graded projects that yield low cost, lower carbon
barrels that are highly cash generative. At the same
time, we are working with our partners to bring new
sources of lower carbon natural gas into production.
These projects address energy affordability and
increase energy security by supplying more gas
to global energy markets, as well as to domestic
markets in Africa.
By 2024, we expect to increase production by
about 50% compared to 2022 levels as we optimize
current production and bring new projects online.
For Kosmos, the cash flow from current and planned
activities enables selective re-investment into the
most compelling opportunities in our portfolio, which
can help meet demand and support the energy
transition for decades to come. Longer term, we plan
to continue shifting the balance of our portfolio from
oil to natural gas and LNG to help meet the world’s
energy needs as cleaner natural gas displaces coal,
heavy fuel oil, and biomass as primary sources of
energy in both developed and emerging economies.
DELIVERING ON OUR STRATEGY
In 2022, Kosmos delivered strong operational and
financial performance in support of this strategy. In
addition to solid production rates that generated
significant free cash flow, we advanced our three
major development projects and further strengthened
our balance sheet, ending the year with more than $1
billion in liquidity and leverage below our 1.5x target.
Looking ahead, Kosmos expects to reach an important
inflection point in the second half of 2023 with
production expected to grow as major development
projects start to come online and capital expenditures
begin to fall. With higher production and lower capital,
free cash flow is expected to rise into 2024 providing
multiple pathways for the company to deliver value for
our shareholders.
As we pursue our strategy, we continue to be guided
by our commitment to sustainability. With our low
cost, lower carbon oil and gas production, Kosmos
aims to be a responsible producer that the world can
count on to balance energy security and affordability
with the need to lower emissions. In early 2020, we set
the goal to become carbon neutral for our operated
Scope 1 and Scope 2 emissions by 2030 or sooner.
We achieved this goal in both 2021 and 2022, and
we remain committed to maintaining it. We are also
working with our partners and host governments on
projects to reduce the carbon intensity of our non-
operated production assets, such as the elimination
of routine flaring in Ghana and Equatorial Guinea. We
also plan to disclose equity emissions and new targets
in this year’s Sustainability Report. Our commitment
to ESG and sustainability is a core value that has been
recognized by stakeholders. MSCI, one of the leading
ESG ratings agencies, recently awarded Kosmos its
highest possible ‘‘AAA’’ rating, which puts us in the
top 20% of companies across the sector.
LOOKING AHEAD
Kosmos offers investors access to a high-quality
reserve base, with unique exposure to world-scale
LNG projects, alongside a portfolio of low cost, lower
carbon oil opportunities through infrastructure-led
exploration. These opportunities underpin sustainable
and value-accretive growth. We look forward to
further delivering on our strategy, creating value for
our shareholders and bringing affordable, secure, and
cleaner energy to the world.
On behalf of the entire board of directors, I thank you
for your participation and investment in our company.
Sincerely yours,
ANDREW G. INGLIS
Chairman of the Board of Directors
and Chief Executive Officer
Financial Highlights
Year Ended (in thousands, except volume data)
2022
2021
2020
Revenues and other income
Net income (loss)
$ 2,299,775
$ 1,333,839
$ 896,198
226,551
(77,836)
(411,586)
Net cash provided by operating activities
1,130,476
374,344
196,145
Pro Forma EBITDAX
Capital expenditures1
Total Assets
Net Debt
1,436,342
969,136
424,987
611,588
924,214
273,979
4,579,988
4,940,651
3,867,593
2,083,179
2,500,104
2,000,236
Average oil sales price per Bbl
100.00
70.10
38.29
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
EBITDAX RECONCILIATION
23.1
276
158
707
19.9
301
185
695
22.1
139
127
69
Year Ended December 31,
Net income (loss)
Exploration expenses
2022
2021
2020
$ 226,551
$ (77,836)
$ (411,586)
134,230
65,382
84,616
Facilities insurance modifications, net
6,243
(1,586)
13,161
Depletion, depreciation and amortization
498,256
467,221
485,862
Impairment of long-lived assets
Equity-based compensation
Derivatives, net
449,969
—
153,959
34,546
31,651
32,706
260,892
270,185
17,180
Cash settlements on commodity derivatives
(327,872)
(224,421)
(2,715)
Restructuring and other
Other, net
Gain on sale of assets
1,517
(10,572)
3,823
6,288
29,167
10,215
(50,471)
(1,564)
(92,163)
Interest and other financing costs, net
118,260
128,371
109,794
Income tax expense (benefit)
110,516
34,456
(5,209)
EBITDAX
$ 1,452,065
$ 701,970
$ 424,987
Sold Ghana & acquired Kodiak Interest EBITDAX1
Pro Forma EBITDAX
(15,723)
$ 1,436,342
1. Adjustment to present Pro Forma EBITDAX for the impact of the revenues less direct operating expenses from the sold Ghana interest associated with the Ghana pre-emption and
the acquired Kodiak interest, for the respective period. 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 and natural gas.
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, 2022
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. ☒
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant
included in the filing reflect the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based
compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
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 $2,764,469,395.
The number of the registrant’s Common Stock outstanding as of February 23, 2023 was 459,584,934.
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, 2022.
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. 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 4.
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
36
62
62
62
62
63
65
66
81
83
131
131
131
132
132
132
132
132
132
132
137
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”
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.
Drill stem test.
“DST”
“Dry hole” or “Unsuccessful well” A well that has not encountered a hydrocarbon bearing reservoir expected to produce
“DT”
“EBITDAX”
in commercial quantities.
Deepwater Tano.
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.
4
“ESG”
“ESP”
“E&P”
“Facility”
“FASB”
“Farm-in”
“Farm-out”
“FEED”
“Field life cover ratio”
“FLNG”
“FPS”
“FPSO”
“GAAP”
“GEPetrol”
“GHG”
“GJFFDP”
“GNPC”
“GoM Term Loan”
“Greater Tortue Ahmeyim”
“GTA UUOA”
“HLS”
“Jubilee UUOA”
“Interest cover ratio”
“LNG”
“Loan life cover ratio”
“LIBOR”
“LSE”
“LTIP”
“MBbl”
“MBoe”
“Mcf”
“Mcfpd”
“MMBbl”
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.
Senior Secured Term Loan Credit Agreement dated September 30, 2020.
Ahmeyim and Guembeul discoveries.
Unitization and Unit Operating Agreement covering the Greater Tortue Ahmeyim
Unit.
Heavy Louisiana Sweet.
Unitization and Unit Operating Agreement covering the Jubilee Unit.
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, however, forecasted
capital expenditures in relation to the additional interests in Ghana acquired in the
October 2021 acquisition of Anadarko WCTP are not included, to (y) the aggregate
loan amounts outstanding under the Facility.
London Interbank Offered Rate
London Stock Exchange.
Long Term Incentive Plan.
Thousand barrels of oil.
Thousand barrels of oil equivalent.
Thousand cubic feet of natural gas.
Thousand cubic feet per day of natural gas.
Million barrels of oil.
5
“MMBoe”
“MMBtu”
“MMcf”
“MMcfd”
“MMTPA”
“Natural gas liquid” or “NGL”
“NYSE”
“Petroleum contract”
“Petroleum system”
“Plan of development” or “PoD”
“Productive well”
“Prospect(s)”
“Proved reserves”
“Proved developed reserves”
“Proved undeveloped reserves”
“RSC”
“SOFR”
“SEC”
“7.125% Senior Notes”
“7.750% Senior Notes”
“7.500% Senior Notes”
“Shelf margin”
“Shell”
“SMH”
“Stratigraphy”
“Stratigraphic trap”
“Structural trap”
“Structural-stratigraphic trap”
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.
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.
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.
A written document outlining the steps to be undertaken to develop a field.
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.
Secured Overnight Financing Rate
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.
Societe Mauritanienne des Hydrocarbures
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.
A structural-stratigraphic trap is a combination trap with structural and stratigraphic
features.
6
“Submarine fan”
“TAG GSA”
“TEN”
“Three-way fault trap”
“Tortue Phase 1 SPA”
“Trafigura”
“Trap”
“Trident”
“Undeveloped acreage”
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:
•
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•
•
•
•
•
•
•
•
•
•
•
•
the impact of a potential regional or global recession, inflationary pressures and other varying macroeconomic
conditions on us and the overall business environment;
the impact of Russia’s invasion of Ukraine and the effects it has on the oil and gas industry as a whole, including
increased volatility with respect to oil, natural gas and NGL prices and operating and capital expenditures;
our ability to find, acquire or gain access to other discoveries and prospects and to successfully develop and produce
from our current discoveries and prospects;
uncertainties inherent in making estimates of our oil and natural gas data;
the successful implementation of our and our block partners’ prospect discovery and development and drilling plans;
projected and targeted capital expenditures and other costs, commitments and revenues;
termination of or intervention in concessions, rights or authorizations granted to us by the governments of the countries
in which we operate (or their respective national oil companies) or any other federal, state or local governments or
authorities;
our dependence on our key management personnel and our ability to attract and retain qualified technical personnel;
the ability to obtain financing and to comply with the terms under which such financing may be available;
the volatility of oil, natural gas and NGL prices, as well as our ability to implement hedges addressing such volatility
on commercially reasonable terms;
the availability, cost, function and reliability of developing appropriate infrastructure around and transportation to our
discoveries and prospects;
the availability and cost of drilling rigs, production equipment, supplies, personnel and oilfield services;
other competitive pressures;
potential liabilities inherent in oil and natural gas operations, including drilling and production risks and other
operational and environmental risks and hazards;
current and future government regulation of the oil and gas industry, applicable monetary/foreign exchange sectors or
regulation of the investment in or ability to do business with certain countries or regimes;
cost of compliance with laws and regulations;
changes in, or new, environmental, health and safety or climate change or GHG laws, regulations and executive orders,
or the implementation, or interpretation, of those laws, regulations and executive orders;
adverse effects of sovereign boundary disputes in the jurisdictions in which we operate;
environmental liabilities;
8
•
geological, geophysical and other technical and operations problems including drilling and oil and gas production and
processing;
• military operations, civil unrest, outbreaks of disease, including the impact of the COVID-19 pandemic, terrorist acts,
wars or embargoes;
•
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•
•
the cost and availability of adequate insurance coverage and whether such coverage is enough to sufficiently mitigate
potential losses and whether our insurers comply with their obligations under our coverage agreements;
our vulnerability to severe weather events, including, but not limited to, tropical storms and hurricanes, and the
physical effects of climate change;
our ability to meet our obligations under the agreements governing our indebtedness;
the availability and cost of financing and refinancing our indebtedness;
the amount of collateral required to be posted from time to time in our hedging transactions, letters of credit,
performance bonds and other secured debt;
our ability to obtain surety or performance bonds on commercially reasonable terms;
the result of any legal proceedings, arbitrations, or investigations we may be subject to or involved in;
our success in risk management activities, including the use of derivative financial instruments to hedge commodity
and interest rate risks; and
other risk factors discussed in the “Item 1A. Risk Factors” section of 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
offshore Atlantic Margins. Our key assets include production offshore Ghana, Equatorial Guinea and the U.S. Gulf of Mexico,
as well as world-class gas projects offshore Mauritania and Senegal. We also pursue a proven basin exploration program in
Equatorial Guinea and the U.S. Gulf of Mexico. Kosmos is listed on the NYSE and LSE and is traded under the ticker symbol
KOS.
Kosmos 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 Greater Tortue 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 acquisition of additional interests in the Jubilee and TEN fields offshore
Ghana in 2021 and the Kodiak and Winterfell fields in the U.S. Gulf of Mexico in 2022.
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 affordable and 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 first gas for the project targeted in the fourth
quarter of 2023 while advancing the second phase of the development, as well as advancing first phase development concepts
for the BirAllah and Orca discoveries in Mauritania and the Yakaar-Teranga discoveries in Senegal. In addition, our portfolio
contains an inventory of prospects, which we plan to continue to mature and high-grade 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 and Equatorial Guinea.
Grow cash flow, proved reserves and production through exploitation, development and infrastructure-led
exploration activities with increasing exposure to natural gas and LNG
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 wells at the Jubilee field in the near term while working with partners to evaluate
and high grade the future activity set to maximize value from the TEN fields. In the U.S. Gulf of Mexico, we plan to progress
the Winterfell Field Development Plan, continue development drilling in existing fields and pursue a deep inventory of
infrastructure-led exploration targets. In addition, the development of the first phase of the Greater Tortue Ahmeyim
10
development offshore Mauritania and Senegal continues to make good progress. 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 phased development of our other natural gas discoveries in Mauritania and Senegal including the BirAllah and
Orca discoveries in Mauritania and the Yakaar and Teranga discoveries in Senegal. During 2023, we plan to continue to mature
development concepts for our existing 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 and Equatorial Guinea.
Focus on optimally developing our discoveries to initial production
Our approach to development is designed to deliver first production on an accelerated timeline, with low cost, lower
carbon solutions, where we can 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 capitally efficient 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 three years after
initial discovery.
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, developing, and maximizing the value of
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.
11
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
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 a “Just Energy Transition” in our host countries and communities –
namely by supporting economic and social development in the places where we work through supplying affordable and cleaner
energy while lowering emissions. We use the United Nations Sustainable Development Goals to understand how our activities
promote economic and social progress in host countries. 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. The report
sets forth a scenario analysis demonstrating the resilience of our portfolio under a scenario aligned with the Paris Agreement’s
goals, and our goal to achieve operated Scope 1 and Scope 2 carbon neutrality by 2030 or sooner. We achieved this goal in
2021, significantly earlier than expected, and have identified a pathway to maintain it through continual monitoring of
emissions, assessment of emission reduction opportunities, and, for residual emissions, investment in high-quality carbon
offsets. We recognize most of our production, and the associated GHG emissions, is derived from assets in which we are non-
operating partners. We are therefore working with our partners to develop a consistent measurement approach to improve our
understanding of these emissions and implement opportunities to reduce them.
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, 2022, our liquidity was approximately $1 billion.
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 one to two 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, 2022, we have hedged positions covering approximately 10.0 million barrels of oil production in 2023. 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 2022 data for our geographic areas.
Percentage
of BOE
Sales
Volumes
Sales Volumes (Net to Kosmos)
Average Oil
Production
Oil
NGL
(MMBbls)
Gas
(Bcf)
Total
Oil
NGL
Gas
Total
Revenue
costs per
(MMBoe)
(per Bbl)
(per Bcf)
(per Boe)
(in Thousands)
Boe(3)
Depletion,
depreciation
and
amortization
per Boe
Geographic Area
For the year ended
December 31, 2022
Jubilee
TEN
Ghana(1)
49 % 11.40
—
—
11.40
101.23
—
9 % 2.00
—
—
2.00
96.83
—
58 % 13.40
—
—
13.40
100.59
—
Equatorial Guinea
14 % 3.30
—
—
3.30
104.24
—
Mauritania/Senegal
—
—
—
—
—
—
—
U.S. Gulf of Mexico
28 % 5.30
0.40
4.10
6.40
95.80
34.37
Total
100 % 22.00
0.40
4.10
23.10
100.00
34.37
—
—
—
—
—
7.24
7.24
101.23 $
1,162,416
96.83
188,546
100.59 $
1,350,962
104.24
346,783
—
86.09
—
547,610
97.13 $
2,245,355
9.93
47.48
15.37
27.23
—
16.50
17.39
For the year ended
December 31, 2021
Jubilee
TEN
Ghana(2)
35 %
7.0
—
—
7.0 $ 71.21
—
— $
71.21 $
500,541 $
11.12 $
10 %
2.0
—
—
2.0
73.82
—
—
73.82
143,691
37.47
45 %
9.0
—
—
9.0 $ 71.77
—
— $
71.77 $
644,232 $
16.83 $
Equatorial Guinea
19 %
3.7
—
—
3.7
70.39
—
Mauritania/Senegal
—
—
—
—
—
—
—
—
—
70.39
—
260,520
25.13
—
—
U.S. Gulf of Mexico
36 %
5.8
Total
100 % 18.5
0.5
0.5
4.9
4.9
7.2
67.35
28.62
3.85
59.57
427,261
14.21
19.9 $ 70.10
$ 28.62 $
3.85 $
67.10 $
1,332,013 $
17.44 $
For the year ended
December 31, 2020
Jubilee
TEN
Ghana
31 %
6.7
—
—
6.7 $ 38.84
—
— $
38.84 $
261,540 $
14.60 $
13 %
3.0
—
—
3.0
35.23
—
—
35.23
104,975
23.85
44 %
9.7
—
—
9.7 $ 37.73
—
— $
37.73 $
366,515 $
17.44 $
Equatorial Guinea
18 %
4.0
—
—
4.0
37.79
—
Mauritania/Senegal
—
—
—
—
—
—
—
—
—
37.79
—
152,501
20.02
—
—
U.S. Gulf of Mexico
38 %
6.8
Total
100 % 20.5
0.6
0.6
5.9
5.9
8.4
39.39
10.25
2.00
34.08
285,017
10.56
22.1 $ 38.29
$ 10.25 $
2.00 $
36.36 $
804,033 $
15.31 $
20.32
28.57
21.52
16.16
—
24.12
21.55
23.93
37.30
26.84
15.26
—
23.44
23.54
20.00
33.81
24.27
16.05
—
21.74
21.97
______________________________________
(1)
(2)
(3)
Our sales volumes during 2022 includes activity related to the interest pre-empted by Tullow prior to the March 17,
2022 closing date of the Tullow pre-emption transaction.
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.
Substantially all NGLs and natural gas sales are associated production from our oil wells and, therefore, production
costs metrics are presented under a common unit of measure.
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
Gladden
Kodiak
Marmalard
Nearly Headless Nick
Danny Noonan
Odd Job
SOB II
S. Santa Cruz
Tornado
Winterfell
Mauritania
Greater Tortue Ahmeyim(1)
BirAllah
Orca
Senegal
License
WCTP/DT
(2)
DT
MC 521
MC 697 / 698 / 742
MC 800
MC 727 / 771
MC 255 / 300
MC 387
EC 381 / GB 506
MC 214 / 215
MC 431
MC 563
GC 281
GC 943 / 944
Block C8
BirAllah
BirAllah
(3)
Greater Tortue Ahmeyim(1)
Saint Louis Offshore
Profond
(3)
Teranga
Yakaar
Cayar Offshore
Profond
Cayar Offshore
Profond
Equatorial Guinea
Ceiba Field and Okume Complex(1) Block G
Asam
Block S
______________________________________
Kosmos
Participating
Interest
Operator
Stage
Expiration
License
38.6 % (2)
20.4 % (4)
Tullow
Tullow
Production
Production
2034
2036
22.5 %
5.3 %
20.0 %
35.0 %
11.4 %
21.9 %
30.0 %
Various
(5)
11.8 %
40.5 %
35.0 %
25.0 %
Kosmos
QuarterNorth
W&T
Kosmos
Murphy
Murphy
Talos
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
Appraisal
(8)
(8)
(8)
(8)
(8)
(8)
(8)
(8)
(8)
(8)
(8)
(8)
Development
2049(9)
Appraisal
Appraisal
2025
2025
Development
2044(10)
30.0 % (7)
BP
Appraisal
2024
30.0 % (7)
BP
Appraisal
2024
40.4 %
40.0 %
Trident
Kosmos
Production
Appraisal
2040
2024
(1)
(2)
(3)
For information concerning our estimated proved reserves as of December 31, 2022, 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 43.05%.
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 and the other block partners of each of these two blocks. 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.
(4)
Our paying interest on development activities in the TEN fields is 22.8%. The table above reflects the acquisition of
additional interests in Ghana in October 2021 and the pre-emption transaction with Tullow in March 2022. See “Item
14
8. Financial Statements and Supplementary Data—Note 3—Acquisitions and Divestitures” for discussion of pre-
emption transaction with Tullow.
Our interests in blocks MC 214 and MC 215 are 61.1% and 54.9%, respectively.
The new PSC covering the BirAllah and Orca discoveries contains provisions for back-in rights for the Government of
Mauritania. Kosmos’ participating interest in the new PSC is currently 28.0% and this interest percentage does not
give effect to the exercise of such back-in rights. Full election by SMH of their back-in rights would reduce Kosmos’
participating interest to approximately 22.1%.
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.
(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.
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
3
1
1
1
49
Interest
64.7%
28.0%
58.9%
30.0%
39.3%
Operator(s)
(1) Kosmos
(2) BP
(3) Kosmos
(4) BP
Kosmos, Murphy, Talos,
QuarterNorth, Occidental,
W&T Offshore, LLOG,
Beacon, Houston Energy
Current Phase
Expiration Range
2024
2025
2023
2024
through 2032 (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.
Full election by SMH of their back-in rights would reduce Kosmos’ participating interest to approximately 22.1%.
SMH will pay its portion of development and production costs in a commercial development on the block. The interest
percentage does not give effect to the exercise of such options.
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 2032.
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%. In November 2021, we received notice from Tullow Oil plc (“Tullow”) and PetroSA that
they were exercising their pre-emption rights in relation to Kosmos’ acquisition of Anadarko WCTP. After execution of
definitive transaction documentation and receipt of governmental approvals, Kosmos concluded the pre-emption transaction
with Tullow in March 2022. Following completion of the pre-emption process, Kosmos’ interest in the Jubilee Unit Area
decreased from 42.1% to 38.6% and Kosmos’ interest in the TEN fields decreased from 28.1% to 20.4%. 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. During 2022, we drilled two Jubilee
Southeast wells, with a third drilled in January 2023. The two producer wells are expected to commence production in the
middle of the year, after installation and tie-in to the subsea infrastructure.
The Government of Ghana completed the construction and connection of a gas pipeline from the Jubilee Field to
transport natural gas to the mainland for processing and sale. In 2022, the partnership exported approximately 98 million
standard cubic feet per day (gross) on average from the Jubilee field to the mainland. In December 2022, an interim gas sales
agreement for 19 bcf (gross) was executed with the Government of Ghana, which allowed for gas to be sold at $0.50 per
mmbtu. The 19 bcf is expected to be exported by the middle of 2023. The partnership is currently in discussions with the
Government of Ghana regarding a future gas sales agreement covering both the Jubilee and TEN fields. Our inability to
continuously export associated natural gas from the Jubilee Field could eventually impact our oil production and could cause us
to re-inject or flare any natural gas we cannot export.
Oil production from the Jubilee Field averaged approximately 83,600 Bopd gross (31,300 Bopd net) during 2022.
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 could provide for multiple phases. During the second quarter of 2022, the partnership drilled two
new riser base wells at TEN to define the extent of the Ntomme reservoir supporting future TEN development. The first well
was drilled to test two separate reservoir objectives and encountered better reservoir quality and thickness than expected but
was water bearing. In October 2022, a second well targeting a different fairway was drilled. The well encountered
approximately 5 meters of net oil pay with poorer than expected reservoir quality. Both wells have been plugged and
abandoned. The partnership will continue to evaluate the full results of the two wells to high-grade and optimize the future
drilling plans for TEN.
Oil production from TEN averaged approximately 23,600 Bopd gross (5,000 Bopd net) during 2022.
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. The partnership is
currently in discussions with the Government of Ghana regarding a future gas sales agreement covering both the Jubilee and
16
TEN fields. Our inability to continuously export associated natural gas from the TEN fields could eventually impact our oil
production and could cause us to re-inject or flare any natural gas we cannot export.
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) discovered resource opportunities, and (iii) a high-quality inventory of infrastructure-led exploration prospects across the
DeSoto Canyon, Green Canyon, Keathley Canyon, Mississippi Canyon and Walker Ridge protraction areas. We expand our
inventory through the U.S. Gulf of Mexico Federal lease sales and farm-in transactions. Our U.S. Gulf of Mexico assets
averaged approximately 17,400 Boepd net (~ 83% oil) from 11 fields during 2022.
The following is a brief discussion of our key fields in the U.S. Gulf of Mexico.
Odd Job
The Odd Job field is producing from three Middle Miocene wells through the Delta House FPS, operated by
Murphy. In June 2022, we executed, as operator of the Odd Job field, a contract for $131.6 million (gross) with Subsea 7 (US)
LLC and OneSubsea LLC to fabricate and install a subsea pump in the Odd Job field. The project commenced in July 2022
with an expected online date around the middle of 2024. Net production during 2022 averaged approximately 4,700 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 2021,
the Tornado 5 infill well was successfully drilled, completed and brought online. Net production during 2022 averaged
approximately 5,000 Boepd net.
Kodiak
The Kodiak field is producing from two wells, which are completed in the Middle Miocene sands. These wells are
flowing through the Devils Tower Spar platform, which is operated by ENI US Operating Co. Inc. (“ENI”). One of these wells,
the Kodiak-3 infill well, was brought online in April 2021. The well experienced production issues and was shut-in. In March
2022, the Company commenced operations to plug back and side-track the original Kodiak-3 infill well. The well was
sidetracked, and the Kodiak-3ST well was brought online in September 2022, with insurance proceeds covering a substantial
portion of the costs incurred to return the well to production. Well results and initial production were in line with expectations,
however well productivity declined through the end of the fourth quarter of 2022 and workover plans have been developed for
remediation in the second half of 2023. Net production during 2022 averaged approximately 3,200 Boepd net.
Winterfell
In January 2021, we announced the Winterfell-1 exploration well encountered approximately 26 meters (85 feet) of net
oil pay in two intervals. Winterfell 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. During the third quarter of 2022, the Field Development Plan for the Winterfell field was approved by all partners and a
drilling rig was secured by BOE Exploration & Production LLC (“Beacon”), the operator of the Winterfell field, to undertake
the development drilling, including the sidetrack and completion of the Winterfell-1 well, completion of the Winterfell-2 well
and drilling and completion of the Winterfell-3 well in an adjacent fault block to the southeast of the Winterfell-1 discovery
well as part of the Field Development Plan. Host facility production handling agreement and midstream export agreement are
expected to be completed within the next several months with first production for the project targeted to be in the first quarter of
2024.
Mauritania
17
The C8 and BirAllah 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.
The C8 and BirAllah blocks cover an aggregate area of approximately 735 thousand acres (gross). We have acquired
approximately 580 line-kilometers of 2D seismic data and 3,000 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 in Block C8 and what is now the BirAllah block.
In June 2022, at the conclusion of the second exploration period, Block C12, offshore Mauritania, was relinquished.
Senegal
The Saint Louis Offshore Profond and Cayar Offshore Profond 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 these 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 exploration and appraisal 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 discoveries range 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
18
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.
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
domestic use in both Mauritania and Senegal. Following a competitive tender process, BP Gas Marketing (“BPGM”) 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 10 years with a seller’s option to extend the term for an additional 10 years. Additionally,
to optimize the commercial value of sales for the gas production from the first phase of Greater Tortue Ahmeyim, Kosmos has
commenced a process with prospective buyers to utilize existing contractual rights under our existing Tortue Phase 1 SPA to
potentially sell cargos in order to benefit from the robust forward gas price outlook, while meeting our contractual obligations
to BPGM. BPGM has disagreed with our position, and we have agreed with BPGM to pursue international arbitration to
interpret the relevant terms of the SPA.
Phase 1 of the project was approximately 90% complete at year-end 2022, with first gas for the project targeted in the
fourth quarter of 2023. The FLNG is on track for sailaway in the first half of 2023, the hub terminal is largely complete and
commissioning activities progressing, the subsea shallow water gas export pipeline from the FPSO to the hub terminal has been
installed, and all four wells needed for first gas have been successfully drilled and completed. In January 2023, the FPSO
departed from the COSCO yard in China to commence its 12,000 nautical mile journey to offshore Mauritania/Senegal. The
partnership has also been focused on optimizing Phase 2 of the project to deliver competitive returns in the current
environment. On Phase 2 of the Greater Tortue Ahmeyim LNG project, the partners (SMH, Petrosen, BP and Kosmos) have
confirmed the development concept and will progress a gravity-based structure (GBS) with total capacity of between 2.5-3.0
million tonnes per annum. GBS LNG developments have a static connection to the seabed with the structure base providing
LNG storage and a foundation for liquefaction facilities. The concept design will also include new wells and subsea equipment,
maximizing the use of existing Phase 1 infrastructure. In July 2021, the Greater Tortue Ahmeyim project was granted the status
of ‘National Project of Strategic Importance’ by the Presidents of Mauritania and Senegal, demonstrating the commitment of
the host governments and the significance of the project to both countries.
Other Mauritania and Senegal Discoveries
BirAllah and Orca Discoveries
The BirAllah discovery (formerly known as Marsouin), located in the BirAllah block offshore Mauritania, is a
significant, play-extending gas discovery, building on our successful exploration program in the outboard Cretaceous petroleum
system offshore Mauritania. In November 2015, the Marsouin-1 well, 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 the BirAllah block 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 supporting 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 Marsouin-1 and Orca-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. In October 2022, the partnership and the government of Mauritania executed a new
Production Sharing Contract (“PSC”) covering the BirAllah and Orca discoveries. The new PSC provides the partnership up to
thirty months to submit a development plan covering the BirAllah and/or Orca discoveries with the terms of the new PSC
substantially similar to the former PSC for Block C8 with additional provisions for enhanced back-in rights for the Government
of Mauritania, local content, SMH’s capacity building and an environmental fund.
19
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, and S 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 7,500
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.
In May 2022, Kosmos and its joint venture partners agreed with the Ministry of Mines and Hydrocarbons of Equatorial
Guinea to extend the Block G petroleum contract term; harmonizing the expiration of the Ceiba Field and Okume Complex
production licenses (from 2029 and 2034 respectively) to 2040. The license extensions support the next phase of investment in
the licenses.
Oil production from the Ceiba Field and Okume Complex averaged approximately 30,900 Bopd gross (9,900 Bopd
net) during 2022.
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. The discovery was subsequently named
Asam. In July 2020, an appraisal work program was approved by the government of Equatorial Guinea. The well is located
within tieback range of the Ceiba FPSO and the appraisal work program is currently ongoing to establish the scale of the
discovered resource and evaluate the optimum development solution. In December 2022, as part of the appraisal work program,
the Asam field appraisal report was submitted to the government of Equatorial Guinea.
20
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 exploration phase
for Block 5 offshore Sao Tome and Principe through November 2022. In the second quarter of 2022, we received approval for a
second six month extension to May 2023 for the current exploration phase for Block 5 offshore Sao Tome and Principe.
Our Reserves
The following table sets forth summary information about our estimated proved reserves as of December 31, 2022. 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, 2022, 2021, and 2020 were associated with our fields in Ghana,
Equatorial Guinea, Mauritania, Senegal and the U.S. Gulf of Mexico.
Summary of Oil and Gas Reserves
2022 Net Proved Reserves(1)
2021 Net Proved Reserves(1)
2020 Net Proved Reserves(1)
Oil,
Condensate,
NGLs(6)
Natural
Gas(3)
Total
Oil,
Condensate,
NGLs(6)
Natural
Gas(3)
Total
Oil,
Condensate,
NGLs(6)
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
43
20
—
21
84
56
5
7
6
74
158
40
16
—
17
73
9
—
618
7
634
707
50
23
—
24
96
58
5
110
8
180
276
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
______________________________________
(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 the acquisition of additional interests in Ghana in October 2021 and the pre-
emption transaction with Tullow in March 2022. See “Item 8. Financial Statements and Supplementary Data—Note 3—
Acquisitions and Divestitures” for discussion of pre-emption transaction with Tullow.
(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
21
associated gas forecasted to be exported from TEN. Total proved natural gas reserves include fuel gas associated with the
Jubilee and TEN fields offshore Ghana of approximately 22.9 Bcf, 30.0 Bcf and 14.0 Bcf for 2022, 2021 and 2020,
respectively. Our natural gas reserves in Equatorial Guinea are all associated with fuel gas. 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 non-
associated gas may be recognized as reserves.
(4) The Mauritania/Senegal Natural Gas reserves presented consists of LNG and Fuel Gas of approximately 51.0 Bcf and 51.0
Bcf in 2022 and 2021, respectively. We note that the LNG is presented as Plant Products in Mboe in our 2021 reserve
report.
(5) Proved undeveloped reserves as of December 31, 2022 expected to be developed beyond five years since initial disclosure
are all related to the Greater Tortue Ahmeyim project in Mauritania and Senegal which is a long-term project being
developed under a continuous drilling program with long-term LNG sales obligations.
(6) Natural gas liquids proved reserves represent an immaterial amount of our total proved reserves. Therefore, we have
aggregated natural gas liquids and crude oil/condensate reserves information.
Changes during the year ended December 31, 2022, at Greater Jubilee include a positive revision of 11.7 MMBoe
primarily due to positive drilling results and field performance, offset by a negative revision of 7.5 MMBoe resulting from the
conclusion of the Tullow pre-emption transaction in March 2022, as well as Jubilee net production of 11.3 MMBoe. These
revisions resulted in the overall decrease in reserves of 7.1 MMBoe. Changes at TEN include a negative revision of 5.5
MMBoe, driven primarily by recent well performance. Additional negative revisions of 9.1 MMBoe resulted from the
conclusion of the Tullow pre-emption transaction in March 2022, along with net TEN production of 2.0 MMBoe. These
revisions resulted in the overall decrease in reserves of 16.7 MMBoe. Changes at Equatorial Guinea included a positive revision
of 4.0 MMBoe driven by the Block G petroleum license extension and improved commodity prices. An additional positive
revision of 0.9 MMBoe due to Ceiba production performance and topsides optimization was offset by net Equatorial Guinea
production of 3.7 MMBoe. These revisions resulted in the overall increase in reserves of 1.2 MMBoe and changes in gas
reserves were negligible. Changes at Mauritania/Senegal include a positive revision of 4.7 MMBoe of gas due to field extension
resulting from the drilling of production wells, as well as a negative revision of 0.7 MMBoe in condensate based on an updated
yield estimate. These revisions resulted in the overall increase in reserves of 4.0 MMBoe. Changes at the U.S. Gulf of Mexico
include positive revisions of 3.0 MMBoe associated with the Winterfell discovery and 0.8 MMBoe related to the acquisition of
an additional interest in the Kodiak field. These changes were offset by a negative revision of 2.0 MMBoe based on recent
water breakthrough in Odd Job and Tornado, and Kodiak production issues. The U.S. Gulf of Mexico net production for the
year ended December 31, 2022 was 6.4 MMBoe. These revisions resulted in the overall decrease in reserves of 4.6 MMBoe.
During the year ended December 31, 2022, we had an overall proved undeveloped reserves decrease of 5.6 MMBoe,
as a result of several factors, including the impact of the Tullow pre-emption transaction in March 2022 (-7.9 MMBoe),
optimization of future drilling in Jubilee (+4.0 MMBoe) and TEN (+2.1 MMBoe), Greater Tortue field extension that resulted
from drilling of production wells and a downward condensate adjustment (+4.0 MMBoe), optimizing future development plans
in the U.S. Gulf of Mexico (+1.3 MMBoe), purchase of minerals-in-place during 2022 in the Kodiak field (+0.2 MMBoe) and
the Winterfell discovery (+3.0 MMBoe). Drilling activity impact on proved undeveloped volume change includes the drilling of
three wells in Jubilee (-4.6 MMBoe), one well in TEN (-5.8 MMBoe), and one well in Kodiak (-2.0 MMBoe). We note that the
changes in the proved undeveloped reserves in Equatorial Guinea were negligible.
In Greater Jubilee, we converted 4.6 MMBoe of proved undeveloped reserves to proved developed with the drilling of
three wells at a cost of approximately $75.1 million. In TEN, we converted 5.8 MMBoe of proved undeveloped reserves to
proved developed with the drilling of one well at a cost of approximately $13.6 million. In the U.S. Gulf of Mexico, we
converted 2.0 MMBoe of proved undeveloped reserves to proved developed with the drilling of one well in Kodiak at a cost of
$13.6 million.
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 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 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
22
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
+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 MMBoe 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 MMBoe. Changes at
TEN included a decrease of 12.0 MMBoe 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 MMBoe due to
strong base performance and positive stimulation results, offset by 4.0 MMBoe 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.
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, 2022, 2021 and 2020 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, 2022 are based on costs in effect
at December 31, 2022 and the 12-month unweighted arithmetic average of the first-day-of-the-month price for the year ended
December 31, 2022, 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.
23
Independent petroleum engineers
Ryder Scott Company, L.P.
RSC, our independent reserve engineers for the years ended December 31, 2022, 2021 and 2020, 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, 2022, 2021 and 2020, 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, 2022, 2021 and 2020 and related future net revenues and PV-10 at December 31, 2022, 2021 and 2020 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, 2022 reserve
report was completed on January 20, 2023, and a copy is included as an exhibit to this report.
In connection with the preparation of the December 31, 2022, 2021 and 2020 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, 2022, 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.
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
24
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 person primarily responsible for our Reservoir Engineering team is Mr. Douglas Trumbauer. Mr.
Trumbauer is a Licensed Professional Engineer in the State of Texas (No. 78735) and has over 37 years of practical experience
in petroleum engineering. He graduated from Pennsylvania State University in 1985 with a Bachelor of Science degree in
Petroleum and Natural Gas Engineering. Mr. Trumbauer worked for DeGolyer and MacNaughton for 20 years prior to joining
Kosmos Energy, and we believe he is proficient in applying industry standard practices to engineering and geoscience
evaluations as well as understanding and applying SEC and other industry reserves definitions and guidelines.
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.
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, 2022 for the countries in which we currently operate.
Developed Area
Undeveloped Area
Current Phase
(Acres)
(Acres)
Total Area (Acres)
Exploration
Gross
Net(1)
Gross
Net(1)
Gross
Net(1)
Range
(In thousands)
Ghana(2)
Equatorial Guinea
Mauritania
Sao Tome and Principe
Senegal
U.S. Gulf of Mexico(3)
Total
163
65
—
—
—
81
309
53
26
—
—
—
22
101
34
1,798
735
527
917
189
4,200
11
1,297
204
310
271
87
2,180
197
1,863
735
527
917
270
4,509
— (2)
2024
2025
2023
2024
through 2032 (3)
64
1,323
204
310
271
109
2,281
______________________________________
(1)
Net acreage based on Kosmos’ participating interests, including any options or back-in rights which have been
exercised (Jubilee, TEN, and Greater Tortue Ahmeyim fields), but before the exercise of any options or back-in rights
that exist, but have not been exercised. 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.
25
(2)
(3)
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 the acquisition of additional interests in Ghana in October
2021 and the pre-emption transaction with Tullow in March 2022. See “Item 8. Financial Statements and
Supplementary Data—Note 3—Acquisitions and Divestitures” for discussion of pre-emption transaction with Tullow.
Our developed 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. For undeveloped areas, the licenses are
immaterial with various exploration phases, with all ending by 2032. Table above reflects additional interests acquired
in U.S Gulf of Mexico. See “Item 8. Financial Statements and Supplementary Data—Note 3—Acquisitions and
Divestitures” for discussion of acquisitions.
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, 2022:
Ghana(2)
Equatorial Guinea
U.S. Gulf of Mexico(2)
Total(1)
Productive
Oil Wells
Productive
Gas Wells
Total
Gross
Net
Gross
Net
Gross
Net
53
83
21
157
17.18
33.53
5.99
56.70
—
—
—
—
—
—
—
—
53
83
21
157
17.18
33.53
5.99
56.70
______________________________________
(1)
(2)
Of the 157 productive wells, 41 (gross) or 10.00 (net) have multiple completions within the wellbore.
Table above reflects our additional interests acquired in Ghana and U.S. Gulf of Mexico. See “Item 8. Financial
Statements and Supplementary Data—Note 3—Acquisitions and Divestitures” for discussion of potential pre-emption
impact.
26
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, 2022
Ghana(4)(5)
—
—
2
0.41
2
0.41
5
1.57
—
—
5
1.57
7
1.98
Equatorial Guinea
—
—
—
—
—
—
—
—
—
—
—
—
—
—
U.S. Gulf of Mexico
—
—
—
—
—
—
—
—
—
—
—
—
—
—
Mauritania/Senegal
—
—
—
—
—
—
3
0.80
—
—
3
0.80
3
0.80
Total
—
—
2.00
0.41
2.00
0.41
8.00
2.37
—
—
8.00
2.37
10.00
2.78
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
______________________________________
(1)
(2)
(3)
(4)
(5)
As of December 31, 2022, 9 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 15 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 the acquisition of additional interests in Ghana in October 2021 and the pre-emption transaction
with Tullow in March 2022. See “Item 8. Financial Statements and Supplementary Data—Note 3—Acquisitions and
Divestitures” for discussion of pre-emption transaction with Tullow.
Includes the NT-10 and NT-11 wells which are considered step out wells from an accounting perspective but were
drilled as part of the TEN Plan of Development.
27
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, 2022.
Ghana(1)
Jubilee Unit
TEN
Equatorial Guinea
Block S
Okume
U.S. Gulf of Mexico
Winterfell
Mauritania / Senegal
Mauritania BirAllah Block
Greater Tortue Ahmeyim Unit
Senegal Cayar Profond
Total
Actively Drilling or
Completing
Wells Suspended or
Waiting on Completion
Exploration
Development
Exploration
Development
Gross
Net
Gross
Net
Gross
Net
Gross
Net
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
1
—
—
—
—
—
1
—
2
0.39
—
—
—
—
—
0.27
—
0.66
—
—
1
—
2
2
1
3
9
—
—
0.40
—
0.50
0.56
0.27
0.90
2.63
9
5
—
1
—
—
—
—
15
3.47
1.02
—
0.40
—
—
—
—
4.89
______________________________________
(1)
Table above reflects the acquisition of additional interests in Ghana in October 2021 and the pre-emption transaction
with Tullow in March 2022. See “Item 8. Financial Statements and Supplementary Data—Note 3—Acquisitions and
Divestitures” for discussion of pre-emption transaction with Tullow.
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 January 1, 2023, the Jubilee partners had fulfilled this commitment, providing 200 Bcf of natural gas to the
government of Ghana. The partnership is currently in discussions with the Government of Ghana regarding a future gas sales
agreement covering both the Jubilee and TEN fields, pending reaching an agreement on acceptable commercial terms.
Significant License Agreements
Below is a discussion concerning the petroleum contracts governing our current drilling and production operations.
Ghana West Cape Three Points Block
Tullow is the operator of the West Cape Three Points Block, including the Mahogany and Teak discoveries. Under the
WCTP petroleum contract, 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
28
Energy and GNPC have agreed such WCTP petroleum contract rights to negotiate extend from July 21, 2011 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 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 26.8% in Mauritania and 26.7% in Senegal 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 petroleum contracts covering offshore Mauritania Blocks C8 and C12 with the
Islamic Republic of Mauritania. The Mauritanian national oil company, SMH, retained a 10% carried interest during the
29
exploration period only. Should a commercial discovery be made, SMH’s 10% carried interest is to be extinguished and 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 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. In June 2022, the exploration period of Block C8 offshore Mauritania
expired. In October 2022, the partnership and the government of Mauritania executed a new Production Sharing Contract
(“PSC”) covering the BirAllah and Orca discoveries. The new PSC (named BirAllah) provides up to thirty months to submit a
development plan covering the BirAllah and/or Orca discoveries with the terms of the new PSC substantially similar to the
former PSC for Block C8 with additional provisions for enhanced back-in rights for the Government of Mauritania, local
content, SMH’s capacity building and an environmental fund. Kosmos’ participating interest in the new PSC is 28.0% and full
election by SMH of their back-in rights would reduce Kosmos’ participating interest to approximately 22.1%. In 2022, at the
conclusion of the second exploration period, Block C12 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.
Ceiba Field and Okume Complex
In Equatorial Guinea, we maintain a 40.4% undivided participating interest in the Ceiba Field and Okume Complex. In
May 2022, Kosmos and its joint venture partners agreed with the Ministry of Mines and Hydrocarbons of Equatorial Guinea to
extend the Block G petroleum contract term harmonizing the expiration of the Ceiba Field and Okume Complex production
licenses (from 2029 and 2034 respectively) to 2040.
Equatorial Guinea Agreements
In March 2018, we entered into petroleum contracts covering Blocks EG-21 and S with the Republic of Equatorial
Guinea. Kosmos currently holds an 80% participating interest in Block EG-21 and a 40% participating interest in Block S. 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. In
December 2022, an extension was granted extending the first exploration sub-period for Block EG-21 to December 2024 and
we received formal approval to proceed to the second exploration sub-period for Block S ending in December 2024.
In June 2018, we closed a farm-in agreement with a subsidiary of Ophir for Block EG-24, offshore Equatorial Guinea,
whereby we acquired a 40% non-operated participating interest. In the first quarter of 2019, we acquired Ophir's remaining
interest in and operatorship of the block, which resulted in Kosmos owning an 80% participating interest in Block EG-24.
GEPetrol, currently has a 20% carried interest during the exploration period. In December 2022, we received formal approval to
enter the second sub-period period ending in December 2024. Should a commercial discovery be made, GEPetrol's 20% carried
interest will convert to a 20% participating interest for all development and production operations. In total, the exploration
petroleum contracts cover approximately 7,500 square kilometers.
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 two years.
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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 and Okume Complex production as are the other Block G partners. We have entered into an agreement with an
oil marketing agent to market our share of the Ceiba Field and Okume Complex 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 monthly through long-
term 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 and at varying physical locations, 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 (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 one of our marketing agents 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, Russia’s invasion of Ukraine, a potential global recession, and other varying
macroeconomic conditions 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 BPGM 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. Additionally, to optimize
the commercial value of sales for the gas production from the first phase of Greater Tortue Ahmeyim, Kosmos has commenced
a process with prospective buyers to utilize existing contractual rights under our existing Tortue Phase 1 SPA to potentially sell
cargos in order to benefit from the robust forward gas price outlook, while meeting our contractual obligations to BPGM.
BPGM has disagreed with our position, and we have agreed with BPGM to pursue international arbitration to interpret the
relevant terms of the SPA.
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.
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The oil and gas industry as a whole has experienced continued volatility. Globally, the impact of COVID-19, Russia’s
invasion of Ukraine, a potential recession, and other varying macroeconomic conditions has impacted supply and demand for
oil and gas, which also resulted in significant variations in oil and gas prices. Dated Brent crude, the benchmark for our
international oil sales, ranged from approximately $76 to $138 per barrel during 2022. 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 $68 to $125 during
2022. Excluding the impact of hedges, our realized oil price for 2022 was $100.00 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
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 operations or facilities to comply with applicable regulations and 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
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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 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.
International (Non-operated)
Tullow, BP, and Trident, our partners and the operators of (i) the Jubilee Unit and the TEN fields offshore Ghana, (ii)
the various fields offshore Mauritania and Senegal, and (iii) the Ceiba Field and Okume Complex offshore Equatorial Guinea,
respectively, maintain Oil Spill Response Plans (“OSRP”) covering the joint operations. The OSRPs include access to Oil Spill
Response Limited’s (“OSRL”) oil spill response services comprising technical expertise and assistance, including access to
response equipment and dispersant spraying systems. 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. Under the OSRPs, emergency response teams may be activated to
respond to oil spill incidents.
In addition, Kosmos develops an emergency response plan and subscribes to a response organization to prepare and
demonstrate our readiness to respond to a subsea well control incident in the event we are the operator.
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 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 where Kosmos is the operator. Kosmos joined several cooperatives that were
established to meet the requirements of the new regulations. For capping and containment, Kosmos joined the HWCG, LLC
consortium whose capabilities include; (i) one dual ram capping stack rated to 15,000 psi and one valve capping stack rated to
20,000 psi, (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 Mmcf 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, dispersants 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. In
addition, Kosmos is also a member of the Marine Spill Response Corporation (“MSRC”) which also provides various oil spill
response services for coastal and inland environments in the U.S. Gulf of Mexico.
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.
The health of our employees and contractors continued to be a priority for 2022 including COVID-19 vaccination and
testing policies, facilitating remote working flexibility for employees normally based in the office full-time, 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.
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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. Based on employee
scores and feedback, Kosmos was named in the 2022 Top 100 Places to Work by the Dallas Morning News, as well as the
Houston Chronicle. The feedback received through this annual survey is used to support continuous improvement and enhance
the overall employee experience. In 2022, Kosmos had a retention rate of 95%.
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, 2022, we had 236 employees with 191 being based in the United States and 45 residing in our
local offices. Our workforce was approximately 37% 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, but not limited to, tropical
storms and hurricanes, and the physical effects of climate change;
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 had, and continue to have, disagreements with certain host governments and contractual counterparties regarding
certain of our rights and responsibilities and may have future disagreements with our host governments and/or
contractual counterparties;
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 substantial or extended decline in oil and natural gas prices may adversely affect our business, financial condition
Our Business and 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 due to decreases in the
estimated future net cash flows from our operations, which may occur as a result of decreases in oil and natural gas
prices, poor field performance, increased expenditures or changes in timing of investment, among other things, and
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such decreases could result in reduced availability under our corporate revolver, commercial debt facility, and GoM
Term Loan;
• 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;
The continued effects of the COVID-19 pandemic and outbreaks of other diseases may adversely affect our business
operations and financial condition;
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
•
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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 rising inflationary pressure or a tightening in the supply of various types of oilfield equipment and related services or
unanticipated geologic conditions.
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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
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 and appraisal 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 significantly decrease or operating or development costs significantly 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 certain of our 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.
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In order to protect our exploration and production rights in our license areas, we may be required to meet various
drilling and declaration requirements. In general, unless we make and declare discoveries within certain time periods specified
in certain of our 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
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 certain 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, 2022, we have unfulfilled drilling obligations for
three development wells and one exploration well in Equatorial Guinea. 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 some of our 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,
development and decommissioning 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 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
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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%. Following the completion of the pre-emption by Tullow in March of 2022,
Kosmos’ interest in the Jubilee Unit Area decreased from 42.1% to 38.6%. 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 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:
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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
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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, 2022.
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
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:
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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 still 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. We granted the Government of Ghana the first 200
Bcf of natural gas exported from the Jubilee Field to shore at zero cost. As of January 1, 2023, the Jubilee partners have
fulfilled this commitment, providing 200 Bcf of zero cost natural gas to the Government of Ghana. The Ghana partners are
currently in discussions with the Government of Ghana regarding a future gas sales agreement covering both the Jubilee and
TEN fields. 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.
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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
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 and construction vessels suitable for the environment in which we operate. The delivery of drilling rigs or
construction vessels may be delayed or cancelled, and we may not be able to gain continued access to suitable rigs or vessels 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. For example, we transport and process natural gas from the Jubilee and TEN
fields to mainland Ghana through a pipeline and processing facilities that are controlled by the Government of Ghana. We
cannot provide any assurance about uptime and availability of the pipeline and processing facilities. In addition, we are party to
an interim gas sale agreement with the government of Ghana relating to the natural gas we produce from the Jubilee field that
we expect to conclude by mid-2023. In the event we cannot put in place a new gas sales agreement on commercially reasonable
terms, our ability to continuously extract and process natural gas may be harmed and we may be required to reinject or flare
such natural gas in order to maintain crude oil production and or reduce our overall crude oil production, which may adversely
impact our results of operations, financial condition and prospects.
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 variations 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, among other factors. 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
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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.
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, but not limited to, tropical storms
and hurricanes, and the physical effects of climate change.
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, the physical impacts of climate change in the areas in which our assets are located or in which we
otherwise operate, including any corresponding increases to the 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. 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
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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
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 previously
experienced mechanical issues at certain of our offshore production facilities, such as the turret bearing issue on the Jubilee
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 had, and continue to have, disagreements with certain host governments and contractual counterparties regarding
certain of our rights and responsibilities and may have future disagreements with our host governments and/or contractual
counterparties.
There can be no assurance that future disagreements will not arise with any host government, national oil companies,
and/or contractual counterparties 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, but if such
disagreements do arise we intend to vigorously dispute them if necessary.
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 Petroleum
Commission and/or Ghana’s Ministry of Energy. We have previously had disagreements with the Ministry of Energy, GNPC,
and the Ghana Revenue Authority (the “GRA”) 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”). For
example, 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 we intend to vigorously dispute them if
necessary, but there can be no assurance regarding the resolution of these or future disagreements.
Additionally, to optimize the commercial value of sales for the gas production from the first phase of Greater Tortue
Ahmeyim, Kosmos has commenced a process with prospective buyers to utilize existing contractual rights under our existing
Tortue Phase 1 SPA to potentially sell cargos in order to benefit from the robust gas price outlook, while meeting our
contractual obligations to BPGM. BPGM has disagreed with our position, and the parties have agreed to pursue international
arbitration to interpret the relevant terms of the SPA.
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.
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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 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
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 and natural gas prices experienced significant volatility in the past few years and will likely continue
to be volatile in the future. For example, Russia’s invasion of Ukraine, the impacts of the ongoing COVID-19 pandemic, a
potential global recession and other varying macroeconomic conditions and the effects on demand for oil and natural gas has
resulted in significant variations in oil and natural gas 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;
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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.
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
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areas. See “—Under the terms of certain of our 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 due to decreases in the
estimated future net cash flows from our operations, which may occur as a result of decreases in oil and natural gas prices,
poor field performance, increased expenditures or changes in timing of investment, among other things, and such decreases
could result in reduced availability under our corporate revolver, commercial debt facility, and GoM Term Loan.
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. For example, if there is a significant and sustained drop in
oil and natural gas prices, field performance is not as expected, or we encounter increased expenditures, we may incur future
write-downs and charges.
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;
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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
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.
The continued effects of 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, created significant volatility, uncertainty and economic disruption in
the markets in which we operate, which affected our business and operations and those of our suppliers, contractors and
partners. For example, during the height of COVID-19, which has since abated, certain contracts necessary for our ongoing
exploration, development and production operations were suspended or terminated as a consequence of the pandemic, and the
pandemic 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. In addition, the measures taken to combat
the pandemic 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
or outbreaks of other diseases. 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 or
outbreaks of other diseases that impact sales or delay production may not be covered by our insurance policies.
The extent to which our future results are affected by COVID-19 will largely depend on future developments that
cannot be accurately predicted. In addition, any 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.
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
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it a global health emergency. It is impossible to predict the effect and potential spread of new outbreaks of the Ebola virus or
other viruses in West Africa and surrounding areas. Should another Ebola or other 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 or other 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 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.
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 due to inflationary pressures or otherwise may increase economic
uncertainty. 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 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 and a potential global recession which have lead to an increase in interest rates during 2022 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, 2022, we had $0.6 billion outstanding and $618.0 million of committed undrawn available capacity
under our commercial debt facility, subject to borrowing base availability. As of December 31, 2022, there were no borrowings
outstanding under the Corporate Revolver and the undrawn availability was $250.0 million. As of December 31, 2022, we had
$1.5 billion principal amount of Senior Notes outstanding and $145 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 economic 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 economic 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 the 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
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repayment or otherwise. Unless they are guarantors, our subsidiaries will not have any obligation to pay amounts due on the
Senior 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 the 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 Deep Gulf Energy) 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 2021, the Colonial Pipeline was subject to a ransomware attack that disabled the
pipeline for several days, affecting consumers throughout the eastern coast of 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, harm our reputation and negatively impact our
operations. 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. 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 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 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
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.
(by value) over a
three-year period,
than 50% of
to utilize
its stock
its
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 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 certain contracts or agreements 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. Litigation challenging the Climate Change Executive Order’s pause on new oil and gas leases commenced soon
after the order was issued; this litigation is ongoing. However, in August 2022, the Inflation Reduction Act was passed by the
U.S. Congress, and included provisions which required the DOI to hold previously announced offshore lease sales in the Gulf
of Mexico and Alaska within two years. The BOEM has proposed for Lease Sale 259 to occur in March 2023. Nonetheless, in
light of the litigation described above, there can be no assurance that Lease Sale 259 will go ahead as planned. 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.
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
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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 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, and continue to face, similar tax related disputes with
the Senegal, Mauritania, and Equatorial Guinea 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.
In addition, we are subject to uncertainties surrounding the economies and fiscal health of the countries in which we
operate. For example, the Republic of Ghana has recently been subject to ratings downgrades on its sovereign debt and has
since reached a staff-level agreement with the International Monetary Fund on economic policies and reforms which, if
successful, could result in a three-year arrangement of about $3.0 billion to support the objective of restoring public debt
sustainability. Ratings downgrades such as this one in Ghana have affected the Company’s own credit ratings due to concerns
over revenue dependence on a single country. A significant reduction in the availability of credit could materially and adversely
affect our ability to achieve our planned growth and operating results.
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;
impact our credit ratings and ability to access capital;
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.
In the U.S. Gulf of Mexico, regulatory initiatives are continually developed and implemented at the federal level to
prevent major well control incidents. The Department of Interior (“DOI”) through the BOEM and the Bureau of Safety and
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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 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;
unitization of oil accumulations;
local content requirements (including the mandatory use of local partners and vendors); and
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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 maintain policies and processes to
comply with these various permits and laws and regulations to which we are subject. If determined that we have violated or
failed 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. Additionally, there is a risk that such requirements
could change in the future or become more stringent. 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.
We take measures to prevent the release of regulated substances. If a release of regulated substances were to occur,
which may 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. 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.
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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 2022,
the international community gathered in Egypt at the 27th Conference to the Parties on the UN Framework Convention on
Climate Change (“COP27”), during which multiple announcements were made, including the EPA’s announcement of more
stringent revisions to previously proposed methane emissions rules for the oil and gas sector. The previously proposed rules,
and EPA’s November 2022 revisions, establish requirements for methane emissions from existing and modified oil and gas
sources and impose additional requirements for new sources. In addition, in March 2022, the SEC proposed rules requiring
disclosure of a range of climate change-related information, including, among other things, companies’ climate change risk
management; short- medium- and long-term climate-related financial risks; and disclosure of Scope 1, Scope 2 and (for certain
companies) Scope 3 emissions. The SEC’s proposed climate disclosure rules have not yet been finalized, but implementation of
the rules as proposed could be costly and time consuming. It cannot be determined at this time what effect the Paris Agreement,
COP27, the EPA’s proposed methane emission rules, the SEC’s proposed climate change disclosure rules and any other 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. 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
compliance with applicable laws. After the program aired, certain government agencies requested that Kosmos voluntarily
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provide information related to the Senegal blocks and other blocks. We have cooperated with these requests to ensure that these
agencies have an accurate and complete understanding concerning the history of the blocks. After an extensive review lasting
over three-years, the SEC informed us in December, 2022 that it had closed its investigation with no enforcement action
recommended. There can be no assurance that 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
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
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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:
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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;
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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;
the issuance or sale of any additional securities of ours;
investor perception of our company and of the industry in which we compete; and
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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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Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities
PART II
Common Stock Trading Summary
Our common stock is traded on the NYSE and LSE under the symbol KOS.
As of February 23, 2023, 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 120. On February 23, 2023, the last reported sale price of
Kosmos’ common stock, as reported on the NYSE, was $7.50 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 share units to our employees. On the date that these restricted
share units 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 unit award agreements and the LTIP, at either the number of vested share units
(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 share
units sold by the grantees to settle their tax liability. The repurchased share units are reallocated to the number of share units
available for issuance under the LTIP.
63
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, 2022, 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,
2017
2018
2019
2020
2021
2022
$ 100.00 $
59.40 $
85.80 $
36.00 $
53.00 $
97.30
100.00
95.60
125.70
148.80
191.50
156.80
Dow Jones U.S. Exploration & Production Index (DWCEXP)
100.00
80.70
89.00
58.90
101.60
159.80
64
Kosmos Energy Ltd. (KOS)S&P 500 (SPX)Dow Jones U.S. Exploration & Production Index (DWCEXP)201720182019202020212022050100150200250
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, 2022.
65
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
offshore Atlantic Margins. Our key assets include production offshore Ghana, Equatorial Guinea and the U.S. Gulf of Mexico,
as well as world-class gas projects offshore Mauritania and Senegal. We also pursue a proven basin exploration program in
Equatorial Guinea and the U.S. Gulf of Mexico.
Globally, the impacts of Russia’s invasion of Ukraine, a potential recession, COVID-19 and other varying
macroeconomic conditions has impacted supply and demand for oil and gas, which also resulted in significant variability in oil
and gas prices. The Company’s revenues, earnings, cash flows, capital investments, debt capacity and, ultimately, future rate of
growth are highly dependent on these commodity prices.
66
Recent Developments
Corporate
In March 2022, we refinanced the Corporate Revolver by replacing it with a new revolving credit facility agreement.
The new revolving credit facility decreases the borrowing capacity from $400 million to $250 million and extends the maturity
date from May 2022 to the end of 2024. In anticipation of the cessation of the LIBOR, as part of the refinancing, interest for the
Corporate Revolver was linked to the SOFR administered by the Federal Reserve Bank of New York. The Company expects
the reduced borrowing capacity of the Corporate Revolver to offset an increase in the margin, resulting in slightly lower interest
expenses going forward. In November 2022, we amended the Corporate Revolver and the Facility to update the interest rate
benchmark under the Facility from LIBOR to term SOFR and to update the interest rate benchmark under the Corporate
Revolver from compounded SOFR to term SOFR, each change to be effective as of April 19, 2023. The Corporate Revolver
was also amended to reflect that The Standard Bank of South Africa Limited has been appointed as the new Facility Agent.
Under the terms of our 2020 farm-out agreement with Shell, 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. During the fourth quarter of 2022, we received formal notice from Shell that an appraisal plan for one of the first
four exploration wells had been submitted under the terms of Shell’s Petroleum Agreement with Namibia. As a result, we
received additional proceeds of $50.0 million from Shell in the fourth quarter of 2022 related to the transaction.
Ghana
During the year ended December 31, 2022, Ghana production averaged approximately 107,200 Bopd gross (36,300
Bopd net). Jubilee production averaged approximately 83,600 Bopd gross (31,300 Bopd net) and TEN production averaged
approximately 23,600 Bopd gross (5,000 Bopd net).
The multi-year development drilling program in Ghana continued to progress in 2022 with the successful drilling and
completion of one producer well and two water injector wells in the Jubilee Field (all successfully brought online during 2022)
and the completion of one water injector well and one producer well at TEN (both successfully brought online during 2022).
During 2022, the partnership drilled two new riser base wells at TEN to further define the extent of the Ntomme reservoir
supporting potential future TEN development. The first well was drilled to test two separate reservoir objectives and
encountered better reservoir quality and thickness than expected but was water bearing. In October 2022, a second well
targeting a different fairway was drilled. The well encountered approximately 5 meters of net oil pay with poorer than expected
reservoir quality. Both wells have been plugged and abandoned. The partnership will continue to evaluate the full results of the
two wells to high-grade and optimize the future drilling plans for TEN. In the fourth quarter of 2022, drilling operations
commenced on the Jubilee Southeast project, successfully drilling two wells, with a third drilled in January 2023. The three
wells consisted of two producer wells and one water injector well. The two producer wells are expected online in the middle of
2023.
In July 2022, the Jubilee partners completed the transition of the operations & maintenance (O&M) services for the
Jubilee FPSO from external provider MODEC, Inc. to Tullow.
Following the closing of the acquisition of Anadarko WCTP Company (“Anadarko WCTP”) in the fourth quarter of
2021, Kosmos’ interest in the Jubilee Unit Area and the TEN fields offshore Ghana were 42.1% and 28.1%, respectively. Under
the DT Block Joint Operating Agreement, certain joint venture partners have pre-emption rights in the Jubilee Unit Area and
the TEN fields. In November 2021, we received notice from Tullow Oil plc (“Tullow”) and PetroSA that they were exercising
their pre-emption rights in relation to Kosmos’ acquisition of Anadarko WCTP. After execution of definitive transaction
documentation and receipt of governmental approvals, Kosmos concluded the pre-emption transaction with Tullow in March
2022. Following the completion of the pre-emption process, Kosmos’ interest in the Jubilee Unit Area decreased from 42.1% to
38.6% and Kosmos’ interest in the TEN fields decreased from 28.1% to 20.4%. Tullow paid Kosmos $118.2 million in cash
consideration after post closing adjustments for the pre-emption. During the first quarter of 2022, our oil and gas properties, net
balance was reduced by $175.5 million which includes the cash proceeds and net liabilities transferred to the purchaser as a
result of concluding the Tullow pre-emption transaction. The difference in the net book value of the proved property, net
liabilities transferred and adjusted purchase price was treated as a recovery of cost and normal retirement, which resulted in no
gain or loss being recognized.
67
In connection with the approval of the Jubilee Phase 1 PoD in 2009, the Jubilee Field partners agreed to provide the
first 200 Bcf of natural gas produced from the Jubilee Field Phase 1 development to the Government of Ghana at no cost. As of
January 1, 2023, the Jubilee partners have fulfilled this commitment, providing 200 Bcf of natural gas to the Government of
Ghana. From 2018 through 2022, approximately 19 Bcf of the first 200 Bcf of natural gas was substituted from the TEN fields
in order to maintain consistent gas volumes to shore for Ghana domestic power purposes. Effective January 1, 2023, the volume
of approximately 19 Bcf of Jubilee gas (in restoration of the amount originally substituted from TEN) will be sold to Ghana
under the terms of the TAG GSA at $0.50 per mmbtu over a period of approximately six months. The Jubilee and TEN partners
are currently in discussions with the Government of Ghana regarding a future gas sales agreement.
U.S. Gulf of Mexico
During the year ended December 31, 2022, U.S. Gulf of Mexico production averaged approximately 17,400 Boepd
(net) (~83% oil). Production for the fourth quarter of 2022 was impacted by planned and unplanned facilities shutdowns as well
as loop currents in the Gulf of Mexico.
In March 2022, the Company commenced operations to plug back and side-track the original Kodiak-3 infill well
located in Mississippi Canyon. The well was sidetracked, and the Kodiak-3ST well was brought back online in early September
2022, with insurance proceeds covering a substantial portion of the costs incurred to return the well to production. Well results
and initial production were in line with expectations, however well productivity declined through the end of the fourth quarter
of 2022 and workover plans have been developed for remediation in the second half of 2023.
In June 2022, Kosmos completed the acquisition of an additional 5.9% interest in the Kodiak oil field from Marubeni
by exercising our preferential right to purchase for a total purchase price of approximately $29.0 million. As a result of the
transaction, our working interest increased from 29.1% to 35.0%.
In January 2021, we announced the Winterfell-1 exploration well encountered approximately 26 meters (85 feet) of net
oil pay in two intervals. The Winterfell-1 well 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. During the third quarter of 2022, the Field Development Plan for the Winterfell field was approved by all partners and a
drilling rig was secured by Beacon, the operator of the Winterfell field, to undertake the development drilling, including the
sidetrack and completion of the Winterfell-1 well, completion of the Winterfell-2 well and drilling and completion of the
Winterfell-3 well in an adjacent fault block to the southeast of the Winterfell-1 discovery well as part of the Field Development
Plan. The Winterfell development project continues to make progress. Drilling of the wells for the first phase of the
development is expected to start in the third quarter of 2023 with first production for the project targeted to be around the end of
the first quarter of 2024. Host facility production handling and midstream export agreements are expected to be completed and
signed within the next several months.
In March 2022, Kosmos completed the acquisition of an additional 5.5% interest in the Winterfell area in Green
Canyon Blocks 943, 944, 987 and 988 and an additional 1.5% interest in Green Canyon blocks 899 and 900 for $9.6 million.
Additionally, in September 2022, Kosmos completed the acquisition of an additional 3.2% interest in the Winterfell area in
Green Canyon Blocks 943, 944, 987 and 988 and an additional 1.4% interest in Green Canyon blocks 899 and 900 for $6.6
million. As a result of the two transactions, our participating interests in the Green Canyon Blocks 943, 944, 987 and 988 is
now 25.0% and our participating interests in the Green Canyon Blocks 899 and 900 is now 37.8%.
In June 2022, we executed, as operator of the Odd Job field, a contract for $131.6 million (gross) with Subsea 7 (US)
LLC and OneSubsea LLC to fabricate and install a subsea pump in the Odd Job field. The project commenced in July 2022
with an expected online date around the middle of 2024. Kosmos’ average working interest in the Odd Job field is
approximately 54.9%.
In the second half of 2023, Kosmos plans to drill the Tiberius infrastructure-led exploration prospect, which is located
in block 964 of Keathley Canyon (33% working interest) in the prolific outer Wilcox play.
Equatorial Guinea
68
Production in Equatorial Guinea averaged approximately 30,900 Bopd gross (9,900 Bopd net) for the year ended
December 31, 2022.
In May 2022, Kosmos and its Joint Venture partners agreed with the Ministry of Mines and Hydrocarbons of
Equatorial Guinea to extend the Block G petroleum contract term harmonizing the expiration of the Ceiba Field and Okume
Complex production licenses (from 2029 and 2034 respectively) to 2040. The license extensions support the next phase of
investment in the licenses. As part of the extension, during the second quarter of 2022, Kosmos paid a signature bonus and
agreed to undertake a future work program including the drilling of three development wells on Block G in either the Ceiba
Field or Okume Complex and the drilling of one exploration well in Block S offshore Equatorial Guinea.
In August 2022, the partnership entered into a drilling rig contract for the next drilling campaign, which is expected to
commence in the second half of 2023. The first well is expected to be online by the end of the fourth quarter of 2023 with
subsequent wells online early in 2024.
In October 2022, we entered into a farm-out agreement with Panoro Energy ASA (Panoro) to farm-out a 6.0%
participating interest in Block S offshore Equatorial Guinea, which will result in our participating interest in Block S reducing
to 34.0%. The transaction is awaiting governmental approvals. During the fourth quarter of 2022, we received approval from
the Government of Equatorial Guinea to enter the second sub-period phase of the Block S exploration license with a scheduled
expiration in December 2024. During 2023, Kosmos and partners plan to progress the infrastructure-led exploration prospect,
Akeng Deep in Block S for drilling in early 2024.
In December 2022, we received approval from the Government of Equatorial Guinea for a two year extension to the
current exploration phase for Block EG-21 offshore Equatorial Guinea through December 2024. Kosmos currently holds an
80% participating interest in Block EG-21.
In December 2022, we received approval from the Government of Equatorial Guinea to enter the second exploration
sub-period for Block EG-24 offshore Equatorial Guinea which has a scheduled expiration in December 2024 and no well
commitments.
Mauritania and Senegal
In June 2022, the exploration period of Block C8 offshore Mauritania expired. In October 2022, the partnership and
the government of Mauritania executed a new Production Sharing Contract (“PSC”) covering the BirAllah and Orca
discoveries, which were previously included in the former Block C8 PSC. The new PSC provides up to thirty months to submit
a development plan covering the BirAllah and/or Orca discoveries with the terms of the new PSC substantially similar to the
former PSC for Block C8 with additional provisions for enhanced back-in rights for the Government of Mauritania, local
content, SMH’s capacity building and an environmental fund. Kosmos’ participating interest in the new PSC is 28.0% and full
election by SMH of their back-in rights would reduce Kosmos’ participating interest to approximately 22.1%.
In June 2022, at the conclusion of the second exploration period, Block C12 offshore Mauritania was relinquished.
Greater Tortue Ahmeyim Unit
Phase 1 of the Greater Tortue project continued to make good progress in 2022 with first gas for the project targeted to
be in the fourth quarter of 2023. The following milestones were achieved through the year-end and filing date:
•
•
•
•
FLNG: on track for sailaway in second quarter of 2023 as construction, mechanical completion activities, and
commissioning work continues.
FPSO: On January 20, 2023, the FPSO vessel departed the COSCO shipyard in Qidong, China. It has begun its 12,000
nautical mile journey to its final destination offshore Mauritania/Senegal, after first making a stop in Singapore. Once
on location, its final stage of hookup and commissioning work is expected to commence.
Hub Terminal: As its construction is complete, work is focused on progressing the final hookup and commissioning
and preparing it for the integration into the other project elements.
Subsea: The infield umbilical installation and 70% of the pipelay have been completed. Work is focused on
completing the remaining flowline installation and completing the subsea structures currently under construction.
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• Drilling: successfully drilled and completed all four wells and demobilized the rig in February 2023. Expected
production capacity is significantly more than what is required for first gas.
On Phase 2 of the Greater Tortue Ahmeyim LNG project, the partners (SMH, Petrosen, BP and Kosmos) have
confirmed the development concept and will progress a gravity-based structure (GBS) with total capacity of between 2.5-3.0
million tonnes per annum. GBS LNG developments have a static connection to the seabed with the structure base providing
LNG storage and a foundation for liquefaction facilities. The concept design will also include new wells and subsea equipment,
maximizing the use of existing Phase 1 infrastructure. In July 2021, the Greater Tortue Ahmeyim project was granted the status
of ‘National Project of Strategic Importance’ by the Presidents of Mauritania and Senegal, demonstrating the commitment of
the host governments and the significance of the project to both countries.
Sao Tome and Principe
In the second quarter of 2022, we received approval for a six month extension to May 2023 for the current exploration
phase for Block 5 offshore Sao Tome and Principe.
70
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, 2022,
2021 and 2020 are included in the following tables. For a discussion of the year ended December 31, 2021 compared to the year
ended December 31, 2020, 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, 2021.
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,
2022(2)
2021(1)
2020
(In thousands, except per volume data)
22,012
4,076
426
23,117
63,335
18,525
4,904
508
19,850
54,384
20,531
5,867
602
22,111
60,412
$
2,201,199 $
1,298,577 $
786,159
29,504
14,652
18,898
14,538
11,706
6,168
2,245,355 $
1,332,013 $
804,033
100.00 $
70.10 $
7.24
34.39
97.13
3.85
28.62
67.10
38.29
2.00
10.25
36.36
387,888 $
332,203 $
15,168
13,803
403,056 $
346,006 $
336,662
1,815
338,477
498,256 $
467,221 $
485,862
$
$
$
$
$
$
16.78 $
16.74 $
0.66
17.44
21.55
0.70
17.44
23.54
15.23
0.08
15.31
21.97
37.28
Total oil and gas production costs, depletion, depreciation and amortization
$
38.99 $
40.98 $
(1)
Includes activity related to our acquisition of additional interests in Ghana commencing October 13, 2021, the
acquisition date.
(2)
Includes activity related to the pre-emption transaction with Tullow on March 13, 2022.
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The discussion of the results of operations and the period-to-period comparisons presented below analyze our
historical results. The following discussion may not be indicative of future results.
Year Ended December 31, 2022 vs. 2021
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
Income (loss) before income taxes
Income tax expense (benefit)
Net income (loss)
Years Ended December 31,
2022(2)
2021(1)
Increase
(Decrease)
(In thousands)
$
2,245,355 $
50,471
1,332,013 $
1,564
3,949
2,299,775
262
1,333,839
403,056
6,243
134,230
100,856
498,256
449,969
118,260
260,892
(9,054)
346,006
(1,586)
65,382
91,529
467,221
—
128,371
270,185
10,111
1,962,708
1,377,219
337,067
110,516
(43,380)
34,456
913,342
48,907
3,687
965,936
57,050
7,829
68,848
9,327
31,035
449,969
(10,111)
(9,293)
(19,165)
585,489
380,447
76,060
$
226,551 $
(77,836) $
304,387
(1)
Includes activity related to our acquisition of additional interests in Ghana commencing October 13, 2021, the
acquisition date.
(2)
Includes activity related to the pre-emption transaction with Tullow on March 13, 2022.
Oil and gas revenue. Oil and gas revenue increased by $913.3 million during the year ended December 31, 2022 as
compared to the year ended December 31, 2021 as a result of higher production rates at Jubilee and our acquisition of additional
interests in Ghana during the fourth quarter of 2021 which drove increased sales volumes in Ghana as well as higher average oil
prices. We sold 23,117 MBoe at an average realized price per barrel of oil equivalent of $97.13 in 2022 and 19,850 MBoe at an
average realized price per barrel of oil equivalent of $67.10 in 2021.
Gain on sale of assets. During the fourth quarter of 2022, we received $50.0 million from Shell under the terms of our
2020 farm-out agreement.
Oil and gas production. Oil and gas production costs increased by $57.1 million during the year ended December 31,
2022 as compared to the year ended December 31, 2021 as a result of our acquisition of additional interests and sales volumes
in Ghana.
Exploration expenses. Exploration expenses increased by $68.8 million during the year ended December 31, 2022, as
compared to the year ended December 31, 2021 primarily as a result of the $64.2 million of previously capitalized costs related
to the BirAllah and Orca discoveries incurred under the Block C8 license offshore Mauritania that were written off to
exploration expense in 2022 with the expiration of the exploration period of Block C8, approximately $15.8 million related to
the exit of leases in the U.S. Gulf of Mexico and Mauritania business units in 2022, and approximately $13.7 million of
72
exploration expense recorded in 2022 related to two abandoned Ntomme step out wells compared to the 2021 activity including
the Zora exploration well, which did not find hydrocarbons and was plugged and abandoned in August 2021 with $14.1 million
of well costs charged to exploration expense in 2021.
General and administrative. General and administrative costs increased by $9.3 million during the year ended
December 31, 2022, as compared to the year ended December 31, 2021 primarily as a result of increased compensation and
benefits, travel costs and professional fees during the year ended December 31, 2022.
Depletion, depreciation and amortization. Depletion, depreciation and amortization increased $31.0 million during the
year ended December 31, 2022, as compared to the year ended December 31, 2021 as a result of higher sales volumes in the
current year.
Impairment of long-lived assets. Impairment of long-lived assets increased $450.0 million during the year ended
December 31, 2022, as compared to the year ended December 31, 2021 as a result of a negative proved oil and gas reserve
revision at TEN, primarily driven by recent well performance, which resulted in impairment charges of $450.0 million for the
year ended December 31, 2022.
Interest and other financing costs, net. Interest and other financing costs, net decreased by $10.1 million during the
year ended December 31, 2022, as compared to the year ended December 31, 2021 primarily as a result of $15.2 million for
loss on extinguishment of debt during 2021 related to the Facility amendment, $4.4 million loss on extinguishment of debt
during 2021 related to the Bridge Notes and increased capitalized interest in 2022 related to the Greater Tortue Ahmeyim
project, offset by increased interest expense on the 7.750% Senior Notes and the 7.500% Senior Notes and guarantee fees on
the Greater Tortue FPSO transaction.
Derivatives, net. During the years ended December 31, 2022 and 2021, we recorded a loss of $260.9 million and
$270.2 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 $19.2 million during the year ended December 31, 2022, as
compared to the year ended December 31, 2021 primarily as a result of $7.0 million insurance settlements and approximately
$3.0 million gain on asset retirement obligations.
Income tax expense (benefit). For the years ended December 31, 2022 and 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.
Liquidity and Capital Resources
We are actively engaged in an ongoing process of anticipating and meeting our funding requirements related to our
strategy as a full-cycle exploration and production company. We have historically met our funding requirements through cash
flows generated from our operating activities and obtained additional funding from issuances of equity and debt, as well as
partner carries.
Oil prices are historically volatile and 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, partner carries and our current liquidity position support our capital program for 2023.
As such, our 2023 capital budget is based on our exploitation and production plans for Ghana, Equatorial Guinea and
the U.S. Gulf of Mexico, our infrastructure-led exploration and appraisal program in the U.S. Gulf of Mexico and Equatorial
Guinea, and our appraisal and development activities in the U.S. Gulf of Mexico, Mauritania and Senegal.
Our future financial condition and liquidity can be impacted by, among other factors, the success of our exploitation,
exploration and appraisal drilling programs, the number of commercially viable oil and natural gas discoveries made and the
quantities of oil and natural gas discovered, the speed with which we can bring such discoveries to production, the reliability of
our oil and gas production facilities, our ability to continuously export oil and gas, our ability to secure and maintain partners
and their alignment with respect to capital plans, the actual cost of exploitation, exploration, appraisal and development of our
oil and natural gas assets, and coverage of any claims under our insurance policies.
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In March 2022, we refinanced the Corporate Revolver by replacing it with a new revolving credit facility agreement.
The total size of the Corporate Revolver reduced from $400 million to $250 million and the maturity date extended from May
2022 to December 31, 2024.
In October 2022, during the Fall 2022 redetermination, the Company’s lending syndicate approved a borrowing base
for the facility of approximately $1.24 billion. As of December 31, 2022, borrowings under the Facility totaled $625.0 million
and the undrawn availability under the facility was $618.0 million.
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,
2022, 2021 and 2020:
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
Tax withholdings on restricted stock units
Dividends
Deferred financing costs
Years Ended December 31,
2022
2021
2020
(In thousands)
$
1,130,476 $
374,344 $
196,145
—
—
—
—
168,703
839,375
136,006
725,000
—
6,354
1,299,179
2,081,079
787,297
22,078
63,183
472,631
465,367
41,733
405,000
1,050,000
2,753
655
6,288
1,100
512
24,604
—
—
300,000
50,000
99,118
645,263
379,593
—
65,112
250,000
4,947
19,271
5,922
Increase (decrease) in cash, cash equivalents and restricted cash
$
11,925 $
25,132 $
(79,582)
1,287,254
2,055,947
724,845
Net cash provided by operating activities. Net cash provided by operating activities in 2022 was $1.1 billion
compared with net cash provided by operating activities of $374.3 million in 2021 and $196.1 million in 2020, respectively.
The increase in cash provided by operating activities in the year ended December 31, 2022 when compared to the same period
in 2021 is primarily a result of increased oil prices and increased production. 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 higher oil
prices.
74
The following table presents our liquidity and financial position as of December 31, 2022 and 2021:
7.125% Senior Notes
7.750% Senior Notes
7.500% Senior Notes
Borrowings under the Facility
GoM Term Loan
Total long-term debt
Cash and cash equivalents
Total restricted cash
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:
Years Ended December 31,
2022
2021
(In thousands)
$
$
$
$
$
650,000
400,000
450,000
625,000
145,000
2,270,000
183,405
3,416
2,083,179
618,034
250,000
1,051,439
$
$
$
$
$
650,000
400,000
450,000
1,000,000
175,000
2,675,000
131,620
43,276
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 appraisal and development activities in Ghana, the U.S. Gulf of Mexico, Mauritania and Senegal; and
execute infrastructure-led exploration and appraisal efforts in the U.S. Gulf of Mexico and Equatorial Guinea.
We have relied on a number of assumptions in budgeting for our future activities. These include the number of wells
we plan to drill, our participating, paying and carried interests in our prospects including disproportionate payment amounts, the
costs involved in developing or participating in the development of a prospect, the timing of third-party projects, the availability
of suitable equipment and qualified personnel and our cash flows from operations. We also evaluate potential corporate and
asset acquisition opportunities to support and expand our asset portfolio, which may impact our budget assumptions. These
assumptions are inherently subject to significant business, political, economic, regulatory, health, environmental and
competitive uncertainties, contingencies and risks, all of which are difficult to predict and many of which are beyond our
control. We may need to raise additional funds more quickly if market conditions deteriorate; or one or more of our
assumptions proves to be incorrect, or if we choose to expand our acquisition, exploration, appraisal, development efforts or
any other activity more rapidly than we presently anticipate. We may decide to raise additional funds before we need them if
the conditions for raising capital are favorable. We may seek to sell assets, equity or debt securities or obtain additional bank
credit facilities. The sale of equity securities could result in dilution to our shareholders. The incurrence of additional
indebtedness could result in increased fixed obligations and additional covenants that could restrict our operations.
2023 Capital Program
We estimate we will spend approximately $700-$750 million of capital for the year ending December 31, 2023,
excluding any acquisitions or divestiture of oil and gas properties during the year. This capital expenditure budget consists of:
•
•
•
Approximately $250-$300 million related to maintenance activities across our Ghana, Equatorial Guinea and
U.S. Gulf of Mexico assets, including infill development drilling and integrity spend
Approximately $350-$400 million related to the developments of Jubilee Southeast in Ghana, Phase 1 of
Greater Tortue Ahmeyim in Mauritania and Senegal, and Winterfell in the U.S. Gulf of Mexico
Approximately $50-$100 million related to progressing our infrastructure-led exploration and appraisal
programs in the U.S. Gulf of Mexico and Equatorial Guinea, as well as the appraisal plans of our greater gas
75
resources in Mauritania and Senegal, including Phase 2 of Greater Tortue Ahmeyim, BirAllah and Yakaar-
Teranga.
The ultimate amount of capital we will spend may fluctuate materially based on market conditions and the success of
our exploitation and drilling results among other factors. Our future financial condition and liquidity will be impacted by,
among other factors, our level of production of oil and the prices we receive from the sale of oil, our ability to effectively hedge
future production volumes, the success of our multi-faceted infrastructure-led exploration and appraisal drilling programs, the
number of commercially viable oil and natural gas discoveries made and the quantities of oil and natural gas discovered, the
speed with which we can bring such discoveries to production, our partners’ alignment with respect to capital plans, and the
actual cost of exploitation, exploration, appraisal and development of our oil and natural gas assets, and coverage of any claims
under our insurance policies.
Significant Sources of Capital
Facility
The Facility supports our oil and gas exploration, appraisal and development programs and corporate activities. The
amount of funds available to be borrowed under the Facility, also known as the borrowing base amount, is determined every
March and September. The borrowing base amount is based on the sum of the net present values of net cash flows and relevant
capital expenditures reduced by certain percentages as well as value attributable to certain assets’ reserves and/or resources in
the Jubilee and TEN fields in Ghana and the Ceiba and Okume fields in Equatorial Guinea, however, excludes the additional
interests in Jubilee and TEN acquired in the October 2021 acquisition of Anadarko WCTP.
In October 2022, during the Fall 2022 redetermination, the Company’s lending syndicate approved a borrowing base
of approximately $1.24 billion. As of December 31, 2022, borrowings under the Facility totaled $625.0 million and the
undrawn availability under the facility was $618.0 million. On November 23, 2022, the Company amended the Facility to
update the interest rate benchmark from LIBOR to term SOFR, to be effective as of April 19, 2023.
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,
2022, we had no letters of credit issued under the Facility. We have the right to cancel all the undrawn commitments under the
amended and restated Facility.
If an event of default exists under the Facility, the lenders can accelerate the maturity and exercise other rights and
remedies, including the enforcement of security granted pursuant to the Facility over certain asset. We were in compliance with
the financial covenants contained in the Facility as of September 30, 2022 (the most recent assessment date). The Facility
contains customary cross default provisions.
Corporate Revolver
On March 31, 2022, we refinanced the Corporate Revolver by replacing it with a new revolving credit facility
agreement resulting in the following changes to the terms:
•
•
•
•
•
The total size of the Corporate Revolver is reduced from $400 million to $250 million.
The maturity date is extended from May 2022 to December 31, 2024.
Borrowings under the Corporate Revolver now bear interest at a rate equal to SOFR administered by the Federal
Reserve Bank of New York plus a credit adjustment spread plus a 7.0% margin plus mandatory costs, if
applicable.
Addition of a negative pledge covenant over the participating interests held by the Company’s wholly-owned
subsidiary, Kosmos Energy Ghana Investments, in the WCTP and DT blocks offshore Ghana.
As the Corporate Revolver is intended to continue to largely remain undrawn, the Company is required to use the
proceeds from any capital markets and loan transactions to first repay any drawn outstanding balance under the
Corporate Revolver and the Company is subject to a cash sweep of at least 50% of the Company’s Excess Cash
(as defined in the Corporate Revolver) to pay outstanding balances, if any, as of March 31 or September 30 in any
calendar year.
76
The Corporate Revolver is available for general corporate purposes and for oil and gas exploration, appraisal and
development programs. The Company expects the reduced Corporate Revolver size to offset an increase in the margin, resulting
in slightly lower interest expenses going forward. On November 23, 2022, the Company amended the Corporate Revolver to
update the interest rate benchmark from compounded SOFR to term SOFR, to be effective as of April 19, 2023, and to reflect
that The Standard Bank of South Africa Limited has been appointed as the new Facility Agent. As of December 31, 2022, there
were no outstanding borrowings under the Corporate Revolver and the undrawn availability was $250.0 million.
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 contained in the Corporate Revolver as of September 30, 2022
(the most recent assessment date). The Corporate Revolver contains customary cross default provisions.
The U.S. and many foreign economies continue to experience uncertainty driven by varying macroeconomic
conditions. Although some of these economies have shown signs of improvement, macroeconomic recovery remains uneven.
Uncertainty in the macroeconomic environment and associated global economic conditions have resulted in extreme volatility
in credit, equity, and foreign currency markets, including the European sovereign debt markets and volatility in various other
markets. If any of the financial institutions within our Facility or Corporate Revolver are unable to perform on their
commitments, our liquidity could be impacted. We actively monitor all of the financial institutions participating in our Facility
and Corporate Revolver. None of the financial institutions have indicated to us that they may be unable to perform on their
commitments. In addition, we periodically review our banking and financing relationships, considering the stability of the
institutions and other aspects of the relationships. Based on our monitoring activities, we currently believe our banks will be
able to perform on their commitments.
Senior Notes
We have three series of senior notes outstanding, which we collectively referred to as the “Senior Notes.” Our 7.125%
Senior Notes mature on April 4, 2026, and interest is payable on the 7.125% Senior Notes each April 4 and October 4. Our
7.500% Senior Notes mature on March 1, 2028, and interest is payable on the 7.500% Senior Notes each March 1 and
September 1. Our 7.750% Senior Notes mature on May 1, 2027, and interest is payable on the 7.750% Senior Notes each May 1
and November 1.
The Senior Notes are senior, unsecured obligations of Kosmos Energy Ltd. and rank equally in right of payment with
all of its existing and future senior indebtedness (including all borrowings under the Corporate Revolver) and rank effectively
junior in right of payment to all of its existing and future secured indebtedness (including all borrowings under the Facility and
the GoM Term Loan). The Senior Notes are jointly and severally guaranteed on a senior, unsecured basis by certain subsidiaries
owning the Company's U.S. Gulf of Mexico assets and the interests acquired in the Anadarko WCTP Acquisition, and on a
subordinated, unsecured basis by entities that borrow under, or guarantee, our Facility.
GoM Term Loan
In September 2020, the Company entered into a five-year $200 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, 2022, borrowings under the GoM Term Loan totaled $145
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.
77
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,
2023
2024
2025
2026
2027
Thereafter
Total
2022
Fixed rate debt:
7.125% Senior Notes
7.750% Senior Notes
7.500% Senior Notes
Variable rate debt:
$ —
$
—
—
$
—
—
—
—
—
—
(In thousands, except percentages)
$ 650,000
$
—
$
400,000
—
—
—
450,000
—
—
$ 650,000 $
558,201
400,000
450,000
335,592
361,958
Weighted average interest rate
8.81 %
8.71 %
8.35 %
8.46 %
8.68 %
— %
Facility(1)
GoM Term Loan
$ —
$
—
$ 177,548
$ 268,880
$ 178,572
$
30,000
30,000
85,000
—
—
—
—
$ 625,000 $
625,000
145,000
145,000
Total principal debt repayments (1)
$ 30,000
$ 30,000
$ 262,548
$ 918,880
$ 578,572
$ 450,000
$ 2,270,000
Interest & commitment fees on long-
term debt
199,756
185,465
163,115
115,704
53,124
16,875
Operating leases(2)
4,032
4,104
Purchase obligations(3)
68,198
34,976
4,175
—
4,246
—
4,192
—
6,652
—
734,039
27,401
103,174
______________________________________
(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, 2022. 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.
Represents gross contractual obligations to execute planned future capital projects. Other joint owners in the properties
operated by Kosmos will be billed for their working interest share of such costs. Does not include our share of
operator’s purchase commitments for jointly owned fields and facilities where we are not the operator and excludes
commitments for exploration activities, including well commitments and seismic obligations, in our petroleum
contracts. The Company's liabilities for asset retirement obligations associated with the dismantlement, abandonment
and restoration costs of oil and gas properties are not included. See Note 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 three development wells and one exploration well in Equatorial Guinea. In
Mauritania and Senegal, we have 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 companies’ share of certain development
costs. Kosmos’ total share for the two agreements combined is currently estimated at approximately $240.0 million, of which
$196.9 million has been incurred through December 31, 2022, excluding accrued interest. These amounts will be repaid through
the national oil companies’ share of future revenues.
78
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, 2022 and 2021, 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, 2022 and 2021,
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;
79
• 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
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,
80
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.
The following table reconciles the changes that occurred in fair values of our open derivative contracts during the year
ended December 31, 2022:
Fair value of contracts outstanding as of December 31, 2021
Changes in contract fair value
Contract maturities
Fair value of contracts outstanding as of December 31, 2022
Commodity Price Risk
Derivative Contracts
Assets (Liabilities)
Commodities
(In thousands)
$
$
(66,315)
(275,465)
344,468
2,688
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
81
are indexed against Dated Brent and Heavy Louisiana Sweet. Oil prices during 2022 ranged between $76.36 and $137.64 per
Bbl for Dated Brent, with Heavy Louisiana Sweet experiencing similar volatility during 2022.
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, 2022. Volumes and weighted average prices are net of any offsetting derivatives entered into.
Term
2023:
Type of Contract
Index
MBbl
Weighted Average Price per Bbl
Net
Deferred
Premium
Payable/
(Receivable)
Sold Put
Floor
Ceiling
Jan — Dec
Jan — Dec
Three-way collars
Dated Brent
6,000 $
1.34 $ 49.17 $ 71.67 $ 107.58
Two-way collars
Dated Brent
4,000
1.90
—
72.50
117.50
______________________________________
(1) Fair values are based on the average forward oil prices on December 31, 2022.
Asset (Liability)
Fair Value at
December 31,
2022(1)
(In thousands)
(2,975)
4,492
In January 2023, we entered into Dated Brent three-way collar contracts for 1.0 MMBbl from January 2024 through
December 2024 with a sold put price of $45.00 per barrel, a floor price of $70.00 per barrel and a ceiling price of $100.00 per
barrel.
At December 31, 2022, our open commodity derivative instruments were in a net asset position of $1.5 million. As of
December 31, 2022, a hypothetical 10% price increase in the commodity futures price curves would decrease future pre-tax
earnings by approximately $30.8 million. Similarly, a hypothetical 10% price decrease would increase future pre-tax earnings
by approximately $31.1 million.
Interest Rate Sensitivity
Changes in market interest rates affect the amount of interest we pay on certain of our borrowings. Outstanding
borrowings under the Facility, Corporate Revolver and GoM Term Loan, which as of December 31, 2022 total approximately
$770.0 million and have a weighted average interest rate of 8.3%, 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 $3.6 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.
82
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
84
88
89
90
91
92
123
83
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,
2022 and 2021, the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the three
years in the period ended December 31, 2022, 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, 2022 and 2021, and the results
of its operations and its cash flows for each of the three years in the period ended December 31, 2022, 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, 2022, 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, 2023 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.
84
Description
of the
Matter
Depletion of oil and gas properties, net
At December 31, 2022, the net book value of the Company’s oil and gas properties, net was $3.8 billion,
and depletion expense was $471.4 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
historical production, 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, 2022.
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 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. We
evaluated the completeness, accuracy, relevance, and reliability, as applicable, of the inputs described
above used by the independent reserve engineers in estimating proved oil and natural gas reserves by
agreeing them to source documentation or performing analytical procedures based on review of
corroborative evidence and consideration of any 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.
Asset Retirement Obligations
Description
of the
Matter
At December 31, 2022, the Company’s asset retirement obligations totaled $302.5 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, 2022.
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.
85
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 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.
Description
of the
Matter
Impairment of long-lived assets
As described in Note 5 to the consolidated financial statements, the Company recorded an impairment of
$450.0 million during the year ended December 31, 2022 related to certain oil and gas proved properties.
A year-end reserve revision triggered an assessment of these long-lived assets for impairment. The
Company evaluated this long-lived asset group and determined the carrying value was not recoverable
through the estimated undiscounted future cash flows. As a result, the Company recognized an
impairment, which is the amount by which the asset group’s carrying value exceeded its estimated fair
value.
Auditing the Company’s discounted cash flows used to measure impairment was complex and judgmental
as the determination of fair value was based on future production, pricing estimates, capital and operating
costs, market-based weighted average cost of capital, and risk adjustment factors.
How We
Addressed
the Matter
in Our Audit
We obtained an understanding, evaluated the design, and tested the operating effectiveness of controls
over the Company's process to determine the fair value of the asset group and measure the impairment.
This included controls over management's review of the significant assumptions underlying the fair value
determination and of the completeness and accuracy of the data used in the determination of the fair
value.
Our audit procedures included, among others, evaluating the significant assumptions and testing the
completeness and accuracy of underlying data used in the calculation of the fair value. We evaluated the
professional qualifications and objectivity of the engineering specialist primarily responsible for the
preparation of the estimated proved reserves used in the valuation. We involved valuation specialists to
assist in our evaluation of the valuation methodologies applied and the significant assumptions used to
determine the fair value of the asset group, including the discount rate, risk adjustment factors, and
forward-looking commodity prices.
/s/ Ernst & Young LLP
We have served as the Company’s auditor since 2004.
Dallas, Texas
February 28, 2023
86
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, 2022, 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, 2022, 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, 2022 and 2021, the related consolidated statements of operations,
shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2022, and the related notes and financial
statement schedules listed in the Index at Item 15(a) and our report dated February 28, 2023 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, 2023
87
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 $13,263 and $19,912 at December 31, 2022 and
December 31, 2021, respectively
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, 2022 and
December 31, 2021
Common stock, $0.01 par value; 2,000,000,000 authorized shares; 500,161,421 and 496,152,331 issued at
December 31, 2022 and December 31, 2021, respectively
Additional paid-in capital
Accumulated deficit
Treasury stock, at cost, 44,263,269 shares at December 31, 2022 and December 31, 2021, respectively
Total stockholders’ equity
Total liabilities and stockholders’ equity
See accompanying notes.
88
December 31,
2022
2021
$
183,405 $
—
28,851
67,483
23,401
133,515
24,722
7,344
468,721
131,620
42,971
36,908
134,004
6,614
165,247
18,899
5,689
541,952
3,837,437
5,210
3,842,647
4,177,323
6,664
4,183,987
3,416
235,696
4,640
1,725
23,143
305
191,150
1,090
1,026
21,141
$
4,579,988 $
4,940,651
$
212,275 $
325,206
30,000
6,773
574,254
184,403
250,670
30,000
65,879
530,952
2,195,911
2,590,495
778
300,800
468,445
251,952
6,298
322,237
711,038
250,394
3,217,886
3,880,462
—
—
5,002
2,505,694
(1,485,841)
(237,007)
787,848
4,579,988 $
$
4,962
2,473,674
(1,712,392)
(237,007)
529,237
4,940,651
KOSMOS ENERGY LTD.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
Years Ended December 31,
2022
2021
2020
Revenues and other income:
Oil and gas revenue
Gain on sale of assets
Other income, net
$ 2,245,355 $ 1,332,013 $ 804,033
92,163
50,471
1,564
3,949
262
2
Total revenues and other income
2,299,775
1,333,839
896,198
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
403,056
346,006
338,477
6,243
134,230
100,856
498,256
449,969
118,260
260,892
(1,586)
65,382
91,529
467,221
—
128,371
270,185
(9,054)
10,111
13,161
84,616
72,142
485,862
153,959
109,794
17,180
37,802
Total costs and expenses
1,962,708
1,377,219
1,312,993
Income (loss) before income taxes
Income tax expense (benefit)
Net income (loss)
Net income (loss) per share:
Basic
Diluted
Weighted average number of shares used to compute net income (loss) per share:
Basic
Diluted
337,067
110,516
(43,380)
(416,795)
34,456
(5,209)
$ 226,551 $
(77,836) $ (411,586)
$
$
0.50 $
0.48 $
(0.19) $
(0.19) $
(1.02)
(1.02)
455,346
474,857
416,943
416,943
405,212
405,212
Dividends declared per common share
$
— $
— $
0.0452
See accompanying notes.
89
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, 2019
445,779 $
4,458 $ 2,297,221 $ (1,222,970) $
Dividends ($0.0452 per share)
Equity-based compensation
Restricted stock 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 units
Tax withholdings on restricted stock units
Net loss
Balance as of December 31, 2021
Dividends
Equity-based compensation
Restricted stock units
Tax withholdings on restricted stock units
Net income
Balance as of December 31, 2022
—
—
3,939
—
—
449,718
43,125
—
—
3,309
—
—
—
—
39
—
—
4,497
432
—
—
33
—
—
(18,576)
33,561
(39)
(4,947)
—
—
—
—
—
(411,586)
(237,007) $
—
—
—
—
—
2,307,220
(1,634,556)
(237,007)
135,574
227
31,786
(33)
(1,100)
—
—
—
—
—
(77,836)
—
—
—
—
—
841,702
(18,576)
33,561
—
(4,947)
(411,586)
440,154
136,006
227
31,786
—
(1,100)
(77,836)
496,152
4,962
2,473,674
(1,712,392)
(237,007)
529,237
—
—
4,009
—
—
—
—
40
—
—
(39)
34,852
(40)
(2,753)
—
—
—
—
—
226,551
—
—
—
—
—
(39)
34,852
—
(2,753)
226,551
500,161 $
5,002 $ 2,505,694 $ (1,485,841) $
(237,007) $
787,848
See accompanying notes.
90
KOSMOS ENERGY LTD.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Years Ended December 31,
2021
2020
2022
$
226,551 $
(77,836) $
(411,586)
508,657
(197,487)
86,941
449,969
275,465
(344,468)
34,546
(50,471)
192
(10,099)
68,829
10,335
(11,039)
3,724
78,831
1,130,476
(787,297)
(22,078)
168,703
(63,183)
(703,855)
—
(405,000)
—
—
—
(2,753)
(655)
(6,288)
(414,696)
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
11,925
174,896
186,821 $
25,132
149,764
174,896 $
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
(79,582)
229,346
149,764
85,791 $
247,889 $
91,032 $
137,421 $
103,674
104,061
— $
— $
50,000
Operating activities
Net income (loss)
Adjustments to reconcile net income (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 $(327.9) million and $(224.4) million
and $(2.7) million on commodity hedges during 2022, 2021, and 2020)
Equity-based compensation
Gain on sale of assets
Loss on extinguishment of debt
Other
Changes in assets and liabilities:
(Increase) decrease in receivables
(Increase) decrease in inventories
(Increase) 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
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.
$
$
$
$
91
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
offshore Atlantic Margins. Our key assets include production offshore Ghana, Equatorial Guinea and the U.S. Gulf of Mexico,
as well as world-class gas projects offshore Mauritania and Senegal. We also pursue a proven basin exploration program in
Equatorial Guinea and the U.S. Gulf of Mexico. Kosmos is listed on the NYSE and LSE and is traded under the ticker symbol
KOS.
Kosmos is engaged in a single line of business, which is the exploration, development, and production of oil and
natural gas. Substantially all of our long-lived assets and all of our product sales are related to operations in four geographic
areas: Ghana, Equatorial Guinea, Mauritania/Senegal and the U.S. Gulf of Mexico.
2. Accounting Policies
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 income (loss), current assets, total assets, current liabilities, total
liabilities, shareholders’ equity or cash flows.
92
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,
2022
2021
2020
(In thousands)
$
183,405 $
—
131,620 $
42,971
3,416
305
149,027
195
542
$
186,821 $
174,896 $
149,764
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. As of March 31, 2022, our net leverage ratio was below 2.50x, therefore in May 2022, we
released $59.1 million from restricted cash upon submission of the net leverage test as of March 31, 2022. As of December, 31,
2022 our net leverage ratio remained below 2.50x.
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 $7.0 million and $5.2 million in current joint interest billings
receivables as of December 31, 2022 and 2021, respectively.
Inventories
Inventories consisted of $125.3 million and $149.5 million of materials and supplies and $8.2 million and $15.7
million of hydrocarbons as of December 31, 2022 and 2021, 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 $1.5 million, $1.2 million and $8.6 million during the years ended December 31,
2022, 2021 and 2020 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
93
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.
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.
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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;
95
• 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, 2022 and 2021, 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:
Revenues from contract with customer - Equatorial Guinea
$
349,443 $
257,628 $
Revenues from contract with customer - Ghana
Revenues from contract with customers - U.S. Gulf of Mexico
1,362,875
547,610
654,644
427,261
149,033
375,603
285,017
Years Ended December 31,
2022
2021
2020
(In thousands)
Provisional oil sales contracts
Oil and gas revenue
Equity-based Compensation
(14,573)
(7,520)
(5,620)
$
2,245,355 $
1,332,013 $
804,033
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, 2022, 2021 and 2020, we
recognized zero, $2.6 million and $16.5 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.
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.
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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, Russia’s invasion of Ukraine, a potential global recession, and other
varying macroeconomic conditions 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
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 amended effective October 5, 2022 by ASU 2022-06, “Reference Rate Reform
(Topic 848): Deferral of the Sunset Date of Topic 848, to extend the sunset date of Topic 848 and can be applied prospectively
through December 31, 2024. 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
2022 Transactions
In March 2022, Kosmos completed the acquisition of an additional 5.5% interest in Winterfell area in Green Canyon
Blocks 943, 944, 987 and 988, offshore U.S. Gulf of Mexico, and an additional 1.5% interest in Green Canyon blocks 899 and
900 for $9.6 million. Additionally, in September 2022, Kosmos completed the acquisition of an additional 3.2% interest in the
Winterfell area in Green Canyon Blocks 943, 944, 987 and 988 and an additional 1.4% interest in Green Canyon Blocks 899
and 900 for $6.6 million. As a result of the two transactions, our participating interests in the Green Canyon Blocks 943, 944,
987 and 988 is now 25.0% and our participating interests in the Green Canyon Blocks 899 and 900 is 37.8%.
In May 2022, Kosmos and its joint venture partners agreed with the Ministry of Mines and Hydrocarbons of Equatorial
Guinea to extend the Block G petroleum contract term harmonizing the expiration of the Ceiba Field and Okume Complex
production licenses (from 2029 and 2034 respectively) to 2040. As part of the extension, during the second quarter of 2022,
Kosmos paid a signature bonus and agreed to undertake a work program including the drilling of three development wells on
Block G in either the Ceiba Field or Okume Complex and the drilling of one exploration well in Block S offshore Equatorial
Guinea.
In June 2022, Kosmos completed the acquisition of an additional 5.9% interest in the Kodiak oil field from Marubeni
by exercising our preferential right to purchase for a total purchase price of approximately $29.0 million. The purchase price
was based on an initial purchase price of $38.3 million reduced by certain purchase adjustments totaling approximately
$9.3 million. The purchase price allocation was based on the estimated fair value of identifiable assets acquired and liabilities
assumed primarily comprised of $27.1 million of oil and gas properties, net. As a result of the transaction, our working interest
increased from 29.1% to 35.0%.
In June 2022, at the conclusion of the second exploration period, Block C12 offshore Mauritania was relinquished.
In October 2022, we entered into a farm-out agreement with Panoro Energy ASA (Panoro) to farm-out a 6.0%
participating interest in Block S offshore Equatorial Guinea, which will result in our participating interest in Block S reducing
97
to 34.0%, in exchange for cash consideration totaling approximately $1.8 million. The transaction is awaiting governmental
approvals.
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%.
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. The purchase price allocation was based on the estimated fair value of identifiable assets acquired and liabilities assumed.
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, $104.4 million of revenues and $10.3 million of direct operating
expenses have been included in our consolidated statements of operations for the period from October 13, 2021 to December
31, 2021.
Under the DT Block Joint Operating Agreement, certain joint venture partners have pre-emption rights in the Jubilee
Unit Area and the TEN fields. In November 2021, we received notice from Tullow Oil plc (“Tullow”) and PetroSA that they
were exercising their pre-emption rights in relation to Kosmos’ acquisition of Anadarko WCTP. After execution of definitive
transaction documentation and receipt of government approvals, Kosmos concluded the pre-emption transaction with Tullow in
March 2022. Following the completion of the pre-emption process, Kosmos’ interest in the Jubilee Unit Area decreased from
42.1% to 38.6% and Kosmos’ interest in the TEN fields decreased from 28.1% to 20.4%. Tullow paid Kosmos $118.2 million
in cash consideration after post closing adjustments for the pre-emption. During the first quarter of 2022, our oil and gas
properties, net balance was reduced by $175.5 million, which includes the cash proceeds and net liabilities transferred to the
purchaser as a result of concluding the Tullow pre-emption transaction. The difference in the net book value of the proved
98
property, net liabilities transferred and adjusted purchase price qualified for treatment as a recovery of cost and normal
retirement under ASC 932, which resulted in no gain or loss being recognized.
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 for the year ended December
31, 2020. 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 is 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. During the fourth quarter of 2022, we received formal notice from Shell that an appraisal plan for one of the
first four exploration wells had been submitted under the terms of Shell’s Petroleum Agreement with Namibia. As a result, we
received additional proceeds of $50.0 million in the fourth quarter of 2022 related to the transaction with Shell resulting in Gain
on sale of assets of $50.0 million for the year ended December 31, 2022.
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.
In July 2020, we provided notice that we declined to enter the final exploration phase of the Suriname Block 45
petroleum agreement.
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, 2022 and 2021, the current portion of the joint interest billing receivables due from GNPC for the TEN fields' development
costs were $6.4 million and $7.9 million, respectively, and the long-term portions were $17.3 million and $20.9 million.
Notes Receivable
In February 2019, Kosmos and BP signed Carry Advance Agreements with the national oil companies of Mauritania
and Senegal obligating us to finance a portion of the respective national oil companies’ share of certain development costs
incurred through first gas production for Greater Tortue Ahmeyim Phase 1, currently targeted to be in the fourth 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, 2022 and 2021, the
balance due from the national oil companies including interest was $218.4 million and $145.2 million, respectively, which is
classified as Long-term receivables in our consolidated balance sheets. Interest income on the long-term notes receivable was
$10.1 million, $7.1 million and $3.8 million for the years ended December 31, 2022, 2021 and 2020, 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
99
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 targeted to be in the fourth 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 Greater Tortue FPSO.
As of December 31, 2022, this Long-term receivable has been non-cash settled against obligations payable to BP Operator,
which included $132.4 million and $67.8 million of non-cash capital expenditures during the fourth quarter of 2021 and the first
quarter of 2022, respectively. These non-cash impacts are excluded from the statement of cash flows.
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,
2022
2021
(In thousands)
$
6,953,435 $
341,334
7,294,769
(3,457,332)
3,837,437
6,725,453
451,454
7,176,907
(2,999,584)
4,177,323
60,730
(55,520)
5,210
58,598
(51,934)
6,664
$
3,842,647 $
4,183,987
We recorded depletion expense of $471.4 million, $442.3 million and $460.9 million and depreciation expense of $3.6
million, $3.9 million and $5.5 million for the years ended December 31, 2022, 2021 and 2020, respectively. In connection with
fair value assessments for oil and gas proved properties, we recorded long-lived asset impairments of $450.0 million related to
the TEN Fields in Ghana, zero and $154.0 million related to oil and gas proved properties in the U.S. Gulf of Mexico during the
years ended December 31, 2022, 2021 and 2020, respectively, in our consolidated statement of operations. Additionally, during
the year ended December 31, 2022, our oil and gas properties, net balance was reduced by $175.5 million as a result of
concluding the Tullow pre-emption transaction in March 2022, $64.2 million as a result of the write-off of previously
capitalized costs related to the BirAllah and Orca discoveries incurred under the C8 license to exploration expense, offset by
additions of $53.1 million related to the acquisition of an additional working interest in the Kodiak oil field, the extension of the
Block G licenses in Equatorial Guinea, and the acquisitions of additional participating interests in the Winterfell area. See Note
3 — Acquisitions and Divestitures and Note 6 — Suspended Well Costs.
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, 2022, 2021 and 2020.
100
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(2)
Ending balance
______________________________________
Years Ended December 31,
2021
2020
2022
(In thousands)
$
218,180 $
186,289 $
445,790
25,209
(34,614)
(62,818)
145,957 $
31,891
—
—
218,180 $
4,001
(263,502)
—
186,289
$
(1)
(2)
Activity for the year ended December 31, 2022 represents the reclassification of exploratory well costs associated with
the Winterfell discovery in Green Canyon Block 944 in the U.S. Gulf of Mexico. Activity for the year ended
December 31, 2020 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.
Represents the impairment of exploratory well costs associated with the BirAllah and Orca Discoveries as a result of
the expiration of the exploration period of Block C8 in June 2022.
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:
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
2022
(In thousands, except well counts)
$
$
— $
32,770
113,187
145,957 $
20,903 $
30,389
166,888
218,180 $
—
66,573
119,716
186,289
2
3
3
As of December 31, 2022, the projects with exploratory well costs capitalized for more than one year since the
completion of drilling are related to the Yakaar and Teranga discoveries in the Cayar Offshore Profond block offshore Senegal
and the Asam discovery in Block S offshore Equatorial Guinea.
Yakaar and Teranga Discoveries — In May 2016, we 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. In July 2021, the current phase of the Cayar Block exploration license was extended up to
an additional three years to 2024. The Yakaar and Teranga discoveries are being analyzed as a joint development. During 2022,
we have continued progressing appraisal studies and maturing the first phase development concept design. Following additional
evaluation, a decision regarding commerciality is expected to be made.
Asam Discovery - In October 2019, we completed the S-5 exploration well offshore Equatorial Guinea, which
encountered hydrocarbon pay. The discovery was subsequently named Asam. In July 2020, an appraisal work program was
approved by the Government of Equatorial Guinea. The well is located within tieback range of the Ceiba FPSO and the
appraisal work program is currently ongoing to integrate all available data into models to establish the scale of the discovered
resource and evaluate the optimum development solution. During the fourth quarter of 2022, we received approval from the
Government of Equatorial Guinea to enter the second sub-period phase of the Block S exploration license with a scheduled
expiration in December 2024. Engineering has continues to progress concepts around required subsea infrastructure necessary
for a subsea tieback. Additionally, in December 2022 the Asam field appraisal report was submitted to the Government of
Equatorial Guinea. Following additional evaluation, a decision regarding commerciality will be made.
101
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, 2022 and 2021 is as follows:
Operating lease cost
Variable lease cost
Short-term lease cost(1)
Total lease cost
__________________________________
December 31,
2022
2021
(In thousands)
3,882 $
1,825
13,970
19,677 $
3,971
1,780
10,790
16,541
$
$
(1)
Includes $12.5 million and $9.4 million during the years ended December 31, 2022 and 2021, respectively, of costs
associated with short-term drilling contracts.
Other information related to operating leases at December 31, 2022 and 2021, 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
2022
2021
(In thousands, except lease term and discount rate)
$
16,044
$
2,181
18,007
17,578
1,905
20,351
Weighted average remaining lease term
6.5 years
7.5 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,
2022 and 2021:
Operating cash flows for operating leases
Investing cash flows for operating leases(1)
__________________________________
(1)
Represents costs associated with short-term drilling contracts.
December 31,
2022
2021
$
(In thousands)
7,170 $
12,449
6,460
9,350
102
Future minimum rental commitments under our leases at December 31, 2022, are as follows:
2023
2024
2025
2026
2027
Thereafter
Total undiscounted lease payments
Less: Imputed interest
Total lease liabilities
__________________________________
Operating Leases(1)
(In thousands)
$
$
$
4,032
4,104
4,175
4,246
4,192
6,652
27,401
(7,213)
20,188
(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.
8. Debt
Outstanding debt principal balances:
Facility
7.125% Senior Notes
7.750% Senior Notes
7.500% Senior Notes
GoM Term Loan
Total long-term debt
Unamortized deferred financing costs and discounts(1)
Total debt, net
Less: Current maturities of long-term debt
Long-term debt, net
________________________________________
December 31,
2022
2021
(In thousands)
$
625,000 $
650,000
400,000
450,000
145,000
2,270,000
(44,089)
2,225,911
(30,000)
2,195,911 $
$
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)
Includes $25.2 million and $31.0 million of unamortized deferred financing costs related to the Facility; $16.7 million and $20.2
million of unamortized deferred financing costs and discounts related to the Senior Notes; and $2.2 million and $3.3 million of
unamortized deferred financing costs related to the GoM Term Loan as of December 31, 2022 and December 31, 2021,
respectively.
Facility
The Facility supports our oil and gas exploration, appraisal and development programs and corporate activities. The
amount of funds available to be borrowed under the Facility, also known as the borrowing base amount, is determined every
March and September. The borrowing base amount is based on the sum of the net present values of net cash flows and relevant
capital expenditures reduced by certain percentages as well as value attributable to certain assets’ reserves and/or resources in
the Jubilee and TEN fields in Ghana and the Ceiba and Okume fields in Equatorial Guinea, however, the additional interests in
Jubilee and TEN acquired in the October 2021 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 part of this amendment to the Facility in May 2021, the Company incurred $15.2 million for loss on extinguishment of debt
during the year ended December 31, 2021. During the year ended December 31, 2022, the Company made principal repayments
totaling $375.0 million on the Facility. In April 2022, during the Spring 2022 redetermination, the Company’s lending
103
syndicate approved a borrowing base capacity in excess of the facility size of $1.25 billion. In October 2022, during the Fall
2022 redetermination, the Company’s lending syndicate approved a borrowing base of approximately $1.24 billion. On
November 23, 2022, the Company amended the Facility to update the interest rate benchmark from LIBOR to term SOFR, to be
effective as of April 19, 2023. As of December 31, 2022, borrowings under the Facility totaled $625.0 million and the undrawn
availability under the facility was $618.0 million.
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. As of March 31,
2022, our net leverage ratio was below 2.50x, and therefore, we released $59.1 million from restricted cash in May 2022 upon
submission of the net leverage test as of March 31, 2022. As of December, 31, 2022 our net leverage ratio remained below
2.50x.
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. Effective April 19, 2023, interest on the Facility will be the
aggregate of the applicable margin (3.75% to 5.00%, depending on the length of time that has passed from the date the Facility
was entered into), plus the term SOFR reference rate administered by CME Group Benchmark Administration Limited for the
relevant period published and a credit adjustment spread. Interest is payable on the last day of each interest period (and, if the
interest period is longer than six months, on the dates falling at six-month intervals after the first day of the interest period). We
pay commitment fees on the undrawn and unavailable portion of the total commitments, if any. Commitment fees are equal to
30% per annum of the then-applicable respective margin when a commitment is available for utilization and, equal to 20% per
annum of the then-applicable respective margin when a commitment is not available for utilization. We recognize interest
expense in accordance with ASC 835—Interest, which requires interest expense to be recognized using the effective interest
method. We determined the effective interest rate based on the estimated level of borrowings under the Facility.
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,
2022, we had no letters of credit issued under the Facility. We have the right to cancel all the undrawn commitments under the
amended and restated Facility.
If an event of default exists under the Facility, the lenders can accelerate the maturity and exercise other rights and
remedies, including the enforcement of security granted pursuant to the Facility over certain assets held by our subsidiaries. We
were in compliance with the financial covenants below contained in the Facility as of September 30, 2022 (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 through March 31, 2024 and 1.30x
after March 31, 2024; 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 3.50x as amended.
The Facility contains customary cross default provisions.
Corporate Revolver
On March 31, 2022, we refinanced the Corporate Revolver by replacing it with a new revolving credit facility
agreement resulting in the following changes to the terms:
•
•
•
The total size of the Corporate Revolver is reduced from $400 million to $250 million.
The maturity date is extended from May 2022 to December 31, 2024.
Borrowings under the Corporate Revolver now bear interest at a rate equal to SOFR administered by the Federal
Reserve Bank of New York plus a credit adjustment spread plus a 7.0% margin plus mandatory costs, if
applicable.
104
•
•
Addition of a negative pledge covenant over the participating interests held by the Company’s wholly-owned
subsidiary, Kosmos Energy Ghana Investments, in the WCTP and DT blocks offshore Ghana.
As the Corporate Revolver is intended to continue to largely remain undrawn, the Company is required to use the
proceeds from any capital markets and loan transactions to first repay any drawn outstanding balance under the
Corporate Revolver and the Company is subject to a cash sweep of at least 50% of the Company’s Excess Cash
(as defined in the Corporate Revolver) to pay outstanding balances, if any, as of March 31 or September 30 in any
calendar year.
The Company capitalized $6.1 million of deferred financing costs associated with entering into the new revolving
credit facility, which will be amortized over the term of the new revolving credit facility. On November 23, 2022, the Company
amended the Corporate Revolver to update the interest rate benchmark from compounded SOFR to term SOFR, to be effective
as of April 19, 2023, and to reflect that The Standard Bank of South Africa Limited has been appointed as the new Facility
Agent. As of December 31, 2022, there were no outstanding borrowings under the Corporate Revolver and the undrawn
availability was $250.0 million The Corporate Revolver is available for general corporate purposes and for oil and gas
exploration, appraisal and development programs.
Interest accrues at a rate equal to the SOFR administered by the Federal Reserve Bank of New York plus a credit
adjustment spread plus a 7.0% margin plus mandatory costs, if applicable. Effective April 19, 2023, interest on the Corporate
Revolver will be the aggregate of a 7.0% margin, the term SOFR reference rate administered by CME Group Benchmark
Administration Limited for the relevant period published and a credit adjustment spread. Interest is payable on the last day of
each interest period (and, if the interest period is longer than six months, on the dates falling at six-month intervals after the first
day of the interest period). We pay commitment fees 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 December 31, 2024. The available amount is not subject to borrowing base
constraints. We have the right to cancel all the undrawn commitments under the Corporate Revolver. We are required to repay
certain amounts due under the Corporate Revolver with sales of certain subsidiaries or sales of certain assets. If an event of
default exists under the Corporate Revolver, the lenders can accelerate the maturity and exercise other rights and remedies,
including the enforcement of security granted pursuant to the Corporate Revolver over certain assets held by us.
We were in compliance with the financial covenants below contained in the Corporate Revolver as of September 30,
2022 (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 3.50x as amended.
The Corporate Revolver contains customary cross default provisions.
7.125% Senior Notes due 2026
In April 2019, the Company issued $650.0 million of 7.125% Senior Notes and received net proceeds of
approximately $640.0 million after deducting commissions and other expenses. We used the net proceeds to redeem all of the
previously issued 7.875% Senior Secured Notes due 2021, 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. The 7.125% Senior Notes contain customary cross
default provisions.
105
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
$400.0 million Bridge Notes (which were issued during the fourth quarter of 2021 in connection with the completion of the
acquisition of Anadarko WCTP) 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. The 7.750% Senior Notes contain customary cross default provisions.
106
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 in the Anadarko WCTP acquisition, and on a subordinated, unsecured
basis by certain subsidiaries that borrow under, or guarantee, the Facility and that guarantee the Corporate Revolver, and the
7.125% Senior Notes and the 7.750% Senior Notes. The 7.500% Senior Notes contain customary cross default provisions.
107
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.
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 GoM Term Loan bears interest at an effective rate of approximately 6.9% per
annum and matures in 2025, with quarterly principal repayments having started in the fourth quarter of 2021. As of
December 31, 2022, $30.0 million of the total $145 million outstanding under the GoM Term Loan have been classified within
Current maturities of long-term debt on our consolidated balance sheet.
The GoM Term Loan contains customary affirmative and negative covenants, including covenants that affect our
ability to incur additional indebtedness, create liens, merge, dispose of assets, and make distributions, dividends, investments or
capital expenditures, among other things. The GoM Term Loan is guaranteed on a senior, secured basis by certain subsidiaries
owning the Company's U.S. Gulf of Mexico assets.
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.
We were in compliance with the covenants, representations and warranties contained in the GoM Term Loan as of
September 30, 2022 (the most recent assessment date). The GoM Term Loan contains customary cross default provisions.
108
At December 31, 2022, the estimated repayments of debt during the five fiscal year periods and thereafter are as
follows:
Principal debt
repayments(1)
Total
2023
2024
2025
2026
2027
Thereafter
Payments Due by Year
(In thousands)
$ 2,270,000 $
30,000 $
30,000 $ 262,548 $ 918,880 $ 578,572 $ 450,000
_______________________________________
(1)
Includes the scheduled maturities for outstanding principal debt balances. The scheduled maturities of debt related to the Facility as
of December 31, 2022 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,
2022
2021
2020
(In thousands)
$
180,046 $
146,706 $
119,857
10,401
192
10,580
19,625
9,347
2,902
(84,342)
(46,098)
(25,013)
(3,318)
(3,401)
(12,139)
(10,257)
27,420
11,216
2,402
(4,773)
5,072
Interest and other financing costs, net
$
118,260 $
128,371 $
109,794
Capitalized interest for the years ended December 31, 2022, 2021 and 2020 was $84.3 million, $46.1 million and
$25.0 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
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, 2022. Volumes and weighted average prices are
net of any offsetting derivative contracts entered into.
109
Term
Type of Contract
Index
MBbl
2023:
Weighted Average Price per Bbl
Net Deferred
Premium
Payable/
(Receivable)
Sold Put
Floor
Ceiling
Jan — Dec
Jan — Dec
Three-way collars
Two-way collars
Dated Brent
Dated Brent
6,000 $
4,000
1.34
1.90
$ 49.17 $ 71.67 $ 107.58
—
72.50
117.50
______________________________________
In January 2023, we entered into Dated Brent three-way collar contracts for 1.0 MMBbl from January 2024 through
December 2024 with a sold put price of $45.00 per barrel, a floor price of $70.00 per barrel and a ceiling price of $100.00 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, 2022 and 2021 and gain/(loss)
from derivatives during the years ended December 31, 2022, 2021 and 2020.
Type of Contract
Balance Sheet Location
2022
2021
(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
$
7,344 $
5,689
Receivables: Oil sales
Derivatives assets—long-term
1,170
1,725
(853)
1,026
Derivatives liabilities—current
(6,773)
(65,879)
Derivatives liabilities—long-term
(778)
(6,298)
Total derivatives not designated as hedging instruments
$
2,688 $
(66,315)
Amount of Gain/(Loss)
Years Ended December 31,
Type of Contract
Location of Gain/(Loss)
2022
2021
2020
(In thousands)
Derivatives not designated as hedging instruments:
Provisional oil sales
Commodity
Total derivatives not designated
as hedging instruments
Oil and gas revenue
Derivatives, net
$
(14,573) $
(260,892)
(7,520) $
(270,185)
(5,620)
(17,180)
$
(275,465) $
(277,705) $
(22,800)
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, 2022 and 2021, 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.
110
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, 2022 and 2021, for each fair value hierarchy level:
December 31, 2022
Assets:
Commodity derivatives
Provisional oil sales
Liabilities:
Commodity derivatives
Total
December 31, 2021
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)
$
$
$
$
— $
9,069 $
— $
—
—
— $
— $
—
—
— $
1,170
(7,551)
2,688 $
6,715 $
(853)
(72,177)
(66,315) $
—
—
— $
— $
—
—
— $
9,069
1,170
(7,551)
2,688
6,715
(853)
(72,177)
(66,315)
The book values of cash and cash equivalents and restricted cash approximate fair value based on Level 1 inputs. Joint
interest billings, oil sales and other receivables, and accounts payable and accrued liabilities approximate fair value due to the
short-term nature of these instruments. Our long-term receivables, after any allowances for credit losses, and other long-term
assets approximate fair value. The estimates of fair value of these items are based on Level 2 inputs.
111
Commodity Derivatives
Our commodity derivatives represent crude oil collars, put options and call options for notional barrels of oil at fixed
Dated Brent or NYMEX WTI oil prices. The values attributable to our oil derivatives are based on (i) the contracted notional
volumes, (ii) independent active futures price quotes for the respective index, (iii) a credit-adjusted yield curve applicable to
each counterparty by reference to the credit default swap (“CDS”) market and (iv) an independently sourced estimate of
volatility for the respective index. The volatility estimate was provided by certain independent brokers who are active in buying
and selling oil options and was corroborated by market-quoted volatility factors. The deferred premium is included in the fair
market value of the commodity derivatives. See Note 9—Derivative Financial Instruments for additional information regarding
the Company’s derivative instruments.
Provisional Oil Sales
The value attributable to 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.
Debt
The following table presents the carrying values and fair values at December 31, 2022 and 2021:
7.125% Senior Notes
7.750% Senior Notes
7.500% Senior Notes
GoM Term Loan
Facility
Total
December 31, 2022
December 31, 2021
Carrying Value
Fair Value
Carrying Value
Fair Value
(In thousands)
$
$
645,699 $
395,893
445,564
145,000
625,000
2,257,156 $
558,201 $
335,592
361,958
145,000
625,000
2,025,751 $
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
The carrying values of our 7.125% Senior Notes, 7.750% Senior Notes and 7.500% Senior Notes represent the
principal amounts outstanding less unamortized discounts. The fair values of our 7.125% Senior Notes, 7.750% Senior Notes
and 7.500% Senior Notes are based on quoted market prices, which results in a Level 1 fair value measurement. The carrying
values of the GoM Term Loan and Facility approximate fair value since they are subject to short-term floating interest rates that
approximate the rates available to us for those periods.
Nonrecurring Fair Value Measurements - Long-lived assets
Certain long-lived assets are reported at fair value on a non-recurring basis on the Company's consolidated balance
sheet. These long-lived assets are not measured at fair value on an ongoing basis but are subject to fair value adjustments in
certain circumstances. Our long-lived assets are reviewed for impairment when changes in circumstances indicate that the
carrying amount of an asset may not be recoverable.
The Company calculates the estimated fair values of its long-lived assets using the income approach described in the
ASC 820 — Fair Value Measurements. Significant inputs associated with the calculation of estimated discounted future net
cash flows include anticipated future production, pricing estimates, capital and operating costs, market-based weighted average
cost of capital, and risk adjustment factors applied to reserves. These are classified as Level 3 fair value assumptions. The
Company utilizes an average of third-party industry forecasts of Dated Brent, adjusted for location and quality differentials, to
determine our pricing assumptions. In order to evaluate the sensitivity of the assumptions, we analyze sensitivities to prices,
production, and risk adjustment factors.
As a result of a negative proved oil and gas reserve revision at TEN, primarily driven by recent well performance, we
reviewed our TEN long-lived assets for impairment at December 31, 2022, which resulted in impairment charges of $450.0
million for the year ended December 31, 2022, reducing the carrying value of the TEN Fields to the estimated fair value of
$235.7 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 was in the low-$80s adjusted for inflation. We also took account
112
of the delayed future investment in the field. 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.
No impairment of proved oil and gas properties was recognized for the year December 31, 2021 as no impairment
indicators were identified.
As a result of the impact of COVID-19 on the demand for oil and the related significant decrease in oil prices in 2020,
our long-lived assets were reviewed for impairment at March 31, 2020, which resulted in impairment charges of $150.8 million
in connection with the fair value assessments for oil and gas proved properties in the U.S. Gulf Mexico, reducing the carrying
value of the properties to their estimated fair values of $243.7 million. As part of our 2020 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. 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.
These impairment charges are included in Impairments of long-lived assets on the consolidated statement of
operations. 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.
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,
2022
2021
(In thousands)
$
$
325,459 $
13,696
(9,277)
(50,600)
23,256
302,534 $
251,421
38,967
(8,705)
22,744
21,032
325,459
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. During the year ended December 31, 2022, our asset
retirement obligations were reduced by approximately $10.0 million as a result of concluding the Tullow pre-emption
transaction in March 2022 and approximately $66.2 million as a result of the extension of the Block G licenses in Equatorial
Guinea in May 2022. The liabilities incurred during the year ended December 31, 2021 include $28.3 million associated with
our acquisition of additional interests in Ghana. The revisions in estimated retirement obligations during 2022 and 2021 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
113
awards under the LTIP. As of December 31, 2022, the Company had approximately 5.9 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.
The following table reflects the outstanding restricted stock units as of December 31, 2022:
Outstanding at December 31, 2019:
Granted(1)
Forfeited(1)
Vested
Outstanding at December 31, 2020:
Granted(1)
Forfeited(1)
Vested
Outstanding at December 31, 2021:
Granted(1)
Forfeited(1)
Vested
Outstanding at December 31, 2022:
__________________________________
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
4,731 $
3,481
(1,187)
(2,185)
4,840
2,905
(649)
(2,400)
4,696
2,820
(147)
(2,453)
4,916
5.71
5.48
6.12
5.91
5.34
2.57
4.05
5.19
3.88
4.70
3.92
4.21
4.18
7,798 $
3,394
(726)
(2,607)
7,859
6,744
(1,998)
(1,372)
11,233
3,388
(389)
(2,191)
12,041
8.42
8.37
8.03
9.47
8.11
3.91
5.50
9.95
5.28
6.98
6.21
5.98
5.61
(1)
The restricted stock units with a combination of market and service vesting criteria may vest between 0% and 200% of the
originally granted units depending upon market performance conditions. Awards vesting over or under target shares of 100% results
in additional shares granted or forfeited, respectively, in the period the market vesting criteria is determined.
As of December 31, 2022, total equity-based compensation to be recognized on unvested restricted stock units is $20.1
million over a weighted average period of 1.7 years.
For restricted stock units with a combination of market and service vesting criteria, the number of common shares to
be issued is determined by comparing the Company’s total shareholder return with the total shareholder return of a
predetermined group of peer companies over the performance period and can vest in up to 200% of the awards granted. The
grant date fair value ranged from $1.06 to $12.33 per award. The Monte Carlo simulation model utilizes multiple input
variables that determined 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 104.8%. 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%. The expected quarterly dividends
ranged from $0.000 to $0.050 commensurate with our current dividend experience.
In January 2023, we granted 2.1 million service vesting restricted stock units and 2.7 million market and service
vesting restricted stock units to our employees under our long-term incentive plan. We expect to recognize approximately
$49.0 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:
114
Share-based compensation expense
Total tax benefit
Net tax shortfall (windfall)
Fair value of awards vested
13. Income Taxes
Years Ended December 31,
2022
2021
2020
(In thousands)
$
34,546 $
5,933
31,651 $
5,786
673
22,205
6,307
9,435
32,706
4,694
1,175
26,039
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.
During the year ended December 31, 2022, our deferred tax liability decreased by approximately $242.7 million.
Approximately $44.6 million of the decrease is the result of concluding the Tullow pre-emption transaction in March 2022. See
Note 3 - Acquisitions and Divestitures. The remaining $198.1 million decrease in our deferred tax liability is primarily the
result of originating and reversing temporary differences.
Income (loss) before income taxes is composed of the following:
United States
Foreign
Income (loss) before income taxes
Years Ended December 31,
2022
2021
(In thousands)
2020
$
$
73,529 $
263,538
337,067 $
(75,948) $
32,568
(43,380) $
(338,746)
(78,049)
(416,795)
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,
2022
2021
2020
(In thousands)
$
7,174 $
282 $
300,829
308,003
103,348
103,630
84
(197,571)
(197,487)
110,516 $
1,202
(70,376)
(69,174)
34,456 $
$
(12,208)
49,586
37,378
34,831
(77,418)
(42,587)
(5,209)
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:
Years Ended December 31,
2021
2020
2022
Tax at statutory rate
Foreign income (loss) taxed at different rates
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 (benefit)
Effective tax rate(1)
______________________________________
$
$
70,784
20,663
3,012
3,993
673
11,391
—
110,516
$
(In thousands)
(9,110)
17,344
2,775
1,719
6,307
15,421
—
34,456
$
$
$
(87,527)
(1,771)
890
387
1,175
86,539
(4,902)
(5,209)
33 %
79 %
1 %
(1)
The effective tax rate during the years ended December 31, 2022, 2021 and 2020, were impacted by (gains) and losses of
$21.0 million, $61.6 million and $(2.9) 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 10%, 2% and 7% for the years ended December 31, 2022,
2021 and 2020, 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, 2022, 2021 and 2020, our effective tax rate in the United States is impacted by changes in
valuation allowances on a portion of our deferred tax assets totaling $(12.3) million, $6.6 million and $96.6 million,
respectively.
The effective tax rate for Ghana is approximately 35%, 35% and 35% for the years ended December 31, 2022, 2021
and 2020, respectively. The effective tax rate in Ghana is impacted by non-deductible expenditures.
The effective tax rate for Equatorial Guinea is approximately 36%, 35% and 34% for the years ended December 31,
2022, 2021 and 2020, 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
Other deferred tax liabilities
Total deferred tax liabilities
Net deferred tax liability
December 31,
2022
2021
(In thousands)
$
196,018 $
19,297
81,040
17,421
7,916
—
67,083
172,836
35,518
109,094
6,725
12,424
21,710
55,859
388,775
(312,968)
75,807
414,166
(318,343)
95,823
(512,019)
(806,861)
(32,233)
—
(544,252)
(806,861)
$
(468,445) $
(711,038)
The Company has foreign net operating loss carryforwards of $61.6 million, that will not expire. Additionally, the
Company has $385.9 million of United States net operating loss that will not expire. All of these losses currently have offsetting
valuation allowances.
The Company is open to tax examinations in the United States for federal income tax return years 2019 through 2021
in Ghana to federal income tax return years 2019 through 2021, and in Equatorial Guinea to federal income tax return years
2019 through 2021.
As of December 31, 2022, 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 income (loss) allocable to common stockholders
$
226,551 $
(77,836) $
(411,586)
Years Ended
December 31,
2022
2021
2020
(In thousands, except per share data)
Denominator:
Weighted average number of shares outstanding:
Basic
Restricted stock units(1)
Diluted
Net income (loss) per share:
Basic
Diluted
______________________________________
455,346
19,511
474,857
416,943
405,212
—
—
416,943
405,212
$
$
0.50 $
0.48 $
(0.19) $
(0.19) $
(1.02)
(1.02)
(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, 2022, 2021 and 2020, we excluded 0.1 million, 19.0 million and 6.1 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.
We currently have a commitment to drill three development wells and one exploration well in Equatorial Guinea. In
Mauritania and Senegal, we have a $200.2 million FPSO Contract Liability related to the deferred sale of the Greater Tortue
FPSO.
Performance Obligations
As of December 31, 2022 and 2021, the Company had performance bonds totaling $195.5 million and $195.5 million,
respectively, for our supplemental bonding requirements stipulated by the BOEM and $9.7 million and $3.5 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.
118
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
Gain on sale of assets
December 31,
2022
2021
(In thousands)
$
80,598 $
26,087
1,732
32,069
44,740
127,183
1,524
6,440
4,833
61,881
31,986
3,222
27,980
31,117
69,392
2,854
19,302
2,936
$
325,206 $
250,670
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 fourth quarter of 2022, we received formal
notice from Shell that an appraisal plan for one well had been submitted under the terms of Shell’s Petroleum Agreement with
Namibia. As a result, we recognized an additional $50.0 million gain related to the additional proceeds of $50.0 million
received in the fourth quarter of 2022 related to the transaction with Shell.
Other Expenses, net
Other expenses, net incurred during the period is comprised of the following:
Loss on disposal of inventory
Gain on insurance settlements
(Gain) loss on asset retirement obligations liability settlements
Restructuring charges
Other, net
Other expenses, net
Years Ended December 31,
2022
2021
(In thousands)
2020
$
$
1,521 $
(7,000)
(3,278)
(4)
(293)
(9,054) $
1,239 $
—
6,351
2,584
(63)
10,111 $
8,607
—
1,966
16,474
10,755
37,802
The restructuring charges for the years ended December 31, 2021 and 2020 are for employee severance and related
benefit costs incurred as part of a corporate reorganization.
119
17. Business Segment Information
Kosmos is engaged in a single line of business, which is the exploration, development and production of oil and gas.
At December 31, 2022, 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:
Years ended December 31, 2022
Revenues and other income:
Oil and gas revenue
Gain on sale of assets
Other income, net
—
428
—
3,350
Total revenues and other income
1,351,390
350,133
Costs and expenses:
Oil and gas production
206,486
90,602
Facilities insurance modifications, net
Exploration expenses
General and administrative
6,243
14,987
15,310
—
7,378
6,703
Depletion, depreciation and amortization
289,058
53,765
Impairment of long-lived assets
450,357
—
Ghana(2)
Equatorial
Guinea
Mauritania
/ Senegal
U.S. Gulf of
Mexico(3)
Corporate &
Other
Eliminations
Total
(in thousands)
$ 1,350,962
$ 346,783 $
— $
547,610 $
— $
— $ 2,245,355
—
—
—
—
—
82,526
9,798
412
—
471
2,405
550,486
105,968
—
22,763
15,794
153,407
(388)
—
—
50,000
386,002
436,002
—
—
6,576
180,594
1,614
—
114,598
260,892
—
50,471
(388,236)
3,949
(388,236)
2,299,775
—
—
—
403,056
6,243
134,230
(127,343)
100,856
—
—
—
—
498,256
449,969
118,260
260,892
(1,178)
10,339
496
(260,893)
(9,054)
Interest and other financing costs, net(1)
64,620
(2,494)
(69,644)
11,180
Derivatives, net
Other expenses, net
—
233,785
—
8,397
Total costs and expenses
1,280,846
164,351
21,914
319,063
564,770
(388,236)
1,962,708
Income (loss) before income taxes
Income tax expense (benefit)
70,544
28,091
185,782
(21,914)
231,423
(128,768)
72,814
—
(1,010)
10,621
—
—
337,067
110,516
Net income (loss)
$
42,453
$ 112,968 $
(21,914) $
232,433 $
(139,389) $
— $ 226,551
Consolidated capital expenditures
$
98,540
$
36,036 $
407,982 $
111,016 $
(41,986) $
— $ 611,588
As of December 31, 2022
Property and equipment, net
$ 1,202,937
$ 396,737 $ 1,396,884 $
829,242 $
16,847 $
— $ 3,842,647
Total assets
$ 2,886,242
$ 1,463,211 $ 2,026,776 $ 3,695,641 $ 19,554,236 $
(25,046,118) $ 4,579,988
______________________________________
(1)
(2)
(3)
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 the interest pre-empted by Tullow prior to the March 17, 2022 closing date of the Tullow pre-emption
transaction. Additionally, cash consideration of $118.2 million is included as a reduction in Consolidated capital expenditures for
the year ended December 31, 2022.
Includes activity related to our acquisition of an additional interest in the Kodiak oil field commencing June 9, 2022, the acquisition
date. Additionally, cash consideration paid of $29.0 million is included in Consolidated capital expenditures for the year ended
December 31, 2022.
120
Year ended December 31, 2021
Revenues and other income:
Oil and gas revenue
Gain on sale of assets
Other income, net
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
—
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
—
—
—
—
—
10,639
8,601
—
1,279
428,540
101,895
—
41,230
17,665
Depletion, depreciation and amortization
240,901
56,468
61
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
—
—
—
346,006
(1,586)
65,382
(124,128)
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
—
—
—
(96,101)
—
—
338,477
13,161
84,616
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
Consolidated capital expenditures:
Consolidated Statements of Cash Flows - Investing activities:
Oil and gas assets
Acquisition of oil and gas properties
Proceeds on sale of assets
Adjustments:
Changes in capital accruals
Exploration expense, excluding unsuccessful well costs and leasehold
impairments(1)
Capitalized interest
Other
Total consolidated capital expenditures
______________________________________
(1)
Unsuccessful well costs are included in oil and gas assets when incurred.
Years Ended December 31,
2021
2020
2022
(In thousands)
$
787,297 $
22,078
(168,703)
472,631 $
465,367
(6,354)
379,593
—
(99,118)
396
(18,534)
(42,315)
47,289
(84,343)
7,574
611,588 $
46,563
(46,098)
10,639
924,214 $
61,459
(25,013)
(627)
273,979
$
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, 2022, 2021 and 2020. 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.
123
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
Oil, Condensate, NGLs (MMBbls)(5)
Natural Gas (Bcf)
Kosmos
Total
(MMBoe)
Net proved developed and
undeveloped reserves at
December 31, 2019(1)
88
Extensions and discoveries(4)
—
Production
Revision in estimate(2)(4)
(10)
(10)
Purchases of minerals-in-place
—
Net proved developed and
undeveloped reserves at
December 31, 2020(1)(4)
Extensions and discoveries
Production
Revision in estimate(2)
Purchases of minerals-in-
place(3)
Net proved developed and
undeveloped reserves at
December 31, 2021(1)
68
—
(10)
10
52
120
Extensions and discoveries
—
Production
Revision in estimate(2)
(13)
7
Purchase of minerals-in-place
—
Sales of minerals-in-place
(14)
Net proved developed and
undeveloped reserves at
December 31, 2022(1)
Proved developed reserves(1)
December 31, 2019
December 31, 2020
December 31, 2021
December 31, 2022
Proved undeveloped reserves(1)(6)
December 31, 2019
December 31, 2020
December 31, 2021
December 31, 2022
99
47
26
52
43
41
42
68
56
26
—
(4)
2
—
24
—
(4)
4
—
24
—
(4)
4
—
—
25
23
21
20
20
3
4
5
5
______________________________________
—
—
—
—
40
154
45
—
—
(7) (21)
(6)
2
—
—
(14)
—
—
—
—
12
—
—
(1)
—
—
—
—
8
—
34
—
127
—
(6) (20)
31
—
—
4
26
52
10
27
8
—
—
(1)
—
32
185
68
3
3
—
(6) (23)
7
(2)
—
(5)
1
1
—
—
—
(14)
(14)
7
27
158
49
—
—
—
—
—
—
8
7
34
104
32
79
28
21
100
84
6
2
4
6
50
48
85
74
31
23
56
40
14
8
12
9
11
—
—
—
—
11
—
—
5
—
—
16
12
11
11
16
—
—
—
—
—
600
—
(600)
—
—
—
—
590
—
590
28
—
(1)
—
—
35
92
—
600
(6)
(6)
(2) (617)
—
—
27
—
(5)
69
—
(5)
5
605
27
27
695
1
29
(4)
—
(4)
—
—
—
—
(14)
169
100
(22)
(109)
—
139
—
(21)
127
57
301
8
(24)
7
1
(16)
618
24
707
276
—
—
—
—
—
—
590
618
28
25
20
17
7
2
6
7
71
59
87
73
21
10
608
634
116
89
115
96
53
50
186
180
124
(1)
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.
(2)
The revisions in estimates in 2022 are related to:
•
•
•
•
•
•
•
•
•
•
•
In Ghana, we had negative revisions of 14.3 MMBbl of oil and 14.2 Bcf of gas resulting from the conclusion of the
Tullow pre-emption transaction in March 2022 in the Jubilee and TEN fields. Jubilee had a positive revision of 11.0
MMBbl due to positive drilling results and field performance and a negative revision of 3.0 Bcf related to changes in
remaining field life, in addition to Jubilee net production of 11.3 MMBbl. TEN had a negative revision of 6.1 MMBbl
and 9.6 Bcf due to recent well performance and updated reservoir model forecast, in addition to the net TEN
production of 2.0 MMBbl. In Ghana, the increase in commodity prices resulted in a positive revision of 2.2 MMBbl
and 7.1 Bcf. The overall decreases in reserves for the year ended December 31, 2022 were 6.6 MMBbl and 2.8 Bcf for
Jubilee and 13.9 MMBbl and 16.7 Bcf for TEN.
In EG, we had a positive revision of 0.9 MMBbl of oil based on production performance and topsides optimization in
Ceiba, offset by net production of 3.7 MMBbl. The increase in commodity prices along with the license extension in
Ceiba from 2029 to 2040 and in Okume from 2034 to 2040 resulted in a positive revision of 3.2 MMBbl and 5.2 Bcf.
Overall, EG had an increase in reserves of 0.4 MMBbl and 5.2 Bcf.
In Mauritania/Senegal, we had a additions of 28.1 Bcf due to a field extension that resulted from drilling of production
wells. We also had a 0.7 MMBbl negative revision in condensate reserves based on an updated yield estimate. We note
that the increase in commodity prices did not result in revisions of estimates.
In the U.S. Gulf of Mexico, we had a negative revision of 2.1 MMBbl and positive revision of 0.3 Bcf of gas based on
recent water breakthrough in Odd Job and Tornado, Kodiak production performance, in addition to the net production
of 5.7 MMBbl and 4.0 Bcf. The Winterfell discovery added 2.9 MMBbl and 1.0 Bcf of gas. The purchase of additional
interest in the Kodiak field resulted in a positive revision of 0.8 MMBbl. We note the changes in commodity prices in
the U.S. Gulf of Mexico were not material. The overall decrease in reserves for the U.S. Gulf of Mexico were 4.1
MMBbl and 2.7 Bcf.
The revisions in estimates in 2021 are related to:
In Ghana, we had 5.5 MMBbl of positive revisions in estimates (primarily related to the Jubilee Field) related to
overall field performance, including positive drilling results on our proved undeveloped well locations and optimized
future well locations. We had 8.0 Bcf of positive revisions in estimates in the TEN field related to the updated
reservoir model forecast. The increase in commodity prices resulted in positive revisions in estimates of 4.1 MMBbl of
oil reserves and 1.7 Bcf of gas reserves.
In Equatorial Guinea, we had 3.0 MMBbl of positive revisions in estimates due to overall field performance and
positive drilling results and 0.7 MMBbl of positive revisions in estimates due to the increase in commodity prices. We
note changes in Equatorial Guinea gas reserves was not material.
In Mauritania/Senegal, we had 8.2 MMBbl and 590.0 Bcf of positive revisions in proved undeveloped reserve
estimates related to the economic status of Phase 1 of the Greater Tortue project due to the project progress and
improved commodity prices.
In the U.S. Gulf of Mexico, we had positive revisions of 0.6 MMBbl and 3.2 Bcf of gas reserves related to strong
performance of certain fields across our portfolio. The increase in commodity prices resulted in positive revisions of
3.0 MMBbl and 1.3 Bcf, respectively.
The revisions in estimates in 2020 are related to:
In Ghana, we had 5.1 MMBbl and 1.2 Bcf of negative revisions in estimates (primarily related to the TEN Field)
related to overall field performance, delayed drilling and our future development plans. The decrease in commodity
prices resulted in negative revisions in estimates of 4.8 MMBbl and 12.0 Bcf (all related to the TEN Field).
In Equatorial Guinea, we had 2.0 MMBbl of positive revisions in estimates due to overall field performance and
positive stimulation support. We note that the decreases in commodity prices during the year did not have a material
impact to the proved reserves as both fields’ economic limit did not change from the previous evaluation. We note
changes in gas reserves was not material.
In the U.S. Gulf of Mexico, we had positive revisions of 2.0 MMBbl related to positive drilling results and strong
performance of certain fields across our portfolio. The impact of commodity price changes and overall impacts to gas
reserves was not material.
125
(3)
(4)
(5)
The purchases of minerals-in-place during 2021 is related to our acquisition of additional interests in the Jubilee field
and TEN fields offshore Ghana, resulting in total proved oil reserve additions of 38.7 MMBbl and 12.8 MMBbl and
total proved gas reserve additions of 7.2 Bcf and 20.1 Bcf, respectively.
The Tortue Phase 1 SPA was signed on February 11, 2020, resulting in approximately 600 Bcf of proved undeveloped
net gas 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.
Natural gas liquids proved reserves represent an immaterial amount of our total proved reserves. Therefore, we have
aggregated natural gas liquids and crude oil/condensate reserves information.
(6)
The changes in proved undeveloped reserves in 2022 are related to:
•
•
•
•
•
•
•
•
•
In Ghana, we converted 4.6 MMBbl of oil in Jubilee of proved undeveloped reserves to proved developed reserves
during the year by drilling three wells at a cost of approximately $75.1 million. In TEN, we converted 5.1 MMBbl and
4.1 Bcf of gas of proved undeveloped reserves to proved developed reserves during the year by drilling one well at a
cost of approximately $13.6 million. We had a decrease in proved undeveloped reserves of 4.3 MMBbl in Jubilee and
3.0 MMBbl and 3.3 Bcf in TEN related to the sale of minerals-in-place during 2022. The Jubilee field had an increase
in proved undeveloped reserves of 4.0 MMBbl related to optimization of future drilling. The TEN field had a proved
undeveloped reserves increase of 1.4 MMBbl and 4.1 Bcf related to an updated plan of development. The overall
proved undeveloped reserves decreased by 5.0 MMBbl in Jubilee and by 6.7 MMBbl and 3.3 Bcf in TEN.
In Equatorial Guinea, During the year ended December 31, 2022, EG had no material changes in proved undeveloped
reserves.
In Mauritania/Senegal, we had a proved undeveloped reserves increase of 28.1 Bcf due to a field extension that
resulted from drilling of production wells. We also had a 0.7 MMBbl negative revision in condensate reserves based
on an updated yield estimate.
In the U.S. Gulf of Mexico, we had a proved undeveloped reserves increase of 1.0 MMBbl and 1.8 Bcf due based on
an updated plans of development in the Odd Job, Marmalard, and Big Bend fields. We converted 1.6 MMBbl and 2.2
Bcf from proved undeveloped by drilling one well in Kodiak at a cost of $13.6 million. The Winterfell discovery
added 2.9 MMBbl and 1.0 Bcf of gas of proved undeveloped reserves. We added 0.2 MMBbl of proved undeveloped
reserves related to our purchase of minerals-in-place during 2022 in the Kodiak field. The overall proved undeveloped
reserves in the U.S. Gulf of Mexico increased by 2.4 MMBbl and 0.6 Bcf.
The changes in proved undeveloped reserves in 2021 are related to:
In Ghana, Jubilee had a proved undeveloped reserves increase of 17.8 MMBbl related to optimization of future
drilling. Related to our purchases of minerals-in-place during 2021, we added 28.5 MMBbl and 4.7 Bcf of proved
undeveloped reserves. We converted 20.7 MMBbl of proved undeveloped reserves to proved developed reserves
during the year by drilling three wells at a cost of $34.1 million.
In Equatorial Guinea, During the year ended December 31, 2021, EG had a PUD increase of 2.9 MMBbl related to
adding a future development well and optimizing future development plans in EG. We converted 1.8 MMBbl of
proved undeveloped reserves to proved developed reserves during the year by drilling two wells and replacing certain
subsea infrastructure at a cost of $35.6 million.
In the U.S. Gulf of Mexico, we had a proved undeveloped reserves increase of 3.5 MMBbl of oil reserves and 6.3 Bcf
of gas reserves related to adding a future development well and optimizing future development plans. We converted
1.8 MMBbl and 1.8 Bcf of gas proved undeveloped reserves to proved developed reserves through drilling of one well
in Tornado at a cost of $19.0 million.
The changes in proved undeveloped reserves in 2020 are related to:
In Ghana, Jubilee had a proved undeveloped reserves increase of 4.7 MMBbl related to adding additional wells to
future development of Greater Jubilee. We converted 3.3 MMBbl of proved undeveloped reserves to proved developed
reserves during the year by drilling one well in TEN at a cost of $28.5 million.
In the U.S. Gulf of Mexico, we had a negative proved undeveloped reserves decrease of 1.0 MMBbl and 3.6 Bcf
primarily related to changes in the development plans in the Marmalard field. Additionally, we converted 2.2 MMBbl
126
and 1.8 Bcf of gas proved undeveloped reserves to proved developed reserves through drilling of one well in Tornado
at a cost of $79.2 million.
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 2022. 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, 2022
Unproved properties
Proved properties
Accumulated depletion
Net capitalized costs
As of December 31, 2021
Unproved properties
Proved properties
Accumulated depletion
Net capitalized costs
$
$
$
$
— $
3,705
3,705
(2,502)
1,203 $
— $
4,116
4,116
(2,231)
1,885 $
85 $
526
611
(214)
397 $
86 $
545
631
(170)
461 $
(In millions)
114 $
1,282
1,396
—
1,396 $
167 $
752
919
—
919 $
130 $
1,440 $
1,570
(741)
829 $
185 $
1,313
1,498
(599)
899 $
13 $
—
13
—
13 $
13 $
—
13
—
13 $
342
6,953
7,295
(3,457)
3,838
451
6,726
7,177
(3,000)
4,177
127
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.
Ghana
Equatorial
Guinea
Mauritania
/ Senegal
U.S. Gulf
of Mexico Other(1)
Kosmos
Total
(In millions)
Year ended December 31, 2022
Property acquisition:
Unproved
Proved
Exploration
Development(3)(5)
Total costs incurred
Year ended December 31, 2021
Property acquisition:
Unproved
Proved(2)
Exploration
Development(4)
Total costs incurred
Year ended December 31, 2020
Property acquisition:
Unproved
Proved
Exploration
Development
Total costs incurred
$ — $
—
15
226
241 $
$
$ — $
718
—
112
830 $
$
2 $
7
9
37
55 $
1 $
1
8
79
89 $
$ — $ — $
(2)
7
20
25 $
—
—
39
39 $
$
— $
—
74
486
560 $
19 $ — $
27
31
17
94 $
—
5
—
5 $
21
34
134
766
955
— $
—
16
333
349 $
(2) $
—
60
46
104 $
(2)
(1) $
719
—
90
6
—
570
5 $ 1,377
— $
—
21
129
150 $
5 $
—
34
99
138 $
(1) $
—
34
—
33 $
4
(2)
96
287
385
______________________________________
(1)
(2)
(3)
(4)
(5)
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.”
Includes $67.8 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.”
Excludes $66.2 million reduction of capitalized asset retirement costs resulting from the extension of the Block G
licenses in Equatorial Guinea in May 2022.
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 2022. 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.
128
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.
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, 2022
Future cash inflows
Future production costs
Future development and abandonment 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)
$ 10,076 $ 2,507 $ 6,419 $ 2,532 $ 21,534
(1,586)
(1,395)
(2,399)
4,696
(1,394)
(877)
(610)
(465)
(2,696)
(753)
(340)
(359) (5,518)
(489) (3,247)
(190) (3,394)
555
43
2,630
1,494
9,375
(1,498)
(365) (3,214)
Standardized measure of discounted future net cash flows
$ 3,302 $
598 $ 1,132 $ 1,129 $ 6,161
At December 31, 2021
Future cash inflows
Future production costs
$ 8,308 $ 1,661 $ 4,314 $ 1,981 $ 16,264
(2,079)
(621)
(2,853)
(334) (5,887)
Future development and abandonment costs
Future tax expenses
Future net cash flows
10% annual discount for estimated timing of cash flows
(1,640)
(1,546)
3,043
(983)
(478)
(307)
255
37
(822)
(284) (3,224)
(43)
(117) (2,013)
596
(671)
1,246
5,140
(262) (1,879)
Standardized measure of discounted future net cash flows
$ 2,060 $
292 $
(75) $ 984 $ 3,261
At December 31, 2020
Future cash inflows
Future production costs
Future development and abandonment 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
$ 2,791 $
986 $
— $ 1,244 $ 5,021
(1,197)
(765)
(251)
578
(214)
$ 364 $
(577)
(352)
(131)
(74)
101
27 $
—
—
—
(249) (2,023)
(306) (1,423)
(7)
(389)
—
682
1,186
—
(109)
(222)
— $ 573 $ 964
129
Changes in the Standardized Measure for Discounted Cash Flows
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
Purchase of minerals in place
Sales of minerals in place
Sales and transfers 2022
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, 2022
______________________________________
Ghana
Equatorial
Guinea
Mauritania /
Senegal
U.S. Gulf
of Mexico
Total
(In millions)
$ 1,426 $
294 $
— $ 1,099 $
2,819
—
(197)
—
(1,292)
44
(65)
(95)
440
212
(109)
—
(72)
—
(390)
33
(19)
27
88
52
14
—
—
80
(80)
—
—
—
—
—
—
—
(197)
—
(633)
126
(57)
44
81
118
—
(466)
80
(2,395)
203
(141)
(24)
609
382
(8)
(103)
$
364 $
27 $
— $
573 $
981
—
(493)
(167)
—
1,232
91
—
479
73
(187)
(124)
367
128
(421)
(146)
53
73
$ 2,060 $
—
(243)
(1,144)
—
2,340
207
(119)
645
(882)
271
167
12
10
292 $
—
—
(256)
—
422
28
(8)
192
(143)
52
19
964
981
—
(325)
(985)
—
602
—
2,238
—
—
—
(75)
—
—
—
—
—
42
(38)
153
(74)
58
—
(75) $
(7)
984 $
—
—
—
171
868
387
(150)
(9)
(77)
—
17
47
—
(442)
46
673
59
(94)
(117)
(87)
106
(46)
206
(349)
648
(641)
123
76
3,261
47
(243)
(1,842)
217
4,303
681
(371)
711
(1,189)
429
157
$ 3,302 $
598 $
1,132 $ 1,129 $
6,161
130
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, 2022, 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, 2022 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.
131
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 2023 Proxy Statement, which will be
filed with the SEC not later than 120 days subsequent to December 31, 2022.
Item 11. Executive Compensation
The information required by this item is incorporated herein by reference to the 2023 Proxy Statement, which will be
filed with the SEC not later than 120 days subsequent to December 31, 2022.
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 2023 Proxy Statement, which will be
filed with the SEC not later than 120 days subsequent to December 31, 2022.
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required by this item is incorporated herein by reference to the 2023 Proxy Statement, which will be
filed with the SEC not later than 120 days subsequent to December 31, 2022.
Item 14. Principal Accounting Fees and Services
The information required by this item is incorporated herein by reference to the 2023 Proxy Statement, which will be
filed with the SEC not later than 120 days subsequent to December 31, 2022.
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 2022, 2021 and
2020 (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.
132
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.
133
KOSMOS ENERGY LTD.
CONDENSED PARENT COMPANY BALANCE SHEETS
(In thousands, except share data)
$
$
$
December 31,
2022
2021
2,286 $
413
1,051
—
—
3,750
2,403,785
—
4,640
—
—
305
461
2,412,941 $
14 $
114,312
27,500
—
—
141,826
1,483,267
—
—
—
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
—
—
—
5,002
2,505,694
(1,485,841)
(237,007)
787,848
2,412,941 $
4,962
2,473,674
(1,712,392)
(237,007)
529,237
2,130,137
$
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 $13,263 and $19,912 at
December 31, 2022 and December 31, 2021, 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, 2022 and December 31, 2021
Common stock, $0.01 par value; 2,000,000,000 authorized shares; 500,161,421 and
496,152,331 issued at December 31, 2022 and December 31, 2021, respectively
Additional paid-in capital
Accumulated deficit
Treasury stock, at cost, 44,263,269 shares at December 31, 2022 and 2021, respectively
Total shareholders’ equity
Total liabilities and shareholders’ equity
134
KOSMOS ENERGY LTD.
CONDENSED PARENT COMPANY STATEMENTS OF OPERATIONS
(In thousands)
Years Ended December 31,
2021
2020
2022
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
Income (loss) before income taxes
Income tax expense (benefit)
Net income (loss)
Dividends declared per common share
$
— $
— $
75,740
75,740
20,307
20,307
44,180
(3,772)
123,247
—
75,740
17
(415,546)
(176,134)
251,874
25,323
226,551 $
38,810
79
98,649
(2,446)
20,307
(61)
(57,195)
98,143
(77,836)
—
(77,836) $
—
2,642
2,642
40,162
4,112
59,200
(5,889)
2,642
—
315,423
415,650
(413,008)
(1,422)
(411,586)
— $
— $
0.0452
$
$
135
KOSMOS ENERGY LTD.
CONDENSED PARENT COMPANY STATEMENTS OF CASH FLOWS
(In thousands)
Operating activities
Net income (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
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
2022
$
226,551 $
(77,836) $
(411,586)
(415,546)
34,546
6,359
18,034
(4,353)
75,741
(70,327)
192
306
(94)
33,214
(4,159)
(99,536)
(57,195)
31,651
5,638
—
6,582
20,307
(28,363)
4,403
134
(49)
218,008
18,003
141,283
315,423
32,706
8,644
(1,422)
(2,642)
2,642
—
—
856
(480)
162,897
2,509
109,547
104,676
104,676
(1,001,494)
(1,001,494)
(190,089)
(190,089)
—
—
—
—
(2,753)
(655)
(6,139)
(9,547)
(4,407)
6,998
2,591 $
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
$
136
Kosmos Energy Ltd.
Valuation and Qualifying Accounts
For the Years Ended December 31, 2022, 2021 and 2020
Additions
Schedule II
Description
2022
Allowance for credit losses
Allowance for deferred tax assets
2021
Allowance for credit losses
Allowance for deferred tax assets
2020
Allowance for credit losses
Allowance for deferred tax assets
Balance
January 1,
Charged to
Costs and
Expenses
Charged To
Other
Accounts
Deductions
From Reserves
Balance
December 31,
$
$
$
$
$
$
5,189 $
318,343 $
2,509 $
(5,616) $
(687) $
— $
— $
— $
7,011
312,727
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
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
137
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, 2023
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, 2023
/s/ NEAL D. SHAH
Neal D. Shah
Senior Vice President and Chief Financial
Officer (Principal Financial Officer)
February 28, 2023
/s/ RONALD W. GLASS
Ronald W. Glass
Vice President and Chief Accounting Officer
(Principal Accounting Officer)
February 28, 2023
/s/ SIR RICHARD B. DEARLOVE
Sir Richard B. Dearlove
Director
February 28, 2023
/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, 2023
Director
February 28, 2023
Director
February 28, 2023
Director
February 28, 2023
138
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).
Senegal
139
Exhibit
Number
Description of Document
10.11 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).
10.12 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).
10.13 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).
Mauritania
10.14 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).
10.15 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).
10.16* Exploration and Production Contract between The Islamic Republic of Mauritania and BP Mauritania
Investments Limited, Kosmos Energy Mauritania, and Societe Mauritanienne Des Hydrocarbures (BirAllah)
dated November 7, 2022.
Equatorial Guinea
10.17 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).
10.18 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).
10.19 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).
10.20 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).
10.21 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).
10.22 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).
10.23 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).
10.24 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).
Greater Tortue Ahmeyim
140
Exhibit
Number
Description of Document
10.25†† 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
10.26
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).
10.27 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).
10.28 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).
10.29†† 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).
10.30†† 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).
10.31 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).
10.32 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).
10.33 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).
10.34 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).
10.35 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 (filed as
Exhibit 10.56 to the Company's Annual Report on Form 10-K for the year ended December 31, 2021, and
incorporated herein by reference).
10.36 Revolving Credit Facility Agreement, dated March 31, 2022, 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 10.1 to the Company's Quarterly Report on Form 10-Q for the
quarter ended March 31, 2022, and incorporated herein by reference).
141
Exhibit
Number
Description of Document
10.37* Amended and Restated Facility Agreement, amended as of November 23, 2022, among Kosmos Energy
Finance International, Kosmos Energy Operating, Kosmos Energy International, Kosmos Energy
Development, Kosmos Energy Ghana HC, Kosmos Energy Equatorial Guinea, Kosmos Equatorial Guinea,
Inc., Kosmos International Petroleum, Inc., 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.
10.38* Revolving Credit Facility Agreement, amended as of November 23, 2022, among Kosmos Energy Ltd., as
Original Borrower, certain of its subsidiaries listed therein, as Guarantors, The Standard Bank of South
Africa Limited, as Facility Agent, Crédit Agricole Corporate and Investment Bank, as Security and
Intercreditor Agent, and the financial institutions listed therein, as Lenders.
Agreements with Shareholders and Directors
10.39 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).
10.40 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").
10.41 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).
10.42
10.43 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
10.44† 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).
10.45† 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).
10.46† 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).
10.47† 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).
10.48† 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).
10.49† 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).
10.50† 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).
10.51† 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).
10.52† 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).
10.53† 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).
10.54† 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).
10.55† Form of Directors Award Agreement (Elective Shares) (filed as Exhibit 10.73 to the Company's Annual
Report on Form 10-K for the year ended December 31, 2021, and incorporated herein by reference).
142
Exhibit
Number
Description of Document
10.56† 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).
10.57† 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).
10.58† 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).
10.59† 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).
10.60† Kosmos Energy Ltd. Change in Control Severance Policy for U.S. Employees (amended and restated as of
January 19, 2022) (filed as Exhibit 10.81 to the Company's Annual Report on Form 10-K for the year ended
December 31, 2021, and incorporated herein by reference).
10.61† 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).
10.62† 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).
10.63† 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).
Deep Gulf Energy Acquisition
10.64 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
10.65 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
10.66†† 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).
10.67†† 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).
10.68†† 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).
10.69 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.
143
Exhibit
Number
Description of Document
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
Corporate Leadership & Information
BOARD OF DIRECTORS
SENIOR LEADERSHIP
CORPORATE INFORMATION
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)
NEAL D. SHAH
Senior Vice President and Chief
Financial Officer
CHRISTOPHER J. BALL
Senior Vice President and Chief
Commercial 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
ROY A. FRANKLIN
Chairman, Wood plc
Director, Energean plc
DEANNA L. GOODWIN
Director, Arcadis NV
Director, Oceaneering
International, Inc.
SIR JOHN GRANT
Member, Advisory Council of
Essar Oil (UK) Limited
MARIA MORÆUS HANSSEN
Director, Schlumberger Limited
(Schlumberger N.V.)
Director, Scatec Solar ASA
ADEBAYO O. OGUNLESI
Chairman and Managing Partner,
Global Infrastructure Partners
STEVEN M. STERIN
Director, DuPont de Nemours, Inc.
J. MICHAEL STICE
Director, Marathon Petroleum
Corporation
Director, MPLX GP LLC
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 8, 2023
8:00 a.m. Central Daylight Time
Virtual-Only Format:
www.virtualshareholdermeeting.com/
KOS2023
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
CAUTIONARY STATEMENTS
REGARDING OIL AND GAS
QUANTITIES
NON-GAAP FINANCIAL
MEASURES
EBITDAX and net debt are supplemental
The SEC permits oil and gas companies,
non-GAAP financial measures used
in their filings with the SEC, to disclose
by management and external users of
only proved, probable and possible reserves
the Company’s consolidated financial
that meet the SEC’s definitions for such
statements, such as industry analysts,
terms, and price and cost sensitivities for
investors, lenders and rating agencies. The
such reserves, and prohibits disclosure
Company defines EBITDAX as net income
of resources that do not constitute such
(loss) plus (i) exploration expense, (ii)
reserves. The Company uses terms in this
depletion, depreciation and amortization
report, such as “discovered resources,”
expense, (iii) equity based compensation
“potential,” “significant resource upside,”
expense, (iv) unrealized (gain) loss on
“resource,” “net resources,” “recoverable
commodity derivatives (realized losses are
resources,” “discovered resource,” “world-
deducted and realized gains are added
class discovered resource,” “significant
back), (v) (gain) loss on sale of oil and
defined resource,” “gross unrisked resource
gas properties, (vi) interest (income)
potential,” “defined growth resources,”
expense, (vii) income taxes, (viii) loss
“recovery potential” and similar terms or
on extinguishment of debt, (ix) doubtful
other descriptions of volumes of reserves
accounts expense and (x) similar other
potentially recoverable that the SEC’s
material items which management believes
guidelines strictly prohibit the Company
affect the comparability of operating
from including in filings with the SEC.
These estimates are by their nature more
speculative than estimates of proved,
probable and possible reserves and
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
accordingly are subject to substantially
Term Loan less cash and cash equivalents
greater risk of being actually realized.
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. EBITDAX and
net debt as presented by us may not be
comparable to similarly titled measures of
other companies.
Investors are urged to consider closely
the disclosures and risk factors in the
Company’s SEC filings, available on the
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
recovered from the Company’s interest may
differ substantially from these estimates.
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
geological and mechanical factors affecting
recovery rates. Estimates of reserves and
resource potential may change significantly
as development of the Company’s oil and
gas assets provides additional data.
FORWARD-LOOKING STATEMENTS
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
Company, including as to estimated oil and
gas in place and recoverability of the oil
and gas, estimated reserves and drilling
locations, capital expenditures, typical well
results and well profiles and production
and operating expenses guidance included
in the report. The Company’s estimates
and forward-looking statements are mainly
based on its current expectations and
estimates of future events and trends, which
affect or may affect its businesses and
operations. Although the Company believes
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
the Company. When used in this report,
the words “anticipate,” “believe,” “intend,”
“expect,” “plan,” “will” or other similar words
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
available in the Company’s Securities and
Exchange Commission (“SEC”) filings. The
Company’s SEC filings are available on the
Company’s website at www.kosmosenergy.
com. Kosmos undertakes no obligation and
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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