SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
|(Mark One)|| |
|☒||ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934|
For the fiscal year ended December 31, 2021
|☐||TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934|
|For the transition period from to |
Commission file number: 001-35167
Kosmos Energy Ltd.
(Exact name of registrant as specified in its charter)
|(State or other jurisdiction of|| ||(I.R.S. Employer|
|incorporation or organization)|| ||Identification No.)|
|8176 Park Lane|
|(Address of principal executive offices)||(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||Trading Symbol||Name of each exchange on which registered:|
|Common Stock $0.01 par value||KOS||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 ||☒|| ||Accelerated filer ||☐|
|Non-accelerated filer ||☐|| ||Smaller reporting company ||☐|
|(Do not check if a smaller reporting company)|| || |
| || ||Emerging growth company ||☐|
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b‑2 of the Exchange Act). Yes ☐ No ☒
The aggregate market value of the voting and non‑voting common stock held by non‑affiliates, based on the per‑share closing price of the registrant’s common stock as of the last business day of the registrant’s most recently completed second fiscal quarter was $1,384,993,421.
The number of the registrant’s Common Stock outstanding as of February 24, 2022 was 455,265,466.
DOCUMENTS INCORPORATED BY REFERENCE
Part III, Items 10‑14, is incorporated by reference from the Proxy Statement for the Annual Meeting of Shareholders which will be filed with the Securities and Exchange Commission not later than 120 days subsequent to December 31, 2021.
Certain exhibits previously filed with the Securities and Exchange Commission are incorporated by reference into Part IV of this report.
TABLE OF CONTENTS
Unless otherwise stated in this report, references to “Kosmos,” “we,” “us” or “the company” refer to Kosmos Energy Ltd. and its subsidiaries. On December 28, 2018, we changed our jurisdiction of incorporation from Bermuda to the State of Delaware, which we refer to herein as the Redomestication. All references to “Kosmos,” “we,” “us” or “the company” on or before December 28, 2018 refer to Kosmos Energy Ltd., an exempted company incorporated pursuant to the laws of Bermuda, and its subsidiaries. All such references after December 28, 2018 refer to Kosmos Energy Ltd., a Delaware corporation, and its subsidiaries. In addition, all references to “common stock” on or before December 28, 2018 refer to the common shares of Kosmos Energy Ltd. prior to the Redomestication, and all such references after December 28, 2018 refer to the common stock of Kosmos Energy Ltd. after the Redomestication. For additional detail, please see “Item 1. Business—Corporate Information.”
In addition, we have provided definitions for some of the industry terms used in this report in the “Glossary and Selected Abbreviations” beginning on page 3.
KOSMOS ENERGY LTD.
GLOSSARY AND SELECTED ABBREVIATIONS
The following are abbreviations and definitions of certain terms that may be used in this report. Unless listed below, all defined terms under Rule 4‑10(a) of Regulation S‑X shall have their statutorily prescribed meanings.
|“2D seismic data”||Two‑dimensional seismic data, serving as interpretive data that allows a view of a vertical cross‑section beneath a prospective area.|
|“3D seismic data”||Three‑dimensional seismic data, serving as geophysical data that depicts the subsurface strata in three dimensions. 3D seismic data typically provides a more detailed and accurate interpretation of the subsurface strata than 2D seismic data.|
|“ANP-STP”||Agencia Nacional Do Petroleo De Sao Tome E Principe.|
|“API”||A specific gravity scale, expressed in degrees, that denotes the relative density of various petroleum liquids. The scale increases inversely with density. Thus lighter petroleum liquids will have a higher API than heavier ones.|
|“Asset Coverage Ratio”||The “Asset Coverage Ratio” as defined in the GoM Term Loan means, as of each March 31, June 30, September 30 and December 31 of each Fiscal Year, commencing December 31, 2020, the ratio of (a) Total PDP PV-10 (as defined in the GoM Term Loan) as of such date to (b) outstanding principal amount of Loans (as defined in the GoM Term Loan) as of such date.|
|“ASC”||Financial Accounting Standards Board Accounting Standards Codification.|
|“ASU”||Financial Accounting Standards Board Accounting Standards Update.|
|“Barrel” or “Bbl”||A standard measure of volume for petroleum corresponding to approximately 42 gallons at 60 degrees Fahrenheit.|
|“BBbl”||Billion barrels of oil.|
|“BBoe”||Billion barrels of oil equivalent.|
|“Bcf”||Billion cubic feet.|
|“Boe”||Barrels of oil equivalent. Volumes of natural gas converted to barrels of oil using a conversion factor of 6,000 cubic feet of natural gas to one barrel of oil.|
|“BOEM”||Bureau of Ocean Energy Management.|
|“Boepd”||Barrels of oil equivalent per day.|
|“Bopd”||Barrels of oil per day.|
|“BP”||BP p.l.c. and related subsidiaries.|
|“Bwpd”||Barrels of water per day.|
|“Corporate Revolver”||Revolving Credit Facility Agreement dated November 23, 2012 (as amended or as amended and restated from time to time).|
|“COVID-19”||Coronavirus disease 2019.|
|“Debt cover ratio”||The “debt cover ratio” is broadly defined, for each applicable calculation date, as the ratio of (x) total long‑term debt less cash and cash equivalents and restricted cash, to (y) the aggregate EBITDAX (see below) of the Company for the previous twelve months.|
|“Developed acreage”||The number of acres that are allocated or assignable to productive wells or wells capable of production.|
|“Development”||The phase in which an oil or natural gas field is brought into production by drilling development wells and installing appropriate production systems.|
|“DGE”||Deep Gulf Energy (together with its subsidiaries).|
|“DST”||Drill stem test.|
|“Dry hole” or “Unsuccessful well”||A well that has not encountered a hydrocarbon bearing reservoir expected to produce in commercial quantities.|
|“EBITDAX”||Net income (loss) plus (i) exploration expense, (ii) depletion, depreciation and amortization expense, (iii) equity‑based compensation expense, (iv) unrealized (gain) loss on commodity derivatives (realized losses are deducted and realized gains are added back), (v) (gain) loss on sale of oil and gas properties, (vi) interest (income) expense, (vii) income taxes, (viii) loss on extinguishment of debt, (ix) doubtful accounts expense and (x) similar other material items which management believes affect the comparability of operating results.|
|“ESG”||Environmental, social, and governance.|
|“ESP”||Electric submersible pump.|
|“E&P”||Exploration and production.|
|“Facility”||Facility agreement dated March 28, 2011 (as amended or as amended and restated from time to time).|
|“FASB”||Financial Accounting Standards Board.|
|“Farm‑in”||An agreement whereby a party acquires a portion of the participating interest in a block from the owner of such interest, usually in return for cash and/or for taking on a portion of future costs or other performance by the assignee as a condition of the assignment.|
|“Farm‑out”||An agreement whereby the owner of the participating interest agrees to assign a portion of its participating interest in a block to another party for cash and/or for the assignee taking on a portion of future costs and/or other work as a condition of the assignment.|
|“FEED”||Front End Engineering Design.|
|“Field life cover ratio”|
The “field life cover ratio” is broadly defined, for each applicable forecast period, as the ratio of (x) the forecasted net present value of net cash flow through depletion plus the net present value of the forecast of certain capital expenditures incurred in relation to the Ghana and Equatorial Guinea assets, to (y) the aggregate loan amounts outstanding under the Facility.
|“FLNG”||Floating liquefied natural gas.|
|“FPS”||Floating production system.|
|“FPSO”||Floating production, storage and offloading vessel.|
|“GAAP”||Generally Accepted Accounting Principles in the United States of America.|
|“GEPetrol”||Guinea Equatorial De Petroleos.|
|“GJFFDP”||Greater Jubilee Full Field Development Plan.|
|“GNPC”||Ghana National Petroleum Corporation.|
|“GoM Term Loan”||Senior Secured Term Loan Credit Agreement dated September 30, 2020.|
|“Greater Tortue Ahmeyim”||Ahmeyim and Guembeul discoveries.|
|“GTA UUOA”||Unitization and Unit Operating Agreement covering the Greater Tortue Ahmeyim Unit.|
|“HLS”||Heavy Louisiana Sweet.|
|“Jubilee UUOA”||Unitization and Unit Operating Agreement covering the Jubilee Unit.|
|“KTIPI”||Kosmos-Trident International Petroleum Inc.|
|“Interest cover ratio”||The “interest cover ratio” is broadly defined, for each applicable calculation date, as the ratio of (x) the aggregate EBITDAX (see above) of the Company for the previous twelve months, to (y) interest expense less interest income for the Company for the previous twelve months.|
|“LNG”||Liquefied natural gas.|
|“Loan life cover ratio”||The “loan life cover ratio” is broadly defined, for each applicable forecast period, as the ratio of (x) net present value of forecasted net cash flow through the final maturity date of the Facility plus the net present value of forecasted capital expenditures incurred in relation to the Ghana and Equatorial Guinea assets, to (y) the aggregate loan amounts outstanding under the Facility.|
|“LSE”||London Stock Exchange.|
|“LTIP”||Long Term Incentive Plan.|
|“MBbl”||Thousand barrels of oil.|
|“MBoe”||Thousand barrels of oil equivalent.|
|“Mcf”||Thousand cubic feet of natural gas.|
|“Mcfpd”||Thousand cubic feet per day of natural gas.|
|“MMBbl”||Million barrels of oil.|
|“MMBoe”||Million barrels of oil equivalent.|
|“MMBtu”||Million British thermal units.|
|“MMcf”||Million cubic feet of natural gas.|
|“MMcfd”||Million cubic feet per day of natural gas.|
|“MMTPA”||Million metric tonnes per annum.|
|“Natural gas liquid” or “NGL”||Components of natural gas that are separated from the gas state in the form of liquids. These include propane, butane, and ethane, among others.|
|“NYSE”||New York Stock Exchange.|
|“Ophir”||Ophir Energy plc.|
|“Petroleum contract”||A contract in which the owner of hydrocarbons gives an E&P company temporary and limited rights, including an exclusive option to explore for, develop, and produce hydrocarbons from the lease area.|
|“Petroleum system”||A petroleum system consists of organic material that has been buried at a sufficient depth to allow adequate temperature and pressure to expel hydrocarbons and cause the movement of oil and natural gas from the area in which it was formed to a reservoir rock where it can accumulate.|
|“Plan of development” or “PoD”||A written document outlining the steps to be undertaken to develop a field.|
|“Productive well”||An exploratory or development well found to be capable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.|
|“Prospect(s)”||A potential trap that may contain hydrocarbons and is supported by the necessary amount and quality of geologic and geophysical data to indicate a probability of oil and/or natural gas accumulation ready to be drilled. The five required elements (generation, migration, reservoir, seal and trap) must be present for a prospect to work and if any of these fail neither oil nor natural gas may be present, at least not in commercial volumes.|
|“Proved reserves”||Estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be economically recoverable in future years from known reservoirs under existing economic and operating conditions, as well as additional reserves expected to be obtained through confirmed improved recovery techniques, as defined in SEC Regulation S‑X 4‑10(a)(2).|
|“Proved developed reserves”||Those proved reserves that can be expected to be recovered through existing wells and facilities and by existing operating methods.|
|“Proved undeveloped reserves”||Those proved reserves that are expected to be recovered from future wells and facilities, including future improved recovery projects which are anticipated with a high degree of certainty in reservoirs which have previously shown favorable response to improved recovery projects.|
|“RSC”||Ryder Scott Company, L.P.|
|“SEC”||Securities and Exchange Commission.|
|“7.125% Senior Notes”||7.125% Senior Notes due 2026.|
|“7.750% Senior Notes”||7.750% Senior Notes due 2027.|
|“7.500% Senior Notes”||7.500% Senior Notes due 2028.|
|“Shelf margin”||The path created by the change in direction of the shoreline in reaction to the filling of a sedimentary basin.|
|“Shell”||Royal Dutch Shell and related subsidiaries.|
|“Stratigraphy”||The study of the composition, relative ages and distribution of layers of sedimentary rock.|
|“Stratigraphic trap”||A stratigraphic trap is formed from a change in the character of the rock rather than faulting or folding of the rock and oil is held in place by changes in the porosity and permeability of overlying rocks.|
|“Structural trap”||A topographic feature in the earth’s subsurface that forms a high point in the rock strata. This facilitates the accumulation of oil and gas in the strata.|
|“Structural‑stratigraphic trap”||A structural‑stratigraphic trap is a combination trap with structural and stratigraphic features.|
|“Submarine fan”||A fan‑shaped deposit of sediments occurring in a deep water setting where sediments have been transported via mass flow, gravity induced, processes from the shallow to deep water. These systems commonly develop at the bottom of sedimentary basins or at the end of large rivers.|
|“TAG GSA”||TEN Associated Gas - Gas Sales Agreement.|
|“TEN”||Tweneboa, Enyenra and Ntomme.|
|“Three‑way fault trap”||A structural trap where at least one of the components of closure is formed by offset of rock layers across a fault.|
“Tortue Phase 1 SPA”
|Greater Tortue Ahmeyim Agreement for a Long Term Sale and Purchase of LNG.|
|“Trafigura”||Trafigura Group PTD, Ltd. and related subsidiaries including Trafigura Trading LLC.|
|“Trap”||A configuration of rocks suitable for containing hydrocarbons and sealed by a relatively impermeable formation through which hydrocarbons will not migrate.|
|“Undeveloped acreage”||Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains discovered resources.|
|“WCTP”||West Cape Three Points.|
Cautionary Statement Regarding Forward‑Looking Statements
This annual report on Form 10‑K contains estimates and forward‑looking statements, principally in “Item 1. Business,” “Item 1A. Risk Factors” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Our estimates and forward‑looking statements are mainly based on our current expectations and estimates of future events and trends, which affect or may affect our businesses and operations. Although we believe that these estimates and forward‑looking statements are based upon reasonable assumptions, they are subject to several risks and uncertainties and are made in light of information currently available to us. Many important factors, in addition to the factors described in our annual report on Form 10‑K, may adversely affect our results as indicated in forward‑looking statements. You should read this annual report on Form 10‑K and the documents that we have filed as exhibits hereto completely and with the understanding that our actual future results may be materially different from what we expect. Our estimates and forward‑looking statements may be influenced by the following factors, among others:
•the impact of the COVID-19 pandemic on us and the overall business environment;
•our ability to find, acquire or gain access to other discoveries and prospects and to successfully develop and produce from our current discoveries and prospects;
•uncertainties inherent in making estimates of our oil and natural gas data;
•the successful implementation of our and our block partners’ prospect discovery and development and drilling plans;
•projected and targeted capital expenditures and other costs, commitments and revenues;
•termination of or intervention in concessions, rights or authorizations granted to us by the governments of the countries in which we operate (or their respective national oil companies) or any other federal, state or local governments or authorities;
•our dependence on our key management personnel and our ability to attract and retain qualified technical personnel;
•the ability to obtain financing and to comply with the terms under which such financing may be available;
•the volatility of oil, natural gas and NGL prices, as well as our ability to implement hedges addressing such volatility on commercially reasonable terms;
•the availability, cost, function and reliability of developing appropriate infrastructure around and transportation to our discoveries and prospects;
•the availability and cost of drilling rigs, production equipment, supplies, personnel and oilfield services;
•other competitive pressures;
•potential liabilities inherent in oil and natural gas operations, including drilling and production risks and other operational and environmental risks and hazards;
•current and future government regulation of the oil and gas industry or regulation of the investment in or ability to do business with certain countries or regimes;
•cost of compliance with laws and regulations;
•changes in, or new, environmental, health and safety or climate change or GHG laws, regulations and executive orders, or the implementation, or interpretation, of those laws, regulations and executive orders;
•adverse effects of sovereign boundary disputes in the jurisdictions in which we operate;
•geological, geophysical and other technical and operations problems including drilling and oil and gas production and processing;
•military operations, civil unrest, outbreaks of disease, terrorist acts, wars or embargoes;
•the cost and availability of adequate insurance coverage and whether such coverage is enough to sufficiently mitigate potential losses and whether our insurers comply with their obligations under our coverage agreements;
•our vulnerability to severe weather events, including tropical storms and hurricanes in the Gulf of Mexico;
•our ability to meet our obligations under the agreements governing our indebtedness;
•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.
Item 1. Business
Kosmos is a full-cycle deepwater independent oil and gas exploration and production company focused along the Atlantic Margins. Our key assets include production offshore Ghana, Equatorial Guinea and the U.S. Gulf of Mexico, as well as a world-class gas development offshore Mauritania and Senegal. We also maintain a sustainable proven basin exploration program in Equatorial Guinea, Ghana and the U.S. Gulf of Mexico. Kosmos is listed on the NYSE and LSE and is traded under the ticker symbol KOS.
Kosmos was founded in 2003 to find oil in under‑explored or overlooked parts of West Africa. In its relatively brief history, we have successfully opened two new hydrocarbon basins through the discovery of the Jubilee field offshore Ghana in 2007 and the Greater Tortue Ahmeyim field in 2015 (which includes the Ahmeyim and Guembeul-1 discovery wells offshore Mauritania and Senegal in 2015 and 2016, respectively). Jubilee was one of the largest oil discoveries worldwide in 2007 and is considered one of the largest finds offshore West Africa discovered during that decade. The Ahmeyim discovery was one of the largest natural gas discoveries worldwide in 2015 and is one of the largest gas discoveries ever offshore West Africa.
Over the past few years, our business strategy has evolved to focus on production enhancing infill drilling and well work, infrastructure-led exploration as well as value-accretive acquisitions. This strategic evolution was initially enabled by our acquisition of the Ceiba Field and Okume Complex assets offshore Equatorial Guinea in 2017, together with access to surrounding exploration licenses, and bolstered by the 2018 acquisition of Deep Gulf Energy, a deepwater company operating in the U.S. Gulf of Mexico, which further enhanced our production, exploitation and infrastructure-led exploration capabilities. Most recently, this strategy was demonstrated by the recent acquisition of additional interests in the Jubilee and TEN fields offshore Ghana.
Our Business Strategy
As a full-cycle deepwater E&P company, our mission is to safely deliver production and free cash flow from a portfolio rich in opportunities through a disciplined allocation of capital and optimal portfolio management for the benefit of our shareholders and stakeholders. As a responsible company, we are working to supply the energy the world needs today, find and develop cleaner energy to advance the energy transition, and be a force for good in our host countries.
Our business strategy is designed to accomplish this mission by focusing on three key objectives: (1) maximize the value of our producing assets; (2) progress our discovered resources toward project sanction and into proved reserves, production, and cash flow through efficient appraisal, development and exploitation; and (3) add new lower carbon resources through an efficient low cost exploration program in proven basins or acquisitions. We are focused on increasing production, cash flows and reserves from our producing assets in Equatorial Guinea, Ghana, and the U.S. Gulf of Mexico. In Mauritania and Senegal, we are progressing our Greater Tortue Ahmeyim development with the objective of reaching first gas in the third quarter of 2023 while advancing the second phase of the development. In addition, our portfolio consists of large discovered resources and an inventory of prospects, which we plan to continue to mature for future drilling and development, providing us access to additional high return growth potential in the coming years. We are also working with our partners and host governments on projects to reduce the carbon intensity of our production assets, such as the elimination of routine flaring in Ghana.
Grow cash flow, proved reserves and production through exploitation, development and infrastructure-led exploration activities
We plan to grow cash flow, proved reserves and production by further exploiting our fields offshore Equatorial Guinea, Ghana, and the U.S. Gulf of Mexico. In Equatorial Guinea, our activity set is expanding beyond production optimization projects, such as utilizing electrical submersible pumps, to include development drilling and infrastructure-led exploration which, if successful, can be brought online quickly via subsea tieback to existing infrastructure. In Ghana, we plan to continue drilling additional development and production wells at both the Jubilee and TEN fields. In the U.S. Gulf of Mexico, we plan to continue development drilling in existing fields and maintain a deep inventory of infrastructure-led exploration targets. In addition, we have sanctioned the first phase of the Greater Tortue Ahmeyim development offshore Mauritania and Senegal, which defines the timing and path to first gas. Beyond the Phase 1 development of Greater Tortue Ahmeyim, growth is also expected to be realized through additional development phases of Greater Tortue Ahmeyim and through the development of all or a portion of our other natural gas discoveries in Mauritania and Senegal. During 2022, we
plan to continue to mature development concepts from previous discoveries in Mauritania, Senegal, the U.S. Gulf of Mexico and Equatorial Guinea, as well as mature additional infrastructure-led prospects in the U.S. Gulf of Mexico, Equatorial Guinea, and Ghana.
Focus on optimally developing our discoveries to initial production
Our approach to development is designed to deliver first production on an accelerated timeline, leverage early learnings to improve future outcomes and maximize returns. In certain circumstances, we believe a phased approach can be employed to optimize full‑field development. A phased approach facilitates refinement of the development plans based on experience gained in initial phases of production and by leveraging existing infrastructure as subsequent phases of development are implemented. Production and reservoir performance from the initial phases are monitored closely to determine the most efficient and effective techniques to maximize the recovery of reserves and returns. Other benefits include minimizing upfront capital costs, reducing execution risks through smaller initial infrastructure requirements, and enabling cash flow from the initial phases of production to fund a portion of capital costs for subsequent phases. Our development of the Jubilee Field is an example of this approach. The Greater Tortue Ahmeyim development is also being developed in a phased approach, consistent with our business strategy. This is anticipated to result in first gas approximately eight years after initial discovery. Finally, our approach to discoveries in the U.S. Gulf of Mexico is to develop them via subsea tie-back to existing host facilities with spare capacity, which reduces development costs and the average timeline to first production. The Winterfell discovery (2021) and subsequent appraisal success (early 2022) is an example of this, with development expected to deliver first production in around two years.
Apply our entrepreneurial culture, which fosters innovation and creativity, to continue our successful exploration and development program
Our employees are critical to the success of our business strategy, and we have created an environment that enables them to focus their knowledge, skills and experience on finding, developing and producing new fields and optimizing production from existing fields. Culturally, we have an open, team‑oriented work environment that fosters entrepreneurial, creative and contrarian thinking. This approach enables us to fully consider and understand both risk and reward, as well as deliberately and collectively pursue ideas that create and maximize value and free cash flow.
We are led by an experienced management team with a successful track record. Our management team members average over 25 years of industry experience and have participated in discovering and developing multiple large-scale upstream projects around the world. Our experience, industry relationships and technical expertise are our core competitive strengths and are crucial to our success.
Our returns focused exploration approach
Our exploration activity, which is deeply rooted in a fundamental, geologic approach, is focused on proven basins with high-graded infrastructure-led prospects and material play extension opportunities. We target specific areas with sufficient size to manage exploration risks and provide scale should the exploration concept prove successful. We also look for: (i) long‑term contract durations to enable the “right” exploration program to be executed, (ii) play type diversity to provide multiple exploration concept options, (iii) prospect dependency to enhance the chance of replicating success, and (iv) attractive fiscal terms to maximize the commercial viability of discovered hydrocarbons. Alongside the subsurface analysis, Kosmos gains a thorough understanding of the “above‑ground” dynamics in each of the countries in which we operate, which may influence a particular country’s relative desirability from an overall oil and natural gas operating and risk adjusted return perspective.
Our approach is aimed at areas where we have existing production and where there is sufficient infrastructure capacity to enable the development of new discoveries via subsea tieback. Acquisition of the Ceiba Field and Okume Complex in Equatorial Guinea and assets in the U.S. Gulf of Mexico have added high-quality prospectivity to our inventory of infrastructure-led exploration opportunities given their attractive acreage positions within proximity of existing infrastructure with excess capacity available. Existing infrastructure allows us to shorten the time cycle from discovery to first production, lower the capital requirements and increase the returns.
Pursuing value accretive, opportunistic transactions that meet our strategic and financial objectives
Since 2017, we have completed three separate significant acquisitions of oil and natural gas producing properties for total value of approximately $2.0 billion dollars, as of the effective date of the acquisitions. These acquisitions were targeted to increase and complement our existing properties, providing production diversification while increasing the quality of investment opportunities in our portfolio. Our experienced team of management and technical professionals intend to continue
identifying, evaluating and pursuing transactions involving oil and natural gas properties that are complementary to our core operating areas, as well as opportunities in other basins where we can apply our existing knowledge, expertise and relationships to create shareholder value. Our focus is on transactions where we can leverage our operational experience and expertise to provide productivity and cost improvements, invest in additional developmental opportunities in such assets and implement an infrastructure-led exploration program for nearby prospects.
Secure a premium license to operate through industry-leading ESG performance
We recognize that advancing the societies in which we work and operating in a manner that protects the environment is critical for creating long-term returns. We aim to continuously improve our ESG credentials by working with a range of stakeholders, including shareholders, partners, suppliers, host governments and civil society organizations.
We aim to act as a force for good by advancing the “Just Transition” in our host countries and communities – namely by supporting economic and social development in the places where we work while lowering emissions. We use the United Nations Sustainable Development Goals to understand how our activities promote economic and social progress in host countries. Adopted in 2013, our Business Principles reflect our shared values as a company, define how we conduct our business and set the standards to which we hold ourselves accountable. Our Business Principles are supported by more detailed policies, procedures, and management systems. Each year, we report on our ESG approach and performance in our Sustainability Report and on our website.
Most recently, we have focused on evaluating the costs, benefits, risks, and opportunities that climate change and the global energy transition may present to our business and integrating them into our business strategy. As part of this effort, we established governance structures to monitor and manage climate-related risks and opportunities; developed a strategy to measure and reduce greenhouse gas emissions from our own operations and mitigate remaining emissions through innovative nature-based solutions. We have published a Climate Risk and Resilience Report that adheres to the recommendations of the Task Force on Climate-related Disclosure (“TCFD”). The report reviews how we are identifying and managing climate-related risks and opportunities across four categories: Governance, Strategy, Risk Management, and Metrics and Targets. In addition, the report sets forth our goal to achieve operated Scope 1 and Scope 2 carbon neutrality by 2030 or sooner, a scenario analysis demonstrating the resilience of our portfolio under a scenario aligned with the Paris Agreement’s goals, and a description of innovative nature-based carbon capture projects used to mitigate emissions that cannot be eliminated.
Maintain financial discipline
Execution of our strategy requires us to maintain a conservative financial approach with a strong balance sheet, ample liquidity, and a commitment to low leverage. As of December 31, 2021, our liquidity was approximately $770 million.
Additionally, we use derivative instruments to partially limit our exposure to fluctuations in oil prices. We have an active commodity hedging program where we aim to hedge a portion of our anticipated sales volumes on a two to three year rolling basis, with the goal to protect against the downside price scenario while still retaining partial exposure to the upside. As of December 31, 2021, we have hedged positions covering approximately 12.5 million barrels of oil production in 2022. We also maintain insurance to partially protect against loss of production revenues from certain of our producing assets.
Operations by Geographic Area
We currently have operations in Africa and the U.S. Gulf of Mexico. Presently, our operating revenues are generated from our operations offshore Ghana, Equatorial Guinea, and the U.S. Gulf of Mexico. The following tables provide a summary of certain key 2021 data for our geographic areas.
|Geographic Area||Sales Volumes (Net to Kosmos)||Percentage of Total Sales Volumes||Revenue||Year-End Estimated Proved Reserves(1)||Percentage of Total Estimated Proved Reserves|
|(in MMboe)||(in thousands)||(in MMboe)|
|Ghana(2)||9.0 ||45 ||%||$||644,232 ||131 ||44 ||%|
|Equatorial Guinea||3.7 ||19 ||%||260,520 ||27 ||9 ||%|
|Mauritania/Senegal||— ||— ||— ||106 ||35 ||%|
|U.S. Gulf of Mexico||7.2 ||36 ||%||427,261 ||36 ||12 ||%|
|Total||19.9 ||100 ||%||$||1,332,013 ||301 ||100 ||%|
(1)For information concerning our estimated proved reserves as of December 31, 2021, see “—Our Reserves.” Totals within table may not add a result of rounding.
(2)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.
Information about our deepwater fields is summarized in the following table.
| || || ||Kosmos|| || || || |
| || || ||Participating|| || || || ||License|
|Fields||License|| ||Interest|| ||Operator|| ||Stage||Expiration|
|Ghana(1)|| || || || || || || |
|Jubilee||WCTP/DT||(2)||42.1 ||%||(2)||Tullow|| ||Production||2034|
|TEN||DT|| ||28.1 ||%||(4)||Tullow|| ||Production||2036|
|U.S. Gulf of Mexico(1)|
|Barataria||MC 521||22.5 ||%||Kosmos||Production||(8)|
|Big Bend||MC 697 / 698 / 742||5.3 ||%||Fieldwood||Production||(8)|
|Don Larsen||EB 598||20.0 ||%||Occidental||Production||(8)|
|Gladden ||MC 800||20.0 ||%||W&T||Production||(8)|
|Kodiak||MC 727 / 771||29.1 ||%||Kosmos||Production||(8)|
|Marmalard||MC 255 / 300||11.4 ||%||Murphy||Production||(8)|
|Nearly Headless Nick||MC 387||21.9 ||%||Murphy||Production||(8)|
|Danny Noonan||EC 381 / GB 506||30.0 ||%||Talos||Production||(8)|
|Odd Job||MC 214 / 215||Various||(5)||Kosmos||Production||(8)|
|Sargent||GB 339||50.0 ||%||Kosmos||Production||(8)|
|SOB II||MC 431||11.8 ||%||Murphy||Production||(8)|
|S. Santa Cruz||MC 563||40.5 ||%||Kosmos||Production||(8)|
|Tornado||GC 281||35.0 ||%||Talos||Production||(8)|
|Winterfell||GC 943 / 944||16.4 ||%||Beacon||Appraisal||(8)|
|Mauritania|| || || || || || || |
|Greater Tortue Ahmeyim||Block C8||(3)||26.8 ||%||BP|| ||Development||2049(9)|
|Bir Allah||Block C8|| ||28.0 ||%||(6)||BP|| ||Appraisal||2022|
|Orca||Block C8||28.0 ||%||(6)||BP||Appraisal||2022|
|Senegal|| || || || || || || |
|Greater Tortue Ahmeyim||Saint Louis Offshore Profond||(3)||26.7 ||%||BP||Development||2044(10)|
|Teranga||Cayar Offshore Profond|| ||30.0 ||%||(7)||BP||Appraisal||2024|
|Yakaar||Cayar Offshore Profond||30.0 ||%||(7)||BP||Appraisal||2024|
|Ceiba Field and Okume Complex||Block G||40.4 ||%||Trident||Production||2029/2034(11)|
|Asam||Block S||40.0 ||%||Kosmos||Appraisal||2022|
(1)For information concerning our estimated proved reserves as of December 31, 2021, see “—Our Reserves.”
(2)The Jubilee Field straddles the boundary between the WCTP petroleum contract and the DT petroleum contract offshore Ghana. To optimize resource recovery in this field, we entered into the Jubilee UUOA in July 2009 with GNPC and the other block partners of each of these two blocks. The Jubilee UUOA governs the interests in and development of the Jubilee Field and created the Jubilee Unit from portions of the WCTP petroleum contract and the DT petroleum contract areas. The interest percentage is subject to redetermination of the participating interests in the Jubilee Field pursuant to the terms of the Jubilee UUOA. Our current paying interest on development activities in the Jubilee Field is 47.0%. Table above reflects additional interests acquired in the recent acquisition of additional interests in Ghana. See “Item 8. Financial Statements and Supplementary Data—Note 3—Acquisitions and Divestitures” for discussion of potential pre-emption impact.
(3)The Greater Tortue Ahmeyim Unit, which includes the Ahmeyim discovery in Mauritania Block C8 and the Guembeul discovery in the Senegal Saint Louis Offshore Profond Block, straddles the border between Mauritania and Senegal. To optimize resource recovery in this field, we entered into the GTA UUOA in February 2019 with the governments of Mauritania and Senegal. The GTA UUOA governs interests in and development of the Greater Tortue Ahmeyim Field and created the Greater Tortue Ahmeyim Unit from portions of the Mauritania Block C8 and the Senegal Saint Louis Offshore Profond Block areas. These interest percentages are subject to redetermination of the participating
interests in the Greater Tortue Ahmeyim Field pursuant to the terms of the GTA UUOA. Our current payment interest on development activities in the Greater Tortue Ahmeyim Unit is 26.7%.
(4)Our paying interest on development activities in the TEN fields is 31.4%. Table above reflects additional interests acquired in recent acquisition of additional interests in Ghana. See “Item 8. Financial Statements and Supplementary Data—Note 3—Acquisitions and Divestitures” for discussion of potential pre-emption impact.
(5)Our interests in blocks MC 214 and MC 215 are 61.1% and 54.9%, respectively.
(6)SMH has the option to acquire up to an additional 4% participating interest in a commercial development on Block C8. These interest percentages do not give effect to the exercise of such option.
(7)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.
(8)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.
(9)License expiration date can be extended by an additional ten years subject to certain conditions being met.
(10)License expiration date can be extended by an additional twenty years subject to certain conditions being met.
(11)The Ceiba and Okume Complex are two approved fields within the Production Sharing Contract for Block G. Based on Commercial Discovery approval date for each field by the Ministry of Mines and Hydrocarbons, the Ceiba field Production Sharing Contract expires in 2029, and the Okume Complex field Production Sharing Contract expires in 2034.
Exploration License and Lease Areas
| ||Kosmos Average|| || |
| ||Number of||Participating|| || ||Current Phase|
|Country||Blocks||Interest|| ||Operator(s)||Expiration Range|
|Sao Tome and Principe||1||58.9%||(3)||Kosmos||2022|
|U.S. Gulf of Mexico||59||39.9%||Kosmos, Murphy, Talos, Fieldwood, Occidental, W&T Offshore, LLOG, Beacon||through 2029||(5)|
(1)Should a commercial discovery be made, GEPetrol's 20% carried interest will convert to a 20% participating interest for all development and production operations.
(2)Should a commercial discovery be made, SMH’s 10% carried interest is extinguished and SMH will have an option to obtain a participating interest in the discovery area between 10% and 14%. SMH will pay its portion of development and production costs in a commercial development on the blocks. The interest percentage does not give effect to the exercise of such option.
(3)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.
(4)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.
(5)Our U.S. Gulf of Mexico blocks can be held by operations or commercial production, and the corresponding lease periods extend as long as governmental approved operations continue on the relevant block. This can extend the lease expiration to a date later than 2029.
The WCTP Block and DT Block are located within the Tano Basin, offshore Ghana. This basin contains a proven world‑class petroleum system as evidenced by our discoveries. In October 2021, Kosmos completed the acquisition of Anadarko WCTP Company which owned a participating interest in the WCTP Block and DT Block offshore Ghana, including an 18.0% participating interest in the Jubilee Unit Area and an 11.1% participating interest in the TEN fields. Following closing of the acquisition, Kosmos’ interest in the Jubilee Unit Area increased from 24.1% to 42.1%, and Kosmos’ interest in the TEN fields increased from 17.0% to 28.1%. Under the Deepwater Tano Block Joint Operating Agreement, certain joint venture partners have pre-emption rights that, if fully exercised and approved by the Government of Ghana, could reduce our ultimate interest in the Jubilee Unit Area by 3.8% to 38.3%, and our ultimate interest in the TEN fields by 8.3% to 19.8%. In November 2021, we received notice from certain joint venture partners that they intend to exercise their pre-emption rights in relation to Kosmos' acquisition of Anadarko WCTP Company. The exercise of pre-emption rights is subject to finalizing definitive agreements with Kosmos and requires approval from GNPC and the Ghanaian Ministry of Energy. The following is a brief discussion of our discoveries on our license areas offshore Ghana.
The Jubilee Field was discovered by Kosmos in 2007, with first oil produced in 2010. Appraisal activities confirmed that the Jubilee discovery straddled the WCTP and DT Blocks. Pursuant to the terms of the Jubilee UUOA, the discovery area was unitized for purposes of joint development by the WCTP and DT Block partners.
The Jubilee Field is located approximately 60 kilometers offshore Ghana in water depths of approximately 1,000 to 1,800 meters, which led to the decision to implement an FPSO based development. The FPSO is designed to provide water and natural gas injection to support reservoir pressure, to process and store oil and to export gas through a pipeline to the mainland. The Jubilee Field is being developed in a phased approach. The initial phase provided subsea infrastructure capacity for additional production and injection wells to be drilled in future phases of development.
The Government of Ghana completed the construction and connection of a gas pipeline in 2017 from the Jubilee Field to transport natural gas to the mainland for processing and sale. In 2021, the partnership exported approximately 85 million standard cubic feet per day (gross) on average from the Jubilee field to the mainland. In the absence of continuous export of large quantities of natural gas from the Jubilee Field, it is anticipated that we will need to re-inject or flare such natural gas. Our inability to continuously export associated natural gas from the Jubilee Field could impact our oil production.
In February 2016, the Jubilee Field operator identified an issue with the turret bearing of the FPSO Kwame Nkrumah. Kosmos and its partners completed the lifting and locking of the main turret bearing, and the rotation of the vessel to its final heading in the second half of 2018. Permanent spread mooring of the vessel was completed in 2019. The catenary anchor leg mooring (“CALM”) Buoy, the final phase of the turret remediation project, was installed and commissioned in February 2021.
Oil production from the Jubilee Field averaged approximately 74,900 Bopd gross (20,200 Bopd net) during 2021.
The TEN fields are located in the western and central portions of the DT Block, approximately 48 kilometers offshore Ghana in water depths of approximately 1,000 to 1,700 meters. The discoveries are being jointly developed with shared infrastructure and a single FPSO, with first oil produced in 2016.
Similar to Jubilee, the TEN fields are being developed in a phased manner. The TEN PoD was designed to include an expandable subsea system that would provide for multiple phases.
Oil production from TEN averaged approximately 32,800 Bopd gross (5,900 Bopd net) during 2021.
The construction and connection of a gas pipeline between the Jubilee and TEN fields to transport natural gas to the mainland for processing and sale was completed in 2017. In December 2017, we signed the TAG GSA. In 2021, the partnership exported approximately 8 million standard cubic feet per day (gross) on average from the TEN field to the mainland. Our inability to continuously export associated natural gas from the TEN fields could impact our oil production.
U.S. Gulf of Mexico
In the U.S. Gulf of Mexico, Kosmos maintains: (i) a portfolio of producing assets that Kosmos can continue to exploit, (ii) infrastructure-led exploration growth assets, and (iii) a high-quality inventory of exploration prospects across the Garden Banks, Green Canyon and Mississippi Canyon protraction areas. We have expanded our inventory through the U.S. Gulf of Mexico Federal lease sales and farm-in transactions, including expansion into the Walker Ridge, De Soto Canyon and Keathley Canyon protraction areas of the U.S. Gulf of Mexico. Our U.S. Gulf of Mexico assets averaged approximately 19,700 Boepd net (~ 82% oil) from 12 fields during 2021.
The following is a brief discussion of our key producing fields in the U.S. Gulf of Mexico.
The Odd Job field is producing through the Delta House FPS, operated by Murphy. The technical team initially identified the Middle Miocene sands at the Odd Job prospect, and these sands are currently producing. The Odd Job 214 #2 well, the third well in the Odd Job field, was drilled in 2018, and came online in the fourth quarter of 2019. Net production during 2021 averaged approximately 6,500 Boepd net.
The Tornado field is producing from three Pliocene wells through the Helix Producer I, a ship-shaped, dynamically-positioned production platform in the deepwater U.S. Gulf of Mexico, which is operated by Talos Energy. To help enhance overall recoveries in the Tornado field, the Tornado 4 water injection well was drilled and came online in 2020. During the second quarter of 2021, the Tornado 5 infill well was successfully drilled and completed. The Tornado 5 well was brought online in July 2021. Net production during 2021 averaged approximately 5,800 Boepd net.
The Kodiak field is producing from one well, which is completed in the Middle Miocene sands. This well is flowing through the Devils Tower Spar platform, which is operated by ENI. In April 2021, a second development well was brought online through existing infrastructure to the Devils Tower Spar platform with one of two zones intermittently producing. During the third quarter of 2021, the well continued to experience production issues and was shut-in. We have agreed with partners to side-track the well in the first half of 2022 to restore production from the second Kodiak development well. Net production during 2021 averaged approximately 2,700 Boepd net.
The Marmalard field produces from four wells, each completed in Middle Miocene sands. These wells are flowing through the Delta House FPS, operated by Murphy. Net production during 2021 averaged approximately 1,800 Boepd net.
South Santa Cruz / Barataria
The South Santa Cruz field is producing from one well in a Late Miocene sand. The Barataria field is also producing from one well in a Late Miocene sand. Both fields produce through the Blind Faith semi-submersible platform, which is operated by Chevron. Net production from these two wells during 2021 averaged approximately 900 Boepd net.
The C8 and C12 blocks are located on the western margin of the Mauritania Salt Basin offshore Mauritania and range in water depths from 100 to 3,000 meters. These blocks are located in a proven petroleum system, with our primary targets being Cretaceous sands in structural and stratigraphic traps.
These blocks cover an aggregate area of approximately 2.4 million acres (gross). We have acquired approximately 2,500 line-kilometers of 2D seismic data and 9,600 square kilometers of 3D seismic data covering portions of our blocks in Mauritania. Based on these 2D and 3D seismic programs, we have drilled three successful exploration wells and an appraisal well and have identified additional prospects in our blocks. We continue to integrate the results of our drilling program in Mauritania. In 2021, at the conclusion of the second exploration period, Block C13 offshore Mauritania was relinquished.
The Senegal Blocks are located in the Senegal River Cretaceous petroleum system and range in water depth from 300 to 3,100 meters. The area is an extension of the working petroleum system in the Mauritania Salt Basin. We acquired approximately 3,700 square kilometers of 3D seismic data over the Senegal Blocks in 2015 and 2016. We have drilled three successful exploration wells and two appraisal wells.
The following is a brief discussion of our discoveries to date offshore Mauritania and Senegal.
Greater Tortue Ahmeyim Development
The Greater Tortue Ahmeyim discoveries are significant, play-opening gas discoveries for the outboard Cretaceous petroleum system and are located approximately 120 kilometers offshore Mauritania and Senegal. The Greater Tortue Ahmeyim development straddles Block C8 offshore Mauritania and Saint Louis Offshore Profond Block offshore Senegal.
We have drilled four wells within the Greater Tortue Ahmeyim development, Tortue-1, Guembeul-1, Ahmeyim-2 and Greater Tortue Ahmeyim-1 (GTA-1). The wells penetrated multiple, excellent quality gas reservoirs, including the Lower Cenomanian, Upper Cenomanian and underlying Albian. The wells successfully delineated the Ahmeyim and Guembeul gas discoveries and demonstrated reservoir continuity, as well as static pressure communication between the three wells drilled within the Lower Cenomanian reservoir. The discovery ranges in water depths from approximately 2,700 meters to 2,800 meters, with total depths drilled ranging from approximately 5,100 meters to 5,250 meters.
The Tortue-1 discovery well, located in Block C8 offshore Mauritania, intersected approximately 117 meters of net hydrocarbon pay. A single gas pool was encountered in the Lower Cenomanian objective, which is comprised of three reservoirs totaling 88 meters in thickness over a gross hydrocarbon interval of 160 meters. A fourth reservoir totaling 19 meters was penetrated within the Upper Cenomanian target over a gross hydrocarbon interval of 150 meters. The exploration well also intersected an additional 10 meters of net hydrocarbon pay in the lower Albian section, which is interpreted to be gas.
The Guembeul-1 discovery well, located in the northern part of the Saint Louis Offshore Profond area in Senegal, is located approximately five kilometers south of the Tortue-1 exploration well in Mauritania. The well encountered 101 meters of net gas pay in two excellent quality reservoirs, including 56 meters in the Lower Cenomanian and 45 meters in the underlying Albian, with no water encountered.
The Ahmeyim-2 appraisal well is located in Block C8 offshore Mauritania, approximately five kilometers northwest, and 200 meters down-dip of the basin-opening Tortue-1 discovery. The well confirmed significant thickening of the gross reservoir sequences down-dip. The Ahmeyim-2 well encountered 78 meters of net gas pay in two excellent quality reservoirs, including 46 meters in the Lower Cenomanian and 32 meters in the underlying Albian.
The Greater Tortue Ahmeyim-1 (GTA-1) appraisal well was drilled on the eastern anticline within the unit development area of Greater Tortue Ahmeyim field. The GTA-1 well encountered approximately 30 meters of net gas pay in high quality Albian reservoir. The well was drilled in approximately 2,500 meters of water, approximately 10 kilometers inboard of the Guembeul-1A and Tortue-1 wells, to a total depth of 4,884 meters.
In 2017, we completed a DST on the Tortue-1 well, demonstrating that the Tortue field is a world-class resource and confirming key development parameters including well deliverability, reservoir connectivity, and fluid composition. The Tortue-1 well flowed at a sustained, equipment-constrained rate of approximately 60 MMcfd during the main extended flow period, with minimal pressure drawdown, providing confidence in well designs that are each capable of producing approximately 200 MMcfd. The DST results confirmed a connected volume per well consistent with the current development scheme, which together with the high well rate is expected to result in a low number of development wells compared to equivalent schemes. Initial analysis of fluid samples collected during the test indicate Tortue gas is well suited for liquefaction given low levels of liquids and minimal impurities. Data acquired from the DST was used to further optimize field development and to refine process design parameters critical to the FEED process.
In December 2018, we and our partners announced that a final investment decision for Phase 1 of the Greater Tortue Ahmeyim project had been agreed. The Greater Tortue Ahmeyim project is designed to produce gas from a deepwater subsea system to a mid-water FPSO, which processes the gas to make it liquefaction ready, and sends the gas through a pipeline to a FLNG facility. The FLNG facility is protected behind a nearshore hub (which serves as a breakwater and LNG terminal) and is located on the Mauritania and Senegal maritime border. The FLNG facility for Phase 1 is designed to produce approximately 2.5 million tons per annum on average. The project will provide LNG for global export, as well as make gas available for
domestic use in both Mauritania and Senegal. Following a competitive tender process, BP Gas Marketing was selected as the buyer for the LNG offtake for Greater Tortue Ahmeyim Phase 1, and the Tortue Phase 1 SPA was executed in February 2020 with an initial term of up to 20 years. Phase 1 of the project was approximately 70% complete at year-end 2021, with first gas for the project expected in the third quarter of 2023. The partnership has also been focused on optimizing Phase 2 of the project to deliver competitive returns in the current environment. Phase 2 of the Greater Tortue Ahmeyim project targets an expansion largely utilizing the infrastructure from Phase 1.
Other Mauritania and Senegal Discoveries
BirAllah and Orca Discoveries
The BirAllah discovery (formally known as Marsouin), located in Block C8 offshore Mauritania, is a significant, play-extending gas discovery, building on our successful exploration program in the outboard Cretaceous petroleum system offshore Mauritania. The Marsouin-1 well is located approximately 60 kilometers north of the Ahmeyim discovery and was drilled to a total depth of 5,150 meters in nearly 2,400 meters of water. Based on analysis of drilling results and logging data, Marsouin-1 encountered at least 70 meters of net gas pay in Upper and Lower Cenomanian intervals comprised of excellent quality reservoir sands.
The Orca-1 well, located in Block C8 offshore Mauritania, was drilled in October 2019 and delivered a major gas discovery. The Orca-1 well, which targeted a previously untested Albian play, encountered 36 meters of net gas pay in excellent quality reservoirs. In addition, the well extended the Cenomanian play fairway by confirming 11 meters of net gas pay in a down-structure position relative to the original Marsouin-1 discovery well. The location of the Orca-1 well proved both the structural and stratigraphic components of the trap are working, thereby proving a significant volume. The Orca-1 well was drilled in approximately 2,510 meters of water to a total measured depth of around 5,266 meters.
In total, we believe that Orca-1 and Marsouin-1 have de-risked more than sufficient resource to support a world-scale LNG project from the Cenomanian and Albian plays in the BirAllah area. The BirAllah and Orca discoveries are being analyzed as a potential joint development. We are currently in discussions with the government of Mauritania to extend the exploration phase of Block C8 which is currently set to expire in June 2022. As of December 31, 2021, capitalized costs related to BirAllah and Orca discoveries approximates $62.0 million.
Yakaar and Teranga Discoveries
The Teranga discovery is located in the Cayar Offshore Profond block approximately 65 kilometers northwest of Dakar and was our second exploration well offshore Senegal. The Teranga-1 discovery well is located in nearly 1,800 meters of water and was drilled to a total depth of approximately 4,850 meters. The well encountered 31 meters of net gas pay in good quality reservoir in the Lower Cenomanian objective. Well results confirm that a prolific inboard gas fairway extends approximately 200 kilometers south from the Marsouin-1 well in Mauritania through the Greater Tortue Ahmeyim area on the maritime boundary to the Teranga-1 well in Senegal.
The Yakaar discovery is located in the Cayar Offshore Profond block offshore Senegal, approximately 95 kilometers northwest of Dakar in approximately 2,600 meters of water. The Yakaar-1 discovery well was drilled to a total depth of approximately 4,900 meters. The well intersected a gross hydrocarbon column of 120 meters in three pools within the primary Lower Cenomanian objective and encountered 45 meters of net pay. In September 2019, we completed the Yakaar-2 appraisal well, which encountered approximately 30 meters of net gas pay. The Yakaar-2 well was drilled approximately nine kilometers from the Yakaar-1 exploration well and further delineated the southern extension of the field.
The results of the Yakaar-2 well underpin our view that the Yakaar-Teranga resource base is world-scale and has the potential to support an LNG project that provides significant volumes of natural gas to both domestic and export markets. Development of Yakaar-Teranga is being considered in a phased approach with Phase 1 providing domestic gas and data to optimize the development of future phases. It could also support the country’s “Plan Emergent Senegal” launched by the President of Senegal in 2014.
The EG-21, EG-24, S, and W blocks are located in the southern part of the Gulf of Guinea, in the Republic of Equatorial Guinea, west of the Rio Muni petroleum province with water depths up to 2,300 meters. These blocks are located in a proven petroleum system, with our primary targets being Cretaceous sands in structural and stratigraphic traps. We have over
10,000 square kilometers of 3D seismic over the blocks. The seismic data is being interpreted and high graded prospects for future drilling are being matured.
Ceiba Field and Okume Complex
In Equatorial Guinea, we maintain a 40.4% undivided participating interest in the Ceiba Field and Okume Complex. These offshore assets in the Gulf of Guinea provide cash flow through production with the potential to increase production through exploration opportunities with potential low cost tie-backs through the existing infrastructure.
The shared development of the Ceiba Field and Okume Complex consists of six subsea-well clusters that feed production to the Ceiba FPSO which is shared by both fields through a system of risers. The Okume Complex includes six platforms with an export line to move Okume production to the Ceiba FPSO.
Oil production from the Ceiba Field and Okume Complex averaged approximately 29,900 Bopd gross (9,700 Bopd net) during 2021.
In October 2019, the S-5 exploration well was drilled to a total depth of 4,400 meters in Block S offshore Equatorial Guinea, encountering 39 meters of net oil pay in good-quality Santonian reservoir. In July 2020, an appraisal plan was approved by the government of Equatorial Guinea. The well is located within tieback range of the Ceiba FPSO and the appraisal program is currently ongoing to establish the scale of the discovered resource and evaluate the optimum development solution.
Sao Tome and Principe
We are the operator for the petroleum contract covering Block 5, offshore Sao Tome and Principe in the Gulf of Guinea. The block covers an area of approximately 0.5 million acres (gross) in water depths ranging from 2,150 to 3,000 meters.
Our block is adjacent to, and represents a potential extension of, a proven and prolific petroleum system offshore Equatorial Guinea and northern Gabon comprising Cretaceous post-rift source rocks and Late Cretaceous reservoirs.
In August 2017, we completed a 3D seismic survey of approximately 2,500 square kilometers offshore Sao Tome and Principe. Processing has been completed and the 3D seismic data has been integrated into our geological evaluation. We continue to mature an inventory of prospects on the license area in Sao Tome and Principe and will continue to refine and assess the prospectivity. In the fourth quarter of 2021, we received approval for a six month extension to the current exploration phase for Block 5 offshore Sao Tome and Principe through November 2022.
The following table sets forth summary information about our estimated proved reserves as of December 31, 2021. See “Item 8. Financial Statements and Supplementary Data—Supplemental Oil and Gas Data (Unaudited)” for additional information.
Our estimated proved reserves as of December 31, 2021, 2020, and 2019 were associated with our fields in Ghana, Equatorial Guinea, Mauritania, Senegal and the U.S. Gulf of Mexico.
Summary of Oil and Gas Reserves
2021 Net Proved Reserves(1)
2020 Net Proved Reserves(1)
2019 Net Proved Reserves(1)
|Reserves Category|| || || || || || || || || |
|Ghana(2)||52 ||56 ||61 ||26 ||23 ||30 ||47 ||31 ||52 |
|Equatorial Guinea||20 ||11 ||22 ||21 ||11 ||23 ||23 ||12 ||25 |
|Mauritania/Senegal||— ||— ||— ||— ||— ||— ||— ||— ||— |
|U.S. Gulf of Mexico||28 ||20 ||31 ||32 ||25 ||36 ||34 ||28 ||39 |
|Total proved developed||100 ||87 ||115 ||79 ||60 ||89 ||104 ||71 ||116 |
|Ghana(2)||68 ||12 ||70 ||42 ||8 ||43 ||41 ||14 ||43 |
|Equatorial Guinea||5 ||— ||5 ||4 ||— ||4 ||3 ||— ||3 |
|Mauritania/Senegal(4)||8 ||590 ||106 ||— ||— ||— ||— ||— ||— |
|U.S. Gulf of Mexico||4 ||6 ||5 ||2 ||2 ||3 ||6 ||7 ||7 |
|Total proved undeveloped(5)||85 ||608 ||186 ||48 ||10 ||50 ||50 ||21 ||53 |
|Total Kosmos proved reserves||185 ||695 ||301 ||127 ||70 ||139 ||154 ||92 ||169 |
(1)Totals within the table may not add as a result of rounding.
(2)Our reserves associated with the Jubilee Field are based on the 54.4%/45.6% redetermination split between the WCTP Block and DT Block. Table above reflects additional interests acquired in the recent acquisition of additional interests in Ghana. See “Item 8. Financial Statements and Supplementary Data—Note 3—Acquisitions and Divestitures” for discussion of potential pre-emption impact.
(3)These reserves include the estimated quantity of gas to be exported as LNG from the Greater Tortue Ahmeyim project, as a result of the Tortue SPA finalized in February of 2020. These reserves also include the estimated quantities of fuel gas required to operate the Jubilee and TEN FPSOs and Equatorial Guinea facilities during normal field operations and the associated gas forecasted to be exported from TEN. If and when a subsequent gas sales agreement is executed for Jubilee, a portion of the remaining Jubilee gas may be recognized as reserves. If and when a gas sales agreement and the related infrastructure are in place for the TEN fields non-associated gas, a portion of the remaining gas may be recognized as reserves.
(4)The Mauritania/Senegal Natural Gas reserves presented consists of LNG and Fuel Gas in our reserve report. We note that the LNG is presented as Plant Products in Mboe in our reserve report.
(5)All of our proved undeveloped reserves are expected to be developed within six years or less. Proved undeveloped reserves expected to be developed beyond five years are related to long-term projects which will be completed under a continuous drilling program.
Changes during the year ended December 31, 2021, at Greater Jubilee include a positive revision of 49.1 MMBoe, of which 39.9 MMBoe were acquired on October 13, 2021 in the recent acquisition of additional interests in Ghana. The other 9.2 MMBoe of additions were primarily due to field performance, positive drilling results, and optimization of future development plans. The additions were partially offset by net Greater Jubilee production of 7.4 MMBoe which includes production related to our acquisition of additional interests in Ghana commencing October 13, 2021, the acquisition date. Changes at TEN include a positive revision of 18.2 MMBoe, of which 16.2 MMBoe were acquired in the recent acquisition of additional interests in Ghana. The other 2.0 MMBoe of additions were primarily due to an increase in estimated associated gas sales. The additions were partially offset by net TEN production of 2.2 MMBoe. Changes at Equatorial Guinea included an increase of 3.7 MMBoe related to Okume Complex performance and drilling results, which was offset by 3.6 MMBoe of net production. Changes at the U.S. Gulf of Mexico included an increase of 4.4 MMBoe related to strong performance of certain fields, offset by net U.S. Gulf of Mexico production of 7.2 MMBoe.
During the year ended December 31, 2021, we had an overall proved undeveloped reserves increase of 136.3 MMBoe as a result of several factors, including the acquisition of additional interests in Ghana (+22.7 MMBoe for Greater Jubilee and
+6.6 MMBoe for TEN), optimization of future drilling in Greater Jubilee (+17.8 MMBoe), adding a future development well and optimizing future development plans in the U.S. Gulf of Mexico and Equatorial Guinea (+6.8 MMBoe), and the economic status of the Greater Tortue Ahmeyim project due to project progress and improved oil price (+106.5 MMBoe). Drilling activity impact on proved undeveloped volume change includes the drilling of two wells in Greater Jubilee (-17.1 MMBoe), one well in TEN (-3.6 MMBoe), two wells in Equatorial Guinea (-1.2 MMBoe), and one well in Tornado in the U.S. Gulf of Mexico (-2.1 MMBoe).
In Greater Jubilee, we converted 17.1 MMBoe of proved undeveloped reserves to proved developed with the drilling of two wells at a cost of $25.2 million. In TEN, we converted 3.6 MMBoe of proved undeveloped reserves with the drilling of one well at a cost of $8.9 million. In Equatorial Guinea we spent $35.6 million to drill two wells and to replace certain subsea infrastructure, which converted 1.8 MMBoe of proved undeveloped reserves to proved developed. In the U.S. Gulf of Mexico, we converted 2.1 MMBoe of proved undeveloped reserves to proved developed with the drilling of one well in Tornado at a cost of $19.0 million.
Changes during the year ended December 31, 2020, were primarily due to 2020 production as well as lower prices. Greater Jubilee includes a negative revision of 0.3 MMBbl related to delayed drilling of water injection wells that will provide needed pressure support to certain production wells, in addition to net Greater Jubilee production of 7.0 MMBbl. Changes at TEN included a decrease of 12.0 MMBbl related to performance, delayed drilling and alterations to future development plans, in addition to net TEN production of 2.9 MMBoe. Changes at Equatorial Guinea included an increase of 2.0 MMBbl due to strong base performance and positive stimulation results, offset by 4.0 MMBbl of net Equatorial Guinea production. Changes at the U.S. Gulf of Mexico included an increase of 2.0 MMBoe primarily due to positive drilling and performance at Kodiak and Tornado, offset by net U.S. Gulf of Mexico production of 8.3 MMBoe.
During the year ended December 31, 2020, we had an overall proved undeveloped reserves decrease of 3.3 MMboe as a result of several factors, including adding additional wells to future development of Greater Jubilee (+4.7 MMboe), a negative revision in TEN (-0.3 MMboe), drilling of one well in TEN (-3.0 MMboe), one well in the Kodiak field (-1.6 MMboe) and one well in the Tornado field (-0.9 MMboe), and loss due to lower SEC pricing (-2.2 MMboe).
In TEN, we converted 3.0 MMboe of proved undeveloped reserves to proved developed with the drilling of a new well, at a cost of $28.5 million. In the U.S. Gulf of Mexico, we spent $79.2 million to drill two new wells, which converted 2.5 MMboe of proved undeveloped reserves to proved developed.
The Tortue Phase 1 SPA was signed on February 11, 2020, resulting in approximately 100 MMBoe of proved undeveloped reserves being recognized at that time as evaluated by the Company's independent reserve auditor, Ryder Scott, LP. Due to the decrease in commodity prices during 2020 and the related commodity price utilized to calculate proved reserves for SEC purposes, the field did not have proved reserves recognition as of December 31, 2020.
Changes during the year ended December 31, 2019, at Greater Jubilee include a positive revision of 8.2 MMBbl related to positive drilling results and increased original oil in place, and optimized development plan, partially offset by net Greater Jubilee production of 7.6 MMBbl. Changes at TEN included an increase of 8.8 MMBoe related to original oil in place adjustments based on updated static modeling and development plan updates, partially offset by net TEN production of 3.8 MMBoe. Changes at Equatorial Guinea included an increase of 6.3 MMBbl due to production optimization plans and plans for new drilling, which was offset by 4.7 MMBbl of net production. Changes at the U.S. Gulf of Mexico included an increase of 2.9 MMBoe related to strong performance of certain fields and the Gladden Deep discovery, offset by net U.S. Gulf of Mexico production of 8.8 MMBoe.
During the year ended December 31, 2019, we had an addition of 16.1 MMBoe of proved undeveloped reserves as a result of several factors, including updated original oil in place due to positive drilling results and improved static models in Greater Jubilee and TEN, plans for one new well to be drilled in TEN and three new wells to be drilled in the Okume Complex.
We converted a total of 13.7 MMBoe of proved undeveloped reserves to proved developed due to completions of three new wells in Greater Jubilee, two new wells in TEN, and three new wells in the U.S. Gulf of Mexico with a combined cost of $176.7 million. We spent $41.6 million to convert 4.0 MMBbl of proved undeveloped reserves in Greater Jubilee and $12.8 million to convert 2.5 MMBoe proved undeveloped reserves in TEN; and $122.3 million spent to convert 7.2 MMBoe of proved undeveloped reserves in the U.S. Gulf of Mexico.
Estimated proved reserves
Unless otherwise specifically identified in this report, the summary data with respect to our estimated net proved reserves for the years ended December 31, 2021, 2020 and 2019 has been prepared by RSC, our independent reserve engineering firm for such years, in accordance with the rules and regulations of the SEC applicable to companies involved in oil and natural gas producing activities. These rules require SEC reporting companies to prepare their reserve estimates using reserve definitions and pricing based on 12‑month historical unweighted first‑day‑of‑the‑month average prices, rather than year‑end prices. For a definition of proved reserves under the SEC rules, see the “Glossary and Selected Abbreviations.” For more information regarding our independent reserve engineers, please see “—Independent petroleum engineers” below.
Our estimated proved reserves and related future net revenues, PV‑10 and Standardized Measure were determined in accordance with SEC rules for proved reserves.
Future net revenues represent projected revenues from the sale of proved reserves net of production and development costs (including operating expenses and production taxes). Such calculations at December 31, 2021 are based on costs in effect at December 31, 2021 and the 12‑month unweighted arithmetic average of the first‑day‑of‑the‑month price for the year ended December 31, 2021, adjusted for anticipated market premium, without giving effect to derivative transactions, and are held constant throughout the life of the assets. There can be no assurance that the proved reserves will be produced within the periods indicated or prices and costs will remain constant.
Independent petroleum engineers
Ryder Scott Company, L.P.
RSC, our independent reserve engineers for the years ended December 31, 2021, 2020 and 2019, was established in 1937. For over 80 years, RSC has provided services to the worldwide petroleum industry that include the issuance of reserves reports and audits, appraisal of oil and gas properties including fair market value determination, reservoir simulation studies, enhanced recovery services, expert witness testimony, and management advisory services. RSC professionals subscribe to a code of professional conduct and RSC is a Registered Engineering Firm in the State of Texas.
For the years ended December 31, 2021, 2020 and 2019, we engaged RSC to prepare independent estimates of the extent and value of the proved reserves of certain of our oil and gas properties. These reports were prepared at our request to estimate our reserves and related future net revenues and PV‑10 for the periods indicated therein. Our estimated reserves at December 31, 2021, 2020 and 2019 and related future net revenues and PV‑10 at December 31, 2021, 2020 and 2019 are taken from reports prepared by RSC, in accordance with petroleum engineering and evaluation principles which RSC believes are commonly used in the industry and definitions and current regulations established by the SEC. The December 31, 2021 reserve report was completed on January 21, 2022, and a copy is included as an exhibit to this report.
In connection with the preparation of the December 31, 2021, 2020 and 2019 reserves report, RSC prepared its own estimates of our proved reserves. In the process of the reserves evaluation, RSC did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, oil and gas production, well test data, historical costs of operation and development, product prices or any agreements relating to current and future operations of the fields and sales of production. However, if in the course of the examination something came to the attention of RSC which brought into question the validity or sufficiency of any such information or data, RSC did not rely on such information or data until it had satisfactorily resolved its questions relating thereto or had independently verified such information or data. RSC independently prepared reserves estimates to conform to the guidelines of the SEC, including the criteria of “reasonable certainty,” as it pertains to expectations about the recoverability of reserves in future years, under existing economic and operating conditions, consistent with the definition in Rule 4‑10(a)(2) of Regulation S‑X. RSC issued a report on our proved reserves at December 31, 2021, based upon its evaluation. RSC’s primary economic assumptions in estimates included an ability to sell hydrocarbons at their respective adjusted benchmark prices and certain levels of future capital expenditures. The assumptions, data, methods and precedents were appropriate for the purpose served by these reports, and RSC used all methods and procedures as it considered necessary under the circumstances to prepare the report.
Technology used to establish proved reserves
Under the SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have proved effective by actual comparison of production from projects in the same reservoir interval, an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
In order to establish reasonable certainty with respect to our estimated proved reserves, RSC employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, production and injection data, electrical logs, radioactivity logs, acoustic logs, whole core analysis, sidewall core analysis, downhole pressure and temperature measurements, reservoir fluid samples, geochemical information, geologic maps, seismic data, well test and interference pressure and rate data. Reserves attributable to undeveloped locations were estimated using performance from analogous wells with similar geologic depositional environments, rock quality, appraisal plans and development plans to assess the estimated ultimate recoverable reserves as a function of the original oil in place. These qualitative measures are benchmarked and validated against sound petroleum reservoir engineering principles and equations to estimate the ultimate recoverable reserves volume. These techniques include, but are not limited to, nodal analysis, material balance, and numerical flow simulation.
Internal controls over reserves estimation process
In our Reservoir Engineering team, we maintain an internal staff of petroleum engineering and geoscience professionals with significant experience that contribute to our internal reserve and resource estimates. This team works closely with our independent petroleum engineers to ensure the integrity, accuracy and timeliness of data furnished in their reserve and resource estimation process. Our Reservoir Engineering team is responsible for overseeing the preparation of our reserves estimates and has over 100 combined years of industry experience among them with positions of increasing responsibility in engineering and evaluations. Each member of our team holds a minimum of a Bachelor of Science degree in petroleum engineering or geology.
The RSC technical person primarily responsible for preparing the estimates set forth in the RSC reserves report incorporated herein is Mr. Tosin Famurewa. Mr. Famurewa has been practicing consulting petroleum engineering at RSC since 2006. Mr. Famurewa is a Licensed Professional Engineer in the State of Texas (No. 100569) and has over 19 years of practical experience in petroleum engineering. He graduated from University of California at Berkeley in 2000 with Bachelor of Science Degrees in Chemical Engineering and Material Science Engineering, and he received a Master of Science degree in Petroleum Engineering from University of Southern California in 2007. Mr. Famurewa meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.
The Audit Committee provides oversight on the processes utilized in the development of our internal reserve and resource estimates on an annual basis. In addition, our Reservoir Engineering team meets with representatives of our independent reserve engineers to review our assets and discuss methods and assumptions used in preparation of the reserve and resource estimates. Finally, our senior management reviews reserve and resource estimates on an annual basis.
Gross and Net Undeveloped and Developed Acreage
The following table sets forth certain information regarding the developed and undeveloped portions of our license and lease areas as of December 31, 2021 for the countries in which we currently operate.
| ||Developed Area||Undeveloped Area|| || |
| ||(Acres)||(Acres)||Total Area (Acres)|
| ||(In thousands)|
|Ghana(2)||163 ||53 ||34 ||11 ||197 ||64 |
|Equatorial Guinea||65 ||26 ||2,355 ||1,292 ||2,420 ||1,318 |
|Mauritania||— ||— ||2,430 ||679 ||2,430 ||679 |
|Sao Tome and Principe||— ||— ||527 ||310 ||527 ||310 |
|Senegal||— ||— ||917 ||271 ||917 ||271 |
|U.S. Gulf of Mexico||98 ||28 ||223 ||105 ||321 ||133 |
|Total||326 ||107 ||6,486 ||2,668 ||6,812 ||2,775 |
(1)Net acreage based on Kosmos’ participating interests, before the exercise of any options or back‑in rights, except for our net acreage associated with the Jubilee, TEN, and Greater Tortue Ahmeyim fields, which are after the exercise of options or back‑in rights. Our net acreage in Ghana may be affected by any redetermination of interests in the Jubilee Unit and our net acreage in Mauritania and Senegal may be affected by any redetermination of interests in the Greater Tortue Ahmeyim Unit.
(2)The Exploration Period of the WCTP petroleum contract and DT petroleum contract has expired. The undeveloped area reflected in the table above represents acreage within our discovery areas that were not subject to relinquishment on the expiry of the Exploration Period. Table above reflects additional interests acquired in Ghana. See “Item 8. Financial Statements and Supplementary Data—Note 3—Acquisitions and Divestitures” for discussion of potential pre-emption impact.
Productive wells consist of producing wells and wells capable of production, including wells awaiting connections. For wells that produce both oil and gas, the well is classified as an oil well. The following table sets forth the number of productive oil and gas wells in which we held an interest at December 31, 2021:
| ||Productive||Productive|| || |
| ||Oil Wells||Gas Wells||Total|
|Ghana(2)||51 ||19.23 ||— ||— ||51 ||19.23 |
|Equatorial Guinea||83 ||33.53 ||— ||— ||83 ||33.53 |
|U.S. Gulf of Mexico||23 ||6.57 ||— ||— ||23 ||6.57 |
|Total(1)||157 ||59.33 ||— ||— ||157 ||59.33 |
(1)Of the 157 productive wells, 42 (gross) or 10.00 (net) have multiple completions within the wellbore.
(2)Table above reflects our additional interests acquired in Ghana. See “Item 8. Financial Statements and Supplementary Data—Note 3—Acquisitions and Divestitures” for discussion of potential pre-emption impact.
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)|| || |
Year Ended December 31, 2021
| || || || || || || || || || || || || || |
|Ghana(4)||— ||— ||— ||— ||— ||— ||4 ||1.54 ||— ||— ||4 ||1.54 ||4 ||1.54 |
|Equatorial Guinea||— ||— ||— ||— ||— ||— ||2 ||0.80 ||— ||— ||2 ||0.80 ||2 ||0.80 |
|U.S. Gulf of Mexico||— ||— ||1 ||0.38 ||1 ||0.38 ||1 ||0.29 ||— ||— ||1 ||0.29 ||2 ||0.67 |
|Total||— ||— ||1 ||0.38 ||1 ||0.38 ||7 ||2.63 ||— ||— ||7 ||2.63 ||8 ||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||— ||— ||1 ||0.40 ||1 ||0.40 ||1 ||0.35 ||— ||— ||1 ||0.35 ||2 ||0.75 |
|Total||— ||— ||1 ||0.40 ||1 ||0.40 ||2 ||0.52 ||2 ||0.34 ||4 ||0.86 ||5 ||1.26 |
Year Ended December 31, 2019
| || || || || || || || || || || || || || |
|Ghana||— ||— ||— ||— ||— ||— ||4 ||0.89 ||— ||— ||4 ||0.89 ||4 ||0.89 |
|Equatorial Guinea||— ||— ||— ||— ||— ||— ||— ||— ||— ||— ||— ||— ||— ||— |
|U.S. Gulf of Mexico||2 ||0.42 ||1 ||0.50 ||3 ||0.92 ||2 ||0.96 ||— ||— ||2 ||0.96 ||5 ||1.88 |
|Total||2 ||0.42 ||1 ||0.50 ||3 ||0.92 ||6 ||1.85 ||— ||— ||6 ||1.85 ||9 ||2.77 |
(1)As of December 31, 2021, ten exploratory and appraisal wells have been excluded from the table until a determination is made if the wells have found proved reserves. Also excluded from the table are 14 development wells awaiting completion. These wells are shown as “Wells Suspended or Waiting on Completion” in the table below.
(2)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.
(3)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.
(4)Table above reflects additional interests acquired in the recent acquisition of additional interests in Ghana. See “Item 8. Financial Statements and Supplementary Data—Note 3—Acquisitions and Divestitures” for discussion of potential pre-emption impact.
The following table shows the number of wells that are in the process of being drilled or are in active completion stages, and the number of wells suspended or waiting on completion as of December 31, 2021.
| ||Actively Drilling or||Wells Suspended or|
| ||Completing||Waiting on Completion|
|Ghana(1)|| || || || || || || || |
|Jubilee Unit||— ||— ||1 ||0.42 ||— ||— ||7 ||2.95 |
|TEN||— ||— ||— ||— ||— ||— ||5 ||1.40 |
|Asam||— ||— ||— ||— ||1 ||0.40 ||— ||— |
|Okume||— ||— ||— ||— ||— ||— ||1 ||0.43 |
|U.S. Gulf of Mexico|
|Winterfell ||1 ||0.16 ||— ||— ||1 ||0.16 ||— ||— |
|Mauritania / Senegal|| || || || || || || || |
|BirAllah-Orca||— ||— ||— ||— ||2 ||0.56 ||— ||— |
|Greater Tortue Ahmeyim Unit||— ||— ||— ||— ||3 ||0.80 ||1 ||0.27 |
|Yakaar-Teranga||— ||— ||— ||— ||3 ||0.90 ||— ||— |
|Total||1 ||0.16 ||1 ||0.42 ||10 ||2.82 ||14 ||5.05 |
(1)Table above reflects additional interests acquired in the recent acquisition of additional interests in Ghana. See “Item 8. Financial Statements and Supplementary Data—Note 3—Acquisitions and Divestitures” for discussion of potential pre-emption impact.
Domestic Supply Requirements
Many of our petroleum contracts or, in some cases, the applicable law governing such agreements, grant a right to the respective host country to purchase certain amounts of oil/gas produced pursuant to such agreements at international market prices for domestic consumption. In addition, in connection with the approval of the Jubilee Phase 1 PoD, the Jubilee Field partners agreed to provide the first 200 Bcf of natural gas produced from the Jubilee Field Phase 1 development to GNPC at no cost. As of December 31, 2021, 159 Bcf of the 200 Bcf of natural gas has been provided.
Significant License Agreements
Below is a discussion concerning the petroleum contracts governing our current drilling and production operations.
Ghana West Cape Three Points Block
As a result of the approval of the GJFFDP by the Ghana Ministry of Energy in 2017, operatorship for the West Cape Three Points Block, including the Mahogany and Teak discoveries, transferred to Tullow in February 2018 and are now included in the Jubilee Unit. Kosmos is required to pay to the government of Ghana a fixed royalty of 5% and a potential sliding‑scale royalty (“additional oil entitlement”), which comes into effect and escalates as the nominal project rate of return increases above a certain threshold. These royalties are to be paid in‑kind or, at the election of the government of Ghana, in cash. A corporate tax rate of 35% is applied to profits at a country level.
The WCTP petroleum contract has a duration of 30 years from its effective date (July 2004). In July 2011, at the end of the seven‑year Exploration Period, parts of the WCTP Block on which we had not declared a discovery area, were not in a development and production area, or were not in the Jubilee Unit, were relinquished (“WCTP Relinquishment Area”). We maintain rights to the Akasa discovery within the WCTP Block as the WCTP petroleum contract remains in effect after the end of the Exploration Period. We and our WCTP Block partners have certain rights to negotiate a new petroleum contract with respect to certain portions of the WCTP Relinquishment Area. We and our WCTP Block partners, the Ghana Ministry of Energy and GNPC have agreed such WCTP petroleum contract rights to negotiate extend from July 21, 2011 until such time as
either a new petroleum contract is negotiated and entered into with us or we decline to match a bona fide third-party offer GNPC may receive for the WCTP Relinquishment Area.
Ghana Deepwater Tano Block
Tullow is the operator of the Deepwater Tano Block. Under the DT petroleum contract, GNPC exercised its option to acquire an additional paying interest of 5% in the commercial discovery with respect to the Jubilee Field development and the TEN Fields development. Kosmos is required to pay to the government of Ghana a fixed royalty of 5% and a potential additional oil entitlement, which comes into effect and escalates as the nominal project rate of return increases above a certain threshold. These royalties are to be paid in‑kind or, at the election of the government of Ghana, in cash. A corporate tax rate of 35% is applied to profits at a country level.
The DT petroleum contract has a duration of 30 years from its effective date (July 2006). In 2013, at the end of the seven‑year Exploration Period, parts of the DT Block on which we had not declared a discovery area, were not in a development and production area, or were not in the Jubilee Unit, were relinquished (“DT Relinquishment Area”). Our existing Wawa discovery within the DT Block was not subject to relinquishment upon expiration of the Exploration Period of the DT petroleum contract, as the DT petroleum contract remains in effect after the end of the Exploration Period while commerciality is being determined. Pursuant to our DT petroleum contract, we and our DT Block partners have certain rights to negotiate a new petroleum contract with respect to certain portions of the DT Relinquishment Area until such time as either a new petroleum contract is negotiated and entered into with us or we decline to match a bona fide third-party offer GNPC may receive for the DT Relinquishment Area.
The Ghanaian Petroleum Exploration and Production Law of 1984 (PNDCL 84) (the “1984 Ghanaian Petroleum Law”) and the WCTP and DT petroleum contracts form the basis of our exploration, development and production operations on the WCTP and DT blocks. Pursuant to these petroleum contracts, most significant decisions, including PoDs and annual work programs, for operations other than exploration and appraisal, must be approved by a joint management committee, consisting of representatives of certain block partners and GNPC. Certain decisions require unanimity.
Ghana Jubilee Field Unitization
The Jubilee Field, discovered by the Mahogany‑1 well in June 2007, covers an area within both the WCTP and DT Blocks. To optimize resource recovery in the Jubilee Field, it was unitized and the Jubilee UUOA was agreed to in 2009 which governs each party’s respective rights and duties in the Jubilee Unit and named Tullow as the Unit Operator. Although the Jubilee Field is unitized, Kosmos’ participating interests in each block outside the boundary of the Jubilee Unit are not impacted by the Jubilee UUOA. Currently, the WCTP petroleum contract has a 54.367% participating interest in the Jubilee Unit and the DT petroleum contract has a 45.633% participating interest in the Jubilee Unit. Our participating interest in the Jubilee Unit is based on these allocations and any event of redetermination in the future would impact Jubilee Unit participating interest.
Greater Tortue Ahmeyim Unitization
The Greater Tortue Ahmeyim Field, discovered by the Tortue‑1 well in May 2015, in Mauritania block C8 and by the Guembuel-1 well in January 2016, in the Saint-Louis Offshore Profond Block in Senegal covers an area within both the C8 and Saint-Louis Offshore Profond Blocks. Mauritania and Senegal agreed that the Greater Tortue Ahmeyim Field would be unitized for optimal resource recovery in the Inter-State Cooperation Agreement (ICA) signed in February 2018. The GTA UUOA was agreed between the contractor groups of the C8 and Saint-Louis Offshore Profond Blocks and approved by the appropriate Ministers in Mauritania and Senegal in February 2019. BP Mauritania and BP Senegal are co-Unit Operator and will allocate responsibilities for the initial development of the Greater Tortue Ahmeyim Field. During the second quarter of 2019, SMH and PETROSEN elected to increase their respective interest in their portion of the Greater Tortue Ahmeyim Unit to the maximum allowed percentages under the respective petroleum contracts. After the election, our interest in the exploration areas of Block C8 offshore Mauritania and in Saint Louis Offshore Profound offshore Senegal are unchanged, however, our interest in the Greater Tortue Ahmeyim Unit is now 26.7% and is subject to redetermination of the participating interests pursuant to the terms of the GTA UUOA. In February 2019, Mauritania and Senegal each issued an exploitation authorization for the Greater Tortue Ahmeyim Unit area covered by the GTA UUOA.
Effective June 2012, we entered into three petroleum contracts covering offshore Mauritania Blocks C8, C12 and C13 with the Islamic Republic of Mauritania. The Mauritanian national oil company, SMH, currently has a 10% carried interest during the exploration period only. Should a commercial discovery be made, SMH’s 10% carried interest is extinguished and
SMH will have an option to obtain a participating interest between 10% and 14%. SMH will pay its portion of development and production costs in a commercial development. Cost recovery oil is apportioned to the contractor from up to 55% (62% for gas) of total production prior to profit oil being split between the government of Mauritania and the contractor. Profit oil is then apportioned based upon “R‑factor” tranches, where the R‑factor is cumulative net revenues divided by the cumulative investment. At the election of the government of Mauritania, the government may receive its share of production in cash or in kind. A corporate tax rate of 27% is applied to profits at the license level. The terms of exploration periods of these Offshore Blocks are all ten years and initially included a first exploration period of four years followed by the second exploration period of three years and the third exploration period of three years. Kosmos is currently in the third exploration period for Blocks C8 and C12, expiring in June 2022. In 2021, at the conclusion of the second exploration period, Block C13 offshore Mauritania was relinquished.
In June 2018, we entered the final renewal of the exploration period for the Senegal Cayar Offshore Profond and Saint Louis Offshore Profond Blocks. In July 2021, the term of the Cayar Offshore Profound license was extended for up to an additional three years, ending in July 2024. In the event of commercial success, we have the right to develop and produce oil and/or gas for a period of 25 years from the grant of an exploitation authorization from the government, which may be extended on two separate occasions for a period of 10 years each under certain circumstances. The exploration period of the St. Louis Offshore Profound license expired in July 2021.
Equatorial Guinea Exploration Agreements
In March 2018, we entered into petroleum contracts covering Blocks EG-21, S, and W with the Republic of Equatorial Guinea. The Equatorial Guinean national oil company, GEPetrol, currently has a 20% carried participating interest during the exploration period. Should a commercial discovery be made, GEPetrol's 20% carried interest will convert to a 20% participating interest. The petroleum contracts cover approximately 6,000 square kilometers, with a first exploration sub-period ending in March 2021. In August 2020, an extension was granted extending the first exploration sub-period ending to December 2022.
In the first quarter of 2019, we became operator of Block EG-24 offshore Equatorial Guinea. GEPetrol, currently has a 20% carried interest during the exploration period. In March 2020, we entered the first extension period ending in March 2021. In August 2020, an extension was granted extending the first extension period to December 2022. The petroleum contract cover covers approximately 3,500 square kilometers. Should a commercial discovery be made, GEPetrol's 20% carried interest will convert to a 20% participating interest for all development and production operations.
Sales and Marketing
As provided under the Jubilee UUOA and the WCTP and DT petroleum contracts, we are entitled to lift and sell our share of the Jubilee and TEN production as are the other Jubilee Unit and TEN partners. Over the years, we have entered into agreements with multiple oil marketing agents to market our share of the Jubilee and TEN fields oil, and we approve the terms of each sale proposed by such agent. We currently have crude oil marketing sales agreements over the Jubilee and TEN fields extending approximately three years.
In December 2017, we signed the TAG GSA and we began exporting TEN associated gas to shore in the fourth quarter of 2018. The TAG GSA provides for an inflation-adjusted sales price of $0.50 per MMBtu.
In Equatorial Guinea, as provided under the petroleum contract for Block G, we are entitled to lift and sell our share of the Ceiba Field production as are the other Ceiba Field partners. We have entered into an agreement with an oil marketing agent to market our share of the Ceiba Field oil, and we approve the terms of each sale proposed by such agent.
In the U.S. Gulf of Mexico, we sell crude oil to purchasers typically through monthly contracts, with the sale taking place at multiple points offshore, depending on the particular property. Natural gas is sold to purchasers through monthly contracts, with the sale taking place either offshore or at an onshore gas processing plant after the removal of NGLs. We actively market our crude oil and natural gas to purchasers, and sales prices for purchased oil and natural gas volumes are negotiated with purchasers and are based on certain published indices. Since most of the oil and natural gas contracts are generally month-to-month, there are very few dedications of production to any one purchaser. We sell the NGLs entrained in the natural gas that we produce. The arrangements to sell these products first requires natural gas to be processed at an onshore gas processing plant. Once the liquids are removed and fractionated (separated into the individual hydrocarbon chains for sale), the products are sold by the processing plant. The residue gas left over is sold to natural gas purchasers as natural gas sales
(referenced above). The contracts for NGL sales are with the processing plant. The prices received for the NGLs are either tied to indices or are based on what the processing plant can receive from a third-party purchaser. The gas processing and subsequent sales of NGLs are subject to contracts with longer terms and dedications of life of lease production from the Company’s leases offshore.
There are a variety of factors which affect the market for oil, including the proximity and capacity of transportation facilities, demand for oil both within the local market and beyond, the marketing of competitive fuels and the effects of government regulations on oil production and sales. Our revenue can be materially affected by current economic conditions and the price of oil. However, based on the current demand for crude oil and the fact that alternative purchasers are available, we believe that the loss of our marketing agent and/or any of the purchasers identified by our marketing agent would not have a long‑term material adverse effect on our financial position or results of operations. The continued economic disruption resulting from the COVID-19 pandemic could further materially impact the Company’s business in future periods. Any potential disruption will depend on the duration and intensity of these events, which are highly uncertain and cannot be predicted at this time.
In February 2020, we, along with the co-venturers in the Greater Tortue Ahmeyim Field signed the Tortue Phase 1 SPA with BP Gas Marketing Limited to sell LNG free on board (FOB) from the Greater Tortue Ahmeyim Field located offshore Mauritania and Senegal. The annual contract quantity under the Tortue Phase 1 SPA is 127,951,000 MMBtu (the “ACQ”) which is equivalent to approximately 2.45 million tonnes per annum, subject to limited downward adjustment by the sellers. The sales price for LNG under the Tortue Phase 1 SPA is set as a percentage of a crude oil price benchmark for the ACQ volumes (the “ACQ Sales Price”). The Tortue Phase 1 SPA has an initial term of up to twenty years that commences on the “Commercial Operations Date”, which occurs after completion of certain LNG project facilities’ performance tests.
The oil and gas industry is competitive. We encounter strong competition from other independent operators and from major oil companies in acquiring licenses and leases. Many of these competitors have financial and technical resources and staff that are substantially larger than ours. As a result, our competitors may be able to pay more for desirable oil and natural gas assets, or to evaluate, bid for and purchase a greater number of licenses and leases than our financial or personnel resources will permit. Furthermore, these companies may also be better able to withstand the financial pressures of lower commodity prices, unsuccessful wells, volatility in financial markets and generally adverse global and industry‑wide economic conditions. These companies may also be better able to absorb the burdens resulting from changes in relevant laws and regulations, which may adversely affect our competitive position.
Historically, we have also been affected by competition for drilling rigs and the availability of related equipment. Higher commodity prices generally increase the demand for drilling rigs, supplies, services, equipment and crews. Shortages of, or increasing costs for, experienced drilling crews and equipment and services may restrict our ability to drill wells and conduct our operations.
The oil and gas industry as a whole has experienced continued volatility. Globally, the impact of COVID-19 has impacted demand for oil, which also resulted in significant variations in oil prices. Dated Brent crude, the benchmark for our international oil sales, ranged from approximately $50 to $86 per barrel during 2021. HLS crude, the benchmark for our U.S. Gulf of Mexico oil sales, which generally trades at a discount to Dated Brent, ranged from approximately $50 to $84 during 2021. Excluding the impact of hedges, our realized price for 2021 was $70.10 per barrel.
Title to Property
We believe that we have satisfactory title to our oil and natural gas assets in accordance with standards generally accepted in the international oil and gas industry. Our licenses and leases are subject to customary royalty and other interests, liens under operating agreements and other burdens, restrictions and encumbrances customary in the oil and gas industry that we believe do not materially interfere with the use of, or affect the carrying value of, our interests.
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 some or all of the operations or facilities deemed not in compliance with permits;
•restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and natural gas drilling, production and transportation activities;
•limit, cap, tax or otherwise restrict emissions of GHG and other air pollutants or otherwise seek to address or minimize the effects of climate change;
•limit or prohibit drilling activities in certain locations lying within protected or otherwise sensitive areas; and
•require measures to mitigate or remediate pollution, including pollution resulting from our block partners’ or our contractors’ operations.
These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. Compliance with these laws can be costly; the regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. We are committed to continued compliance with all environmental laws and regulations applicable to our operations in all countries in which we do business. We have established policies, operating procedures and training programs designed to limit the environmental impact of our operations and to identify and comply with changes in existing laws and regulations, however the cost of compliance with more stringent laws and regulations in the future could have a material adverse effect on our financial condition and results of operations.
Moreover, public interest in the protection of the environment continues to increase. Offshore drilling in some areas has been opposed by environmental groups and, in other areas, has been restricted. Our operations could be adversely affected to the extent laws or regulations are enacted or other governmental action is taken that prohibits or restricts offshore drilling or imposes environmental requirements that increase costs to the oil and gas industry in general, such as more stringent or costly waste handling, disposal or cleanup requirements or financial responsibility and assurance requirements.
Capping and Containment (Excluding the U.S. Gulf of Mexico)
We entered into an agreement with a third-party service provider for it to supply subsea capping and containment equipment on a global basis (excluding the U.S. Gulf of Mexico). The equipment includes capping stacks, debris removal, subsea dispersant and auxiliary equipment. The equipment meets industry accepted standards and can be deployed by air cargo and other conventional means to suit multiple application scenarios. We also developed an emergency response plan and response organization to prepare and demonstrate our readiness to respond to a subsea well control incident. Capping and containment for the U.S. Gulf of Mexico is detailed in the U.S. Gulf of Mexico (Operated and Non-operated) section below.
Oil Spill Response
To complement our agreement discussed above for subsea capping and containment equipment, we became a charter member of the Global Dispersant Stockpile (“GSD”). The dispersant stockpile, which is managed by Oil Spill Response Limited (“OSRL”) of Southampton, England, an oil spill response contractor, consists of 5,000 cubic meters of dispersant strategically located at OSRL bases around the world. The total volume of the stockpile located at the OSRL bases is calculated to provide members with the ability to respond to a major spill incident. Dispersant from the GSD can be used in the U.S. Gulf of Mexico.
Mauritania and Senegal (Non-operated)
Kosmos transferred operatorship of Mauritania and Senegal operations to BP at the beginning of 2018 and was not the operator for any operations during 2021.
Tullow, our partner and the operator of the Jubilee Unit and the TEN fields, maintains Oil Spill Contingency Plans (“OSCP”) covering the Jubilee Field and Deepwater Tano Block. Under the OSCPs, emergency response teams may be activated to respond to oil spill incidents. Tullow has access to OSRL’s oil spill response services comprising technical expertise and assistance, including access to response equipment and dispersant spraying systems. Tullow maintains lease agreements with OSRL for Tier 1 and Tier 2 packages of oil spill response equipment.
Equatorial Guinea (Operated and Non-operated)
Effective January 1, 2019, Trident became operator of the Ceiba Field and Okume Complex. In addition, Kosmos has joined the Equatorial Guinea Oil and Gas Operators Emergency Resource Allocation Agreement to share equipment with other in country operators in case of emergency. Our membership in OSRL provides access to Tier II and III equipment located in Accra, Ghana and Southampton, England, UK.
U.S. Gulf of Mexico (Operated and Non-operated)
After the major well control incident and oil release in the U.S. Gulf of Mexico in 2010, the U.S. Department of Interior updated regulations which govern the type, amount and capabilities of response equipment that needs to be available to operators to respond to similar incidents. These regulations also dictate the type and frequency of training that operating personnel need to receive and demonstrate proficiency in. Kosmos also has an Oil Spill Response Plan (“OSRP”) which is approved by the Bureau of Safety and Environmental Enforcement (“BSEE”). This OSRP would be activated if needed in the event of an oil spill or containment event in the U.S. Gulf of Mexico. Kosmos joined several cooperatives that were established to meet the requirements of the new regulations. For capping and containment, Kosmos joined the Helix Well Containment Group (“HWCG”) consortium whose capabilities include; (i) two dual ram capping stacks rated at 15,000 psi and 10,000 psi respectively, (ii) intervention equipment to cap and contain a well with the mechanical and structural integrity to be shut in at depths up to 10,000 feet, and (iii) the ability to capture and process 130,000 barrels of fluid per day and 220 Mcf of gas per day. Kosmos is also a member of the Clean Gulf Associate (“CGA”) Oil Spill Cooperative, which provides oil spill response capabilities to meet regulatory requirements. Equipment and services include a High Volume Open Sea Skimming System (“HOSS”), dedicated oil spill response vessels strategically positioned along the U.S. gulf coast, dispersant and dispersant delivery systems, various types of spill response booms and mobile wildlife rehabilitation equipment. Due to federal regulations, all of the HWCG and CGA equipment is dedicated to U.S. operations and cannot be utilized outside the country.
Human Capital Resources
Health and Safety
The health and safety of our employees and those that work with us is a priority for Kosmos. Employees and contractors are expected to take all necessary and reasonable actions to ensure safe operations by following safe work practices, complying with relevant policies and regulations, and completing all applicable training. To support our dedication to health, safety and the environment, we have a comprehensive Health, Safety, Environment and Security (“HSES”) management system that applies to all Kosmos employees and contractors known as “The Standard.” In addition to adoption of The Standard, Kosmos fosters a strong safety culture through online and in person training, regular emergency response drills, and impactful safety discussions.
With the ongoing COVID-19 pandemic, the health of our employees and contractors continued to be a priority for 2021 including the establishment of a COVID-19 vaccination and testing policy, facilitating remote working flexibility for employees normally based in the office, and safeguarding operations offshore through a variety of enhanced operational safeguards and monitoring measures, including strict pre-embarkation quarantine procedures, wellness screenings, and COVID-19 testing.
Culture, Engagement and Development
Kosmos aims to be a world-class company known for delivering results and being a workplace of choice. We pride ourselves on our ability to provide employees with careers that are professionally challenging, personally rewarding, and focused on delivering value. We aim to provide a stimulating and rewarding work environment through an inclusive culture that promotes entrepreneurial thinking, facilitates teamwork, and embraces ethical behavior.
Kosmos is committed to investing in the development of our employees. We support development through a blend of learning approaches including in-person and virtual training opportunities, on-the-job training, conferences, cross team projects and experiences and our leadership development program. Each year, all employees also have an opportunity to provide feedback on the employee experience and Kosmos culture through our annual employee opinion survey. In 2021, Kosmos achieved top quartile performance relative to peer companies. The feedback received through this annual survey is used to support continuous improvement and enhance the overall employee experience. In 2021, Kosmos had a retention rate greater than 93%.
Diversity and Inclusion
Kosmos focuses on recruiting, retaining, and developing a diverse and inclusive workforce that embraces our values and culture. We seek to promote diversity in our workforce both because it is the right thing to do and because it gives us access to the widest range of talents. Through social and educational events that address the different backgrounds and identities of employees, Kosmos helps foster a spirit of inclusion across the company. We promote and celebrate the array of diverse perspectives and experiences of Kosmos employees and applicants, whether in terms of race, ethnicity, sex, gender, sexual orientation, gender expression, religion, national origin, disability, or experiences.
We seek to employ qualified individuals from the countries in which we operate and are proud of our record of recruitment and retention of local staff. This year we maintained 100% local employees across all our host country offices.
As of December 31, 2021, we had 229 employees with 199 being based in the United States and 30 residing in our local offices. Our workforce was approximately 38% gender diverse and approximately 33% minority.
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.
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.
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.
Item 1A. Risk Factors
You should consider and read carefully all of the risks and uncertainties described below, together with all of the other information contained in this report, including the consolidated financial statements and the related notes included in “Item 8. Financial Statements and Supplementary Data.” If any of the following risks actually occurs, our business, business prospects, financial condition, results of operations or cash flows could be materially adversely affected. The risks below are not the only ones we face. Additional risks not currently known to us or that we currently deem immaterial may also adversely affect us.
Summary Risk Factors
Our business is subject to a number of risks, including risks that may prevent us from achieving our business objectives or may adversely affect our business, financial condition, results of operations, cash flows, and prospects. These risks are discussed more fully below and include, but are not limited to, risks related to:
Our Oil and Natural Gas Operations
•We have limited proved reserves;
•We face substantial uncertainties in estimating the characteristics of our discoveries and our prospects;
•Drilling wells is speculative and may not result in any discoveries;
•Development wells may not result in commercially productive quantities of oil and gas reserves;
•Our identified drilling and infrastructure locations are scheduled out over time, making them susceptible to uncertainties;
•We are contractually obligated to drill wells and declare any discoveries in order to retain exploration and production rights;
•Inability of third parties who contract with us to meet their obligations may adversely affect our financial results;
•The unit partners’ respective interests in the Jubilee Unit and Greater Tortue Ahmeyim Unit are subject to redetermination;
•We are not the operator on all of our license areas and facilities and do not hold all of the working interests in certain of our license areas;
•Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate;
•The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves;
•We may not be able to commercialize our interests in any natural gas produced from our license areas;
•Our inability to access appropriate equipment and infrastructure in a timely manner may hinder our access to oil and natural gas markets or delay our oil and natural gas production;
•We are subject to numerous risks inherent to the exploration and production of oil and natural gas;
•We are subject to drilling and other operational and environmental risks and hazards;
•Our operations may be materially adversely affected by weather-related events including tropical storms and hurricanes;
•The development schedule of oil and natural gas projects is subject to delays and cost overruns;
•Our offshore and deepwater operations involve special risks that could adversely affect our results of operations;
•We have had disagreements with host governments regarding certain of our rights and responsibilities and may have future disagreements with our host governments;
•The geographic locations of our licenses in Africa and the U.S. Gulf of Mexico subject us to a risk of loss of revenue or curtailment of production from factors specifically affecting those areas;
Our Business and Financial Condition
•The COVID-19 pandemic and outbreaks of other diseases may adversely affect our business operations and financial condition;
•A substantial or extended decline in oil and natural gas prices may adversely affect our business, financial condition and results of operations;
•Our business plan requires substantial additional capital;
•We may be required to take write‑downs of the carrying values of our oil and natural gas assets as a result of decreases in oil and natural gas prices;
•We face various risks associated with increased activism against, or change in public sentiment for, oil and gas exploration, development, and production activities and ESG considerations including climate change and the transition to a lower carbon economy;
•Deterioration in the credit or equity markets could adversely affect us;
•We may incur substantial losses and become subject to liability claims as a result of future oil and natural gas operations, for which we may not have adequate insurance coverage;
•Slower global economic growth rates may materially adversely impact our operating results and financial position;
•Increased costs and availability of capital could adversely affect our business;
•Our derivative activities could result in financial losses or could reduce our income;
•Our commercial debt facility, revolving credit facility, indentures governing our Senior Notes and GoM Term Loan contain certain covenants that may inhibit our ability to make certain investments, incur additional indebtedness and engage in certain other transactions;
•Provisions of our Senior Notes could discourage an acquisition of us by a third-party;
•Our level of indebtedness may increase and thereby reduce our financial flexibility;
•We are a holding company and our ability to make payments on our outstanding indebtedness is dependent upon the receipt of funds from our subsidiaries;
•We may be subject to risks in connection with acquisitions and the integration of significant acquisitions may be difficult;
•If we fail to realize the anticipated benefits of a significant acquisition, our results of operations may be adversely affected;
•A cyber incident, including a breach of digital security, could result in information theft, data corruption, operational disruption, and/or financial loss;
•Our ability to utilize net operating loss carryforwards may be subject to certain limitations;
•Changes in the method of determining LIBOR, or the replacement of LIBOR with an alternative reference rate, may adversely affect interest expense related to outstanding debt;
•Our business, operations and financial condition may be directly and indirectly adversely affected by political, economic, and environmental circumstances;
•More comprehensive and stringent regulation in the U.S. Gulf of Mexico has materially increased costs and delays in offshore oil and natural gas exploration and production operations;
•The oil and gas industry is intensely competitive and many of our competitors possess and employ substantially greater resources than us;
•Participants in the oil and gas industry are subject to numerous laws, regulations, and other legislative instruments that can affect the cost, manner or feasibility of doing business;
•We are subject to numerous health, safety and environmental laws and regulations which may result in material liabilities and costs;
•We may be exposed to assertions concerning or liabilities under anti‑corruption laws;
•Federal regulatory law could have an adverse effect on our ability to use derivative instruments;
•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.
Risks Relating to our Oil and Natural Gas Operations
We have limited proved reserves and areas that we decide to drill may not yield oil and natural gas in commercial quantities or quality, or at all.
We have limited proved reserves. A portion of our oil and natural gas assets consists of discoveries without approved PoDs and with limited well penetrations, as well as identified yet unproven prospects based on available seismic and geological information that indicates the potential presence of hydrocarbons. However, the areas we decide to drill may not yield oil or natural gas in commercial quantities or quality, or at all. Many of our current discoveries and all of our prospects are in various stages of evaluation that will require substantial additional analysis and interpretation. Even when properly used and interpreted, 2D and 3D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. Accordingly, we do not know if any of our discoveries or prospects will contain oil or natural gas in sufficient quantities or quality to recover drilling and completion costs or to be economically viable. Even if oil or natural gas is found on our discoveries or prospects in commercial quantities, construction costs of gathering lines, subsea infrastructure, other production facilities and floating production systems and transportation costs may prevent such discoveries or prospects from being economically viable, and approval of PoDs by various regulatory authorities, a necessary step in order to develop a commercial discovery, may not be forthcoming. Additionally, the analogies drawn by us using available data from other wells, more fully explored discoveries or producing fields may not prove valid with respect to our drilling prospects. We may terminate our drilling program for a discovery or prospect if data, information, studies and previous reports indicate that the possible development of a discovery or prospect is not commercially viable and, therefore, does not merit further investment. If a significant number of our discoveries or prospects do not prove to be successful, our business, financial condition and results of operations will be materially adversely affected.
The deepwater offshore Mauritania and Senegal, an area in which we currently focus a substantial amount of our development efforts, has only recently been considered economically viable for hydrocarbon production due to the costs and difficulties involved in drilling and development at such depths and the relatively recent discovery of commercial quantities of hydrocarbons in the region. Likewise, our deepwater offshore Sao Tome and Principe license has not yet proved to be an economically viable production area. We have limited proved reserves, and we may not be successful in developing additional commercially viable production from our other discoveries and prospects.
We face substantial uncertainties in estimating the characteristics of our discoveries and our prospects.
In this report we provide numerical and other measures of the characteristics of our discoveries and prospects. These measures may be incorrect, as the accuracy of these measures is a function of available data, geological interpretation and judgment. To date, a limited number of our prospects have been drilled. Any analogies drawn by us from other wells, discoveries or producing fields may not prove to be accurate indicators of the success of developing proved reserves from our discoveries and prospects. Furthermore, we have no way of evaluating the accuracy of the data from analog wells or prospects produced by other parties which we may use.
It is possible that few or none of our wells to be drilled will find accumulations of hydrocarbons in commercial quality or quantity. Any significant variance between actual results and our assumptions could materially affect the quantities of hydrocarbons attributable to any particular prospect.
Drilling wells is speculative, often involving significant costs that may be more than we estimate, and may not result in any discoveries or additions to our future production or reserves. Any material inaccuracies in drilling costs, estimates or underlying assumptions will materially affect our business.
Exploring for and developing hydrocarbon reserves involves a high degree of technical, operational and financial risk, which precludes definitive statements as to the time required and costs involved in reaching certain objectives. The budgeted costs of planning, drilling, completing and operating wells are often exceeded and can increase significantly when drilling costs rise due to a tightening in the supply of various types of oilfield equipment and related services or unanticipated geologic conditions.
Before a well is spud, we incur significant geological and geophysical (seismic) costs, which are incurred whether or not a well eventually produces commercial quantities of hydrocarbons or is drilled at all. Drilling may be unsuccessful for many reasons, including geologic conditions, weather, cost overruns, equipment shortages and mechanical difficulties or force
majeure events. Exploratory wells bear a much greater risk of failure than development wells. In the past we have experienced unsuccessful drilling efforts, having drilled dry holes. Furthermore, the successful drilling of a well does not necessarily result in the commercially viable development of a field or be indicative of the potential for the development of a commercially viable field. A variety of factors, including geologic and market‑related, can cause a field to become uneconomic or only marginally economic. A lack of drilling opportunities or projects that cease production may cause us to incur significant costs associated with an idle rig and/or related services, particularly if we cannot contract out rig slots to other parties. Many of our prospects that may be developed require significant additional exploration, appraisal and development, regulatory approval and commitments of resources prior to commercial development. In addition, a successful discovery would require significant capital expenditure in order to appraise, develop and produce oil and natural gas, even if we deemed such discovery to be commercially viable. See “—Our business plan requires substantial additional capital, which we may be unable to raise on acceptable terms or at all in the future, which may in turn limit our ability to develop our exploration, appraisal, development and production activities.” In the international areas in which we operate, we face higher above‑ground risks necessitating higher expected returns, the requirement for increased capital expenditures due to a general lack of infrastructure and underdeveloped oil and gas industries, and increased transportation expenses due to geographic remoteness, which either require a single well to be exceptionally productive, or the existence of multiple successful wells, to allow for the development of a commercially viable field. See “—Our operations may be adversely affected by political and economic circumstances in the countries in which we operate.” Furthermore, if our actual drilling and development costs are significantly more than our estimated costs, we may not be able to continue our business operations as proposed and could be forced to modify our plan of operation.
Development drilling may not result in commercially productive quantities of oil and gas reserves.
Our exploration success has provided us with major development projects on which we are moving forward, and any future exploration discoveries will also require significant development efforts to bring to production. We must successfully execute our development projects, including development drilling, in order to generate future production and cash flow. However, development drilling is not always successful and the profitability of development projects may change over time.
For example, in new development projects available data may not allow us to completely know the extent of the reservoir or choose the best locations for drilling development wells. A development well we drill may be a dry hole or result in noncommercial quantities of hydrocarbons. All costs of development drilling and other development activities are capitalized, even if the activities do not result in commercially productive quantities of hydrocarbon reserves. This puts a property at higher risk for future impairment if commodity prices decrease or operating or development costs increase.
Our identified drilling and infrastructure locations are scheduled out over time, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling or infrastructure installation or modification.
Our management team has identified and scheduled drilling locations and possible infrastructure locations on our license and lease areas over a multi‑year period. Our ability to drill and develop these locations depends on a number of factors, including the availability of equipment and capital, approval by block or lease partners and national and state regulators, seasonal conditions, oil prices, assessment of risks, costs and drilling results. For example, a shutdown of the U.S. federal government could delay the regulatory review and approval process associated with drilling or developmental activities within our license areas in the U.S. Gulf of Mexico. The final determination on whether to drill or develop any of these locations will be dependent upon the factors described elsewhere in this report as well as, to some degree, the results of our drilling and production activities with respect to our established wells and drilling locations. Because of these uncertainties, we do not know if the drilling locations we have identified will be drilled or infrastructure installed or modified within our expected timeframe or at all or if we will be able to economically produce hydrocarbons from these or any other potential drilling locations. As such, our actual drilling and development activities may be materially different from our current expectations, which could adversely affect our results of operations and financial condition.
Under the terms of our various petroleum contracts, we are contractually obligated to drill wells and declare any discoveries in order to retain exploration and production rights. In the competitive market for our license areas, failure to drill these wells or declare any discoveries may result in substantial license renewal costs or loss of our interests in the undeveloped parts of our license areas, which may include certain of our prospects or undeveloped discoveries.
In order to protect our exploration and production rights in our license areas, we must meet various drilling and declaration requirements. In general, unless we make and declare discoveries within certain time periods specified in our various petroleum contracts and licenses, our interests in the undeveloped parts of our license areas may lapse. Should the prospects yield discoveries, we cannot assure you that we will not face delays in the appraisal and development of these prospects or otherwise have to relinquish these prospects. The costs to maintain petroleum contracts over such areas may
fluctuate and may increase significantly since the original term, and we may not be able to renew or extend such petroleum contracts on commercially reasonable terms or at all. Our actual drilling activities may therefore materially differ from our current expectations, which could adversely affect our business.
Under these petroleum contracts, we have work commitments to perform exploration and other related activities. Failure to do so may result in our loss of the licenses. As of December 31, 2021, we have an unfulfilled drilling obligation in one of our Mauritania petroleum contracts. In certain other petroleum contracts, we are in the initial exploration phases, some of which have certain obligations that have yet to be fulfilled. Over the course of the next several years, we may choose to enter into the next phase of those petroleum contracts which will likely include firm obligations to drill wells. Failure to execute our obligations may result in our loss of the licenses.
The Exploration Period of each of the WCTP and DT petroleum contracts has expired. For each of our petroleum contracts, we cannot assure you that any renewals or extensions will be granted or whether any new agreements will be available on commercially reasonable terms, or, in some cases, at all. For additional detail regarding the status of our operations with respect to our various petroleum contracts, please see “Item 1. Business—Operations by Geographic Area.”
The inability of one or more third parties who contract with us to meet their obligations to us may adversely affect our financial results.
We may be liable for certain costs if third parties who contract with us are unable to meet their commitments under such agreements. We are currently exposed to credit risk through joint interest receivables from our block and/or unit partners. If any of our partners in the blocks or unit in which we hold interests are unable to fund their share of the exploration and development expenses, we may be liable for such costs. In the past, certain of our partners have not paid their share of block costs in the time frame required by the joint operating agreements for these blocks. This has resulted in such party being in default, which in return requires Kosmos and its non‑defaulting block partners to pay their proportionate share of the defaulting party’s costs during the default period. Should a default not be cured, Kosmos could be required to pay its share of the defaulting party’s costs going forward.
In addition, we contract with third parties to conduct drilling and related services on our development projects and exploration prospects. Such third parties may not perform the services they provide us on schedule or within budget. Furthermore, the drilling equipment, facilities and infrastructure owned and operated by the third parties we contract with is highly complex and subject to malfunction and breakdown. Any malfunctions or breakdowns may be outside our control and result in delays, which could be substantial. Any delays in our drilling campaign caused by equipment, facility or equipment malfunction or breakdown could materially increase our costs of drilling and cause an adverse effect on our business, financial position and results of operations.
Our principal exposure to credit risk will be through receivables resulting from the sale of our oil, which we currently sell to oil marketing companies, and to cover our commodity derivatives contracts. The inability or failure of our significant customers or counterparties to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. In addition, our oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. Joint interest receivables arise from our block partners. The inability or failure of third parties we contract with to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. We are unable to predict sudden changes in creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited and we could incur significant financial losses.
The unit partners’ respective interests in the Jubilee Unit and Greater Tortue Ahmeyim Unit are subject to redetermination and our interests in each such unit may decrease as a result.
The interests in and development of the Jubilee Field are governed by the terms of the Jubilee UUOA. The parties to the Jubilee UUOA, the collective interest holders in each of the WCTP and DT Blocks, initially agreed that interests in the Jubilee Unit will be shared equally, with each block deemed to contribute 50% of the area of such unit. The respective interests in the Jubilee Unit were therefore initially determined by the respective interests in such contributed block interests. Pursuant to the terms of the Jubilee UUOA, the percentage of such contributed interests is subject to a process of redetermination once sufficient development work has been completed in the unit. The initial redetermination process was completed on October 14, 2011. As a result of the initial redetermination process, the tract participation was determined to be 54.4% for the WCTP Block and 45.6% for the DT Block. Consequently, our Unit Interest (participating interest in the Jubilee Unit) was increased from 23.5% to 24.1% upon completion of the initial redetermination process. Following the acquisition of Anadarko WCTP Company, which owned a participating interest in the WCTP Block and DT Block, our Unit Interest (participating interest in the Jubilee Unit) increased from 24.1% to 42.1%. An additional redetermination could occur sometime if requested by a party that holds greater than a 10% interest in the Jubilee Unit. We cannot assure you that any redetermination pursuant to the terms
of the Jubilee UUOA will not negatively affect our interests in the Jubilee Unit or that such redetermination will be satisfactorily resolved.
The interests in and development of the Greater Tortue Ahmeyim Field are governed by the terms of the GTA UUOA. The parties to the GTA UUOA, the collective interest holders in each of the Mauritania Block C8 and Senegal Saint Louis Offshore Profond blocks, initially agreed that interests in the Greater Tortue Ahmeyim Unit will be shared equally, with each block deemed to contribute 50% of the area of such unit. The respective interests in the Greater Tortue Ahmeyim Unit were therefore initially determined by the respective interests in such contributed block interests. Pursuant to the terms of the GTA UUOA, the percentage of such contributed interests is subject to a process of redetermination once sufficient development work has been completed in the unit. We cannot assure you that any redetermination pursuant to the terms of the GTA UUOA will not negatively affect our interests in the Greater Tortue Ahmeyim Unit or that such redetermination will be satisfactorily resolved.
We are not, and may not be in the future, the operator on all of our license areas and facilities and do not, and may not in the future, hold all of the working interests in certain of our license areas. Therefore, we have reduced control over the timing of exploration or development efforts, associated costs, and the rate of production of any non‑operated and to an extent, any non‑wholly-owned, assets.
As we carry out our exploration and development programs, we have arrangements with respect to existing license areas and may have agreements with respect to future license areas that result in a greater proportion of our license areas being operated by others. Currently, we are not the operator of the Jubilee Unit, the TEN fields, Ceiba and Okume, the Greater Tortue Ahmeyim Unit or certain producing fields in the U.S. Gulf of Mexico and do not hold operatorship in certain other offshore blocks. As a result, we may have limited ability to exercise influence over the operations of the discoveries or prospects operated by our block or unit partners, or which are not wholly-owned by us, as the case may be. Dependence on block or unit partners could prevent us from realizing our target returns for those discoveries or prospects. Further, because we do not have majority ownership in all of our properties, we may not be able to control the timing, or the scope, of exploration or development activities or the amount of capital expenditures and, therefore, may not be able to carry out one of our key business strategies of minimizing the cycle time between discovery and initial production. The success and timing of exploration and development activities will depend on a number of factors that will be largely outside of our control, including:
•the timing and amount of capital expenditures;
•if the activity is operated by one of our block partners, the operator’s expertise and financial resources;
•approval of other block partners in drilling wells;
•the scheduling, pre‑design, planning, design and approvals of activities and processes;
•selection of technology;
•the available capacity of processing facilities and related pipelines; and
•the rate of production of reserves, if any.
This limited ability to exercise control over the operations on our license areas may cause a material adverse effect on our financial condition and results of operations.
Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
The process of estimating oil and natural gas reserves is technically complex. It requires interpretations of available technical data and many assumptions, including those relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves shown in this report. See “Item 1. Business—Our Reserves” for information about our estimated oil and natural gas reserves and the present value of our net revenues at a 10% discount rate (“PV‑10”) and Standardized Measure of discounted future net revenues (as defined herein) as of December 31, 2021.
In order to prepare our estimates, we must project production rates and the timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The process also requires economic
assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this report. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.
The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves.
You should not assume that the present value of future net revenues from our proved reserves is the current market value of our estimated oil and natural gas reserves. In accordance with the SEC requirements, we have based the estimated discounted future net revenues from our proved reserves on the 12‑month unweighted arithmetic average of the first‑day‑of‑the‑month price for the preceding twelve months, adjusted for an anticipated market premium, without giving effect to derivative transactions. Actual future net revenues from our oil and natural gas assets will be affected by factors such as:
•actual prices we receive for oil and natural gas;
•actual cost of development and production expenditures;
•the amount and timing of actual production; and
•changes in governmental regulations or taxation.
The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas assets will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net revenues may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general. Actual future prices and costs may differ materially from those used in the present value estimates included in this report. Oil prices have recently experienced significant volatility. See “Item 1. Business—Our Reserves.”
We may not be able to commercialize our interests in any natural gas produced from our license areas.
The development of the market for natural gas in certain of our international license areas is in its early stages. Currently the infrastructure to transport and process natural gas on commercial terms is limited and the expenses associated with constructing such infrastructure ourselves may not be commercially viable given local prices currently paid for natural gas. Accordingly, there may be limited or no value derived from any natural gas produced from some of our international license areas.
In Ghana, we currently produce associated gas from the Jubilee and TEN fields. A gas pipeline from the Jubilee Field has been constructed to transport such natural gas for processing and sale. However, we granted the Government of Ghana the first 200 Bcf of natural gas exported from the Jubilee Field to shore at zero cost. Through December 31, 2021, the Jubilee partners have provided approximately 159 Bcf from the Jubilee Field to the Government of Ghana and are currently forecasted to provide the remaining portion of the first 200 Bcf of natural gas to the Government of Ghana in around one year. The Jubilee partners are currently in discussions with the Government of Ghana regarding a gas sales agreement for volumes of Jubilee natural gas beyond the first 200 Bcf. We do not currently book proved gas reserves associated with natural gas sales from the Jubilee Field in Ghana. However, we expect to book gas reserves upon finalization and execution of a gas sales agreement for such Jubilee Field natural gas that will have a price associated with it. A gas pipeline from the TEN fields to the Jubilee Field was completed in 2017 to transport associated natural gas as well as non-associated natural gas for processing and sale. We finalized the TAG GSA, and as a result, we booked proved gas reserves for the associated natural gas from the TEN fields in Ghana. If and when a gas sales agreement and the related infrastructure are in place for the TEN fields non-associated gas, a portion of the remaining gas may be recognized as reserves.
In Mauritania and Senegal, we plan to export the majority of our gas resource to the LNG market. However, that plan is contingent on making additional final investment decisions on our gas discoveries and constructing the necessary
infrastructure to produce, liquefy and transport the gas to the market. Additionally, such plans are contingent upon receipt of required partner and government approvals.
Our inability to access appropriate equipment and infrastructure in a timely manner may hinder our access to oil and natural gas markets or delay our oil and natural gas production.
Our ability to market our oil and natural gas production will depend substantially on the availability and capacity of processing facilities, oil and LNG tankers and other infrastructure, including FPSOs, owned and operated by third parties. Our failure to obtain such facilities on acceptable terms could materially harm our business. We also rely on continuing access to drilling rigs suitable for the environment in which we operate. The delivery of drilling rigs may be delayed or cancelled, and we may not be able to gain continued access to suitable rigs in the future. We may be required to shut in oil and natural gas wells because of the absence of a market or because access to processing facilities may be limited or unavailable. If that were to occur, then we would be unable to realize revenue from those wells until arrangements were made to deliver the production to market, which could cause a material adverse effect on our financial condition and results of operations. In addition, the shutting in of wells can lead to mechanical problems upon bringing the production back online, potentially resulting in decreased production and increased remediation costs.
Additionally, the future exploitation and sale of associated and non‑associated natural gas and liquids and LNG will be subject to timely commercial processing and marketing of these products, which depends on the contracting, financing, building and operating of infrastructure by third parties. The Government of Ghana completed the construction and connection of a gas pipeline from the Jubilee Field and the pipeline between the Jubilee and TEN fields to transport such natural gas to the mainland for processing and sale was completed in 2017. However, the uptime of the pipeline and processing facilities in future periods is not known. In the absence of the continuous removal of natural gas, it is anticipated that we will either need to flare such natural gas in order to maintain crude oil production or reduce crude oil production. If we are unable to resolve potential issues related to the continuous removal of associated natural gas, our oil production will be negatively impacted.
We are subject to numerous risks inherent to the exploration and production of oil and natural gas.
Oil and natural gas exploration and production activities involve many risks that a combination of experience, knowledge and interpretation may not be able to overcome. Our future will depend on the success of our exploration and production activities and on the development of an infrastructure that will allow us to take advantage of our discoveries. Additionally, many of our license areas are located in deepwater, which generally increases the capital and operating costs, chances of delay, planning time, technical challenges and risks associated with oil and natural gas exploration and production activities. See “— Our offshore and deepwater operations involve special risks that could adversely affect our results of operation.” As a result, our oil and natural gas exploration and production activities are subject to numerous risks, including the risk that drilling will not result in commercially viable oil and natural gas production. Our decisions to purchase, explore or develop discoveries, prospects or licenses will depend in part on the evaluation of seismic data through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations.
Furthermore, the marketability of expected oil and natural gas production from our discoveries and prospects will also be affected by numerous factors. These factors include, but are not limited to, market fluctuations of prices (such as recent significant declines in oil and natural gas prices), proximity, capacity and availability of drilling rigs and related equipment, qualified personnel and support vessels, processing facilities, transportation vehicles and pipelines, equipment availability, access to markets and government regulations (including, without limitation, regulations relating to prices, taxes, royalties, allowable production, domestic supply requirements, importing and exporting of oil and natural gas, the ability to flare or vent natural gas, health and safety matters, environmental protection and climate change). The effect of these factors, individually or jointly, may result in us not receiving an adequate return on invested capital.
In the event that our currently undeveloped discoveries and prospects are developed and become operational, they may not produce oil and natural gas in commercial quantities or at the costs anticipated, and our projects may cease production, in part or entirely, in certain circumstances. Discoveries may become uneconomic as a result of an increase in operating costs to produce oil and natural gas. Our actual operating costs and rates of production may differ materially from our current estimates. Moreover, it is possible that other developments, such as increasingly strict environmental, climate change, and health and safety laws, regulations and executive orders and enforcement policies thereunder and claims for damages to property or persons resulting from our operations, could result in substantial costs and liabilities, delays, an inability to complete the development of our discoveries or the abandonment of such discoveries, which could cause a material adverse effect on our financial condition and results of operations.
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:
•fires, blowouts, spills, cratering and explosions;
•mechanical and equipment problems, including unforeseen engineering complications;
•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;
•formations with abnormal pressures;
•pollution, environmental risks, and geological problems; and
•weather conditions and natural or man‑made disasters.
These risks are particularly acute in deepwater drilling, exploration, and development. Any of these events could result in loss of human life, significant damage to property, environmental or natural resource damage, impairment, delay or cessation of our operations, lower production rates, adverse publicity, substantial losses and civil or criminal liability. We expect to maintain insurance against some, but not all, of these risks and losses. The occurrence of any of these events, whether or not covered by insurance, could have a material adverse effect on our financial position and results of operations.
Our operations may be materially adversely affected by weather-related events, including tropical storms and hurricanes.
Tropical storms, hurricanes and the threat of tropical storms and hurricanes often result in the shutdown of operations, particularly in the U.S. Gulf of Mexico, as well as operations within the path and the projected path of the tropical storms or hurricanes. In addition, climate change could result in an increase in the frequency and severity of tropical storms, hurricanes or other extreme weather events. Weather events have caused significant disruption to the operations of offshore and coastal facilities in the U.S. Gulf of Mexico region. In the future, during a shutdown period, we may be unable to access well sites and our services may be shut down. Additionally, tropical storms or hurricanes may cause evacuation of personnel and damage to our platforms and other equipment, which may result in suspension of our operations. The shutdowns, related evacuations and damage can create unpredictability in activity and utilization rates, as well as delays and cost overruns, which could have a material adverse effect on our business, financial condition and results of operations.
The development schedule of oil and natural gas projects, including the availability and cost of drilling rigs, equipment, supplies, personnel and oilfield services, is subject to delays and cost overruns.
Historically, some oil and natural gas development projects have experienced delays and capital cost increases and overruns due to, among other factors, the unavailability or high cost of drilling rigs and other essential equipment, supplies, personnel and oilfield services, mechanical and technical issues, as well as weather-related delays. The cost to develop our projects has not been fixed and remains dependent upon a number of factors, including the completion of detailed cost estimates and final engineering, contracting and procurement costs. Our construction and operation schedules may not proceed as planned and may experience delays or cost overruns. Any delays may increase the costs of the projects, requiring additional capital, and such capital may not be available in a timely and cost‑effective fashion.
Our offshore and deepwater operations involve specific risks that could adversely affect our results of operations.
Offshore operations are subject to a variety of operating risks specific to the marine environment, such as capsizing, sinking, collisions and damage or loss to pipeline, subsea or other facilities or from weather conditions. We could incur substantial expenses that could reduce or eliminate the funds available for exploration, development or license acquisitions, or result in loss of equipment and license interests.
Deepwater exploration generally involves greater operational and financial risks than exploration in shallower waters. Deepwater drilling generally requires more time and more advanced drilling technologies, involving a higher risk of equipment failure and usually higher drilling costs. In addition, there may be production risks of which we are currently unaware. If we participate in the development of new subsea infrastructure and use floating production systems to transport oil from producing
wells, these operations may require substantial time for installation or encounter mechanical difficulties and equipment failures that could result in loss of production, significant liabilities, cost overruns or delays. For example, we have experienced mechanical issues in the Jubilee Field, including failures of its gas and water injection facilities on the FPSO, and the turret bearing issue on the FPSO. The equipment downtime caused by these mechanical issues negatively impacted oil production.
Furthermore, deepwater operations generally, and operations in Africa, in particular, lack the physical and oilfield service infrastructure present in other regions. As a result, a significant amount of time may elapse between a deepwater discovery and the marketing of the associated oil and natural gas, increasing both the financial and operational risks involved with these operations. Because of the lack and high cost of this infrastructure, further discoveries we may make in Africa may never be economically producible.
In addition, in the event of a well control incident, containment and, potentially, cleanup activities for offshore drilling are costly. The resulting regulatory costs or penalties, and the results of third-party lawsuits, as well as associated legal and support expenses, including costs to address negative publicity, could well exceed the actual costs of containment and cleanup. As a result, a well control incident could result in substantial liabilities, and have a significant negative impact on our earnings, cash flows, liquidity, financial position, and stock price.
We have had disagreements with host governments regarding certain of our rights and responsibilities and may have future disagreements with our host governments.
There can be no assurance that future disagreements will not arise with any host government and/or national oil companies that may