Kosmos Energy Ltd

General

Kosmos is a full-cycle, deepwater, independent oil and gas exploration and production company focused along the offshore Atlantic Margins. Our key assets include production offshore Ghana, Equatorial Guinea and the U.S. Gulf of Mexico, as well as world-class gas projects offshore Mauritania and Senegal. We also pursue a proven basin exploration program in Equatorial Guinea and the U.S. Gulf of Mexico. Kosmos is listed on the NYSE and LSE and is traded under the ticker symbol KOS.

Kosmos was founded in 2003 to find oil in under‑explored or overlooked parts of West Africa. In its relatively brief history, we have successfully opened two new hydrocarbon basins through the discovery of the Jubilee Field offshore Ghana in 2007 and the Greater Tortue Ahmeyim Field in 2015 (which includes the Ahmeyim and Guembeul-1 discovery wells offshore Mauritania and Senegal in 2015 and 2016, respectively). Jubilee was one of the largest oil discoveries worldwide in 2007 and is considered one of the largest finds offshore West Africa discovered during that decade. The Greater Tortue Ahmeyim discovery was one of the largest natural gas discoveries worldwide in 2015 and is one of the largest gas discoveries ever offshore West Africa.

Over the past few years, our business strategy has evolved to focus on enhancing production through 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, we have demonstrated this infrastructure-led exploration strategy by the Winterfell and Tiberius discoveries in the U.S. Gulf of Mexico in 2021 and 2023, respectively. We have demonstrated the value-accretive acquisitions strategy with the acquisition of additional interests in the Jubilee and TEN fields offshore Ghana in 2021, the Kodiak and Winterfell fields in the U.S. Gulf of Mexico in 2022, and the Yakaar and Teranga fields in Senegal in 2023.

Our Business Strategy

As a full-cycle deepwater E&P company, our mission is to safely deliver production and free cash flow from a portfolio rich in opportunities through a disciplined allocation of capital and optimal portfolio management for the benefit of our shareholders and stakeholders. As a responsible company, we are working to supply the energy the world needs today, find and develop affordable and cleaner energy to advance the energy transition, and be a force for good in our host countries.

Our business strategy is designed to accomplish this mission by focusing on three key objectives: (1) maximize the value of our producing assets; (2) progress our discovered resources toward project sanction and into proved reserves, production, and cash flow through efficient appraisal, development and exploitation; and (3) add new lower carbon resources through an efficient low cost exploration program in proven basins or acquisitions. We are focused on increasing production, cash flows and reserves from our producing assets in Equatorial Guinea, Ghana, and the U.S. Gulf of Mexico as well as executing our appraisal and development efforts in the U.S. Gulf of Mexico and Equatorial Guinea. In Mauritania and Senegal, we are progressing our Greater Tortue Ahmeyim development with first gas for Phase 1 of the project targeted in the third quarter of 2024, while advancing Phase 2 of the development, as well as advancing phased development concepts for the Yakaar and Teranga discoveries in Senegal and the BirAllah and Orca discoveries in Mauritania. In addition, our portfolio contains an inventory of infrastructure-led exploration prospects, which we plan to continue to mature and high-grade for future drilling and development, providing us access to additional high return growth potential in the coming years. We are also working with our partners and host governments on projects to reduce the carbon intensity of our production assets, such as the elimination of routine flaring in Ghana and Equatorial Guinea.

Grow cash flow, proved reserves and production through exploitation and development with increasing exposure to natural gas and LNG

We plan to grow cash flow, proved reserves and production by further exploiting our fields offshore Equatorial Guinea, Ghana, and the U.S. Gulf of Mexico. In Equatorial Guinea, our activity set is expanding beyond production optimization projects, such as utilizing electrical submersible pumps, to include development drilling and infrastructure-led exploration which, if successful, can be brought online quickly via subsea tieback to existing infrastructure. In Ghana, we plan to continue drilling additional development wells at the Jubilee Field in the near term. In the U.S. Gulf of Mexico, we plan to continue development drilling and well work in existing fields. We are also executing the Winterfell Field Development Plan with first production for Phase 1A of the project targeted for early in the second quarter of 2024 with future phases to follow. In addition, we are working with partners to progress development concepts for the Tiberius discovery which was made in 2023. The development of Phase 1 of the Greater Tortue Ahmeyim development offshore Mauritania and Senegal continues to make good progress. Beyond the Phase 1 development of Greater Tortue Ahmeyim, growth is also expected to be realized through additional development phases of Greater Tortue Ahmeyim and through development of the Yakaar and Teranga natural gas discoveries in Senegal and the BirAllah and Orca discoveries in Mauritania. During 2024, we plan to continue to mature development concepts for our existing discoveries in Mauritania, Senegal, the U.S. Gulf of Mexico and Equatorial Guinea.

Focus on optimally developing our discoveries to initial production

Our approach to development is designed to deliver first production on an accelerated timeline, with low cost, lower carbon solutions, where we can leverage early learnings to improve future outcomes and maximize returns. In certain circumstances, we believe a phased approach can be employed to optimize full‑field development. A phased approach facilitates refinement of the development plans based on experience gained in initial phases of production and by leveraging existing infrastructure as subsequent phases of development are implemented. Production and reservoir performance from the initial phases are monitored closely to determine the most efficient and effective techniques to maximize the recovery of reserves and returns. Other benefits include minimizing upfront capital costs, reducing execution risks through smaller initial infrastructure requirements, and enabling cash flow from the initial phases of production to fund a portion of capital costs for subsequent phases. Our development of the Jubilee Field is an example of this approach. The Greater Tortue Ahmeyim development is also being developed in a phased approach, consistent with our business strategy. This is anticipated to result in first gas approximately nine 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 approach, with development expected to deliver first production in around three years after initial discovery. In addition, we anticipate that the Tiberius discovery (2023) will follow a similar approach.

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 28 years of industry experience and have participated in discovering, developing, and maximizing the value of multiple large-scale upstream projects around the world. Our experience, industry relationships and technical expertise are our core competitive strengths and are crucial to our success.

Our returns focused exploration approach

Our exploration activity, which is deeply rooted in a fundamental, geologic approach, is focused on proven basins with high-graded infrastructure-led prospects and material play extension opportunities. We target specific areas with sufficient size to manage exploration risks and provide scale should the exploration concept prove successful. We also look for: (i) long‑term contract durations to enable the “right” exploration program to be executed, (ii) play type diversity to provide multiple exploration concept options, (iii) prospect dependency to enhance the chance of replicating success, and (iv) attractive fiscal terms to maximize the commercial viability of discovered hydrocarbons. Alongside the subsurface analysis, Kosmos gains a thorough understanding of the “above‑ground” dynamics in each of the countries in which we operate, which may influence a particular country’s relative desirability from an overall oil and natural gas operating and risk adjusted return perspective.

Our approach is aimed at areas where we have existing production and where there is sufficient infrastructure capacity to enable the development of new discoveries via subsea tieback. Acquisition of the Ceiba Field and Okume Complex in Equatorial Guinea and assets in the U.S. Gulf of Mexico have added high-quality prospectivity to our inventory of infrastructure-led exploration opportunities given their attractive acreage positions within proximity of existing infrastructure with excess capacity available. Existing infrastructure allows us to shorten the time cycle from discovery to first production, lower the capital requirements and increase the returns.

Pursuing value accretive, opportunistic transactions that meet our strategic and financial objectives

Since 2017, we have completed three separate significant acquisitions of oil and natural gas producing properties for total value of approximately $2.0 billion dollars, as of the effective date of the acquisitions. These acquisitions were targeted to increase and complement our existing properties, providing production diversification while increasing the quality of investment opportunities in our portfolio. Our experienced team of management and technical professionals intend to continue identifying, evaluating and pursuing transactions involving oil and natural gas properties that are complementary to our core operating areas, as well as opportunities in other basins where we can apply our existing knowledge, expertise and relationships to create shareholder value. Our focus is on transactions where we can leverage our operational experience and expertise to provide productivity and cost improvements, invest in additional developmental opportunities in such assets and implement an infrastructure-led exploration program for nearby prospects.

Secure a premium license to operate through industry-leading ESG performance

We recognize that advancing the societies in which we work and operating in a manner that protects the environment is critical for creating long-term returns. We aim to continuously improve our ESG credentials by working with a range of stakeholders, including shareholders, partners, suppliers, host governments and civil society organizations.

We aim to act as a force for good by advancing a just energy transition in our host countries and communities – namely by supporting economic and social development in the places where we work through supplying affordable and cleaner energy while lowering emissions. We use the United Nations Sustainable Development Goals to understand how our activities promote economic and social progress in host countries. Our Business Principles reflect our shared values as a company, define how we conduct our business and set the standards to which we hold ourselves accountable. Our Business Principles are supported by more detailed policies, procedures, and management systems. Each year, we report on our ESG approach and performance in our Sustainability Report and on our website.

Most recently, we have focused on evaluating the costs, benefits, risks, and opportunities that climate change and the global energy transition may present to our business and integrating them into our business strategy. As part of this effort, the Health, Safety, Environment and Sustainability Board Committee oversees our response to climate change. A Chief Executive Officer led, cross functional, Climate Change Task force manages climate-related risks and opportunities, and is responsible for implementing our climate change strategy. We have published a Climate Risk and Resilience Report that adheres to the recommendations of the Task Force on Climate-related Disclosure (“TCFD”). The report reviews how we are identifying and managing climate-related risks and opportunities across four categories: Governance, Strategy, Risk Management, and Metrics and Targets. The report sets forth a scenario analysis demonstrating the resilience of our portfolio under a scenario aligned with the Paris Agreement’s goals, and our goal to achieve operated Scope 1 and Scope 2 carbon neutrality by 2030 or sooner. We first achieved this goal in 2021 and have identified a pathway to help maintain it through continual monitoring of emissions, assessment of emission reduction opportunities, and, for residual emissions, investment in high-quality carbon offset projects. We recognize most of our production, and the associated GHG emissions, is derived from assets in which we are non-operating partners. In 2023 we set a target to reduce absolute Scope 1 equity emissions 25% by 2026, compared to a 2022 baseline. This tangible, near-term target addresses the need to manage the climate impact of our portfolio and we are working with our partners to assess and implement emission reduction opportunities with minimal impact to production.

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, 2023, our liquidity was approximately $670 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 one to two year rolling basis, with the goal to protect against the downside price scenario while still retaining partial exposure to the upside. As of January 31, 2024, we have hedged positions covering approximately 9.2 million barrels of oil production in 2024 and are now looking to protect our exposure to oil prices in 2025. 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 2023 data for our geographic areas.

(1)Our sales volumes during 2022 includes activity related to the interest pre-empted by Tullow prior to the March 17, 2022 closing date of the Tullow pre-emption transaction.

(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.

(3)Substantially all NGLs and natural gas sales are associated production from our oil wells and, therefore, production costs metrics are presented under a common unit of measure.

Information about our deepwater fields is summarized in the following table.

(1)For information concerning our estimated proved reserves as of December 31, 2023, 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 43.05%.

(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 and the other block partners of each of these two blocks. The GTA UUOA governs interests in and development of the Greater Tortue Ahmeyim Field and created the Greater Tortue Ahmeyim Unit from portions of the Mauritania Block C8 and the Senegal Saint Louis Offshore Profond Block areas. These interest percentages are subject to redetermination of the participating interests in the Greater Tortue Ahmeyim Field pursuant to the terms of the GTA UUOA.

(4)Our paying interest on development activities in the TEN Fields is 22.8%.

(5)Our interests in blocks MC 214 and MC 215 are 61.1% and 54.9%, respectively.

(6)The Petroleum Contract covering the BirAllah and Orca discoveries contains provisions for back-in rights for the Government of Mauritania. Kosmos’ participating interest in the Petroleum contract is currently 28.0% and this interest percentage does not give effect to the exercise of such back-in rights. Full election by SMH of their back-in rights would reduce Kosmos’ participating interest to approximately 22.1%.

(7)PETROSEN has the right to increase its participating interest after final investment decision and issuance of an exploitation authorization to up to 35%. 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.

Exploration License and Lease Areas

(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)Full election by SMH of their back-in rights would reduce Kosmos’ participating interest to approximately 22.1%. SMH will pay its portion of development and production costs in a commercial development on the block. The interest percentage does not give effect to the exercise of such options.

(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 right to increase its participating interest after final investment decision and issuance of an exploitation authorization to up to 35%. 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 2033.

Ghana

The WCTP and DT Blocks 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 (“Anadarko WCTP”), a subsidiary of Occidental Petroleum Corporation, which owned a participating interest in the WCTP Block and DT Block offshore Ghana, including an 18.0% participating interest in the Jubilee Unit Area and an 11.1% participating interest in the TEN Fields. Following closing of the acquisition, Kosmos’ interest in the Jubilee Unit Area increased from 24.1% to 42.1%, and Kosmos’ interest in the TEN Fields increased from 17.0% to 28.1%. In

November 2021, we received notice from Tullow Oil plc (“Tullow”) that they were exercising their pre-emption rights in relation to Kosmos’ acquisition of Anadarko WCTP. After execution of definitive transaction documentation and receipt of governmental approvals, Kosmos concluded the pre-emption transaction with Tullow in March 2022. Following completion of the pre-emption process, Kosmos’ interest in the Jubilee Unit Area decreased from 42.1% to 38.6% and Kosmos’ interest in the TEN Fields decreased from 28.1% to 20.4%. The following is a brief discussion of our discoveries on our license areas offshore Ghana.

Ghana West Cape Three Points Block

Tullow is the operator of the West Cape Three Points Block. Under the WCTP petroleum contract, Kosmos is required to pay to the Government of Ghana a fixed royalty of 5% and a potential sliding‑scale royalty (“additional oil entitlement”), which comes into effect and escalates as the nominal project rate of return increases above a certain threshold. These royalties are to be paid in‑kind or, at the election of the Government of Ghana, in cash. A corporate tax rate of 35% is applied to profits at a country level. The WCTP petroleum contract has a duration of 30 years from its effective date (July 2004).

In July 2011, at the end of the seven‑year Exploration Period, parts of the WCTP Block on which we had not declared a discovery area, were not in a development and production area, or were not in the Jubilee Unit, were relinquished (“WCTP Relinquishment Area”). We maintain rights to the Akasa discovery within the WCTP Block as the WCTP petroleum contract remains in effect after the end of the Exploration Period. We and our WCTP Block partners have certain rights to negotiate a new petroleum contract with respect to certain portions of the WCTP Relinquishment Area. We and our WCTP Block partners, the Ghana Ministry of 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.

Jubilee Field

The Jubilee Field was discovered by Kosmos in 2007 by the Mahogany-1 well with first oil produced in 2010. The field 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.

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 continues to be 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 phased development of the Jubilee Field continued during 2023 successfully bringing four production wells and two injection wells online which included three wells (two production wells and one injection well) as part of the successful startup of the Jubilee Southeast project. The Jubilee Southeast project also included the installation of a new subsea production manifold. The development drilling campaign is planned to continue in 2024. One new injection well and one new production well were brought online early in the first quarter of 2024. The partnership expects to bring an additional three wells online in 2024 including two production wells and one injection well before we expect the rig contract to end.

In 2022, the partnership exported approximately 98 million standard cubic feet of natural gas per day (gross) on average from the Jubilee Field to the mainland. In December 2022, an interim gas sales agreement for 19 Bcf (gross) was executed with the Government of Ghana, which allowed for natural gas to be sold at $0.50 per MMBtu. In January 2023, the volume of approximately 19 Bcf of Jubilee gas (in restoration of the amount originally substituted from TEN) had been sold to Ghana under the terms of the TAG GSA at $0.50 per MMBtu. The Jubilee partners reached an interim agreement to sell Jubilee Field gas at a price of $2.95 per MMBtu to the Government of Ghana beyond the 19 Bcf from the Jubilee Field through May 2024, while the partners continue on-going discussions with the Government of Ghana regarding a long-term future gas sales agreement. Our inability to continuously export associated natural gas from the Jubilee Field could eventually impact our oil production and could cause us to re-inject or flare any natural gas we cannot export.

TEN

The TEN Fields are located in the western and central portions of the DT Block, approximately 48 kilometers offshore Ghana in water depths of approximately 1,000 to 1,700 meters. The discoveries have been jointly developed with shared infrastructure and a single FPSO, with first oil produced in 2016. Similar to Jubilee, the TEN Fields have been developed in a phased manner. The TEN PoD was designed to include an expandable subsea system that could provide for multiple phases.

The construction and connection of a gas pipeline between the Jubilee and TEN Fields to transport natural gas to the mainland for processing and sale was completed in 2017. In December 2017, we signed the TAG GSA. The partnership is currently in discussions with the Government of Ghana regarding a future gas sales agreement. During the second quarter of 2023, the operator submitted a draft amended plan of development for TEN, as well as a term sheet for a gas sales agreement covering future gas sales from both Jubilee and TEN Fields, to the Government of Ghana. If the amended plan of development is delayed or not approved, it could lead to a curtailment or delay of investment and development activity in TEN. Our inability to continuously export associated natural gas from the TEN Fields could eventually impact our oil production and could cause us to re-inject or flare any natural gas we cannot export.

U.S. Gulf of Mexico

In the U.S. Gulf of Mexico, Kosmos maintains: (i) a portfolio of producing assets that Kosmos can continue to exploit, (ii) discovered resource opportunities, and (iii) a high-quality inventory of infrastructure-led exploration prospects across the DeSoto Canyon, Green Canyon, Keathley Canyon, Mississippi Canyon and Walker Ridge protraction areas. We expand our inventory through the U.S. Gulf of Mexico Federal lease sales and farm-in transactions.

The following is a brief discussion of our key fields in the U.S. Gulf of Mexico.

Odd Job

The Odd Job Field is producing from three Middle Miocene wells through the Delta House FPS, operated by Murphy. In June 2022, we executed, as operator of the Odd Job Field, a contract for $131.6 million (gross) with Subsea 7 (US) LLC and OneSubsea LLC to fabricate and install a subsea pump in the Odd Job Field. The Odd Job Field subsea pump installation project was approximately 90% complete as of the end of 2023 with an expected online date around the middle of 2024. The project is expected to sustain long-term production from the Odd Job Field.

Tornado

The Tornado Field is producing from three Pliocene wells through the Helix Producer I, a ship-shaped, dynamically-positioned production platform in the deepwater U.S. Gulf of Mexico, which is operated by Talos Energy.

Kodiak

The Kodiak Field is producing from two wells, which are completed in the Middle Miocene sands. These wells are flowing through the Devils Tower Spar platform, which is operated by ENI US Operating Co. Inc. (“ENI”). One of these wells, the Kodiak-3 infill well, was brought online in April 2021. The well experienced production issues and was shut-in. In March 2022, the Company commenced operations to plug back and side-track the original Kodiak-3 infill well. The well was sidetracked, and the Kodiak-3ST well was brought online in September 2022. Well results and initial production were in line with expectations, however well productivity declined through the end of the third quarter of 2022. Workover plans have been developed and are expected to commence around the middle of 2024.

Winterfell

In January 2021, we announced the Winterfell-1 exploration well encountered approximately 26 meters (85 feet) of net oil pay in two intervals. Winterfell was designed to test a sub-salt Upper Miocene prospect located in Green Canyon Block 944. In January 2022, the Winterfell-2 appraisal well in Green Canyon Block 943 was drilled to evaluate the adjacent fault block to the northwest of the original Winterfell discovery and was designed to test two horizons that were oil bearing in the Winterfell-1 well, with an exploration tail into a deeper horizon. The well discovered approximately 40 meters (120 feet) of net oil pay in the first and second horizons with better oil saturation and porosity than pre-drill expectations. The exploration tail discovered an additional oil-bearing horizon in a deeper reservoir which is also prospective in the blocks immediately to the north. During the third quarter of 2022, the Field Development Plan for the Winterfell Field was approved by all partners as a five well tieback to the Heidelberg facility which is operated by Oxy. The development drilling plan for the first phase included the sidetrack and completion of the Winterfell-1 well, completion of the Winterfell-2 well and drilling and completion of the Winterfell-3 well in an adjacent fault block to the southeast of the Winterfell-1 discovery well. The development drilling plan commenced in the third quarter of 2023 with the sidetrack and completion of the Winterfell-1 well in the fourth quarter of 2023. The Winterfell-2 well was completed early in the first quarter of 2024. The Winterfell-3 well is expected to commence drilling later in 2024. In addition, the host facility production handling agreement and oil export agreements have been executed. First production for Phase 1A of the project is targeted for early in the second quarter of 2024.

Tiberius

In July 2023, Kosmos spud the Tiberius infrastructure-led exploration prospect, which is located in block 964 of Keathley Canyon (33% working interest) in the Outer Wilcox play. In October 2023, we announced the well encountered approximately 75 meters (250 feet) of net oil pay in the primary Wilcox target. Initial fluid and core analysis supports the production potential of the wells, with characteristics analogous with similar nearby discoveries in the Wilcox trend. We are now working with partners on development options for the discovery.

Mauritania

In June 2012, we entered into a petroleum contract covering offshore Mauritania Block C8 with the Islamic Republic of Mauritania. 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. In June 2022, the exploration period of Block C8 offshore Mauritania expired and in October 2022 the partnership and the Government of Mauritania executed a new Petroleum contract covering the BirAllah and Orca discoveries in Block C8. The new Petroleum contract (named BirAllah) provides up to thirty months to submit a development plan covering the BirAllah and/or Orca discoveries with the terms of the new Petroleum contract substantially similar to the former Petroleum contract for Block C8 with additional provisions for enhanced back-in rights for the Government of Mauritania, local content, SMH’s capacity building and an environmental fund. Kosmos’ participating interest in the new Petroleum contract is 28.0% and full election by SMH of their back-in rights would reduce Kosmos’ participating interest to approximately 22.1%.

The C8 and BirAllah blocks are located on the western margin of the Mauritania Salt Basin offshore Mauritania and range in water depths from 100 to 3,000 meters. These blocks are located in a proven petroleum system, with our primary targets being Cretaceous sands in structural and stratigraphic traps.

The C8 and BirAllah blocks cover an aggregate area of approximately 735 thousand acres (gross). We have acquired approximately 580 line-kilometers of 2D seismic data and 3,000 square kilometers of 3D seismic data covering portions of our blocks in Mauritania. Based on these 2D and 3D seismic programs, we have drilled three successful exploration wells and one appraisal well in Block C8 (now Greater Tortue Ahmeyim) and what is now the BirAllah block.

Senegal

The Saint Louis Offshore Profond and Cayar Offshore Profond Blocks are located in the Senegal River Cretaceous petroleum system and range in water depth from 300 to 3,100 meters. The area is an extension of the working petroleum system in the Mauritania Salt Basin. We acquired approximately 3,700 square kilometers of 3D seismic data over these Senegal blocks. We have drilled three successful exploration wells and two appraisal wells.

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. We are currently working with the Government of Senegal on a further extension of the term for the Cayar Offshore Profond license. 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.

The following is a brief discussion of our discoveries to date offshore Mauritania and Senegal.

Greater Tortue Ahmeyim Development

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 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 interests in their portion of the Greater Tortue Ahmeyim Unit to the maximum allowed percentages under the respective petroleum contracts. After the elections, our interest in the exploration areas of Block C8 offshore Mauritania and in Saint Louis Offshore Profound offshore Senegal are unchanged, however, our interest in the Greater Tortue Ahmeyim Unit is now 26.8% in Mauritania and 26.7% in Senegal and is subject to redetermination of the participating interests pursuant to the terms of the GTA UUOA. In February 2019, Mauritania and Senegal each issued an exploitation authorization for the Greater Tortue Ahmeyim Unit area covered by the GTA UUOA.

The Greater Tortue Ahmeyim discoveries are significant, play-opening gas discoveries for the outboard Cretaceous petroleum system and are located approximately 120 kilometers offshore Mauritania and Senegal. The Greater Tortue Ahmeyim development straddles Block C8 offshore Mauritania and Saint Louis Offshore Profond Block offshore Senegal.

We have drilled four exploration and appraisal wells within the Greater Tortue Ahmeyim development, Tortue-1, Guembeul-1, Ahmeyim-2 and Greater Tortue Ahmeyim-1 (GTA-1). The wells penetrated multiple, excellent quality gas reservoirs, including the Lower Cenomanian, Upper Cenomanian and underlying Albian. The wells successfully delineated the Ahmeyim and Guembeul gas discoveries and demonstrated reservoir continuity, as well as static pressure communication between the three wells drilled within the Lower Cenomanian reservoir. The discoveries range in water depths from approximately 2,700 meters to 2,800 meters, with total depths drilled ranging from approximately 5,100 meters to 5,250 meters.

The Tortue-1 discovery well, located in Block C8 offshore Mauritania, intersected approximately 117 meters of net hydrocarbon pay. A single gas pool was encountered in the Lower Cenomanian objective, which is comprised of three reservoirs totaling 88 meters in thickness over a gross hydrocarbon interval of 160 meters. A fourth reservoir totaling 19 meters was penetrated within the Upper Cenomanian target over a gross hydrocarbon interval of 150 meters. The exploration well also intersected an additional 10 meters of net hydrocarbon pay in the lower Albian section, which is interpreted to be gas.

The Guembeul-1 discovery well, located in the northern part of the Saint Louis Offshore Profond area in Senegal, is located approximately five kilometers south of the Tortue-1 exploration well in Mauritania. The well encountered 101 meters of net gas pay in two excellent quality reservoirs, including 56 meters in the Lower Cenomanian and 45 meters in the underlying Albian, with no water encountered.

The Ahmeyim-2 appraisal well is located in Block C8 offshore Mauritania, approximately five kilometers northwest, and 200 meters down-dip of the basin-opening Tortue-1 discovery. The well confirmed significant thickening of the gross reservoir sequences down-dip. The Ahmeyim-2 well encountered 78 meters of net gas pay in two excellent quality reservoirs, including 46 meters in the Lower Cenomanian and 32 meters in the underlying Albian.

The Greater Tortue Ahmeyim-1 (GTA-1) appraisal well was drilled on the eastern anticline within the unit development area of Greater Tortue Ahmeyim field. The GTA-1 well encountered approximately 30 meters of net gas pay in high quality Albian reservoir. The well was drilled in approximately 2,500 meters of water, approximately 10 kilometers inboard of the Guembeul-1A and Tortue-1 wells, to a total depth of 4,884 meters.

In 2017, we completed a DST on the Tortue-1 well, demonstrating that the Tortue field is a world-class resource and confirming key development parameters including well deliverability, reservoir connectivity, and fluid composition. The Tortue-1 well flowed at a sustained, equipment-constrained rate of approximately 60 MMcfd during the main extended flow period, with minimal pressure drawdown, providing confidence in well designs that are each capable of producing approximately 200 MMcfd. The DST results confirmed a connected volume per well consistent with the current development scheme, which together with the high well rate is expected to result in a low number of development wells compared to equivalent schemes. Initial analysis of fluid samples collected during the test indicate Tortue gas is well suited for liquefaction given low levels of liquids and minimal impurities.

In December 2018, we and our partners announced that a final investment decision for Phase 1 of the Greater Tortue Ahmeyim project had been agreed. The Greater Tortue Ahmeyim project is designed to produce gas from a deepwater subsea system to a mid-water FPSO, which processes the gas to make it liquefaction ready, and sends the gas through a pipeline to a FLNG facility. The FLNG facility is protected behind a nearshore hub (which serves as a breakwater and LNG terminal) and is located on the Mauritania and Senegal maritime border. The FLNG facility for Phase 1 is designed to produce approximately 2.5 million tons per annum on average. The project will provide LNG for global export, as well as make gas available for domestic use in both Mauritania and Senegal. Following a competitive tender process, BP Gas Marketing (“BPGM”) was selected as the buyer for the LNG offtake for Greater Tortue Ahmeyim Phase 1, and the Tortue Phase 1 SPA was executed in February 2020 with an initial term of 10 years with a seller’s option to extend the term for an additional 10 years. Additionally, to optimize the commercial value of sales for the gas production from Phase 1 of Greater Tortue Ahmeyim, Kosmos has commenced a process with prospective buyers to utilize existing contractual rights under our existing Tortue Phase 1 SPA to potentially sell cargos in order to benefit from the robust forward gas price outlook, while meeting our contractual obligations to BPGM. BPGM has disagreed with our position, and we have agreed with BPGM to pursue international arbitration to interpret the relevant terms of the SPA.

Phase 1 of the project was approximately 90% complete at year-end 2023, with first gas for the project targeted in the third quarter of 2024. The operator has successfully drilled and completed all four wells needed for Phase 1 start up. The FLNG construction was completed in 2023 and the vessel arrived on location offshore Mauritania/Senegal in the first quarter of 2024. Hookup and pre-commissioning work is now underway. Construction work is complete on the hub terminal and handover to operations was completed in August 2023. Significant progress has been made on the installation of the infield flowlines and subsea structures. Work re-commenced in the fourth quarter of 2023 and is expected to be completed at the end of the second quarter of 2024. The FPSO is currently in a shipyard in Tenerife for inspection and repair of fairleads. Completion of this work and transit to the project site is expected early in the second quarter of 2024 ahead of final hookup and commissioning.

Other Mauritania and Senegal Discoveries

BirAllah and Orca Discoveries

The BirAllah discovery (formerly known as Marsouin), located in the BirAllah block offshore Mauritania, is a significant, play-extending gas discovery, building on our successful exploration program in the outboard Cretaceous petroleum system offshore Mauritania. In November 2015, the Marsouin-1 well, located approximately 60 kilometers north of the Ahmeyim discovery, and was drilled to a total depth of 5,150 meters in nearly 2,400 meters of water. Based on analysis of drilling results and logging data, Marsouin-1 encountered at least 70 meters of net gas pay in Upper and Lower Cenomanian intervals comprised of excellent quality reservoir sands.

The Orca-1 well, located in the BirAllah block offshore Mauritania, was drilled in October 2019 and delivered a major gas discovery. The Orca-1 well, which targeted a previously untested Albian play, encountered 36 meters of net gas pay in excellent quality reservoirs. In addition, the well extended the Cenomanian play fairway by confirming 11 meters of net gas pay in a down-structure position relative to the original Marsouin-1 discovery well. The location of the Orca-1 well proved both the structural and stratigraphic components of the trap are working, thereby supporting a significant volume. The Orca-1 well was drilled in approximately 2,510 meters of water to a total measured depth of around 5,266 meters.

In total, we believe that Marsouin-1 and Orca-1 have de-risked significant resource in support of a potential world-scale LNG project from the Cenomanian and Albian plays in the BirAllah area. The BirAllah and Orca discoveries are being analyzed as a potential joint development. In October 2022, the partnership and the Government of Mauritania executed a new Petroleum contract covering the BirAllah and Orca discoveries. The new Petroleum contract provides the partnership up to thirty months to submit a development plan covering the BirAllah and/or Orca discoveries with the terms of the new Petroleum contract substantially similar to the former Petroleum contract for Block C8 with additional provisions for enhanced back-in rights for the Government of Mauritania, local content, SMH’s capacity building and an environmental fund.

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 Yakaar and Teranga discoveries continue to be analyzed as a joint development. During 2023, we continued progressing appraisal studies, maturing concept design, and proposed to partners that the Yakaar and Teranga discoveries in the Cayar Offshore Profond Block be pursued as a commercial joint development. PETROSEN agreed to the proposal, however, BP decided not to participate in the development and exploitation of the Yakaar and Teranga discoveries. In accordance with the provisions of the Contract for Exploration and Production Sharing of Hydrocarbons for the Cayar Offshore Profond Block and the related Joint Operating Agreement (the “JOA”), BP has waived its rights in respect of the Yakaar and Teranga discoveries. As provided in the JOA, Kosmos has assumed BP’s participating interest under the contract and the JOA and has become operator of the Cayar Offshore Profond Block, with customary government approvals having been received effective January 18, 2024. The participating interests in the Cayar Offshore Profond Block are now: Kosmos 90% and PETROSEN 10%, with PETROSEN having the right to increase its participating interest after issuance of an exploitation authorization to up to 35%.

Equatorial Guinea

In March 2018, we entered into petroleum contracts covering Blocks EG-21 and S with the Republic of Equatorial Guinea. Kosmos currently holds an 80% participating interest in Block EG-21 and a 34% participating interest in Block S. The Equatorial Guinean national oil company, GEPetrol, currently has a 20% carried participating interest in each Block during the exploration period. Should a commercial discovery be made, GEPetrol's 20% carried interest in such Block will convert to a 20% participating interest. In December 2022, an extension was granted extending the first exploration sub-period for Block EG-21 to December 2024 and we received formal approval to proceed to the second exploration sub-period for Block S ending in December 2024. In March 2023, we closed a farm-out agreement with Panoro, whereby, Panoro acquired a 6.0% participating interest in Block S offshore Equatorial Guinea. As a result of the farm-out agreement, Kosmos’ participating interest in Block S was reduced to 34.0%.

In June 2018, we closed a farm-in agreement with a subsidiary of Ophir for Block EG-24, offshore Equatorial Guinea, whereby we acquired a 40% non-operated participating interest. In the first quarter of 2019, we acquired Ophir's remaining interest in and operatorship of the block, which resulted in Kosmos owning an 80% participating interest in Block EG-24. GEPetrol currently has a 20% carried interest during the exploration period. In December 2022, we received formal approval to enter the second sub-period of the exploration period ending in December 2024. Should a commercial discovery be made, GEPetrol's 20% carried interest will convert to a 30% participating interest for all development and production operations.

In February 2023, Kosmos and Panoro Energy ASA (“Panoro”) entered into a petroleum contract covering Block EG-01 offshore Equatorial Guinea with the Republic of Equatorial Guinea. Kosmos holds a 24% participating interest in the block and the operator, Panoro, holds a 56% participating interest. 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. Block EG-01 currently comprises approximately 59,400 acres (240 square kilometers), with a first exploration period of three years from the effective date (March 1, 2023).

The EG-01, EG-21, EG-24 and S blocks are located in the southern part of the Gulf of Guinea, in the Republic of Equatorial Guinea, west of the Rio Muni petroleum province with water depths up to 2,300 meters. These blocks are located in a proven petroleum system, with our primary targets being Cretaceous sands in structural and stratigraphic traps. In total, the exploration petroleum contracts cover approximately 7,500 square kilometers and we have over 6,400 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 to existing infrastructure.

The shared development of the Ceiba Field and Okume Complex consists of six subsea-well clusters that feed production to the Ceiba FPSO which is shared by both fields through a system of risers. The Okume Complex includes six platforms with an export line to move Okume production to the Ceiba FPSO.

In May 2022, Kosmos and its joint venture partners agreed with the Ministry of Mines and Hydrocarbons of Equatorial Guinea to extend the Block G petroleum contract term; harmonizing the expiration of the Ceiba Field and Okume Complex production licenses (from 2029 and 2034 respectively) to 2040. The license extensions support the next phase of investment in the licenses.

The 2023 Ceiba Field and Okume Complex development rig campaign commenced in the fourth quarter of 2023. The campaign initially completed one production well workover. However, as a result of safety issues with the drilling rig, the operator terminated the rig contract in early February 2024. The partnership is seeking to secure an alternative rig and drilling contractor to resume the work, which is planned to include the drilling of in-fill production wells in Block G and the Akeng Deep ILX prospect in Block S.

Asam Discovery

In October 2019, the S-5 exploration well was drilled to a total depth of 4,400 meters in Block S offshore Equatorial Guinea, encountering 39 meters of net oil pay in good-quality Santonian reservoir. The discovery was subsequently named Asam. In July 2020, an appraisal work program was approved by the Government of Equatorial Guinea. The well is located within tieback range of the Ceiba FPSO and the appraisal work program is currently ongoing to establish the scale of the discovered resource and evaluate the optimum development solution. In December 2022, as part of the appraisal work program, the Asam field appraisal report was submitted to the Government of Equatorial Guinea.

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 second quarter of 2023, we received approval to extend the exploration phase for Block 5 offshore Sao Tome and Principe through May 2024.

Our Reserves

The following table sets forth summary information about our estimated proved reserves as of December 31, 2023. 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, 2023, 2022, and 2021 were associated with our fields in Ghana, Equatorial Guinea, Mauritania, Senegal and the U.S. Gulf of Mexico.

Summary of Oil and Gas Reserves

(1)Totals within the table may not add as a result of rounding.

(2)Our reserves associated with the Jubilee Field are based on the 54.4%/45.6% redetermination split between the WCTP Block and DT Block. Table above reflects the acquisition of additional interests in Ghana in October 2021 and the pre-emption transaction with Tullow in March 2022. See “Item 8. Financial Statements and Supplementary Data—Note 3—Acquisitions and Divestitures” for discussion of pre-emption transaction with Tullow.

(3)These reserves include the estimated quantity of gas to be exported as LNG from the Greater Tortue Ahmeyim Phase 1 project, as a result of the Tortue SPA finalized in February of 2020. We note that the LNG is presented as Plant Products in MBoe in our 2021 reserve report. Our natural gas reserves in Ghana include natural gas forecasted to be sold to the Government of Ghana. If and when a future long-term gas sales agreement is executed with the Government of Ghana, a portion of the remaining gas may be recognized as reserves.

These natural gas reserves also include the estimated quantities of fuel gas required to operate the Jubilee and TEN FPSOs, the Equatorial Guinea facilities and the Greater Tortue Ahmeyim facilities during normal field operations. For Ghana, total proved natural gas reserves include fuel gas associated with the Jubilee and TEN Fields offshore Ghana of approximately 19.9 Bcf, 22.9 Bcf and 30.0 Bcf for 2023, 2022 and 2021, respectively. Our natural gas reserves in Equatorial Guinea are all associated with fuel gas. For Mauritania/Senegal, total proved natural gas reserves include fuel gas of approximately 52.3 Bcf, 51.0 Bcf and 51.0 Bcf in 2023, 2022 and 2021, respectively. For the U.S. Gulf of Mexico, total proved natural gas reserves include fuel gas of approximately 1.1 Bcf in 2023.

(4)Proved undeveloped reserves as of December 31, 2023 expected to be developed beyond five years since initial disclosure are all related to the Greater Tortue Ahmeyim project in Mauritania and Senegal which is a long-term project being developed under a continuous drilling program with long-term LNG sales obligations.

(5)Natural gas liquids proved reserves represent an immaterial amount of our total proved reserves. Therefore, we have aggregated natural gas liquids and crude oil/condensate reserves information.

Changes during the year ended December 31, 2023 at Greater Jubilee include a positive revision of 35.1 MMBoe primarily due to positive field performance, the addition of gas sales recognition and positive drilling results, offset by Jubilee net production of 12.8 MMBoe. There were no changes related to the commodity price effect in Jubilee. These revisions resulted in an overall increase of 22.4 MMBoe. Changes at TEN include a negative revision of 12.6 MMBoe, primarily driven by a change in the partnership’s development work scope for the TEN Fields and well performance, net TEN production of 1.3 MMBoe, for an overall decrease in reserves of 13.9 MMBoe. There were no changes related to the commodity price effect in TEN. Changes at Equatorial Guinea included a positive revision of 3.0 MMBoe due to field performance, offset by a negative revision related to the commodity price effect of 0.7 MMBoe and net production of 3.5 MMBoe. The overall net reserves at Equatorial Guinea decreased by 1.1 MMBoe. Changes in Mauritania and Senegal include a small positive revision of 1.3 MMBoe due to optimization of the timing of the Greater Tortue Ahmeyim Phase 1 project. There were no changes related to the commodity price effect on reserves in Mauritania and Senegal. Changes at the U.S. Gulf of Mexico include a negative revision of 2.3 MMBoe primarily driven by the performance of Odd Job and Tornado Fields as well as the negative results from the drilling of a Marmalard well. The U.S. Gulf of Mexico net production for the year ended December 31, 2023 was 5.6 MMBoe for an overall reserves decrease of 7.9 MMBoe. The changes related to the commodity price effect in the U.S. Gulf of Mexico were immaterial.

During the year ended December 31, 2023, we had an overall proved undeveloped reserves decrease of 1.3 MMBoe due to several factors including the addition of sales gas and positive revision of future well forecasts based on improved performance of existing wells in Jubilee (+26.0 MMBoe), positive drilling results in Jubilee (+0.7 MMBoe), offset by a change to the partnership’s development work scope and forecasts of planned wells in TEN (-6.4 MMBoe), removal of one of the planned wells from the Okume drilling plan (-0.3 MMBoe), optimization of the timing of the Greater Tortue Ahmeyim Phase 1 project (+1.3 MMBoe), and changes to the recovery of several U.S. Gulf of Mexico fields (-0.3 MMBoe). Conversion of proved undeveloped volumes to proved developed related to drilling during 2023 includes the drilling of five wells in Jubilee (-21.5 MMBoe) and one well in Marmalard (-0.8 MMBoe).

In Greater Jubilee, we converted 21.5 MMBoe of proved undeveloped reserves to proved developed with the drilling of five wells at a cost of approximately $98.0 million as well as approximately $91.3 million in subsea costs. In addition, we spent approximately $40.5 million on wells that are expected to convert in future years. In Mauritania and Senegal, we spent approximately $259.8 million progressing the Greater Tortue Ahmeyim Phase 1 development with first gas for the project targeted in the third quarter of 2024. In the U.S. Gulf of Mexico, we converted 0.8 MMBoe at a cost of approximately $16.5 million with the drilling of one well in the Marmalard Field. In addition, we spent approximately $49.0 million on the Odd Job subsea pump installation and approximately $67.5 million towards the development of the Winterfell Field.

Changes during the year ended December 31, 2022, at Greater Jubilee include a positive revision of 11.7 MMBoe primarily due to positive drilling results and field performance, offset by a negative revision of 7.5 MMBoe resulting from the conclusion of the Tullow pre-emption transaction in March 2022, as well as Jubilee net production of 11.3 MMBoe. These revisions resulted in an overall decrease in reserves of 7.1 MMBoe. Changes at TEN include a negative revision of 5.5 MMBoe, driven primarily by recent well performance. Additional negative revisions of 9.1 MMBoe resulted from the conclusion of the Tullow pre-emption transaction in March 2022, along with net TEN production of 2.0 MMBoe. These revisions resulted in an overall decrease in reserves of 16.7 MMBoe. Changes at Equatorial Guinea included a positive revision of 4.0 MMBoe driven by the Block G petroleum license extension and improved commodity prices. An additional positive revision of 0.9 MMBoe due to Ceiba production performance and topsides optimization was offset by net Equatorial Guinea production of 3.7 MMBoe. These revisions resulted in an overall increase in reserves of 1.2 MMBoe and changes in gas reserves were negligible. Changes at Mauritania/Senegal include a positive revision of 4.7 MMBoe of gas due to field extension resulting from the drilling of production wells, as well as a negative revision of 0.7 MMBoe in condensate based on an updated yield estimate. These revisions resulted in an overall increase in reserves of 4.0 MMBoe. Changes at the U.S. Gulf of Mexico include positive revisions of 3.0 MMBoe associated with the Winterfell discovery and 0.8 MMBoe related to the acquisition of an additional interest in the Kodiak field. These changes were offset by a negative revision of 2.0 MMBoe based on recent water breakthrough in Odd Job and Tornado, and Kodiak production issues. The U.S. Gulf of Mexico net production for the year ended December 31, 2022 was 6.4 MMBoe. These revisions resulted in an overall decrease in reserves of 4.6 MMBoe.

During the year ended December 31, 2022, we had an overall proved undeveloped reserves decrease of 5.6 MMBoe, as a result of several factors, including the impact of the Tullow pre-emption transaction in March 2022 (-7.9 MMBoe), optimization of future drilling in Jubilee (+4.0 MMBoe) and TEN (+2.1 MMBoe), Greater Tortue field extension that resulted from drilling of production wells and a downward condensate adjustment (+4.0 MMBoe), optimizing future development plans in the U.S. Gulf of Mexico (+1.3 MMBoe), purchase of minerals-in-place during 2022 in the Kodiak field (+0.2 MMBoe) and the Winterfell discovery (+3.0 MMBoe). Drilling activity impact on proved undeveloped volume change includes the drilling of three wells in Jubilee (-4.6 MMBoe), one well in TEN (-5.8 MMBoe), and one well in Kodiak (-2.0 MMBoe). We note that the changes in the proved undeveloped reserves in Equatorial Guinea were negligible.

In Greater Jubilee, we converted 4.6 MMBoe of proved undeveloped reserves to proved developed with the drilling of three wells at a cost of approximately $75.1 million. In TEN, we converted 5.8 MMBoe of proved undeveloped reserves to proved developed with the drilling of one well at a cost of approximately $13.6 million. In the U.S. Gulf of Mexico, we converted 2.0 MMBoe of proved undeveloped reserves to proved developed with the drilling of one well in Kodiak at a cost of $13.6 million.

Changes during the year ended December 31, 2021, at Greater Jubilee include a positive revision of 49.1 MMBoe, of which 39.9 MMBoe were acquired on October 13, 2021 in the acquisition of additional interests in Ghana. The other 9.2 MMBoe of additions were primarily due to field performance, positive drilling results, and optimization of future development plans. The additions were partially offset by net Greater Jubilee production of 7.4 MMBoe which includes production related to our acquisition of additional interests in Ghana commencing October 13, 2021, the acquisition date. Changes at TEN include a positive revision of 18.2 MMBoe, of which 16.2 MMBoe were acquired in the acquisition of additional interests in Ghana. The other 2.0 MMBoe of additions were primarily due to an increase in estimated associated gas sales. The additions were partially offset by net TEN production of 2.2 MMBoe. Changes at Equatorial Guinea included an increase of 3.7 MMBoe related to Okume Complex performance and drilling results, which was offset by 3.6 MMBoe of net production. Changes at the U.S. Gulf 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.

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, 2023, 2022 and 2021 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, 2023 are based on costs in effect at December 31, 2023 and the 12‑month unweighted arithmetic average of the first‑day‑of‑the‑month price for the year ended December 31, 2023, 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, 2023, 2022 and 2021, 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, 2023, 2022 and 2021, 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, 2023, 2022 and 2021 and related future net revenues and PV‑10 at December 31, 2023, 2022 and 2021 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, 2023 reserve report was completed on January 15, 2024, and a copy is included as an exhibit to this report.

In connection with the preparation of the December 31, 2023, 2022 and 2021 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, 2023, 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 person primarily responsible for our Reservoir Engineering team is Mr. Douglas Trumbauer. Mr. Trumbauer is a Licensed Professional Engineer in the State of Texas (No. 78735) and has over 38 years of practical experience in petroleum engineering. He graduated from Pennsylvania State University in 1985 with a Bachelor of Science degree in Petroleum and Natural Gas Engineering. Mr. Trumbauer worked for DeGolyer and MacNaughton for 20 years prior to joining Kosmos Energy, and we believe he is proficient in applying industry standard practices to engineering and geoscience evaluations as well as understanding and applying SEC and other industry reserves definitions and guidelines.

The RSC technical person primarily responsible for preparing the estimates set forth in the RSC reserves report incorporated herein is Mr. Tosin Famurewa. Mr. Famurewa has been practicing consulting petroleum engineering at RSC since 2006. Mr. Famurewa is a Licensed Professional Engineer in the State of Texas (No. 100569) and has over 20 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, 2023 for the countries in which we currently operate.

(1)Net acreage based on Kosmos’ participating interests, including any options or back-in rights which have been exercised (Jubilee, TEN, and Greater Tortue Ahmeyim fields), but before the exercise of any options or back‑in rights that exist, but have not been exercised. Our net acreage in Ghana may be affected by any redetermination of interests in the Jubilee Unit and our net acreage in Mauritania and Senegal may be affected by any redetermination of interests in the Greater Tortue Ahmeyim Unit.

(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.

(3)Our developed U.S. Gulf of Mexico blocks are held by production/operations, and the lease periods extend as long as production/governmental approved operations continue on the relevant block. For undeveloped areas, the licenses are immaterial with various exploration phases, with all ending by 2033.

Productive Wells

Productive wells consist of producing wells and wells capable of production, including wells awaiting connections. For wells that produce both oil and gas, the well is classified as an oil well. The following table sets forth the number of productive oil and gas wells in which we held an interest at December 31, 2023:

(1)Of the 162 productive wells, 51 (gross) or 17 (net) have multiple completions within the wellbore.

(2)Table above reflects our additional interests acquired in Ghana and U.S. Gulf of Mexico. See “Item 8. Financial Statements and Supplementary Data—Note 3—Acquisitions and Divestitures” for discussion of potential pre-emption impact.

Drilling activity

The results of oil and natural gas wells drilled and completed for each of the last three years were as follows:

(1)As of December 31, 2023, 8 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 10 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 the acquisition of additional interests in Ghana in October 2021 and the pre-emption transaction with Tullow in March 2022. See “Item 8. Financial Statements and Supplementary Data—Note 3—Acquisitions and Divestitures” for discussion of pre-emption transaction with Tullow.

(5)Includes the NT-10 and NT-11 wells which are considered step out wells from an accounting perspective but were drilled as part of the TEN Plan of Development.

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, 2023.

Domestic Supply Requirements

Many of our petroleum contracts or, in some cases, the applicable law governing such agreements, grant a right to the respective host country to purchase certain amounts of oil/gas produced pursuant to such agreements at international market prices for domestic consumption. In addition, in connection with the approval of the Jubilee Phase 1 PoD, the Jubilee Field partners agreed to provide the first 200 Bcf of natural gas produced from the Jubilee Field Phase 1 development to GNPC at no cost. As of January 1, 2023, the Jubilee partners had fulfilled this commitment. The Jubilee partners reached an interim agreement to sell Jubilee Field gas at a price of $2.95 per MMBtu to the Government of Ghana through May 2024 while the partners continue on-going discussions with the Government of Ghana regarding a long-term future gas sales agreement.

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. In Equatorial Guinea, as provided under the petroleum contract for Block G, we are entitled to lift and sell our share of the Ceiba Field and Okume Complex production as are the other Block G partners. We currently have crude oil marketing sales agreements with oil marketers to market our share of the Jubilee, TEN and Ceiba Field and Okume Complex oil, and we approve the terms of each sale proposed by such agents.

In the U.S. Gulf of Mexico, we sell crude oil to purchasers typically through monthly contracts, with the sale taking place at multiple points offshore, depending on the particular property. Natural gas is sold to purchasers monthly through long-term contracts, with the sale taking place either offshore or at an onshore gas processing plant after the removal of NGLs. We actively market our crude oil and natural gas to purchasers, and sales prices for purchased oil and natural gas volumes are negotiated with purchasers and are based on certain published indices. Since most of the oil and natural gas contracts are generally month-to-month and at varying physical locations, there are very few dedications of production to any one purchaser. We sell the NGLs entrained in the natural gas that we produce. The arrangements to sell these products first require natural gas to be processed at an onshore gas processing plant. Once the liquids are removed and fractionated (separated into the individual hydrocarbon chains for sale), the products are sold by the processing plant. The residue gas left over is sold to natural gas purchasers as natural gas sales (referenced above). The contracts for NGL sales are with the processing plant. The prices received for the NGLs are either tied to indices or are based on what the processing plant can receive from a third-party purchaser. The gas processing and subsequent sales of NGLs are subject to contracts with longer terms and dedications of life of lease production from the Company’s leases offshore.

There are a variety of factors which affect the market for oil, including the proximity and capacity of transportation facilities, demand for oil both within the local market and beyond, the marketing of competitive fuels and the effects of government regulations on oil production and sales. Our revenue can be materially affected by current economic conditions and the price of oil. However, based on the current demand for crude oil and the fact that alternative purchasers are available, we believe that the loss of one of our marketing agents and/or any of the purchasers identified by our marketing agent would not have a long‑term material adverse effect on our financial position or results of operations. The continued economic disruption resulting from Russia’s war in Ukraine, potential instability in the Middle East, a potential regional or global recession, inflationary pressures and other varying macroeconomic conditions could further materially impact the Company’s business in future periods. Any potential disruption will depend on the duration and intensity of these events, which are highly uncertain and cannot be predicted at this time.

In February 2020, we, along with the co-venturers in the Greater Tortue Ahmeyim Field signed the Tortue Phase 1 SPA with BPGM to sell LNG free on board (FOB) from the Greater Tortue Ahmeyim Field located offshore Mauritania and Senegal. The annual contract quantity under the Tortue Phase 1 SPA is 127,951,000 MMBtu (the “ACQ”) which is equivalent to approximately 2.45 million tonnes per annum, subject to limited downward adjustment by the sellers. The sales price for LNG under the Tortue Phase 1 SPA is set as a percentage of a crude oil price benchmark for the ACQ volumes (the “ACQ Sales Price”). The Tortue Phase 1 SPA has an initial term of up to twenty years that commences on the “Commercial Operations Date”, which occurs after completion of certain LNG project facilities’ performance tests. Additionally, to optimize the commercial value of sales for the gas production from the Phase 1 of Greater Tortue Ahmeyim, Kosmos has commenced a process with prospective buyers to utilize existing contractual rights under our existing Tortue Phase 1 SPA to potentially sell cargos in order to benefit from the robust forward gas price outlook, while meeting our contractual obligations to BPGM. BPGM has disagreed with our position, and we have agreed with BPGM to pursue international arbitration to interpret the relevant terms of the SPA.

Competition

The oil and gas industry is competitive. We encounter strong competition from other independent operators and from major oil companies in acquiring licenses and leases. Many of these competitors have financial and technical resources and staff that are substantially larger than ours. As a result, our competitors may be able to pay more for desirable oil and natural gas assets, or to evaluate, bid for and purchase a greater number of licenses and leases than our financial or personnel resources will permit. Furthermore, these companies may also be better able to withstand the financial pressures of lower commodity prices, unsuccessful wells, volatility in financial markets and generally adverse global and industry‑wide economic conditions. These companies may also be better able to absorb the burdens resulting from changes in relevant laws and regulations, which may adversely affect our competitive position.

Historically, we have also been affected by competition for drilling rigs and the availability of related equipment. Higher commodity prices generally increase the demand for drilling rigs, supplies, services, equipment and crews. Shortages of, or increasing costs for, experienced drilling crews and equipment and services may restrict our ability to drill wells and conduct our operations.

The oil and gas industry as a whole has experienced continued volatility. Globally, the impact of Russia’s war in Ukraine, potential instability in the Middle East, a potential recession, inflationary pressures and other varying macroeconomic conditions has impacted supply and demand for oil and gas, which also resulted in significant variations in oil and gas prices. Dated Brent crude, the benchmark for our international oil sales, ranged from approximately $71 to $98 per barrel during 2023. HLS crude, the benchmark for our U.S. Gulf of Mexico oil sales, which generally trades at a discount to Dated Brent, ranged from approximately $68 to $95 during 2023. Excluding the impact of hedges, our realized oil price for 2023 was $81.35 per barrel.

Title to Property

We believe that we have satisfactory title to our oil and natural gas assets in accordance with standards generally accepted in the international oil and gas industry. Our licenses and leases are subject to customary royalty and other interests, liens under operating agreements and other burdens, restrictions and encumbrances customary in the oil and gas industry that we believe do not materially interfere with the use of, or affect the carrying value of, our interests.

Environmental Matters

General

We are subject to various stringent and complex international, foreign, federal, state and local environmental, health and safety laws and regulations governing matters including the emission and discharge of pollutants into the ground, air or water; the generation, storage, handling, use and transportation of regulated materials; and the health and safety of our employees. These laws and regulations may, among other things:

•require the acquisition, renewal and maintenance of various permits before operations commence or for operations to continue;

•enjoin operations or facilities to comply with applicable regulations and permits;

•restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and natural gas drilling, production and transportation activities;

•limit, cap, tax or otherwise restrict emissions of GHG and other air pollutants or otherwise seek to address or minimize the effects of climate change, as well as require disclosure of GHG emissions and other climate change-related information;

•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 existing and new laws and regulations, however the cost of compliance with existing or more stringent laws and regulations in the future could have a material adverse effect on our financial condition and results of operations.

Moreover, public interest in the protection of the environment continues to increase. Offshore drilling in some areas has been opposed by environmental groups and, in other areas, has been restricted. Our operations could be adversely affected to the extent laws or regulations are enacted or other governmental action is taken that prohibits or restricts offshore drilling or imposes environmental requirements that increase costs to the oil and gas industry in general, such as more stringent or costly waste handling, disposal or cleanup requirements or financial responsibility and assurance requirements.

Per common industry practice, under agreements governing the terms of use of the drilling rigs contracted by us or our block or lease partners, the drilling rig contractors typically indemnify us and our block partners in respect of pollution and environmental damage originating above the surface of the water and from such drilling rig contractor’s property, including their drilling rig and other related equipment. Furthermore, pursuant to the terms of the operating agreements for our blocks and leases, except in certain circumstances, each block or lease partner is responsible for its share of liabilities in proportion to its participating interest incurred as a result of pollution and environmental damage, containment and clean‑up activities, loss or damage to any well, loss of oil or natural gas resulting from a blowout, crater, fire, or uncontrolled well, loss of stored oil and natural gas, as well as for plugging or bringing under control any well. We maintain insurance coverage typical of the industry in the areas we operate in; these include property damage insurance, loss of production insurance, wreck removal insurance, control of well insurance, general liability including pollution liability to cover pollution from wells and other operations. We also participate in an insurance coverage program for the FPSOs we own. We believe our insurance is carried in amounts typical for the industry relative to our size and operations and in accordance with our contractual and regulatory obligations.

International (Non-operated)

Tullow, BP, and Trident, our partners and the operators of (i) the Jubilee Unit and the TEN Fields offshore Ghana, (ii) various fields offshore Mauritania and Senegal, and (iii) the Ceiba Field and Okume Complex offshore Equatorial Guinea, respectively, maintain Oil Spill Response Plans (“OSRP”) covering the joint operations. The OSRPs include access to Oil Spill Response Limited’s (“OSRL”) oil spill response services comprising technical expertise and assistance, including access to response equipment and dispersant spraying systems. The equipment includes capping stacks, debris removal, subsea dispersant and auxiliary equipment. The equipment meets industry accepted standards and can be deployed by air cargo and other conventional means to suit multiple application scenarios. Under the OSRPs, emergency response teams may be activated to respond to oil spill incidents.

In addition, Kosmos develops an emergency response plan and subscribes to a response organization to prepare and demonstrate our readiness to respond to a subsea well control incident in the event we are the operator.

U.S. Gulf of Mexico (Operated and Non-operated)

After the major well control incident and oil release in the U.S. Gulf of Mexico in 2010, the U.S. Department of Interior updated regulations which govern the type, amount and capabilities of response equipment that needs to be available to operators to respond to similar incidents. These regulations also dictate the type and frequency of training that operating personnel need to receive and demonstrate proficiency in. Kosmos also has an OSRP which is approved by the Bureau of Safety and Environmental Enforcement (“BSEE”). This OSRP would be activated if needed in the event of an oil spill or containment event in the U.S. Gulf of Mexico where Kosmos is the operator. Kosmos joined several cooperatives that were established to meet the requirements of the new regulations. For capping and containment, Kosmos joined the HWCG, LLC consortium whose capabilities include; (i) one dual ram capping stack rated to 15,000 psi and one valve capping stack rated to 20,000 psi, (ii) intervention equipment to cap and contain a well with the mechanical and structural integrity to be shut in at depths up to 10,000 feet, and (iii) the ability to capture and process 130,000 barrels of fluid per day and 220 MMcf of gas per day. Kosmos is also a member of the Clean Gulf Associate (“CGA”) Oil Spill Cooperative, which provides oil spill response capabilities to meet regulatory requirements. Equipment and services include a High Volume Open Sea Skimming System (“HOSS”), dedicated oil spill response vessels strategically positioned along the U.S. gulf coast, dispersants and dispersant delivery systems, various types of spill response booms and mobile wildlife rehabilitation equipment. Due to federal regulations, all of the HWCG and CGA equipment is dedicated to U.S. operations and cannot be utilized outside the country. In addition, Kosmos is also a member of the Marine Spill Response Corporation (“MSRC”) which also provides various oil spill response services for coastal and inland environments in the U.S. Gulf of Mexico.