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Tullow Oil Releases 2020 Operations Report

Exploration & Development

Kenya
Throughout 2020, Tullow worked closely with its joint venture partners to progress the full field development plan. In August 2020, Force Majeure notices that had applied since May 2020 were withdrawn by Tullow and the joint venture partners. In September 2020, the Government of Kenya agreed to an initial extension for the 10BB and 13T licence blocks until 31 December 2020 and in December 2020, following approval of the 2021 Work Programme and Budget, granted a full extension until 31 December 2021 by which date the Group is required to submit a Field Development Plan.

At the CMD, Tullow announced a joint decision to re-assess the development plan and design a project that is economic at low oil prices whilst preserving the phased development concept. Tullow and its joint venture partners expect to complete a revised assessment of the project by the second quarter of 2021.

During 2020, the Early Oil Pilot Scheme (EOPS) successfully completed two years of production and all the required reservoir and production data gathering was completed as planned. Tullow and the joint venture partners then closed down EOPS and demobilisation of all rental equipment was completed. The reservoir and production data gathered during EOPS is now being used in redesigning the full field development concept. EOPS production of more than 350,000 barrels of oil from the Ngamia and Amosing fields provided six months’ sustained rate and pressure data. The data confirms reservoir quality and continuity in both fields, enabling the Group to optimise plans to focus on the most productive wells at the crest of the fields, leading to improved rates per well and refined injector/producer patterns. The impact of this on plateau rates and recoverable resources is being assessed.

In parallel, the joint venture partners are also working closely with the Government of Kenya on securing approval of the Environmental and Social Impact Assessments and finalizing the commercial framework for the project.Separately, the farm down process was suspended in mid-2020 to allow time for the joint venture partners to complete their comprehensive review of the development concept, following which Tullow will assess its strategic options.

Uganda
On 23 April 2020, Tullow agreed the sale of its assets in Uganda to Total for $500 million in cash on completion plus $75 million in cash following the Final Investment Decision
(FID) and incremental post first oil contingent payments linked to oil prices over $62/bbl. On 28 May 2020 CNOOC Uganda Limited informed both Tullow and Total that it had
elected not to exercise its pre-emption rights. On 18 June 2020 Tullow published the shareholder circular relating to the transaction and on 15 July 2020 a General Meeting was held, at which the transaction received approval with over 99 per cent of the 56 per cent votes cast in favour.

On 6 August 2020 the Government of Uganda provided their consent to the transfer of operatorship from Tullow to Total and on 21 October 2020, Tullow announced that the Government of Uganda and the Ugandan Revenue Authority had executed a binding Tax Agreement that reflected the pre-agreed principles on the tax treatment of the sale of Tullow’s Ugandan assets to Total. The Ugandan Minister of Energy and Mineral Development also approved the transfer of Tullow’s interests to Total and the transfer of operatorship for Block 2. Consequently, the sale of the Uganda assets to Total completed on 10 November 2020 with $500 million consideration received on the same day.
Based on recent disclosures from Total at their Full Year results, Tullow expects FID for the Lake Albert Development to be taken this year which would trigger the $75 million
payment to Tullow.

Production

Ghana
The effects of the COVID-19 pandemic on our operations have been managed safely across the business with no impact on Ghana production. This has been achieved in close cooperation with the Government of Ghana who have enabled effective testing and quarantine measures to be put in place. However, this increased the net cost of operations by approximately $10 million in 2020.

Both fields in Ghana performed in line with expectations in 2020, with the Jubilee field averaging 83,600 bopd gross (net: 29,500 bopd) and the TEN field averaging 48,700 bopd
gross (net: 23,000 bopd). This production performance was supported by increased and sustained gas offtake nominations from the Government of Ghana, approval from the Ministry of Energy to increase flaring, higher than forecast facility uptime of over 95% at both FPSOs and improved well optimisation and water injection facility performance on the Jubilee FPSO.

To deliver an operational turnaround for the Ghana assets starting in 2020, key areas of focus have been asset integrity, process safety, maintenance and reliability. Gas offtake and water injection on Jubilee have been an important part of the strategy to address the decline in production in the absence of sustained drilling. The engineering work to increase redundancy and reliability has resulted in record levels of water injection
with rates now in excess of 200kbwpd, despite a failure in a water injection riser in November 2020. Sustained water injection helps support reservoir pressure and improves overall sweep efficiency. Good progress has also been made on gas offtake. Onshore gas demand is stabilising, facility reliability has improved and there is greater alignment with the Government of Ghana on projected offtake. Overall this has resulted in current offtake levels of approximately 125 mmscfd. Gas processing and water injection capacities are both expected to be steadily enhanced through 2021 and
beyond to deliver long term stable production.

In consultation with the Ghana joint venture partners and supported by expert advisors, a comprehensive review of the investment and production optimisation plans for Jubilee and TEN was conducted in the second half of 2020. The resulting plan was presented at the CMD and demonstrated the substantial potential of the Ghana portfolio given its large resource base and extensive infrastructure in place. It showed that, managed with a
rigorous focus on costs and capital discipline, these assets have the potential to generate material cash flow over the next decade and deliver significant value for Ghana and investors.

The Maersk Venturer drillship has been contracted to start a STRATEGIC REPORT
multi-well programme which is envisaged to be for a minimum period of four years. The rig has arrived in Ghanaian waters and is scheduled to commence drilling in April. The same rig worked on the previous drilling programme in Ghana, but the contract was terminated due to the oil price impacts of the COVID-19 pandemic. The drilling hiatus, along with historical underinvestment has had a negative impact on 2021 production.
In 2021, the rig is expected to drill and complete four wells in total, consisting of two Jubilee production wells, one Jubilee water injector well and one TEN gas injector well to provide pressure support to two Ntomme oil production wells. This well campaign is expected to begin to offset near term production decline and further wells in 2022 will see production materially recover and be sustained for the long term. This drilling
programme incorporates lessons learned from the previous programme and is targeting a 20% reduction in drilling costs through simplified well designs, improved rig reliability and supply chain savings.

The final phase of the Jubilee Turret Remediation Project was the installation of a Catenary Anchor Leg Mooring (CALM) buoy to assist with offloading. The CALM buoy arrived in Ghana early in 2020 and following a series of delays, related to the impacts
of COVID-19 and some equipment issues, the buoy and one of two offloading lines were installed at the end of 2020 and fully commissioned in early 2021. The tanker support vessels on contract since 2016 have now been released resulting in anticipated operating expense savings of $60 million (gross) per annum going forwards. Options for the potential need for and installation of a second offloading line are being considered.

 

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