Tullow Oil plc, the independent oil and gas exploration and production group ("Group"), announces its Full Year Results for the year ended 31 December 2021.
Rahul Dhir, Chief Executive Officer, Tullow Oil plc, commented today:
"Following a transformational 2021, in which Tullow successfully refinanced its balance sheet, drilled highly productive wells in Ghana and demonstrated operational excellence and financial discipline across the Group, we are now concentrating on the successful delivery of our long-term business plan. This year will see a great deal of activity at our flagship Jubilee field with investment in new infrastructure and new wells to grow production in the near term and we are taking on the operation and maintenance of the FPSO. At TEN, we will drill two important, strategic wells that will help define our future plans for the fields and we will continue to build production in Gabon . I also expect us to make tangible progress towards our ambitious target of achieving Net Zero by 2030. With additional opportunities to deliver value across our portfolio, including gas commercialisation in Ghana , our revised Kenya development project and an exciting well in a proven play in Guyana , we are well-placed to deliver value from our assets and to grow our business."
2021 FULL YEAR RESULTS SUMMARY
· Revenue of $1,273 million ; gross profit of $634 million ; loss after tax of $81 million primarily driven by exploration costs written off, impairments, restructuring costs and other provisions.
· Underlying operating cash flow1 of $711 million and free cash flow1 of $245 million .
· Capital and decommissioning expenditure of $263 million1 and $69 million respectively.
· Net debt at year-end of $2.1 billion ; gearing of 2.2x1 net debt/EBITDAX; liquidity headroom of $0.9 billion .
· Group working interest production averaged 59.2 kboepd, in line with guidance with notable production growth from Jubilee in Ghana and Simba in Gabon , but lower production than expected from TEN and Espoir.
· In Ghana , strong performance delivered across key operational areas of FPSO uptime, water injection and gas processing. Drilling recommenced in April, with four wells and a workover successfully completed, ahead of plan.
· Commitment made to becoming Net Zero on Scope 1 and 2 emissions by 2030 and to eliminate routine flaring in Ghana by 2025.
· Received $133 million from divestment of non-core interests in Equatorial Guinea and the Dussafu Marin Permit in Gabon .
· Comprehensive debt refinancing completed in May, with new $1.8 billion five-year Senior Secured Notes; a new undrawn $500 million revolving credit facility provides strong liquidity headroom.
· Continued focus on costs helped achieve c.25% year-on-year reduction in administrative expenses to $64 million ; operating costs reduced to $269 million (2020: $332 million ), driven by lower facilities operations and maintenance costs in Ghana , as well as asset disposals.
· Phuthuma Nhleko appointed Chair of Tullow, succeeding Dorothy Thompson who stepped down on 31 December 2021.
2021 key financial results
· Group working interest oil production guidance remains 55 to 61 kboepd based on Tullow's existing equity interests in TEN and Jubilee. This forecast will be adjusted following completion of the pre-emption of the sale of Occidental Petroleum's interest in Ghana to Kosmos Energy. The estimated full year impact of the completed pre-emption would be an addition of c.5 kboepd (net) to the Group's 2022 production forecast, adjusted for completion timing.
· Full year underlying operating cash flow1 guidance remains c. $750 million , assuming $75 /bbl for the remainder of the year.
· Full year free cash flow guidance remains c. $100 million assuming $75 /bbl for the remainder of the year; year-to-date cash flow positively impacted by oil prices at the start of the year, largely offsetting the one-off impact of a $76 million payment to HiTec Vision in relation to the purchase of Spring Energy in 2013, following an arbitral decision in HiTec Vision's favour. Material cash flow contribution secured in February with receipt of $75 million contingent consideration following Final Investment Decision (FID) in Uganda .
· Capex of c. $350 million , split c. $270 million in Ghana , c. $30 million for non-operated portfolio, c. $5 million in Kenya , and exploration spend of c. $45 million . Decommissioning spend is expected to be c. $100 million .
· Three new wells at Jubilee and three new wells at the TEN fields planned, including two strategic wells at TEN to further define future development plans, as well as investment in infrastructure for the undeveloped Jubilee South East and North East areas.
· Tullow will self-operate the Jubilee FPSO from mid-2022 onwards, following the scheduled end of the contract with MODEC, enabling the Group to realise further efficiency improvements and cost savings.
· Tullow expects to secure a gas commercialisation agreement in Ghana which will come into effect once all foundation gas volumes have been delivered; this is forecast to occur before year-end.
· In Kenya , a revised Field Development Plan was submitted in late 2021 and discussions are progressing with potential strategic partners.
· In mid-2022 Tullow will participate in the Repsol operated Beebei-Potaro well, which is a follow-up to the Carapa light oil discovery made in 2020 in the Kanuku licence, offshore Guyana .
· Work plan in place to progress towards Net Zero target, focusing on gas compression facilities on the Jubilee FPSO; MOU signed with the Ghana Forestry Commission to identify and develop nature-based carbon offset projects in Ghana to offset hard to abate and residual emissions.
ENVIRONMENT, SOCIAL AND GOVERNANCE (ESG)
In March 2021, Tullow committed to achieving Net Zero on its Scope 1 and 2 emissions by 2030 on a net equity basis. As part of this commitment, we have identified the core gas handling and process modifications required to reduce our operated emissions at our FPSOs. Work to increase gas processing capacity at the Jubilee FPSO is planned during a scheduled shutdown in the second quarter of 2022, which, together with compressor upgrades and other de-bottlenecking initiatives through 2022 and early 2023, will increase gas handling capacity and contribute towards the target of eliminating routine flaring in Ghana by 2025. The Group increased average daily gas offtake in Ghana in 2021, and natural gas from Jubilee and TEN provides power for c.30% of Ghana's national grid which in turn increases the availability of reliable power in Ghana and reduces the country's reliance on diesel and biomass for domestic power and heat generation. The Group is currently negotiating Gas Sales Agreements for associated natural gas as well as discussing development concepts for non-associated gas with the Government of Ghana , which will allow for greater quantities of natural gas to be supplied to Ghana's national grid and potentially beyond.
Elsewhere, as part of Tullow's re-design of its development in northern Kenya , carbon emissions from this project will be limited through a combination of heat conservation, use of associated gas for power and reinjection of excess gas into the reservoir to eliminate flaring. There are also opportunities to use the Kenyan national grid which is substantially powered by renewables and options to offset remaining emissions through local projects. In addition, the 825-kilometre-long pipeline that will transport crude oil from Turkana to the port of Lamu will be buried to further reduce the environmental impact of the project.
Tullow is committed to off-setting its residual, hard-to-abate emissions and has appointed a Group Carbon Offset Manager to lead the carbon offset strategy and identify high-quality offset projects. To this end, Tullow recently signed a Memorandum of Understanding with the Ghana Forestry Commission to identify and develop a portfolio of Reduced Emissions from Deforestation and Forest Degradation (REDD+) and afforestation/reforestation (ARR) projects that will support Ghana's REDD+ strategy and Tullow's offset targets. The portfolio will target a minimum of 600,000 tonnes per annum of verified carbon emissions reductions that will be certified under leading carbon standards such as the Verified Carbon Standard (VCS) and the Climate Community and Biodiversity Standard (CCB).
In Tullow's Half-Year Results statement, published in September 2021, the Group underscored its purpose to build a better future through the responsible development of oil and gas resources and to build Shared Prosperity in the countries where it works. It remains Tullow's view that as long as global hydrocarbon demand exists, it is imperative that African economies have the opportunity to benefit from the responsible development of their resources. At COP26 in Glasgow , President Akufo-Addo of Ghana articulated the case for continued development of Ghana's resources as part of a fair energy transition for developing countries.
With a long and proud history in Africa , Tullow is uniquely positioned to be a financially and operationally responsible contractor to its host Governments and to ensure that their oil and gas resources are developed efficiently and safely while minimising the environmental impact.
Tullow's social impact is presented in the Sustainability Report which details the Group's efforts in Local Content and Social Investment as well as its total payments to Governments which amounted to $234 million in 2021.
As previously announced, Les Wood, Chief Financial Officer (CFO) will step down from the Board and leave Tullow at the end of March. Tullow's recruitment of a new CFO to replace Les is ongoing and the process is expected to conclude shortly. The Nominations Committee have approved the appointment of Richard Miller, Group Financial Controller, as interim CFO with effect from 1 April. Richard is a chartered accountant and has worked in a number of senior roles within Finance since he joined Tullow in 2011.
With the appointment of Phuthuma Nhleko as Non-executive Chairman of Tullow from 1 January 2022, Tullow now has three African nationals on the Board out of nine directors. Female representation on the Board has dropped from 33% to 22% (two out of nine) following Dorothy Thompson's departure from Tullow. Jeremy Wilson, Tullow's Senior Independent Non-executive Director, will retire from the Board later this year following nine years' service.
Finally, Tullow's 2021 Sustainability Report, which will be published alongside the Annual Report and Accounts later this month, details the Group's commitment to the environment and its approach to managing climate risk. Tullow will also publish a separate Climate Risk Report as part of its TCFD disclosures.
Production, Reserves and Resources
In 2021, Group working interest production averaged 59.2 kboepd, in line with guidance, with notable production growth from the Jubilee field in Ghana and Simba field in Gabon , but lower production than expected from the TEN fields in Ghana and the Espoir field in Côte d'Ivoire.
In 2022, Group working interest production guidance is 55 to 61 kboepd. This forecast is based on Tullow's existing equity interests in Jubilee (35.48%) and TEN (47.175%) and will be adjusted following completion of the pre-emption of the sale of Occidental Petroleum's interest in Ghana to Kosmos Energy. The estimated full year impact of the completed pre-emption would be an addition of c.5 kboepd (net) to the Group's 2022 production forecast, subject to adjustment for completion timing.
The Group's audited 2P reserves decreased from 260 mmboe at the end of 2020 to 231 mmboe at the end of 2021. About half of this reduction was the result of the sale of assets in Equatorial Guinea and the Dussafu Marin Permit in Gabon (15 mmboe). Reserve additions and positive revisions included a 13 mmboe increase at Jubilee following improved field performance and acceleration of new projects and a 11 mmboe increase in the non-operated portfolio due to better field performance and maturation of new projects. These gains were offset by a 16 mmboe decrease at TEN reflecting poorer than expected Ntomme field performance and re-categorisation of certain reserves at Enyenra. Overall, with the Group producing 22 mmboe during 2021, the organic reserves replacement ratio was approximately 36%.
The Group's audited 2C resources decreased from 640 mmboe to 623 mmboe. The reduction was driven primarily by the sale of assets in Equatorial Guinea and Gabon, the maturation of selected TEN projects from 2C to 2P and poorer than expected field performance at TEN. However, these reductions were largely offset by a positive revision from Tullow's auditors of the Kenyan assets, to align with the updated Field Development Plan.
The Jubilee field averaged 74.9 kbopd gross (net 26.6 kbopd) in 2021, ahead of guidance at the start of the year. Average daily production grew from c.70 kbopd at the beginning of the year to exceed 90 kbopd by year-end, as new wells were brought onstream and operational performance remained high with FPSO uptime averaging c.98%, gas offtake rates averaging c.85 mmscfd and water injection rates averaging over 200 kbwpd. The annual gas offtake rate was impacted by overrunning maintenance and subsequent reduced capacity at the the Ghana National Gas Company (GNGC) onshore gas processing plant during the fourth quarter of the year. Tullow continues to work closely with GNGC to help improve offtake reliability. Gas offtake has now returned to regular rates of over 100 mmscfd and Tullow and its JV Partners are still targeting average offtake of c.135 mmscfd in 2022.
The drilling programme, which commenced in April, delivered two producers (J56-P online in July, J57-P online in December), one water injector (J55-WI online in September) and a work over (J12-WI online early in January 2022). Strong drilling performance was achieved during the year with wells costing approximately 20% less than wells drilled from 2018 to 2020, ahead of the assumptions included in the Business Plan.
The field continues to perform well, and average 2022 production is expected to increase to between c.80 to 84 kbopd gross (net: 28 to 30 kbopd). This forecast includes a planned shutdown in the second quarter of 2022 for approximately two weeks. Three new wells are planned to be drilled at Jubilee in 2022, focused on delivering reliable in-year production: a water injector, which will provide pressure support to existing producers, is due onstream in the first quarter; this will be followed by a producer and a second water injector.
The core developed area of the Jubilee field has c.1.5 billion barrels gross oil initially in place (STOIIP), with an estimated ultimate recovery (EUR) approaching 40%. To date, around half of the expected reserves have been produced. Outside of the core area, the development of the Jubilee North East (JNE) and Jubilee South East (JSE) areas marks a step change that targets relatively untapped areas of the field, containing over 500mmbbls gross oil in place. These areas combined gross EUR is over 170 mmbbls gross oil, of which less than 10% has been produced. The 2022 work programme is focused on investment in infrastructure for the JSE and JNE projects that will access the undeveloped resources and lead to meaningful production growth in subsequent years.
The TEN fields averaged 32.8 kbopd gross (net: 15.5 kbopd) in 2021, below guidance given at the start of the year. This was primarily due to higher production decline rates than expected on particular wells. A gas injector at the Ntomme field (Nt06-GI), was brought onstream in the fourth quarter to provide pressure support to existing production wells. Nt06-GI also encountered oil at the base of the well, de-risking the development potential of areas further to the north of Ntomme. In 2021, uptime on the TEN FPSO was c.97%, water injection was c.65 kbwpd and gas injection was c.135 mmscfd. In 2022, TEN is expected to produce between 22 to 26 kbopd gross (net: 11-12kbopd).
Within the core developed areas of Ntomme and Enyenra, which contain c.750 mmbbls gross oil initially in place (STOIIP), around half of the expected reserves have been produced to date. However, production decline within this core area has been faster than expected and while material reserves remain, the overall view of ultimate recovery from these fields has reduced. As a consequence, Tullow and its Joint Venture (JV) Partners have improved their understanding of the broader TEN area and the significant remaining potential. The addition of undeveloped reservoirs in the Tweneboa area, accessible from the Ntomme riser base area, and the extension of the Enyenra field development to the north and south of the core developed area, introduce a similar volume of undeveloped STOIIP as the core areas. Tullow and its JV Partners will start to target these new areas in 2022, with two development wells planned in the Ntomme riser base area. Investment in infrastructure will allow these to be brought on stream from 2023. Furthermore, an additional production well is planned in the undeveloped Enyenra North area in the fourth quarter of the year.
Operational Transformation Plan
The operational transformation that Tullow embarked on in 2020 has delivered strong performance across safety, reliability and costs. A singular focus on personal and process safety across the organisation and visible leadership have provided a foundation for a strong safety culture. The production potential is being maximised by optimising performance of every element of production from the reservoir to the surface facilities. High levels of facility uptime have been achieved at both FPSOs by addressing long-standing equipment defects and sustaining this by implementing systemised monitoring and mitigating of equipment risk. In addition, Tullow is building an equipment systems maintenance management infrastructure to help sustain the reliability improvements. All this has been achieved by taking more direct control of day-to-day operations on the Jubilee and TEN FPSOs.
In order to build on these improvements and to achieve the ambition to be a top quartile operator in terms of safety, reliability and costs, Tullow, supported by its JV Partners and the Government of Ghana , has taken the decision to self-operate the Jubilee FPSO. Accordingly, Tullow will take over all operations and maintenance (O&M) from MODEC on the Jubilee field when the current O&M contract comes to a scheduled end in 2022. This will allow greater control and integration over the core areas of safety, efficiency, emissions, reliability and local content, in turn presenting an opportunity to further reduce costs.
Progress towards elimination of routine flaring in Ghana
As part of Tullow's commitment to becoming a Net Zero Company by 2030 on its Scope 1 and 2 emissions, work to increase gas processing capacity at the Jubilee FSPO is planned during a scheduled shutdown in the second quarter of 2022, which together with compressor upgrades and other facility de-bottlenecking activities through 2022 and early 2023 will increase gas handling capacity and contribute towards the target of eliminating routine flaring in Ghana by 2025. Other activities planned during the shutdown will focus on maintenance, integrity, and reliability of the FPSO for the long-term.
Ghana gas commercialisation
Associated gas from Jubilee and non-associated gas from the TEN fields has the potential to be a significant value driver for Tullow and for Ghana . In 2009, Tullow and its JV Partners pledged to provide 200 bcf of rich/wet associated gas ("Foundation gas") from the Jubilee field free of charge to the Government of Ghana . The Group currently expects to complete the provision of this Foundation gas, which Tullow estimates has delivered over c. $2.4 billion of value to Ghana including the onshore extraction of liquids yields, by the end of 2022. Based on Tullow's calculations, gas from the Jubilee field currently fuels c.30% of thermal power generation in Ghana and continued offtake of associated gas from the Jubilee field is vital to maintaining oil production, increasing power generation in Ghana and the production of Liquid Petroleum Gas for Ghana's domestic market. Tullow is currently in commercial negotiations with the Government of Ghana to finalise the Post Foundation Volume Gas Sales Agreement which would deliver 500 BCF of natural gas and would add c.6 kboepd to Group production. The Group's investment in upstream gas handling infrastructure on the Jubilee FPSO and the ability to supply comingled Jubilee & TEN gas gives Tullow confidence that it can meet growing domestic demand and be the most competitive supplier of gas into the Ghanaian market.
Tullow is also in positive discussions with JV partners and the Government of Ghana on the development of incremental gas volumes present at the TEN fields where c.1 tcf of gas is estimated to be in place. Because of the upstream infrastructure in place, including a gas pipeline to shore, TEN gas is well-placed to be a stable and reliable source of gas at potential rates of 6 kboepd for Ghana and, as the power sector in West Africa develops further, the wider region. With such substantial volumes in place, this resource has the potential to drive significant industrial transformation in Ghana across the mining and petrochemical sectors among others and be a reliable and low-cost provider of wet gas at a time when the benefit of having significant domestic gas supplies is so clear.
Pre-emption of Deep Water Tano component of Kosmos Energy/Occidental Petroleum Ghana transaction
In November 2021, Tullow exercised its right of pre-emption related to the sale of Occidental Petroleum's interests in the Jubilee and TEN fields in Ghana to Kosmos Energy. As a result, Tullow's equity interests are expected to increase to 38.9% in the Jubilee field and 54.8% in the TEN fields upon completion of the transaction. The transaction documents are now in agreed form between Tullow and Kosmos. On this basis, Tullow and Kosmos have jointly requested consent from the Government of Ghana and discussions with the Government are progressing positively.
Production from Tullow's non-operated portfolio averaged 17.2 kboepd in 2021, including contributions from Tullow's continuing interests in Gabon , Côte d'Ivoire and partial contribution from divested assets. 2022 net production is expected to average between 16 to 19 kboepd.
In February 2021, Tullow announced an agreement to sell its entire interests in Equatorial Guinea and the Dussafu Marin Permit in Gabon to Panoro Energy ASA. The deals were completed in March 2021 and June 2021, respectively, for $180 million including contingent cash payments of up to $40 million which are linked to asset performance and oil price.
In Gabon , the Simba expansion project made good progress in 2021, and an infill well was brought onstream in September 2021. A new 10-inch pipeline, allowing increased oil offtake from the field, became operational in December 2021. After initial operational issues post start-up, the well is now performing as expected and consequently, net production for the Simba field in 2022 is expected to average c.6kbopd, 40% higher than in 2021. Also in Gabon , two infrastructure-led exploration wells were drilled in the year near the Tchatamba field. One well was unsuccessful and the other resulted in the Wamba (TCTS-B14) discovery in the second half of 2021. Wamba is adjacent to the Tchatamba South oil field and extended production tests are planned in 2022.
In Côte d'Ivoire, the Espoir field was shut down for approximately four weeks in the first half of the year following a major incident onboard the FPSO in January 2021. A further shutdown of approximately eight weeks was conducted in the second half of the year to carry out remediation work identified by BW Offshore, the FPSO operator. The field is now back onstream and Tullow continues to engage with the operator (CNR International) on further remediation plans for the FPSO and on identifying development drilling opportunities.
In the UK , post-decommissioning surveys have been completed and submitted as part of the operated decommissioning programme approval process, with formal approval expected in 2022. The Group's non-operated decommissioning activities are ongoing and are expected to continue through to 2026.
In Mauritania , the Group's operated decommissioning programme of the Banda and Tiof fields is expected to commence in the fourth quarter of 2022. Planning is well advanced, with major service providers secured. Non-operated decommissioning of the Chinguetti field is ongoing and seabed infrastructure clearance is expected to complete this year.
The expected remaining UK and Mauritania decommissioning exposure over 2022-26 is c. $180 million , with over half of this forecast spend in 2022. The final exposure may vary depending on the final required scope and work programmes agreed across the various projects. Provisioning for decommissioning of producing assets in Ghana and parts of the non-operated portfolio has commenced this year at c. $30 million per annum.
In 2021 Tullow and its JV Partners (Africa Oil and Total Energies) completed the redesign of the Kenya development project (Blocks 10BB and 13T licences) to ensure it is a technically, commercially and environmentally robust project. The key changes to the development concept have been driven by incorporating the production data from the Early Oil Pilot Scheme (EOPS), optimising the number of wells to be drilled and changing the producer to injector ratio, adding the Ekales field into the first phase of production and increasing the Central Processing Facility capacity to 130,00 bopd and the pipeline size from 18" to 20" to handle the increased flow rates.
These changes have increased total gross capital expenditure (capex), which covers both the upstream and the pipeline to First Oil, to c. $3.4 billion and delivers a 30% increase in resources whilst lowering the unit cost to $22 /bbl (previously c. $31 /bbl). A higher production plateau of 120 kbopd is now planned, with expected gross oil recovery of 585 mmbo over the full life of the field. This resource position is supported by a Competent Persons Report completed by external international auditors Gaffney Cline Associates (GCA).
Simultaneous to the development, an exploration and appraisal (E&A) plan will be implemented to ensure the remaining five discoveries are developed efficiently. This will extend and sustain initial plateau rates while keeping costs low by using the rigs used for development drilling. The E&A plan also focuses on additional exploration potential within the Blocks 10BB and 13T licences and exploring the wider Blocks 10BA and 12B licence acreage.
Tullow and its JV Partners have taken the opportunity of this review to improve the environmental and social aspects of the project. Carbon emissions will be limited through a combination of heat conservation, use of associated gas for power and reinjection of excess gas into the reservoir. Further, there are opportunities to use the Kenyan national grid that is substantially powered by renewables and options to offset remaining emissions. As per the previous development plan, the 825 kilometres long pipeline that will transport the crude oil from Turkana to the port of Lamu will be heated and buried to avoid long-term disruption. The project will also require water for reservoir pressure which will be abstracted through a pipeline from the Turkwell Dam and will also be used to provide water to local communities. This project would also be Kenya's first oil and gas development and would represent a stable, long-term source of income for the Government of Kenya .
In line with licence extension requirements, Tullow and its JV Partners submitted a final FDP to the Government of Kenya in December 2021, incorporating their feedback on the draft FDP submitted earlier in the year.
Submission of the FDP for the 10BB/13T licences will allow Tullow and its JV Partners to secure the Production Licences for blocks and the continuation of the exploration licences on the 10BA and 12B blocks through the commitments made in the E&A plan. The JV is now working closely with the Ministry of Petroleum and Mines to secure FDP approval which needs to be ratified by the Kenyan parliament. The FDP is conditional on a number of critical work streams for both the Government of Kenya and the JV Partners, including, but not limited to, the successful introduction of a new strategic partner. Constructive discussions with interested parties are progressing as Tullow and the JV Partners look to secure a strategic partner for the project.
In Tullow's core area of West Africa , the exploration team is focused on maturing near-field and infrastructure-led (ILX) exploration opportunities around existing producing fields, to unlock additional value from the Group's asset base.
In Gabon , focus in on strengthening the prospective resource base within the Simba licence and several low-risk and compelling investment options adjacent to infrastructure have been identified which will be considered for future drilling programmes.
In Côte d'Ivoire, Tullow has a 90% interest in offshore Block CI-524 which is a continuation of the proven Cretaceous turbidite plays that are producing at the adjacent TEN and Jubilee fields. This block presents a unique opportunity due to Tullow's deep understanding of the area and its proximity to the Group's producing fields that could realise cost and operational synergies in the event of discoveries. Focus has been on maturing opportunities through 3D seismic reprocessing which has identified additional prospective resources in several stacked reservoirs that are being matured as future drilling candidates. Tullow, together with its JV Partner PetroCi, has proceeded into the second exploration phase in CI-524, which includes a commitment well to be drilled before August 2024.
In Ghana , focus is on opportunities around the Jubilee and TEN fields to unlock additional value from the Group's asset base, with potential reserves additions from ILX opportunities.
Tullow also continues to focus on unlocking value from the substantial prospective resource base in the emerging basins of Guyana and Argentina , while seeking to mitigate capital exposure from historical work commitments. In 2022, commitments include the Beebei-Potaro exploration well in the Kanuku Block in Guyana , which will target the Cretaceous light oil play of the Guyana-Suriname Basin, as well as seismic acquisition over Block MLO 122 in Argentina .
In 2021, Tullow drilled the unsuccessful Goliathberg-Voltzberg North exploration well, on Block 47, offshore Suriname. The well encountered good quality reservoir but only minor oil shows. In Argentina , a multi-client 3D seismic acquisition was completed on Tullow-operated licences MLO114 and MLO119. In Côte d'Ivoire, Tullow has now exited all onshore blocks but retains its 90% interest in the offshore Block CI-524, adjacent to the TEN fields.
The Group continued to rationalise its portfolio during the year and exited 11 exploration blocks in 2021, including all of its licences in Suriname and Peru , reorienting its exploration effort towards near-field and infrastructure-led exploration activities to enhance value in core areas. In January 2022, Tullow also exited the PEL 90 licence in Namibia .
Production and commodity prices
Group working interest production averaged 59,200 boepd, a decrease of 21 per cent for the year (2020: 74,900 boepd). The decrease in production primarily resulted from the sale of Tullow's interests in Equatorial Guinea and the Dussafu Marine Permit in Gabon in 1H21, and lower than expected production from the TEN fields.
The Group's realised oil price after hedging for the period was $62.7 /bbl and before hedging $70.3 /bbl. (2020: $50.9 /bbl and $42.9 /bbl respectively). There has been a strong recovery in oil markets which has led to higher realised prices partially offset by hedge losses, decreasing total revenue by $153 million (2020: increased revenue by $219 million ).
Underlying cash operating costs, depreciation, impairments, write-offs and administrative expenses
Underlying cash operating costs amounted to $269 million ; $12.4 /boe (2020: $332 million ; $12.1 /boe). The reduction in operating costs is mainly driven by the disposal of Equatorial Guinea in 2021 ( $23 million ) and decrease in Facilities O&M costs in Ghana ( $47 million ), offset by an increase in Gabon mainly due to the costs relating to the Simba well which came onstream in 2021 ( $12 million ). Cash operating costs excluding COVID-19 operating procedures and shuttle tanker operations in Ghana were $12.1 /boe (2020: $11.8 /boe).
Depreciation, depletion and amortisation (DD&A) charges on production and development assets amounted to $361 million ; $16.7 /boe (2020: $446 million ; $16.3 /boe). This increase in DD&A per barrel is mainly attributable to a downward revision of TEN 2P reserves.
Administrative expenses of $64 million (2020: $87 million ) have decreased against the comparative period. In February 2020, Tullow concluded its Business Review, which included a review of the Group's organisation structure and resources and resulted in a significant headcount reduction. Furthermore, the Group has focused on reducing non-payroll G&A costs including outsourced information systems expenses, professional fees and office rent. However, this is partially offset by the adverse GBP:USD FX variance in 2021. During 2021, Tullow met its $125 million cost savings target by delivering $127 million in cash savings and is expected to deliver in excess of this in 2022 and beyond.
The Group recognised a net impairment charge on producing assets of $54 million in respect of 2021 (2020: $251 million ). Impairments primarily related to the TEN fields following reduced 2P reserves and higher capital expenditure offset by higher price assumptions and lower expected future decommissioning costs. The TEN fields' impairment was offset by impairment reversals on the non-operated fields associated with increased 2P reserves and higher price assumptions.
In March 2021, the Group completed the sale of its assets in Equatorial Guinea with a cash consideration received of $88.9 million . This transaction included contingent future payments of up to $16.0 million which are linked to asset performance and oil price. As per the SPA, a further $5.0 million of additional consideration was also received on completion of the sale of the Dussafu Marin Permit in Gabon.
In June 2021, the Group completed the asset sale of the Dussafu Marin Permit in Gabon with a cash consideration received of $39.0 million . This transaction included contingent future payments of up to $24.0 million which are linked to asset performance and oil price.
Tullow received $75 million (net of $7 million indemnity provision relating to tax audits) from Total following a Final Investment Decision (FID) for the Lake Albert Development in Uganda on 16 February 2022.
Derivative financial instruments
Tullow continues to undertake hedging activities as part of the ongoing management of its business risk to protect against commodity price volatility and to ensure the availability of cash flow for re-investment in capital programmes that are driving business delivery.
At 31 December 2021, Tullow's hedge portfolio provides downside protection for 75% of forecast production entitlements through to May 2023 and 50% for a further 12 months to May 2024. Since completion of the comprehensive debt refinancing in May where increased hedges for May 2021 to May 2024 (75%, 75%, 50%) were a requirement, new hedges have been placed with $55 /bbl floors and weighted average sold calls of c. $76 /bbl for the period January 2022 to May 2024. The strong recovery in oil prices allowed the Group to secure sold calls above $95 /bbl by the end of the hedging programme implementation.
All of the Group's derivatives are Level 2 (2020: Level 2). There were no transfers between fair value levels during the year.
At 31 December 2021, the Group's derivative instruments had a net negative fair value of $180 million (2020: net positive $2 million ).
Net financing costs
Net financing costs for the year were $312 million (2020: $255 million ). The increase in financing costs during the period is mainly driven by finance fees, such as legal and advisor fees related to the assessment of alternative refinancing options of the extinguished RBL Facility directly expensed to the income statement ( $18 million ), as well as increased average cost of debt following completion of the refinancing transactions in May 2021, partly offset by the net gain on early settlement and derecognition of the RBL Facility and the 2022 Notes ( $8 million credit).
Net financing costs include interest incurred on the Group's debt facilities, foreign exchange gains/losses, the unwinding of discount on decommissioning provisions, and the net financing costs associated with lease assets. These costs are offset by interest earned on cash deposits. A reconciliation of net financing costs is included in Note 6.
The net tax expense of $283 million (2020: credit of $52 million ) primarily relates to tax charges in respect of the Group's production activities in West Africa, as well as UK decommissioning assets, reduced by deferred tax credits associated with exploration write-offs, impairments and other provisions.
Based on a profit before tax for the period of $203 million (2020: loss of $1,273 million ), the effective tax rate is 139.8 per cent (2020: 4.1 per cent). After adjusting for non-recurring amounts related to restructuring costs, exploration write-offs, disposals, impairments, other provisions and their associated deferred tax benefit, the Group's adjusted effective tax rate is 117.1 per cent (2020: 35.6 per cent). The adjusted effective tax rate has increased primarily due to there being no UK tax benefit from net interest and hedging losses of $417 million , compared to net profits of $16 million arising on hedging gain and net interest in 2020. Non-deductible expenditure in Ghana, the change in mix of taxable and non-taxable profits in Gabon, prior year adjustments and taxes on uncertain tax treatments are additional contributing factors.
The Group's future statutory effective tax rate is sensitive to the geographic mix in which pre-tax profits and exploration costs written off arise. Unsuccessful exploration is often incurred in jurisdictions where the Group has no taxable profits such that no related tax benefit results. Consequently, the Group's tax charge will continue to vary according to the jurisdictions in which pre-tax profits and exploration costs write-offs occur.
Capital expenditure amounted to $263 million (2020: $288 million ) with $205 million invested in production and development activities and $58 million invested in exploration and appraisal activities.
Tullow will continue to maintain capital discipline with 2022 capital investment primarily directing investment to maximising value from the Group's producing assets. The Group's 2022 capital expenditure is expected to total c. $350 million and comprises Ghana c. $270 million , West Africa non-operated c. $30 million , Kenya c. $5 million , and exploration c. $45 million .
On 17 May 2021, the Group completed a comprehensive refinancing of its debt with the issuance of five-year $1.8 billion Senior Secured Notes ("2026 Notes") and a new undrawn $500 million Super Senior Revolving Credit Facility ("SSRCF") which will be primarily used for working capital purposes.
The 2026 Notes have been used to (i) repay all amounts outstanding under, and cancel all commitments made available pursuant to, the Group's RBL Facility, (ii) redeem in full the Group's senior notes due 2022, (iii) repay in full and cancel the Group's convertible bonds and (iv) pay fees and expenses incurred in connection with the transactions.
The 2026 Notes, maturing in May 2026, require an annual prepayment of $100 million , in May, of the outstanding principal amount plus accrued and unpaid interest, with the balance due on maturity.
The Senior Notes due 2025 is payable in a single payment in March 2025.
The SSRCF, maturing in December 2024, comprises (i) a $500 million revolving credit facility and (ii) a $100 million letter of credit facility. The revolving credit facility remains undrawn as at 31 December 2021.
The 2026 Notes and the SSRCF are senior secured obligations of Tullow Oil Plc and are guaranteed by certain of the Group's subsidiaries.
Tullow maintains corporate credit ratings with Standard & Poor's (S&P's) and Moody's Investors Service (Moody's).
On 5 February 2021, S&P's placed Tullow's CCC+ corporate credit rating and CCC+ ratings for bonds maturing in 2022 and 2025 on negative credit watch to reflect the uncertainty associated with ongoing debt refinancing discussions at the time. On 18 May 2021, S&P's upgraded Tullow's corporate credit rating to B-, removed the rating from negative credit watch and revised the outlook to stable. At the same time S&P's assigned a B- rating to the $1.8 billion 2026 Notes and confirmed the CCC+ rating of the $800 million Senior Notes maturing in 2025.
On 29 April 2021, Moody's assigned and placed under review for upgrade a B3 rating to the $1.8 billion 2026 Notes, and at the same time placed Tullow's Caa1 corporate credit rating under review for upgrade. Moody's confirmed their Caa2 ratings of the Senior Notes maturing in 2022 and 2025. On 20 October 2021, Moody's upgraded Tullow's corporate credit rating to B3 with stable outlook from Caa1 under review for upgrade, and at the same time upgraded its rating of the $1.8 billion Senior Secured Notes to B2 with stable outlook from B3 under review for upgrade. Moody's also affirmed their Caa2 rating of the Senior Notes maturing in 2025.
Liquidity risk management and going concern
Assessment period and assumptions
The Directors consider the going concern assessment period to be up to 31 March 2023. The Group closely monitors and manages its liquidity headroom. Cash forecasts are regularly produced and sensitivities run for different scenarios including, but not limited to, changes in commodity prices, different production rates from the Group's producing assets and different outcomes on ongoing disputes or litigation. Management has applied the following oil price assumptions for the going concern assessment:
Base Case: $76 /bbl for 2022, $71 /bbl for 2023; and
Low Case: $60 /bbl for 2022, $60 /bbl for 2023.
The Low Case includes, in addition to lower oil price assumptions, a 5 per cent production decrease and 12% increased operating costs compared to the Base Case, as well as increased outflows associated with ongoing disputes.
On 17 May 2021, the Group announced the completion of its offering of $1.8 billion 2026 Notes. The net proceeds, together with cash on balance sheet, have been used to (i) repay all amounts outstanding under, and cancel all commitments made available pursuant to, the Company's RBL Facility, (ii) redeem in full the Company's senior notes due 2022, (iii) at maturity, repay in full and cancel the Company's convertible bonds due 2021 and (iv) pay fees and expenses incurred in connection with the transactions. The Group also entered into a $600 million SSRCF which is undrawn and will be primarily used for working capital purposes. The 2026 Senior Notes and the SSRCF do not have any maintenance covenants (disclosure of key covenants and the determination of availability under the SSRCF are provided in note 18). Following completion of these transactions the Directors have concluded that the material uncertainties noted in the 2020 Annual Report and Accounts, associated with implementing a Refinancing Proposal and obtaining amendments or waivers in respect of covenant breaches or, in the event a Refinancing Proposal is implemented, the revised covenants are subsequently breached, no longer exist.
The Group had $0.9 billion liquidity headroom of unutilised debt capacity and non restrictive cash as at 31 December 2021. The Group's forecasts show that the Group will be able to operate within its current debt facilities and have sufficient financial headroom for the going concern assessment period under its Base Case and Low Case. These forecasts show full availability of the $600 million SSRCF, which under the Base Case remains undrawn. Furthermore management has performed a reverse stress test and the average oil price throughout the going concern period required to reduce headroom to zero during the assessment period is $39 /bbl. Based on the analysis above, the Directors have a reasonable expectation that the Company has adequate resources to continue in operational existence for the foreseeable future. Thus, they have adopted the going concern basis of accounting in preparing the year end results.
Events since 31 December 2021
On 15 February 2022 a panel of arbitrators, working under the jurisdiction of Norwegian law, delivered an award in favour of HiTec Vision (HiTec) in relation to its dispute with Tullow (Award). The panel had been asked to adjudicate as to whether discoveries made in the PL-537 Licence (Offshore Norway) between 2013 and 2016 had triggered a further payment under the SPA between Tullow and HiTec regarding the purchase of Spring Energy in 2013. With the Award, the panel has decided by way of split decision that conditions for a further payment outlined in the SPA were met. The Tribunal ruled that Tullow should pay $76 million . This amount also includes interest and costs. This has been recognised in the balance sheet as a liability as at 31 December 2021.
FID for the Tilenga Project in Uganda and the East African Crude Oil Pipeline (EACOP) as reported by Total Energies Ltd on 1 February 2022 triggered a contingent consideration payment of $75 million (net of $ 7 million indemnity provision relating to tax audits) in relation to Tullow's sale of its assets in Uganda to Total in 2020 which was received on 16 February 2022. This was recognised as a current receivable as at 31 December 2021.
There have not been any other events since 31 December 2021 that have resulted in a material impact on the year end results.