Tullow oil PLC - 2022 FULL Year Results

8 March 2023 - Tullow Oil plc ("Tullow"), the independent oil and gas exploration and production group ("Group"), announces its Full Year Results for the year ended 31 December 2022. Details of a management presentation and webcast are available on the last page of this announcement or visit the Group's website www.tullowoil.com.

 

Rahul Dhir, Chief Executive Officer, Tullow Oil plc, commented today:

"2022 saw Tullow successfully deliver against our business plan. A high focus on cost control and a disciplined approach to operational efficiency has driven a very strong performance for the year, with group production in line with guidance and expectations, delivering free cash flow of $267 million, lowering net debt to $1.9 billion and reducing cash gearing to 1.3x net debt to EBITDAX.

"Looking ahead, we have multiple catalysts to deliver further profitable growth. There is strong momentum across the portfolio with the commissioning of Jubilee South East on track for the second half of 2023, bringing undeveloped reserves online and Jubilee gross production to more than 100 kbopd before the end of the year. Engagements to secure a strategic partner for the Kenya development project continue and we are preparing a plan of development to monetise the remaining resources at TEN.

"We have created a unique platform of assets and capability, including industry leading safety performance, which positions us strongly to create significant value for all our stakeholders."

 

2022 FULL YEAR results HIGHLIGHTS

·    Significant growth in revenue to $1,783 million (including hedge costs of $319 million), representing a c.40% increase versus 2021.

·    Gross profit of $1,086 million (2021: $647 million); profit after tax of $49 million (2021: loss after tax of $81 million).

·    Increase in underlying operating cash flow¹ to $972 million (2021: $711 million) and free cash flow¹ to $267 million (2021: $245 million), despite increased capital expenditure of $354 million (2021: $263 million), decommissioning expenditure of $72 million (2021: $69 million) and $126 million consideration for the pre-emption transaction in Ghana.

·    Net debt¹ at year-end reduced to $1,864 million (2021: $2,131 million); cash gearing of net debt to EBITDAX¹ of 1.3 times (2021: 2.2 times) three years ahead of original target; liquidity headroom of $1,055 million (2021: $876 million).

·    Industry leading safety performance, with zero lost time injuries and zero Tier 1 process safety incidents across Tullow's global operations in 2022.

·    Group working interest production averaged 61.1 kboepd (2021:59.2 kboepd).

·    Strong operating, drilling and completion performance in Ghana, with facilities uptime of c.97% and four Jubilee wells and two Enyenra wells brought online. Two Ntomme riser base area wells were also drilled but did not encounter economically developable resources.

·    The transition of operatorship of the Jubilee FPSO took place in July 2022 and FPSO uptime averaged c.99% in the second half of 2022, compared to c.95% in the first half.

·    Interim Gas Sales Agreement for 19 bcf of Jubilee gas executed, representing the first commercialisation of Jubilee gas.

·    A significant milestone was reached in Ghana with a Letter of Intent (LoI) signed with the Ghana Forestry Commission for a nature-based carbon offset project. Final Investment Decision (FID) is expected in 2023.

·    New exploration licence secured in Côte d'Ivoire (CI-803), building a strategic position adjacent to the Group's producing fields in Ghana.

·    Phuthuma Nhleko appointed as Chair from January 2022.

 

2022 Key Financial Results

	2022	2021 Restated2
Total revenue ($m)	1,783	1,285
Gross profit ($m)	1,086	647
Profit / (loss) after tax ($m)	49	(81)
Free cash flow ($m)1	267	245
Net debt ($m)1	1,864	2,131
Gearing (times)1	1.3	2.2

1       Alternative performance measures are reconciled on pages 31 to 34.

 

2       Refer to note 7 for details on prior year restatement.

2023 outlook

·    Group working interest oil production guidance of 58 to 64 kbopd.

·    Gross production from Jubilee expected to increase to over 100 kbopd with four new wells at Jubilee South East and a further Jubilee producer onstream later this year.

·    Forecast capital expenditure of c.$400 million, split c.$300 million in Ghana, c.$40 million in Gabon, c.$20 million in Côte d'Ivoire, c.$10 million in Kenya and c.$30 million on exploration and appraisal activities.

·    Completion of Jubilee South East infrastructure in the first half of 2023 will mark the end of the current major infrastructure spend on Jubilee.

·    Forecast decommissioning expenditure of c.$90 million in the UK and Mauritania, with a further c.$20 million placed into escrow funds for future decommissioning in Ghana and parts of the non-operated portfolio. Decommissioning expenditure is weighted more than 80% to the first half of the year.

·    Full year underlying operating cash flow¹ guidance of c.$900 million at $100/bbl (c.$800 million at $80/bbl).

·    Full year free cash flow¹ guidance of c.$200 million at $100/bbl (c.$100 million at $80/bbl). Free cash flow will be weighted towards the second half of the year as the Jubilee South East wells come onstream.

·    Cash gearing of net debt to EBITDAX¹ expected to be c.1 times by year end at $100/bbl.

·    Jubilee FPSO operations & maintenance (O&M) costs expected to be c.23% lower than in 2021, following O&M transformation undertaken in 2022.

·    Plan to agree a long-term gas sales agreement with the Government of Ghana covering both Jubilee and TEN fields.

·    Two disputed Ghanaian tax assessments filed for arbitration with International Chamber of Commerce in London in February 2023.

·    Continued focus on securing FDP approval and a strategic partner for Project Oil Kenya.

·    Richard Miller appointed as Chief Financial Officer (CFO) from January 2023.

·    Roald Goethe appointed as independent non-executive Director from February 2023.

Environment, Social and Governance (ESG)

Environment

Tullow has made progress on its decarbonisation roadmap to achieve Net Zero on its Scope 1 and 2 CO₂e emissions by 2030 on a net equity basis:

§ Significant progress was made on the commitment to eliminate routine flaring by 2025, the largest source of Scope 1 emissions. Tullow invested $15 million in its floating production, storage and offloading (FPSO) vessels in 2022 as part of a multi-year, $45 million decarbonisation programme that is expected to reduce Scope 1 and 2 emissions by c.40% against a 2020 baseline.

§ Tullow completed a feasibility study for a nature-based carbon offset project that could off-set remaining, hard to abate CO₂e emissions, estimated to be 600,000 tonnes per annum. In December 2022, Tullow signed an LoI with the Ghana Forestry Commission, marking a key milestone for the project as part of Tullow's plans to reach Net Zero by 2030. This project can also support Ghana in meeting its Nationally Determined Contributions under the Paris Agreement. FID is expected in 2023.

Social

Tullow's Shared Prosperity strategy delivered positive impact through focusing on young people's education, enterprise support, developing local supply chains and material fiscal contributions to host governments. Key highlights include:

§ Supported 6,000+ secondary and tertiary students with Tullow STEM scholarships, bursaries and after school support in Ghana, Kenya, Guyana and Suriname.

§ Provided accommodation and classroom facilities for 3,000 pupils through a $10 million infrastructure commitment to promote enrolment in Free Senior High Schools in Ghana.

§ The Fisherman's Anchor Project provided small loans to over 1,300 businesses; over 90% of the businesses are owned by women and nearly 90% are fish processing businesses.

§ Spent $173 million with local suppliers in 2022, which represented 15% of local procurement spend, bringing total five year spend to c.$1.2 billion.

§ Fiscal contributions to host governments amounted to $468 million in 2022 (2021: $234 million).

§ Employee engagement initiatives in place, including employee advisory panel and an 88% response rate to our most recent employee survey, with an overall positivity score of 70%.

¹ Alternative performance measures are reconciled on pages 31 to 34

Governance

Phuthuma Nhleko was appointed as Chair of Tullow in January 2022, having joined as a Non-Executive Director in October 2021. Jeremy Wilson retired as a Non-Executive Director in October, having completed nine years on the Board of Tullow. Roald Goethe was appointed as independent Non-Executive Director of Tullow in February 2023 following a review of Board composition by the Nominations Committee. The composition of Tullow's Board reflects the countries in which it operates, and three out of nine directors are African nationals. Female representation remains 22% (two out of nine).

Richard Miller was appointed as CFO and as an Executive Director of Tullow in January 2023. Richard was appointed as Interim CFO in April 2022 and has been with Tullow for over 11 years. During that time Richard led the Tullow Finance team, supporting a number of acquisitions, disposals and capital markets transactions. Richard played a significant role in the continued turnaround of Tullow with the successful rebasing of Tullow's cost structure, the resetting of the balance sheet and the change to a more focused capital allocation.

On 30 May 2023, Mike Daly will have served nine years on the Board as an independent Non-Executive Director and will therefore not seek re-election as a Director at this year's Annual General Meeting, anticipated to be on 24 May 2023. He will step down as a Director with effect from the conclusion of the AGM. The Nominations Committee is undertaking a search for his replacement, taking into account the results of the external facilitated evaluation of Board effectiveness in 2022, the skills and experience required on the Board to implement the Company's strategy, and Tullow's inclusion and diversity ambitions.

Operational Review

Production, Reserves and Resources

In 2022, Group working interest production averaged 61.1 kboepd, in line with guidance following pre-emption of the Deep Water Tano component of the Kosmos Energy/Occidental Petroleum Ghana transaction.

Group working interest production guidance for 2023 is 58-64 kboepd, excluding 19 bcf of gas sold under the Interim Gas Sales Agreement and any additional volumes of gas sold during the course of the year. The main driver of production growth in 2023 is expected to be the Jubilee South East development which is due onstream in the second half of the year. The near-term focus on TEN is to sustain the strong operational uptime and improve gas handling on the FPSO this year, which will facilitate a reduction in flaring and increased gas injection to support oil production. Improvements on the gas processing facilities will be implemented during a planned maintenance shutdown, scheduled for the third quarter of the year. A two week FPSO maintenance shut-down will impact production from TEN. Production from the non-operated portfolio will be supported by new wells planned at Tchatamba, Ezanga and Etame.

Group average working interest production	FY 2022 (kboepd)	FY 2023 range (kboepd)
Ghana	44.4	48
Jubilee	31.9	37
TEN	12.5	11
Non-operated portfolio	16.7	14
Gabon	14.9	13
Cote d'Ivoire	1.8	1
Group	61.1	58-64

 

The Group's audited 2P reserves are 229 mmboe at the end of 2022 (2021: 231 mmboe). Group reserves replacement was c.90% as a result of the additional equity acquired through the pre-emptive transaction in Ghana and other positive revisions including transfers from contingent resources, offset by reduction in TEN due to greater than expected base decline in Enyenra and the two Ntomme riser base area well results. As at 31 December 2022 the audited 2P NPV10 was $3,895 million (2021: $3,633 million).

The Group's audited 2C resources reduced to 605mmboe at the end of 2022 (2021: 625mmboe). This was principally due to the evaluation of several projects in the TEN development area, some of which have been upgraded from contingent resources to reserves.

Ghana

Jubilee

Production from the Jubilee field increased from an average of 74.9 kbopd (26.6 kbopd net) in 2021 to 83.6 kbopd (31.9 kbopd net) in 2022. Continued excellent operational efficiency of c.97% (2021: c.98%) was achieved and production was supported by four new wells (one producer and three water injectors) coming online ahead of schedule due to outstanding drilling and completions performance.

Two wells were drilled in the Jubilee South East area in the second half of 2022 and a third well in January 2023. Primary target reservoir results are in line with expectations, but with upside from deeper appraisal target reservoirs that encountered oil resources for future development. These wells will commence production in the second half of the year after the installation and tie-in to the Jubilee South East Project subsea infrastructure, in line with the initial project schedule. The completion of the Jubilee South East Project will mark the end of the current major infrastructure spend in the Jubilee area with the majority of near-term capex expected to be focused on drilling and completing new wells.

First oil from the Jubilee South East project will be a significant milestone, bringing previously undeveloped reserves to production and helping define future growth opportunities in the Jubilee area. This project, which was delivered through a multi-national supply chain effort, is being delivered on budget despite the inflationary environment and challenges associated with COVID-19 during 2020-22, highlighting Tullow's project management strengths and ability to integrate deliverables across a global team.

In 2023, Jubilee oil production is expected to average c.95 kbopd (c.37 kbopd net), with five wells expected to come online, starting in the middle of the year. Gross oil production from the Jubilee field is expected to exceed 100 kbopd once all these wells have been brought online. This rate increase is also enabled by the successful execution of expansion work on the Jubilee FPSO, increasing water and gas handling capacity to support the additional well stock coming online. The focus on operational excellence in production, drilling and major project delivery in recent years has yielded appreciable value and will continue to be an area of leverage for Tullow.

TEN

Production from the TEN fields averaged 23.6 kbopd (12.5 kbopd net) in 2022. Continued excellent operational efficiency of c.98% (2021: c.97%) was achieved with overall production at the lower end of guidance.

Ntomme gross production averaged 16.8 kbopd for the full year. No new wells were brought online during the year at Ntomme, but pressure support from existing gas and water injection wells resulted in steady production. Enyenra gross production averaged 6.8 kbopd for the full year, supported strongly in the fourth quarter by a new production well, which was brought online in September 2022. Currently producing 3 kbopd, this well and a new water injector brought online in December 2022 will contribute to supporting production in 2023.

Two wells drilled in the Ntomme riser base area did not encounter economically developable resources and will not be completed in 2023 as originally intended, removing c.2.5 kbopd net from previously expected 2023 production.

The longer term plan for TEN is to monetise its significant remaining resources through infill drilling, phased development of new areas near existing infrastructure, development of the significant gas resources and drilling of prospective resources. A restructuring of the FPSO cost base is under evaluation to enable sustained cost efficiency in production operations. Tullow expects to submit a plan of development to the Government of Ghana later this year.

In 2023, TEN production is expected to average c.20 kbopd (c.11 kbopd net), including the planned two-week maintenance shutdown. No new wells are planned to be added in TEN in 2023.

Jubilee Operations and Maintenance Transformation

The transition of operatorship to Tullow on the Jubilee FPSO took place in July 2022. This is a major step in Tullow's transformation to a leading low-cost deep-water operator, and is expected to deliver sustainable improvements in safety, reliability and cost. Following the transition, which is supported by a comprehensive multi-year transformation plan, FPSO uptime averaged c.99% in the second half of 2022, compared to c.95% in the first half. Operations and maintenance (O&M) costs were c.30% lower in the second half of the year compared to the first, and 2023 full year O&M costs are expected to be c.23% lower than in 2021, demonstrating the sustainability of the structural changes delivered through the transformation, helping mitigate the impact of inflation through the supply chain, and allowing for sustained prioritisation of FPSO upkeep activities which are important for maintaining the FPSO's top-tier performance for the long-term.

Gas Commercialisation

In December 2022, an Interim Gas Sales Agreement for 19 bcf gross of Jubilee gas was executed, utilising the price for TEN associated gas referenced in the 2017 TEN Gas Sales Agreement which was $50c/mmbtu. The 19 bcf is expected to have been supplied by the middle of the year at an anticipated export rate in excess of 100 mmscfpd, adding c.7 kboepd net production during the first half of the year. Further gas export will be contingent on reaching agreement on acceptable commercial terms for future volumes.

Tax exposure

As announced on 14 February 2023, throughout 2021 and 2022, Tullow has received revised and new tax assessments from the Ghana Revenue Authority (GRA). Tullow believes these assessments are without merit and filed requests for arbitration with the International Chamber of Commerce in London, in accordance with the dispute resolution process set out in the Petroleum Agreements which govern TGL's activities in Ghana. Notwithstanding this formal step, Tullow intends to continue to engage with the Government of Ghana, including the GRA, with the aim of resolving these disputes on a mutually acceptable basis.

 

NON-OPERATED PORTFOLIO

Production from Tullow's non-operated portfolio in Gabon and Côte d'Ivoire averaged 16.7 kboepd net in 2022 (2021: 17.2 kboepd net), supported by new wells brought online in Tchatamba, Ezanga and Etame. Capital expenditure in Gabon and Côte d'Ivoire in 2022 was c.$43 million net, with approximately 60% allocated to infrastructure projects, including the tie-back of the Wamba discovery for a long-term production test.

In Côte d'Ivoire, remediation work on the Espoir FPSO will continue through 2023. A 4D seismic survey will be acquired over the licence to support the upcoming infill development drilling campaign and mature future investment projects.

Net production from the non-operated portfolio is expected to average c.14 kboepd in 2023, which includes production from the Wamba discovery long-term production test which will continue throughout 2023. Total capital expenditure is expected to be c.$60 million net, of which c.75% will be allocated to infrastructure projects to support future developments and production. The remaining investment will be in new wells at the Ezanga Complex and workovers across the portfolio to sustain production levels.

DECOMMISSIONING

In the UK and Mauritania, decommissioning expenditure was c.$72 million in 2022 and is expected to be c.$90 million in 2023 which is the last year of significant decommissioning spend. At the end of 2023, it is expected that less than $30 million of decommissioning liabilities will remain for the two countries.

In 2022, UK decommissioning activity included the removal of four platforms (three at the Murdoch Hub and the Ketch platform). Removal of the Ketch pipeline commenced in 2022 and is expected to complete in the second half of 2023. Eleven Schooner wells were successfully plugged and abandoned. Plugging and abandonment work has also begun at the Boulton field, as part of an eight well campaign in the CMS area. In Mauritania, the Tullow operated Banda and Tiof decommissioning campaign commenced in December 2022 and is expected to complete by the middle of the year.

Starting in 2023, c.$20 million will be required to be paid annually into escrow for future decommissioning of currently producing assets in Ghana and parts of the non-operated portfolio.

KENYA

Engagements to secure a strategic partner for the development project in Kenya are ongoing.

In March 2023, Tullow and its JV Partners submitted an updated Field Development Plan to the Ministry of Energy and Petroleum and the Energy and Petroleum Regulatory Commission Authority, for their approval. This is currently under review by the relevant authorities.

Kenya continues to remain an important asset in Tullow's development portfolio, with the potential to add material reserves and create value for shareholders.

EXPLORATION

Capital expenditure on exploration and appraisal activities was c.$45 million in 2022 and is expected to be c.$30 million in 2023.

In Guyana, the operator of the Kanuku licence (Tullow 37.5%), Repsol, drilled the Beebei-Potaro prospect which encountered water bearing reservoirs, and the well was plugged and abandoned.

In Gabon, Tullow, together with JV Partner Perenco, is focused on maturing the prospective resource base within the Simba licence, where several low-risk and compelling investment options adjacent to infrastructure have been high-graded for near term drilling programmes.

In Côte d'Ivoire, Tullow, together with its JV Partner PetroCi, has elected to proceed into the second exploration phase in Block CI-524 and is maturing a number of drilling candidates. Tullow has enhanced its strategic position in the Tano Basin, where it has a differentiated subsurface understanding, with a 90% interest in a new offshore exploration licence (CI-803), which is adjacent to Block CI-524 and also to Tullow's producing fields in Ghana.

In the emerging basins of Argentina and Guyana, Tullow continues to pursue activities to unlock value from its significant prospective resource base. A two year extension has been secured in Block MLO-122 in Argentina.

PROPOSED MERGER

On 1 June 2022, Tullow entered into an agreement for a proposed all-share merger with Capricorn Energy PLC ("Capricorn"). The aim of the proposed merger was to create a leading African energy company, and it would have enabled Tullow to accelerate its deleveraging trajectory and investment in growth.

On 29 September 2022, Tullow noted the announcement released by Capricorn in connection with its proposed combination with NewMed Energy Limited Partnership. Tullow's Board decided that it would not increase the value of Tullow's offer for Capricorn or to elect to implement its offer by way of a contractual offer, and later confirmed that it will no longer proceed with the proposed merger.

 

Finance review

Income Statement

Income Statement (key metrics)	2022	2021 Restated1
Revenue ($m)
Sales volume (boepd)	55,170	55,450
Realised oil price ($/bbl)	88.0	63.3
Total revenue	1,783	1,285
Operating costs ($m)
Underlying cash operating costs 2	(267)	(269)
Depreciation, Depletion and Amortisation (DDA) of oil and gas and leased assets	(411)	(361)
DDA before impairment charges ($/bbl)	(18.4)	(16.7)
Underlift and oil stock movements	(46)	(20)
Administrative expenses	(51)	(64)
Gain on bargain purchase	197	-
Exploration costs written off	(105)	(60)
Impairment of property, plant and equipment, net	(391)	(54)
Net financing costs	(293)	(312)
Profit from continuing activities before tax	442	215
Income tax expense	(393)	(296)
Profit/(Loss) for the year from continuing activities	49	(81)
Adjusted EBITDAX 2	1,469	973
Basic earnings/(loss) per share (cents)	3.4	(5.7)

1       Refer to note 7 for details on prior year restatement.

2       Alternative performance measures are reconciled on pages 31 to 34.

Revenue

Sales Volumes

During the period there were 55,170 boepd (2021: 55,450 boepd) of liftings. This mainly consisted of 13 liftings in Jubilee of 29,322 boepd and 5 liftings in TEN of 12,270 boepd compared to 10 liftings in Jubilee of 25,987 boepd and 5 liftings in TEN of 13,511 boepd in 2021. The increase in Jubilee liftings was mainly driven by increased production. Refer to Operations Review on page 3.

Realised oil price ($/bbl)

The Group's realised oil price after hedging for the period was $88.0/bbl and before hedging $104.3/bbl (2021: $63.3/bbl and $70.9/bbl, respectively). The higher oil price during 2022 resulted in hedge losses, decreasing total revenue by $319 million (2021: decrease of $153 million). The increase in oil prices was triggered by Russia's invasion of Ukraine in February 2022.

Cost of Sales

Underlying cash operating costs

Underlying cash operating costs amounted to $267 million; $11.9/boe (2021: $269 million; $12.4/boe). The decrease in operating costs is due to the disposal of Equatorial Guinea and the Dussafu asset in Gabon in 2021 and the O&M transformation project on Jubilee (refer to Operations Review) offset by the shutdown in Jubilee in Ghana, the Simba expansion project costs in Gabon and the increased equity interest in Ghana following pre-emption.

Normalised cash operating costs which exclude COVID-19 operating procedures, shuttle tanker operations, Construction Support Vessel (CSV) campaign and shutdown costs were $11.3/boe (2021: $12.1/boe).

Depreciation, depletion and amortisation

DD&A charges before impairment of oil and gas and leased assets amounted to $411 million; $18.4/boe (2021: $361 million: $16.7/boe). This increase in DD&A per barrel is mainly attributable to Ghana pre-emption which was effective 1Q22 and downward revision of TEN 2P reserves partially offset by 2021 impairments.

Underlift and oil stock movements

The underlift in the income statement was mainly due to timings of the liftings in Ghana as well as increased oil prices and stock positions in Gabon.

Administrative expenses

Administrative expenses of $51 million (2021: $64 million) have decreased against the comparative period mainly due to lower payroll related costs as a result of the reduced headcount as well as a favourable GBP:USD FX variance in 2022. Tullow achieved approximately $300 million in net cash savings since mid-2020 to date thereby delivering in excess of the target set.

Gain on bargain purchase

On 17 March 2022, the Group completed the 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 of this acquisition, the Group's interest in the TEN fields increased from 47.18% to 54.84%, and from 35.48% to 39.0% in the Jubilee field. The difference between the fair value of net assets acquired and consideration paid was recognised within the income statement as a gain on bargain purchase of $197 million. Refer to note 12 Business combination.

Exploration costs written off

During 2022, the Group has written off exploration costs of $105 million (2021: $60 million) which are predominantly driven by write-offs from Guyana after the completion of the Beebei-Potaro commitment well which was plugged and abandoned.

Impairment of property, plant and equipment

The Group recognised a net impairment charge on producing assets of $391 million in respect of 2022 (2021: $54 million). Impairments are mainly due to downward revision of TEN reserves as well as changes to estimates on the cost of decommissioning for certain UK and Mauritania assets.

Net financing costs

Net financing costs for the period were $293 million (2021: $312 million). The decrease in financing costs is mainly due to $19 million fees incurred in 2021 in relation to the refinancing of the RBL facility, and a decrease of $7 million in interest on obligations under finance leases due to a decrease in lease liability position offset by an increase in interest on borrowings of $7 million.

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.

Taxation

The overall net tax expense of $393 million (2021: $296 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 provisions for onerous service contracts.

Based on a profit before tax for the year of $442 million (2021: $215 million), the effective tax rate is 88.9 per cent (2021: 137.6 per cent). After adjusting for non-recurring amounts related to acquisition through business combination, exploration write-offs, disposals, impairments, provisions for onerous service contracts and their associated deferred tax benefit, the Group's adjusted tax rate is 70.3 per cent (2021: 116.4 per cent). The effective tax rate has decreased primarily due to the release of provisions on the settlement of tax audits and higher taxes on uncertain treatments in the prior year, offset by there being no UK tax benefit from net interest and hedging expenses of $570m (2021: $417m). Non-deductible expenditure in Ghana and Gabon and prior year adjustments are additional contributing factors.

The Group's future statutory effective tax rate is sensitive to the geographic mix in which pre-tax profits arise. There is no UK tax benefit from net interest and hedging expenses, whereas net interest income and hedging profits would be taxable in the UK. Consequently, the Group's tax charge will continue to vary according to the jurisdictions in which pre-tax profits occur.

Analysis of adjusted effective tax rate ($m)		Adjusted Profit/(loss) before tax	Tax (expense)/credit	Adjusted Effective tax rate
Ghana	FY 2022	994.8	(359.7)	36.2%
	FY 2021	450.9	(163.3)	36.2%
Gabon	FY 2022	316.1	(158.9)	50.3 %
	FY 2021	185.0	(95.2)	51.5%
Equatorial Guinea	FY 2022	-	-	-
	FY 2021	15.5	(5.4)	35.0%
Corporate	FY 2022	(584.5)	3.5	0.6%
	FY 2021	(386.0)	(41.8)	(10.8)%
Other non-operated & exploration	FY 2022	15.9	(6.9)	43.5 %
	FY 20211	5.1	(9.1)	178.2 %
Total	FY 2022	742.3	(522.1)	70.3%
	FY 20211	270.6	(314.9)	116.4%

1       The prior year has been restated to include the notional tax on the profit oil within current tax expense in accordance with the terms of the respective Production Sharing Contracts (PSCs).

 

Adjusted EBITDAX

Adjusted EBITDAX for the year was $1,469 million (2021: $973 million). The increase from 2021 was predominantly due to higher revenues.

Profit for the year from continuing activities and earnings per share

The profit for the year from continuing activities amounted to $49 million (2021: $81 million loss). Profit after tax has increased by $130 million driven by higher revenues and lower costs. Basic earnings per share was 3.4 cents (2021: 5.7 cents loss per share).

Balance Sheet and Liquidity management

Balance Sheet and Liquidity management (key metrics)	2022	2021
Capital investment ($m)1	354	263
Derivative financial instruments ($m)	(244)	(180)
Borrowings ($m)	(2,473)	(2,569)
Underlying operating cash flow ($m) 1	972	711
Free cash flow ($m)1	267	245
Net debt ($m)1	1,864	2,131
Gearing (times)1	1.3	2.2

1       Alternative performance measures are reconciled on pages 31 to 34.

 

Capital investment

Capital expenditure amounted to $354 million (2021: $263 million) with $309 million invested in production and development activities and $45 million invested in exploration and appraisal activities.

Tullow will continue to maintain capital discipline primarily directing investment towards maximising value from the Group's producing assets. The Group's 2023 capital expenditure is expected to comprise Ghana capex of c.$300 million, West African non-operated capex of c.$60 million, Kenya capex of c.$10 million and exploration spend of c.$30 million.

 

Derivative financial instruments

Tullow has a material hedge portfolio in place 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 2022, Tullow's hedge portfolio provides downside protection for 64% of forecast production entitlements through to May 2023 and 40% for a further 12 months to May 2024 with $55/bbl floors and weighted average sold calls of $75/bbl.

All financial instruments that are initially recognised and subsequently measured at fair value have been classified in accordance with the hierarchy described in IFRS 13 Fair Value Measurement. Fair value is the amount for which the asset or liability could be exchanged in an arm's length transaction at the relevant date. Where available, fair values are determined using quoted prices in active markets (Level 1). To the extent that market prices are not available, fair values are estimated by reference to market-based transactions or using standard valuation techniques for the applicable instruments and commodities involved. (Level 2).

All of the Group's derivatives are Level 2 (2021: Level 2). There were no transfers between fair value levels during the year.

At 31 December 2022, the Group's derivative instruments had a net negative fair value of $244 million (2021: net negative $180 million).

Hedge position as at 31 December 2022

                                                                                                                    2023                                          2024                         2025

Hedged volume (bopd)	33,095	11,305	-
Weighted average bought put (floor) ($/bbl)	$55/bbl	$55/bbl	-
Weighted average sold call ($/bbl)	$75/bbl	$75/bbl	-

 

Borrowings

In May 2022, the Group made a mandatory prepayment of $100 million of the Senior Secured Notes due 2026, which reduced total drawn debt to $2.5 billion.

Management regularly reviews options for optimising the Group's capital structure and may seek to retire or purchase outstanding debt from time to time through cash purchases or exchanges in the open market or otherwise.

Credit Ratings

Tullow maintains credit ratings with Standard & Poor's (S&P) and Moody's Investors Service (Moody's).

On 31 May 2022, S&P's revised Tullow's outlook to positive, and re-affirmed Tullow's B- corporate credit rating, the B- rating of the $1.7 billion Senior Secured Notes due 2026, and the CCC+ rating of the $800 million Senior Notes due 2025. On 18 August 2022, S&P's revised Tullow's outlook to negative following S&P's downgrade of Ghana's foreign and local currency sovereign ratings. Concurrently, S&P's affirmed the B- rating of the $1.7 billion Senior Secured Notes due 2026, and the CCC+ rating of the $800 million Senior Notes due 2025.

On 9 June 2022, Moody's changed Tullow's outlook to positive and affirmed the B3 corporate credit rating, the B2 rating of the $1.7 billion Senior Secured Notes due 2026, and the Caa2 rating of the $800 million Senior Notes due 2025. On 6 October 2022, Moody's placed Tullow's ratings on review for downgrade, primarily driven by Moody's downgrade and placing on review for further downgrade of Ghana's long-term issuer and senior unsecured debt ratings to Caa2 from Caa1. On 2 December 2022, Moody's downgraded Tullow's corporate credit rating to Caa1 with negative outlook, and the rating of the $1.7 billion Senior Secured Notes due 2026 to Caa1. Concurrently, Moody's confirmed the Caa2 rating of the $800 million Senior Notes due 2025. The rating action concluded the review for downgrade initiated by Moody's on 6 October 2022 and reflected Moody's downgrade of Ghana's long-term issuer rating to Ca from Caa2 and the concurrent downward revision of Ghana's local currency and foreign currency country ceilings to Caa1 and Caa2 respectively, from B2 and B3.

Free cash flow and Underlying operating cash flow

Underlying operating cash flow increased to $972 million (2021: $711 million), primarily due to an increase in revenue.

Free cash flow increased to $267 million compared to $245 million in 2021 primarily due to an increase in underlying operating cash flow as explained above and no debt arrangement fees being incurred in 2022, partially offset by increase in capital investment due to the increased equity interest in Ghana.

 

Net debt and Gearing Reconciliation of net debt	$m
Year-end 2021 net debt	2,131
Sales revenue	(1,783)
Operating costs	267
Other operating and administrative expenses	257
Cash flow from operations	(1,259)
Movement in working capital	(29)
Tax paid	229
Purchases of intangible exploration and evaluation assets and property, plant and equipment	433
Other investing activities	(77)
Other financing activities	434
Foreign exchange loss on cash	2
Year-end 2022 net debt	1,864

 

Net debt reduced by $267 million during the year to $1,864 million at 31 December 2022 (31 December 2021: $2,131 million), consisting of $800 million Senior Notes due 2025 and $1,700 million Senior Secured Notes due 2026 less cash and cash equivalents. In May 2022, $100 million of the Senior Secured Notes due 2026 was prepaid at par.

The Gearing ratio has decreased to 1.3 times (2021: 2.2 times) due to an increase in Adjusted EBITDAX as explained above primarily due to higher revenues. This is ahead of guidance at the start of the year which indicated that gearing should reach less than 1.5 times by year-end 2023.

Liquidity risk management and Going Concern

The Directors consider the going concern assessment period to be up to 31 March 2024. 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: $84/bbl for 2023, $79/bbl for 2024; and

Low Case: $70/bbl for 2023, $70/bbl for 2024.

The Low Case includes, amongst other downside assumptions, a 5 per cent production decrease compared to the Base Case.

At 31 December 2022, the Group had $1.1 billion liquidity headroom consisting of c.$0.6 billion free cash and $0.5 billion available under the revolving credit facility.

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. Based on the analysis above, the Directors have a reasonable expectation that the Group 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 result.

 

Events since 31 December 2022

As announced on 14 February 2023, throughout 2021 and 2022, Tullow has received revised and new tax assessments from the Ghana Revenue Authority (GRA). Tullow believes these assessments are without merit and filed requests for arbitration with the International Chamber of Commerce in London, in accordance with the dispute resolution process set out in the Petroleum Agreements which govern TGL's activities in Ghana. Notwithstanding this formal step, Tullow intends to continue to engage with the Government of Ghana, including the GRA, with the aim of resolving these disputes on a mutually acceptable basis.

In March 2023, Tullow and its JV Partners submitted an updated Field Development Plan to the Ministry of Energy and Petroleum and the Energy and Petroleum Regulatory Commission Authority in Kenya, for their approval. This is currently under review by the relevant authorities.

In 2023, there were two new appointments:

Richard Miller appointed as Chief Financial Officer (CFO) from January 2023.

Roald Goethe appointed as independent non-executive Director from February 2023.

There have not been any other events since 31 December 2022 that have resulted in a material impact on the year end results.

 

Group income statement

Year ended 31 December 2022

$m	Notes	2022	2021 Restated1
Continuing activities
Revenue		1,783.1	1,285.4
Cost of sales	5	(697.5)	(638.9)
Gross profit		1,085.6	646.5
Administrative expenses	5	(51.0)	(64.1)
Gain on bargain purchase	12	196.8	-
Gain on disposals	8	-	120.3
Other gains and losses		3.1	-
Exploration costs written off	9	(105.2)	(59.9)
Impairment of property, plant and equipment, net	10	(391.2)	(54.3)
Restructuring costs and other provisions	5	(4.2)	(61.8)
Operating profit		733.9	526.7
Gain on hedging instruments		0.8	-
Finance income	6	42.9	44.3
Finance costs	6	(335.5)	(356.1)
Profit from continuing activities before tax		442.1	214.9
Income tax expense	7	(393.0)	(295.6)
Profit/ (loss) for the year from continuing activities		49.1	(80.7)
Attributable to
Owners of the Company		49.1	(80.7)
Earnings/ (loss) per ordinary share from continuing activities		¢	¢
Basic		3.4	(5.7)
Diluted		3.3	(5.7)

 

1       Refer to Note 7 for details on prior year restatement.

Group statement of comprehensive income and expense

Year ended 31 December 2022

$m	2022	2021
Profit/ (loss) for the year from continuing activities	49.1	(80.7)
Items that may be reclassified to the income statement in subsequent periods
Cash flow hedges
Loss arising in the year	(399.5)	(159.3)
Gains/ (losses) arising in the period - time value	21.7	(182.1)
Reclassification adjustments for items included in profit on realisation	288.5	112.3
Reclassification adjustments for items included in loss on realisation - time value	30.8	40.7
Exchange differences on translation of foreign operations	10.2	(1.4)
Other comprehensive expense	(48.3)	(189.8)
Tax relating to components of other comprehensive expense	-	2.7
Net other comprehensive expense for the year	(48.3)	(187.1)
Total comprehensive income/ (expense) for the year	0.8	(267.8)
Attributable to
Owners of the Company	0.8	(267.8)

 

 

Group balance sheet

As at 31 December 2022

$m	Notes	2022	2021
Assets
Non-current asset
Intangible exploration and evaluation assets	9	288.6	354.6
Property, plant and equipment	10	2,981.4	2,914.6
Other non-current assets	11	327.1	489.1
Deferred tax assets		14.5	354.4
		3,611.6	4,112.7
Current assets
Inventories		181.6	134.8
Trade receivables		26.8	99.8
Other current assets	11	567.9	704.5
Current tax assets		15.4	19.7
Cash and cash equivalents		636.3	469.1
		1,428.0	1,427.9
Total assets		5,039.6	5,540.6
Liabilities
Current liabilities
Trade and other payables	13	(750.2)	(751.1)
Borrowings		(100.0)	(100.0)
Provisions	14	(98.8)	(296.5)
Current tax liabilities		(186.0)	(115.1)
Derivative financial instruments		(186.3)	(80.9)
		(1,321.3)	(1,343.6)
Non-current liabilities
Trade and other payables	13	(780.0)	(987.1)
Borrowings		(2,372.8)	(2,468.7)
Provisions	14	(415.6)	(431.0)
Deferred tax liabilities		(551.5)	(677.3)
Derivative financial instruments		(57.9)	(99.0)
		(4,177.8)	(4,663.1)
Total liabilities		(5,499.1)	(6,006.7)
Net liabilities		(459.5)	(466.1)
Equity
Called up share capital		215.2	214.2
Share premium		1,294.7	1,294.7
Foreign currency translation reserve		(238.6)	(248.8)
Hedge reserve		(150.3)	(39.3)
Hedge reserve - time value		(94.4)	(146.9)
Merger reserve		755.2	755.2
Retained earnings		(2,241.3)	(2,295.2)
Equity attributable to equity holders of the Company		(459.5)	(466.1)
Total equity		(459.5)	(466.1)

 

Group statement of changes in equity

Year ended 31 December 2022

$m	Called up share capital		Share premium	Equity component of convertible bonds	Foreign currency translation reserve¹	Hedge reserve²	Hedge reserve - time value²	Merger reserves	Retained earnings	Total
At 1 January 2021		211.7	1,294.7	48.4	(247.4)	4.8	(5.4)	755.2	(2,272.0)	(210.0)
Profit for the year		-	-	-	-	-	-	-	(80.7)	(80.7)
Hedges, net of tax		-	-	-	-	(44.1)	(141.5)	-	-	(185.6)
Derecognition of the convertible bond3		-	-	(48.4)	-	-	-	-	48.4	-
Currency translation adjustments		-	-	-	(1.4)	-	-	-	-	(1.4)
Exercise of employee share options		2.5	-	-	-	-	-	-	(2.5)	-
Share-based payment charges		-	-	-	-	-	-	-	11.6	11.6
At 31 December 2021		214.2	1,294.7	-	(248.8)	(39.3)	(146.9)	755.2	(2,295.2)	(466.1)
Profit for the year		-	-	-	-	-	-	-	49.1	49.1
Hedges, net of tax		-	-	-	-	(111.0)	52.5	-	-	(58.5)
Currency translation adjustments		-	-	-	10.2	-	-	-	-	10.2
Exercise of employee share options		1.0	-	-	-	-	-	-	(1.0)	-
Share-based payment charges		-	-	-	-	-	-	-	5.8	5.8
At 31 December 2022		215.2	1,294.7	-	(238.6)	(150.3)	(94.4)	755.2	(2,241.3)	(459.5)

1       The foreign currency translation reserve represents exchange gains and losses arising on translation of foreign currency subsidiaries, monetary items receivable from or payable to a foreign operation for which settlement is neither planned nor likely to occur, which form part of the net investment in a foreign operation.

2       The hedge reserve represents gains and losses on derivatives classified as effective cash flow hedges.

3       On 12 July 2021 Tullow repaid the $300 million Convertible Bond due 2021. As the conversion option was not exercised, the equity component of $48.4 million has been transferred from the separate reserve to retained earnings.

 

 

Group cash flow statement

Year ended 31 December 2022

$m	Notes	2022	2021 Restated1
Profit from continuing activities before tax		442.1	214.9
Adjustments for:
Depreciation, depletion and amortisation	10	425.8	378.9
Gain on bargain purchase	12	(196.8)	-
Gain on disposals		-	(120.3)
Other gains and losses		(3.1)	-
Taxes paid in kind	7	(21.4)	(12.2)
Exploration costs written off	9	105.2	59.9
Impairment of property, plant and equipment, net	10	391.2	54.3
Restructuring costs and other provisions		4.2	61.8
Payment under restructuring costs and other provisions	14	(127.3)	(12.6)
Decommissioning expenditure	14	(57.7)	(52.8)
Share-based payment charge		5.8	11.6
Gain on hedging instruments		(0.8)	-
Finance income	6	(42.9)	(44.3)
Finance costs	6	335.5	356.1
Operating cash flow before working capital movements		1,259.8	895.3
Decrease/ (increase) in trade and other receivables		288.4	(17.9)
Increase in inventories		(48.0)	(41.9)
(Decrease)/increase in trade payables		(193.1)	7.5
Cash generated from operating activities		1,307.1	843.0
Income taxes paid		(229.3)	(56.1)
Net cash from operating activities		1,077.8	786.9
Cash flows from investing activities
Proceeds from disposals	11	68.1	132.8
Purchase of additional interest in joint operation		(126.8)	-
Purchase of intangible exploration and evaluation assets		(42.6)	(86.1)
Purchase of property, plant and equipment		(263.8)	(150.4)
Interest received		8.9	2.0
Net cash used in from investing activities		(356.2)	(101.7)
Cash flows from financing activities
Debt arrangement fees		-	(56.6)
Repayment of borrowings		(100.0)	(2,379.9)
Drawdown of borrowings		-	1,800.0
Payment of obligations under leases		(203.8)	(155.9)
Finance costs paid		(249.0)	(234.9)
Net cash used in financing activities		(552.8)	(1,027.3)
Net increase/ (decrease) in cash and cash equivalents		168.8	(342.1)
Cash and cash equivalents at beginning of year		469.1	805.4
Foreign exchange gain		(1.6)	5.8
Cash and cash equivalents at end of year		636.3	469.1

 

1       Refer to Note 7 for details on prior year restatement.

Notes to the financial statements

Year ended 31 December 2022

1.   Basis of preparation and presentation of financial information

The Financial Statements have been prepared in accordance with UK-adopted international accounting standards (UK-adopted IFRSs) and International Financial Reporting Standards adopted pursuant to Regulation (EC) No. 1606/2002 as it applies in the European Union. The financial reporting framework that has been applied in the preparation of the parent company financial statements is applicable law and United Kingdom Accounting Standards, including FRS 101 "Reduced Disclosure Framework" (United Kingdom Generally Accepted Accounting Practice).

The financial information for the year ended 31 December 2022 does not constitute statutory accounts as defined in sections 435 (1) and (2) of the Companies Act 2006. Statutory accounts for the year ended 31 December 2021 have been delivered to the Registrar of Companies and those for 2022 will be delivered following the Company's annual general meeting. The auditor has reported on these accounts; their reports were unqualified. Their report did not include a reference to any other matters to which the auditor drew attention by way of emphasis of matter and did not contain a statement under section 498 (2) or (3) of the Companies Act 2006.

The Financial Statements have been prepared on the historical cost basis, except for derivative financial instruments and contingent consideration which have been measured at fair value which are carried at fair value less cost to sell. The Financial Statements are presented in US dollars and all values are rounded to the nearest $0.1 million, except where otherwise stated.

The accounting policies applied are consistent with those adopted and disclosed in the Group's financial statements for the year ended 31 December 2021, with an exception of the change discussed below. There have been a number of amendments to accounting standards and new interpretations issued by the International Accounting Standards Board which were applicable from 1 January 2022, however these have not any impact on the accounting policies, methods of computation or presentation applied by the Group. Further details on new International Financial Reporting Standards adopted will be disclosed in the 2022 Annual Report and Accounts.

Certain new accounting standards and interpretations have been published that are not mandatory for 31 December 2022 reporting periods and have not been early adopted by the Group. These standards are not expected to have a material impact on the entity in the current or future reporting periods and on foreseeable future transactions.

Changes in accounting policy

The Group has revised its accounting policy in relation to the presentation of corporate income taxes in Gabon and Côte d'Ivoire Production Sharing Contracts (PSCs).

Under the terms of the PSCs the share of the profit oil which the government is entitled to is deemed to include the notional corporate income tax which is paid by the government on behalf of Tullow. From 1 January 2022 the notional corporate income tax is classified as an income tax in accordance with IAS 12 Income taxes which has resulted in a gross up of revenue with a corresponding increase in income tax expense. In the previous years, the Revenues and Taxes from Gabon and Côte d'Ivoire were presented on a net basis. This change has been implemented to more accurately represent the Group's income tax obligations in Gabon and Côte d'Ivoire and to be more comparable with other entities in the sector. Prior period balances have been adjusted to conform with the same presentation. As a result of the change, revenue for the year ended 31 December 2021 increased from $1,273.2 million to $1,285.4 million, whilst income tax expense increased from $283.4 million to $295.5 million. There is no impact on profit/(loss) for the year from continuing activities nor on basic and diluted earnings per share. In addition, the restatement had no impact on reported net assets, cash flows or total equity. Accordingly, an additional balance sheet as at 1 January 2020 has not been presented. Refer to Note 7.

Other than the above, the Group's accounting policies are consistent with the prior year.

2.   Earnings/(loss) per ordinary share

Basic earnings/(loss) per ordinary share amounts are calculated by dividing net profit/ (loss) for the year attributable to ordinary equity holders of the Parent by the weighted average number of ordinary shares outstanding during the year.

Diluted earnings per ordinary share amounts are calculated by dividing net profit/ (loss) for the year attributable to ordinary equity holders of the Parent by the weighted average number of ordinary shares outstanding during the year plus the weighted average number of dilutive ordinary shares that would be issued if employee and other share options were converted into ordinary shares.

3.   2022 Annual Report and Accounts

The 2022 Annual Report and Accounts will be mailed in March 2023 only to those shareholders who have elected to receive it. Otherwise, shareholders will be notified that the Annual Report and Accounts are available on the Group's website (www.tullowoil.com). Copies of the Annual Report and Accounts will also be available from the Company's registered office at Building 9, Chiswick Park, 566 Chiswick High Road, London, W4 5XT.

 

4.   Segmental reporting

The information reported to the Group's Chief Executive Officer for the purposes of resource allocation and assessment of segment performance is focused on four Business Units - Ghana, Non-operated producing assets including Uganda and decommissioning assets, Kenya and Exploration. Therefore, the Group's reportable segments under IFRS 8 are Ghana, Non-operated, Kenya and Exploration.

The following tables present revenue, loss and certain asset and liability information regarding the Group's reportable business segments for the years ended 31 December 2022 and 31 December 2021.

$m	Ghana	Non-Operated	Kenya	Exploration	Corporate	Total
2022
Sales revenue by origin	1,578.5	524.0	-	-	(319.4)	1,783.1
Segment result1	692.5	337.3	(0.5)	(102.6)	(337.5)	589.2
Other provisions2						(4.1)
Gain on bargain purchase						196.8
Other gains and losses						3.1
Unallocated corporate expenses3						(51.1)
Operating profit						733.9
Gain on hedging instruments						0.8
Finance income						42.9
Finance costs						(335.5)
Profit before tax						442.1
Income tax expense						(393.0)
Profit after tax						49.1
Total assets	3,827.7	380.6	265.6	46.0	519.7	5,039.6
Total liabilities4	(2,220.5)	(401.6)	(14.1)	(4.6)	(2,858.3)	(5,499.1)
Other segment information
Capital expenditure:
Property, plant and equipment	342.9	26.9	-	-	0.9	370.7
Intangible exploration and evaluation assets	0.9	(1.7)	(2.1)	42.1	-	39.2
Depletion, depreciation and amortisation	(362.1)	(52.7)	(1.3)	-	(9.7)	(425.8)
Impairment of property, plant and equipment, net	(380.6)	(10.6)	-	-	-	(391.2)
Exploration costs written off	(0.9)	1.8	(0.5)	(105.6)	-	(105.2)

1       Segment result is a non IFRS measure which includes gross profit, exploration costs written off, impairment of property, plant and equipment. See reconciliation below.

2       This is included within Restructuring costs and other provisions in the Group Income Statement.

3       Unallocated expenditure and include amounts of a corporate nature and not specifically attributable to a geographic area. The liabilities comprise the Group's external debt and other non-attributable corporate liabilities.

4       Total liabilities - Corporate comprise of the Group's external debt and other non-attributable liabilities.

 

Reconciliation of segment result	2022	2021 Restated1
Segment result	589.2	532.2
Add back:
Exploration costs written off	105.2	59.9
Impairment of Property, plant and equipment	391.2	54.3
Gross profit	1,085.6	646.5

1       Revenue from crude oil sales has been restated following a revision to the Group's accounting policy. This resulted in an increase to revenue for the year ended 31 December 2022 of $21.4 million (2021: $12.2 million), and a corresponding increase to income tax expense.  Refer to note 7.

 

1.       

4.   Segmental reporting continued

$m	Ghana	Non-Operated	Kenya	Exploration	Corporate	Total
2021
Sales revenue by origin - restated6	1,020.4	417.9	-	-	(152.9)	1,285.4
Segment result1 - restated6	469.8	298.7	-	(70.5)	(165.7)	532.3
Other provisions2	6.6	-	(13.2)	-	(52.1)	(58.7)
Gain on disposal						120.3
Unallocated corporate expenses3						(67.2)
Operating profit						526.7
Finance income						44.3
Finance costs						(356.1)
Profit before tax						214.9
Income tax expense						(295.6)
Loss after tax						(80.7)
Total assets - restated6	4,283.8	501.2	264.6	122.3	368.8	5,540.6
Total liabilities - restated6	(2,529.3)	(478.9)	(18.0)	(12.8)	(2,967.7)	(6,006.7)
Other segment information
Capital expenditure:
Property, plant and equipment	99.6	43.9	-	-	4.6	148.1
Intangible exploration and evaluation assets5	1.2	(11.8)	8.2	48.8	-	46.3
Depletion, depreciation and amortisation	(334.5)	(28.8)	(1.4)	(0.1)	(14.1)	(378.9)
Impairment of property, plant and equipment, net	(119.1)	64.8	-	-	-	(54.3)
Exploration costs written off5	(1.2)	11.8	-	(70.5)	-	(59.9)

1       Segment result is a non-IFRS measure which includes gross profit, exploration costs written off and impairment of property, plant and equipment. See reconciliation below.

2       This is included within the Restructuring costs and other provisions in the Group Income Statement.

3       Unallocated expenditure includes amounts of a corporate nature and not specifically attributable to a geographic area.

4       Total liabilities - Corporate comprise of the Group's external debt and other non-attributable liabilities.

5       Non-operated segment includes release of $15.3 million indirect tax provision following settlement.

6       Segment revenue and segment result allocation between the reportable segments have been restated to correct a prior period error arising from incorrect classification of loss on realisation of the cash flow hedges within reportable segments. Total balances have remained unchanged.
The allocation for the year ended 31 December 2021 increased revenue for Ghana and Non-Operated by $109.8 million and $43.1 million, respectively, whilst the hedging loss of $152.9 million was allocated to Corporate.
Total assets and total liabilities allocation between the reportable segments have been restated to correct a prior period error arising from incorrect classification of tax assets and liabilities within reportable segments.

 

The above balances have been restated by:

$m	Ghana	Non-Operated	Kenya	Exploration	Corporate	Total
Total assets - increase/(decrease)	(35.1)	5.4	(6.0)	(22.0)	57.8	-
Total liabilities - (increase)/ decrease	(32.0)	(11.2)	6.0	24.0	13.2	-

 

In addition, revenue from crude oil sales has been restated following a revision to the Group's accounting policy. This resulted in an increase to revenue for the year ended 31 December 2022 of $21.4 million (2021: $12.2 million), and a corresponding increase to income tax expense. Refer to note 7.

 

5.   Other costs

$m	2022	2021
Cost of sales
Operating costs	266.5	268.7
Depletion and amortisation of oil and gas and leased assets1	410.7	360.9
Underlift, overlift and oil stock movements	(46.3)	(20.0)
Royalties	61.7	40.5
Share-based payment charge included in cost of sales	0.4	0.5
Other cost of sales	4.4	(11.7)
Total cost of sales	697.5	638.9
Administrative expenses
Share-based payment charge included in administrative expenses	5.4	11.1
Depreciation of other fixed assets	15.1	18.0
Other administrative costs	30.5	35.0
Total administrative expenses	51.0	64.1
Total restructuring costs and other provisions2	4.2	61.8

1       Depreciation expense on leased assets of $60.9 million as per note 10 includes a charge of $3.9 million on leased administrative assets, which is presented within administrative expenses in the income statement. The remaining balance of $57.0 million relates to other leased assets and is included within cost of sales.

2       This includes restructuring and redundancy costs of $0.1 million (2021: $3.1 million) as well as movements in other provisions of $4.1 million (2021: $58.7 million).

 

6.   Net financing costs

$m	2022	2021
Interest on bank overdrafts and borrowings	250.4	243.0
Interest on obligations for leases	76.4	83.4
Total borrowing costs	326.8	326.4
Finance and arrangement fees	0.3	19.1
Other Interest expense	2.4	3.0
Unwinding of discount on decommissioning provisions	6.0	7.6
Total finance costs	335.5	356.1
Interest income on amounts due from Joint Venture partners for leases	(29.6)	(38.8)
Other finance income	(13.3)	(5.5)
Total finance income	(42.9)	(44.3)
Net financing costs	292.6	311.8

 

7.   Taxation on profit on continuing activities

$m	2022	2021 Restated1
Current tax on profits for the year
UK corporation tax	(11.8)	(19.2)
Foreign tax	321.0	162.2
Taxes paid in kind under production sharing contracts	21.4	12.2
Adjustments in respect of prior periods	(3.3)	(3.3)
Total corporate tax	327.3	151.9
UK petroleum revenue tax	(2.8)	(1.2)
Total current tax	324.5	150.7
Deferred tax Origination and reversal of temporary differences
UK corporation tax	11.4	18.1
Foreign tax	54.0	80.3
Adjustments in respect of prior periods	(2.9)	43.8
Total deferred corporate tax	62.5	142.2
Deferred UK petroleum revenue tax	6.0	2.7
Total deferred tax	68.5	144.9
Total income tax expense	393.0	295.6

1       Income tax expense has been restated following a revision to the Group's accounting policy. The revenue from certain Production Sharing Contracts in Gabon and Côte d'Ivoire is now presented gross of corporate income taxes deemed to have been paid as part of the Government's share of profit oil. This resulted in an increase to revenue for the year ended 31 December 2022 of $21.4 million (2021: $12.2 million), and a corresponding increase to income tax expense. This change has been implemented to more accurately represent the income taxes suffered by the Group on its profits in Gabon and Côte d'Ivoire and to be more comparable with other entities in the sector.

$m	2022	2021 Restated
Profit from continuing activities before tax	442.1	214.9
Tax on profit from continuing activities at the standard UK corporation tax rate of 19% (2020: 19%)	84.0	40.8
Effects of:
Non-deductible exploration expenditure	0.5	8.5
Other non-deductible expenses	27.8	13.3
Deferred tax asset not recognised	138.5	94.4
Utilisation of tax losses not previously recognised	(0.4)	(0.1)
Adjustment relating to prior years	(6.2)	40.4
Other tax rates applicable outside the UK	214.6	118.3
Other income not subject to corporation tax	(0.1)	(20.0)
Tax impact of acquisition through business combination (note 12)	(65.7)	-
Group total tax expense for the year	393.0	295.6

Uncertain tax treatments

The Group is subject to various material claims which arise in the ordinary course of its business in various jurisdictions, including cost recovery claims, claims from regulatory bodies and both corporate income tax and indirect tax claims. The Group is in formal dispute proceedings regarding a number of these tax claims. The resolution of tax positions, through negotiation with the relevant tax authorities or litigation, can take several years to complete. In assessing whether these claims should be provided for in the Financial Statements, Management has considered them in the context of the applicable laws and relevant contracts for the countries concerned. Management has applied judgement in assessing the likely outcome of the claims and has estimated the financial impact based on external tax and legal advice and prior experience of such claims.

Due to the uncertainty of such tax items, it is possible that on conclusion of an open tax matter at a future date the outcome may differ significantly from Management's estimate. If the Group was unsuccessful in defending itself from all of these claims, the result would be additional liabilities of $1,024.0 million (2021: $1,025.5 million) which includes $32.4 million of interest and penalties (2021: $33.6 million).

 

7.   Taxation on profit on continuing activities continued

Uncertain tax treatments continued

Provisions of $106.4 million (2021: $127.9 million) are included in income tax payable ($70.6 million (2021: $34.1 million)), deferred tax liability ($nil (2021:41.0 million)), and provisions ($35.8 million (2021: $52.8 million)). Where these matters relate to expenditure which is capitalised within Intangible Exploration and Evaluation Assets and Property, Plant and Equipment, any difference between the amounts accrued and the amounts settled is capitalised within the relevant asset balance, subject to applicable impairment indicators. Where these matters relate to producing activities or historical issues, any differences between the accrued and settled amounts are taken to the group income statement.

The provisions and contingent liabilities relating to these disputes have decreased following the conclusion of tax authority challenges and matters lapsing under the statute of limitations, but have increased, following new claims being initiated and extrapolation of exposures through to 31 December 2022, giving rise to an overall decrease in provision of $21.5 million and decrease in contingent liability of $1.5 million.

Ghana tax assessments

In October 2021, Tullow Ghana Limited (TGL) filed a Request for Arbitration with the International Chamber of Commerce (ICC) disputing the $320 million branch profits remittance tax (BPRT) assessment issued as part of the direct tax audit for the financial years 2014 to 2016. The GRA is seeking to apply BPRT under a law which the Group considers is not applicable to TGL, since it falls outside the tax regime provided for in the Petroleum Agreements and relevant double tax treaties. The parties have agreed a procedural timetable for the arbitration under which the first Tribunal hearing will be held in October 2023.

In December 2022, TGL received a $190.5 million corporate income tax assessment and payment demand from the GRA relating to the disallowance of loan interest for the financial years 2010 to 2020. The Group has previously disclosed assessments by the GRA relating to the same issue; this revised assessment supersedes all previous claims. The Group considers the assessment to breach TGL's rights under its Petroleum Agreements. In February 2023, TGL filed a Request for Arbitration with the ICC, disputing the assessment with the suspension of TGL's obligation to pay any amount in relation to the assessment until the dispute is formally resolved.

In December 2022, TGL received a $196.5 million corporate income tax assessment and payment demand from the GRA relating to proceeds received by Tullow during the financial years 2016 to 2019 under Tullow's corporate Business Interruption Insurance policy. The Group considers the assessment to breach TGL's rights under its Petroleum Agreements. In February 2023, TGL filed a Request for Arbitration to the ICC, disputing the assessment with the suspension of TGL's obligation to pay any amount in relation to the assessment until the dispute is formally resolved.

The Group continues to engage with the Government of Ghana with the aim of resolving all tax disputes on a mutually acceptable basis.

Bangladesh litigation

The National Board of Revenue (NBR) is seeking to disallow $118 million of tax relief in respect of development costs incurred by Tullow Bangladesh Limited (TBL). The NBR subsequently issued a payment demand to TBL in February 2020 for Taka 3,094 million (c.$37 million) requesting payment by 15 March 2020. However, under the Production Sharing Contract (PSC), the Government is required to indemnify TBL against all taxes levied by any public authority, and the share of production paid to Petrobangla (PB), Bangladesh's national oil company, is deemed to include all taxes due which PB is then obliged to pay to the NBR. TBL sent the payment demand to PB and the Government requesting the payment or discharge of the payment demand under their respective PSC indemnities. On 14 June 2021, TBL issued a formal notice of dispute under the PSC to the Government and PB. A further request for payment was received from NBR on 28 October 2021 demanding settlement by 15 November 2021. Arbitration proceedings were initiated under the PSC on 29 December 2021. A procedural hearing was held on 28 June 2022 which set the timetable for the process going forward. The first submissions have been made in October 2022 with the first Tribunal hearing scheduled for May 2024.

Other items

Other items totalling $280.0 million (2021: $547.5 million) comprise exposures in respect of claims for corporation tax in respect of disallowed expenditure or withholding taxes that are either currently under discussion with the tax authorities or which arise in respect of known issues for periods not yet under audit.

Timing of cash flows

While it is not possible to estimate the timing of tax cash flows in relation to possible outcomes with certainty, Management anticipates that there will not be material cash taxes paid in excess of the amounts provided for uncertain tax treatments.

 

8.   Asset Disposals

On 31 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 Dussafu Marin Permit in Gabon.

On 9 June 2021, the Group completed the asset sale of 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.

Given Tullow no longer holds interest in the above assets, based on publicly available information the Company has assessed that the asset performance condition is not met. Accordingly, no contingent consideration has been recognised as at 31 December 2021.

Book value of assets disposed $m	Equatorial Guinea	Dussafu	Total
Property, plant and equipment	72.9	52.0	124.9
Inventories	6.9	3.2	10.1
Other current assets	68.5	1.7	70.2
Total assets disposed	148.3	56.9	205.2
Trade and other payables	(36.1)	(18.5)	(54.6)
Provisions	(118.2)	(4.7)	(122.9)
Current tax liabilities	(13.6)	-	(13.6)
Deferred tax liabilities	(17.8)	-	(17.8)
Total liabilities disposed	(185.7)	(23.2)	(208.9)
Net (liabilities)/ assets disposed	(37.4)	33.7	(3.7)
Cash consideration	93.8	39.0	132.8
Transaction costs	(11.0)	(0.3)	(11.3)
Gain on disposal1	120.2	5.0	125.2

1       In 2021, in addition to $125.2 million gain on disposals recognised following the Equatorial Guinea and Dussafu disposals, the Group recognised a loss of $5.1 million relating to its sale of Dutch assets to Hague and London Oil plc (HALO) in 2017, and a gain of $0.2 million relating to other transactions during the period which resulted in an overall gain of $120.3 million. No gain on disposals was recognised for the year ended 31 December 2022.

 

Uganda

Contingent asset

During 2020, the Group completed the disposal of its interest in Uganda for upfront cash consideration of $500.0 million, with $75.0 million received following FID and contingent future payments linked to oil prices. Given the existing uncertainties around the project, management has concluded that the conditions for recognition of an asset associated with contingent consideration under IFRS 15 were not met as of 31 December 2022.

 

9.   Intangible exploration and evaluation assets

$m	2022	2021
At 1 January	354.6	368.2
Additions1	39.2	46.3
Exploration costs written off	(105.2)	(59.9)
At 31 December	288.6	354.6

1       In Kenya, proceeds from Early Oil Pilot Scheme (EOPS) cargo sales of $6.9 million have been recorded as a credit against capital expenditure.

 

The below table provides a summary of the exploration costs written off on a pre-tax basis by country.

Country	CGU	Rationale for 2022 write-off	2022 write off $m	2022 Remaining recoverable amount  $m
Guyana	Kanuku	a, b	75.3	-
Guyana	Orinduik	b	22.4	-
Côte d'Ivoire	Block 524	c	3.1	-
New Ventures	Various	d	3.0	-
Other	Various		1.4	-
Total write-off			105.2	-

a. Unsuccessful well costs written off.

b. Licence relinquishments, expiry, planned exit or reduced activity.

c. Current year expenditure on assets previously written off.

d. New Ventures expenditure is written off as incurred.

 

In Kenya, the Group had received a 15-month licence extension from September 2020 to December 2021 which was contingent on certain conditions, including submission of a technically and commercially compliant Field Development Plan (FDP). On 10 December 2021, Tullow and its Joint Venture Partners submitted an FDP to the Government of Kenya and fulfilled its licence obligations. The Group expects a production licence to be granted once due Government process has been completed.

Since 1 January 2022, there have been ongoing discussions with the Government of Kenya on approval of the FDP and securing government deliverables. An updated FDP was submitted on 3 March 2023 and is being reviewed by the Government of Kenya before ratification by the Kenyan Parliament. In addition, the Company continues to progress with the farm down process.

In line with its accounting policy, the Group has performed a VIU assessment of the Kenya asset following identification of triggers for impairment and impairment reversal. This resulted in an NPV significantly in excess of the book value of $252.6 million. However, the Group has identified the following uncertainties in respect to the Group's ability to realise the estimated VIU; receiving and subsequently finalising an acceptable offer from a strategic partner and securing governmental approvals relating thereto, obtaining financing for the project and government deliverables. These items require satisfactory resolution before the Group can take a Final investment Decision (FID). Due to the binary nature of these uncertainties the Group was unable to either adjust the cash flows or discount rate appropriately. It has therefore used its judgement and assessed a probability of achieving FID and therefore the recognition of commercial reserves. This probability was applied to the VIU to determine a risk adjusted VIU and compared against the net book value of the asset. Based on this there is no impairment or impairment reversal as at 31 December 2022. The cash flows in the VIU assessment were discounted using a pre-tax nominal discount rate of 20%. Refer to note 10 for oil price assumptions.

Should the uncertainties around the project be resolved, there will be a reversal of a previously recorded impairment. However, if the uncertainties are not resolved there will be an additional impairment of $252.6 million. A reduction or increase in the two-year forward curve of $5/bbl, based on the approximate range of annualized average oil price over recent history, and a reduction or increase in the medium and long-term price assumptions of $5/bbl, based on the range of annualized average historical prices, are considered to be reasonably possible changes for the purposes of sensitivity analysis. Decreases to oil prices specified above would result in an impairment charge of $31.6 million, whilst increases to oil prices specified above would result in an impairment reversal of $35.2 million. A 1% increase in the pre-tax discount rate would result in an impairment charge of $34.2 million. The Group believes a 1% change in the pre-tax discount rate to be a reasonable possibility based on historical analysis of the Group's and a peer group of companies' impairments.

 

10. Property, plant and equipment

$m	2022 Oil and gas assets	2022 Other fixed assets	2022 Right of use assets	2022 Total	2021 Oil and gas assets	2021 Other fixed assets	2021 Right of use assets	2021 Total
Cost
At 1 January	10,521.7	69.5	1,091.7	11,682.9	10,460.2	69.6	1,018.6	11,548.4
Additions	305.2	2.0	63.5	370.7	73.0	1.6	73.5	148.1
Acquisitions1	473.2	-	-	473.2
Transfer2	-	-	86.6	86.6
Asset retirement	-	(38.1)	(41.7)	(79.8)	-	(1.4)	-	(1.4)
Currency translation adjustments	(117.5)	(3.4)	(3.3)	(124.2)	-	-	-	-
At 31 December	11,182.6	30.0	63.5	370.7	10,521.7	69.5	1,091.7	11,682.9
Depreciation, depletion, amortisation and impairment
At 1 January	(8,263.7)	(53.8)	(450.8)	(8,768.3)	(7,915.9)	(42.3)	(352.3)	(8,310.5)
Charge for the year	(353.7)	(11.2)	(60.9)	(425.8)	(304.9)	(13.4)	(60.6)	(378.9)
Impairment loss	(391.2)	-	-	(391.2)	(54.3)	-	-	(54.3)
Capitalised depreciation	-	-	(46.1)	(46.1)	-	-	(38.0)	(38.0)
Asset retirement	-	38.1	41.7	79.8	-	1.4	-	1.4
Currency translation adjustments	120.2	2.5	0.9	123.6	11.4	0.5	0.1	12.0
At 31 December	(8,888.4)	(24.4)	(515.2)	(9,428.0)	(8,263.7)	(53.8)	(450.8)	(8,768.3)
Net book value at 31 December	2,294.2	5.6	681.6	2,981.4	2,258.0	15.7	640.9	2,914.6

1       This relates to an acquisition through business combination discussed in Note 12.

2       As a result of Ghana pre-emption a proportionate amount has been reclassified from receivables due from joint venture partners to right of use assets relating to the Group's existing interest in lease contracts in the joint operation.

 

The currency translation adjustments arose due to the movement against the Group's presentation currency, USD, of the Group's UK assets which have functional currencies of GBP.

During 2022 and 2021, the Group applied the following nominal oil price assumption for impairment assessments:

	Year 1	Year 2	Year 3	Year 4	Year 5	Year 6 onwards
2022	$84/bbl	$79/bbl	$70/bbl	$70/bbl	$70/bbl	$70/bbl inflated at 2%
2021	$76/bbl	$71/bbl	$68/bbl	$65/bbl	$65/bbl	$65/bbl inflated at 2%

 

 

10. Property, plant and equipment continued

		Trigger for 2022 impairment/(reversal)	2022 Impairment/(reversal) $m	Pre-tax discount rate assumption	2022 Remaining recoverable amountd $m
Limande and Turnix CGU (Gabon)		a	(1.6)	15%	44.6
Tchatamba (Gabon)		a	(1.3)	15%	38.0
Oba and Middle Oba CGU (Gabon)		a	(0.4)	17%	11.8
Echira, Niungo and Igongo (Gabon)		a	(1.4)	17%	8.6
TEN (Ghana)		b	380.6	13%	926.9
Mauritania		a	12.8	n/a	-
UK CGU		a,c	2.5	n/a	-
			391.2

a. Change to decommissioning estimate.

b. Revision of value based on revisions to reserves

c. The fields in the UK are grouped into one CGU as all fields within those countries share critical gas infrastructure.

d. The remaining recoverable amount of the asset is its value in use.

 

Impairments identified in the TEN fields of $380.6 million were primarily due to lower 2P reserves partially offset by oil price assumptions.

Oil prices stated above are benchmark prices to which an individual field price differential is applied. All impairment assessments are prepared on a VIU basis using discounted future cash flows based on 2P reserves profiles. A reduction or increase in the two-year forward curve of $5/bbl, based on the approximate range of annualized average oil price over recent history, and a reduction or increase in the medium and long-term price assumptions of $5/bbl, based on the range of annualized average historical prices, are considered to be reasonably possible changes for the purposes of sensitivity analysis. Decreases to oil prices specified above would increase the impairment charge by $131.4 million for Ghana and increase the impairment by $19.2 million for Non-Operated, whilst increases to oil prices specified above would result in a credit to the impairment charge of $122.0 million for Ghana and no change to Non-Operated. A 1% increase in the pre-tax discount rate would increase the impairment by $33.0 million for Ghana and increase the impairment by $2.9 million for Non-Operated. The Group believes a 1% change in the pre-tax discount rate to be a reasonable possibility based on historical analysis of the Group's and peer group of companies' impairments.

11. Other assets

$m	2022	2021
Non-current
Amounts due from joint venture partners	323.3	486.0
VAT recoverable	3.8	3.1
	327.1	489.1
Current
Amounts due from joint venture partners	452.3	554.7
Underlifts	76.2	26.7
Prepayments	31.3	49.6
Other current assets	8.1	73.5
	567.9	704.5
	895.0	1,193.6

 

The decrease in non-current receivables from JV Partners compared to December 2021 mainly relates to reduction in time remaining on the TEN FPSO lease, net decrease in GNPC (Ghana National Petroleum Corporation) receivable and reduction in partner share following Ghana pre-emption.

 

11. Other assets continued

The movement in current receivables from JV Partners relates mainly to timing of partner balances and reduction in partner share following Ghana pre-emption.

The decrease in other current assets compared to 2021 is mainly due to a collection of the deferred consideration relating to the Uganda disposal in March 2022 ($67.9 million net).

12. Business combination

Summary of acquisition

On 17 March 2022 the Group completed the 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 of this acquisition, the Group's interest in the TEN fields increased from 47.18% to 54.84%, and from 35.48% to 39.0% in the Jubilee field. Tullow did not obtain control as a result of this transaction, as all joint venture partners retain joint control.

The total purchase consideration, which was funded from cash on the balance sheet, comprises of $118.2 million cash settled on completion, and $8.6 million subsequent post-completion adjustment paid in May 2022. There is no element of contingent consideration included in the purchase price.

The fair values of the identifiable assets and liabilities acquired were:

$m	Fair value recognised on acquisition
Property, plant and equipment	473.2
Inventories	12.1
Other current assets	31.4
Total assets acquired	516.7
Trade and other payables	(10.5)
Provisions	(61.6)
Deferred tax liabilities	(143.6)
Total liabilities assumed	(215.5)
Net identifiable assets acquired	301.0
Purchase consideration transferred	(126.8)
Deemed settlement of provision	22.6
Gain on bargain purchase	196.8

 

There were no acquisitions in the year ended 31 December 2021.

The property, plant and equipment acquired through the business combination has been recognised at the fair value based on the net present value of the discounted future cash flows. Significant inputs to the valuation include short- and long-term commodity prices, reserve estimates, production volume profiles, planned development expenditure, cost profiles and discount rates, and are consistent with those applied by management when testing assets for impairments.

The fair value of acquired other receivables is nil. The gross contractual amount for other receivables due is $0.9 million, with a loss allowance of $0.9 million recognised on acquisition.

The deferred tax liability mainly comprises the tax effect of the accelerated depreciation for tax purposes of tangible assets.

Contingent liabilities recognised in a business combination

A contingent liability recognised in a business combination is initially measured at its fair value. Subsequently, it is measured at the higher of the amount that would be recognised in accordance with the requirements for provisions as per IAS 37 "Provisions, Contingent Liabilities and Contingent Assets", or the amount initially recognised less (when appropriate) cumulative amortisation recognised in accordance with the requirements for revenue recognition.

As part of the pre-emption Tullow has taken on pro-rated exposure relating to Anadarko WCTP Company's (Anadarko) BPRT and AOE disputed claims. In February 2018, Anadarko, whom Occidental Petroleum acquired the interests from, received a provisional assessment for AOE for $346.6 million, including a penalty of $329.5 million (the portion of this claim related to Tullow's acquired interests was $67.2 million), covering the financial years 2006 to 2016 and in November 2018 the Ministry of Finance confirmed that the assessment was suspended pending the Government reaching a final view on the basis for calculating AOE. Anadarko continued to dispute the AOE assessment issued and considered no AOE was payable for these periods. In September 2021, Anadarko received a revised tax audit report from the GRA for the

12. Business combination continued

financial years 2014 to 2018 including a $228.3m branch profits remittance tax (BPRT) assessment (including late payment interest of $52.1m) (the portion of this claim related to Tullow's acquired interests was $67.1 million). The Anadarko BPRT assessment is covered by a Notice of Dispute issued in June 2020.

A contingent liability at fair value of $36.8 million was recognised at the acquisition date for provisions resulting from certain contractual indemnities. There was no change in provision as at 31 December 2022.

Revenue and net profit contribution

The acquired business contributed revenues of $133.2 million and net profit of $19.6 million to the Group for the period from 17 March 2022 to 31 December 2022. If the acquisition had occurred on 1 January 2022, the consolidated pro-forma revenues would have been $169.2 million higher and the consolidated pro-forma profit for the period ended 31 December 2022 would have been higher by $11.4 million.

These amounts have been calculated using the acquired interest's results and adjusting them for the additional depreciation and amortisation that would have been charged assuming the fair value adjustments to property, plant and equipment had applied from 1 January 2022, together with the consequential tax effects.

Acquisition-related costs 

Acquisition-related costs of $0.6 million are included in administrative expenses in the statement of profit or loss and in operating cash flow in the statement of cash flows.

Recognition of gain on bargain purchase

The difference between the fair value of net assets acquired and consideration paid was recognised within the income statement as gain on bargain purchase of $196.8 million. This is mostly due to the change in the oil markets from 2021, when the transaction between Occidental Petroleum and Kosmos Energy was negotiated, to March 2022, when the acquisition was completed by Tullow. The consideration paid by Tullow for the acquired interest was based on the proportionate consideration agreed between Occidental Petroleum and Kosmos Energy, subject to completion adjustments. Additionally, the original transaction between the two parties was driven by the seller's intention to leave the region and dispose of the non-core elements of the portfolio which it had acquired from Anadarko Petroleum in August 2019.

13. Trade and other payables

$m	2022	2021
Current liabilities
Trade payables	68.4	60.2
Other payables	51.4	57.4
Overlifts	-	0.7
Accruals1	379.3	381.3
Current portion of lease liabilities	251.2	251.5
	750.2	751.1
Non-current liabilities
Other non-current liabilities2	47.1	75.2
Non-current portion of lease liabilities	732.9	911.9
	780.0	987.1

1       Accruals mainly relate to capital expenditure, interest expense on bonds and staff related expenses.

2       Other non-current liabilities include balances related to JV Partners.

 

Trade and other payables are non-interest bearing except for leases.

Payables related to operated Joint Ventures (primarily in Ghana and Kenya) are recorded gross with the amount representing the partners' share recognised in amounts due from Joint Venture Partners (note 11). The change in trade payables and in other payables predominantly represents timing differences and levels of work activity.

The decrease in non-current portion of lease liabilities mainly relates to reduction in time remaining on the TEN FPSO lease.

 

14. Provisions

$m	Decommissioning 2022	Other provisions 2022	Total 2022	Decommissioning 2021	Other provisions 2021	Total 2021
At 1 January	498.7	228.8	727.5	696.1	154.6	850.7
New provisions, changes in estimates and reclassifications	(47.6)	(19.7)	(67.3)	(134.8)	90.0	(44.8)
Acquisitions1	24.8	36.8	61.6	-	-	-
Payments	(72.1)	(127.3)	(199.4)	(69.3)	(15.7)	(85.0)
Unwinding of discount	6.0	-	6.0	7.6	-	7.6
Currency translation adjustment	(11.6)	(2.3)	(13.9)	(0.9)	(0.1)	(1.0)
At 31 December	398.1	116.3	514.4	498.7	228.8	727.5
Current provisions	87.7	11.1	98.8	101.2	195.3	296.5
Non-current provisions	310.4	105.2	415.6	397.5	33.5	431.0

1       This relates to an acquisition through business combination discussed in note 12.

 

Other provisions include non-income tax provisions of $68.3 million (2021: $52.8 million) and $48.0 million (2021: $176.0 million) of disputed cases and claims. Management estimates non-current other provisions would fall due between two and five years.

Non-Current other provisions mainly relates to Bangladesh litigation. Refer to Uncertain Tax Treatments in Accounting Policies for further detail. This also includes a provision relating to a potential claim arising out of historical contractual agreement. Further information is not provided as it will be seriously prejudicial to the Company's interest.

On 15 February 2022, an arbitration panel delivered an award against Tullow in respect to a historic contractual dispute in Norway related to the acquisition of Spring Energy Norway AS (Spring) from HiTecVision (HiTec). The Tribunal decided by way of split decision that conditions under the Spring SPA in respect of the bonus payment had been met. The Tribunal ruled that Tullow should pay $76 million to HiTec (an amount which includes interest and costs) and a further amount of $0.7 million in respect of Tribunal costs. This balance was provided for as at 31 December 2021 and was settled in March 2022.

The decommissioning provision represents the present value of decommissioning costs relating to the European and African oil and gas interests. The Group has assumed cessation of production as the estimated timing for outflow of expenditure. However, expenditure could be incurred prior to cessation of production or after and actual timing will depend on a number of factors including underlying cost environment, availability of equipment and services and allocation of capital.

In 2022, the Group has increased the decommissioning discount rate by 1.5-2% from 31 December 2021 due to movement in the risk-free rate. This resulted in a decrease of the provision by $39.5 million in Ghana, $15.6 million in Côte d'Ivoire and $12.1 million in Gabon.

Decommissioning provisions	Inflation assumption	Discount rate assumption 2022	Cessation of production assumption 2022	Total 2022 $m	Discount rate assumption 2021	Cessation of production assumption 2021	Total 2021 $m
Côte d'Ivoire	2%	3.5%	2035	45.6	1.5%	2033	61.7
Gabon	2%	3.5%	2025-2037	49.2	1.5-2%	2026-2036	61.9
Ghana	2%	3.5%	2036	190.2	1.5-2%	2035-2036	193.3
Mauritania	n/a	n/a	2018	56.0	n/a	2018	61.6
UK	n/a	n/a	2018	57.1	n/a	2018	120.2
				398.1			498.7

1       Short term inflation rate assumption has increased from 2% to 4.7% in 2023 and to 2.5% in 2024. Medium and long-term rates of 2% remained unchanged from 31 December 2021.

 

The Group's decommissioning activities in the UK and Mauritania are ongoing and the majority of the future costs is expected to be incurred in 2023 ($87.4 million). The remaining activities are planned to continue through to 2027, with an associated expenditure of $25.7 million.

 

15. Commercial Reserves and Contingent Resources summary working interest basis

	Ghana				Non-Operated				Kenya		Exploration		Total
	Oil mmbbl	Gas bcf		Oil mmbbl		Gas bcf		Oil mmbbl	Gas bcf	Oil mmbbl	Gas bcf	Oil mmbbl	Gas bcf	Petroleum mmboe
COMMERCIAL RESERVES1
1 January 2022	168.3	138.9		38.8		7.1		-	-	-	-	207.1	145.9	231.4
Revisions3,4,6	(4.5)	4.3		4.8		(0.6)		-	-	-	-	0.4	3.8	1.0
Acquisitions7	16.7	14.1		-		-		-	-	-	-	16.7	14.1	19.0
Production6	(16.2)	-		(5.8)		(1.4)		-	-	-	-	(22.1)	(1.4)	(22.3)
31 December 2022	164.3	157.3		37.8		5.1						202.1	162.4	229.1
CONTINGENT RESOURCES2
1 January 2022	212.1	585.2		29.7		0.9		231.4	-	54.5	-	527.6	586.1	625.4
Revisions3,4,6	(47.8)	(77.1)		6.3		7.7		-	-	-	-	(41.4)	(69.4)	(53.0)
Acquisitions7	20.7	69.7		-		-		-	-	-	-	20.7	69.7	32.3
31 December 2022	185.0	577.8		36.0		8.6		231.4	-	54.5	-	506.9	586.4	604.6
TOTAL
31 December 2022	349.3	735.1		73.8		13.7		231.4	-	54.5	-	709.0	748.8	833.7

1       Commercial Reserves above are as audited and reported by independent third-party reserve auditors. The auditor was provided with all the significant data up until 31 December 2022.

2       Contingent Resources above are also as audited and reported by independent third-party auditors based on best available information as of 31 December 2022. Numbers represent the working interest net to Tullow.

3       Reserves and Resources revisions in Ghana relate to successful infill drilling and good field performance in Jubilee and the maturation of a number of projects on TEN: the Tweneboa Oil development, infill well on Ntomme and the Enyenra South extension development. This is balanced by a downward revision of Ntomme and Enyenra reflecting field production performance and removal of reserves associated with the two TEN Riser Base wells drilled in 2022.

4       Reserves revisions in Gabon mainly relate to development progress in Tchatamba, and reserves in Etame.

5       Resource estimates for Kenya are from independent evaluation of resources by independent third-party reserve auditors.

6       A gas conversion factor of 6 Mscf/boe is used to calculate the total Petroleum mmboe.

7       Acquisitions in Ghana relates to the pre-emption of the Deep Water Tano component of the Kosmos Energy/Occidental Petroleum Ghana transaction. This transaction increased Tullow's equity interests to 39.0% in the Jubilee field and to 54.8% in the TEN fields.

 

The Group provides for depletion and amortisation of tangible fixed assets on a net entitlements basis, which reflects the terms of the Production Sharing Contracts related to each field. Total net entitlement reserves were 219.6 mmboe at 31 December 2022 (31 December 2021: 222.0 mmboe).

Contingent Resources relate to resources in respect of which development plans are in the course of preparation or further evaluation is under way with a view to future development.

 

Alternative performance measures

The Group uses certain measures of performance that are not specifically defined under IFRS or other generally accepted accounting principles. These non-IFRS measures include capital investment, net debt, gearing, adjusted EBITDAX, underlying cash operating costs, free cash flow, underlying operating cash flow and pre-financing cash flow.

Capital investment

Capital investment is defined as additions to property, plant and equipment and intangible exploration and evaluation assets less decommissioning asset additions, right-of-use asset additions, capitalised share-based payment charge, capitalised finance costs, additions to administrative assets, Norwegian tax refund and certain other adjustments. The Directors believe that capital investment is a useful indicator of the Group's organic expenditure on exploration and appraisal assets and oil and gas assets incurred during a period because it eliminates certain accounting adjustments such as capitalised finance costs and decommissioning asset additions.

$m		2022	2021
Additions to property, plant and equipment		370.7	148.1
Additions to intangible exploration and evaluation assets		39.2	46.3
Less
Changes to decommissioning asset estimate		(19.9)	(134.8)
Right-of-use asset additions		63.5	73.5
Lease payments related to capital activities		(40.2)	(26.8)
Additions to administrative assets		2.0	1.6
Other non-cash capital expenditure		50.4	17.7
Capital investment		354.1	263.2
Movement in working capital		(49.7)	(28.3)
Additions to administrative assets		2.0	1.6
Cash capital expenditure per the cash flow statement		306.4	236.5

 

Net debt

Net debt is a useful indicator of the Group's indebtedness, financial flexibility and capital structure because it indicates the level of cash borrowings after taking account of cash and cash equivalents within the Group's business that could be utilised to pay down the outstanding cash borrowings. Net debt is defined as current and non-current borrowings plus non-cash adjustments, less cash and cash equivalents. Non-cash adjustments include unamortised arrangement fees, adjustment to convertible bonds, and other adjustments.

$m		2022	2021
Borrowings		2,472.8	2,568.7
Non-cash adjustments		27.2	31.3
Less cash and cash equivalents		(636.3)	(469.1)
Net debt		1,863.7	2,130.9

 

 

Gearing and Adjusted EBITDAX

Gearing is a useful indicator of the Group's indebtedness, financial flexibility and capital structure and can assist securities analysts, investors and other parties to evaluate the Group. Gearing is defined as net debt divided by adjusted EBITDAX. Adjusted EBITDAX is defined as profit/(loss) from continuing activities adjusted for income tax (expense)/credit, finance costs, finance revenue, gain/(loss) on hedging instruments, depreciation, depletion and amortisation, share-based payment charge, restructuring costs, gain/(loss) on disposal, exploration costs written off, impairment of property, plant and equipment net, and other provisions.

$m		2022	2021 Restated1
Profit/(Loss) from continuing activities		49.1	(80.7)
Adjusted for
Income tax expense		393.0	295.6
Finance costs		335.5	356.1
Finance revenue		(42.9)	(44.3)
Gain on hedging instruments		(0.8)	-
Gain on bargain purchase		(196.8)	-
Depreciation, depletion and amortisation		425.8	378.9
Share-based payment charge		5.8	11.6
Restructuring costs and other provisions		4.2	61.8
Gain on disposal		(0.4)	(120.3)
Exploration costs written off		105.2	59.9
Impairment of property, plant and equipment, net		391.2	54.3
Adjusted EBITDAX		1,468.9	972.9
Net debt		1,863.7	2,130.9
Gearing (times)		1.3	2.2

1       Revenue from crude oil sales has been restated following a revision to the Group's accounting policy. This resulted in an increase to revenue for the year ended 31 December 2022 of $21.4 million (2021: $12.2 million), and a corresponding increase to income tax expense.  Refer to note 7.

 

Underlying cash operating costs

Underlying cash operating costs is a useful indicator of the Group's costs incurred to produce oil and gas. Underlying cash operating costs eliminates certain non-cash accounting adjustments to the Group's cost of sales to produce oil and gas. Underlying cash operating costs is defined as cost of sales less operating lease expense, depletion and amortisation of oil and gas assets, underlift, overlift and oil stock movements, share-based payment charge included in cost of sales, royalties and certain other cost of sales. Underlying cash operating costs are divided by production to determine underlying cash operating costs per boe.

In 2021 and 2022, Tullow incurred abnormal non-recurring costs which are presented separately below. The adjusted normalised cash operating costs are a helpful indicator to the forward underlying costs of the business.

$m		2022	2021
Cost of sales		697.5	638.9
Less:
Depletion and amortisation of oil and gas and leased assets		410.7	360.9
Underlift, overlift and oil stock movements		(46.3)	(20.0)
Share-based payment charge included in cost of sales		0.4	0.5
Royalties		61.7	40.0
Other cost of sales		4.4	(11.7)
Underlying cash operating costs		266.5	268.7
Covid-19 & OOSYS costs		(14.7)	(7.9)
Total normalised cash operating costs		251.8	260.8
Production (MMboe)		21.6	21.6
Underlying cash operating costs per boe ($/boe)		12.3	12.4
Normalised cash operating costs per boe ($/boe)		11.3	12.1

Free cash flow

Free cash flow is a useful indicator of the Group's ability to generate cash flow to fund the business and strategic acquisitions, reduce borrowings and provide returns to shareholders through dividends. Free cash flow is defined as net cash from operating activities, and net cash from/(used) in investing activities, repayment of obligations under leases, finance costs paid and foreign exchange gain/(loss).

$m		2022	2021
Net cash from operating activities		1,077.8	786.9
Net cash used in investing activities		(356.2)	(101.7)
Repayment of obligations under leases		(203.8)	(155.9)
Finance costs paid		(230.5)	(234.9)
Debt arrangement fees		-	(56.6)
Foreign exchange gain		(1.6)	6.9
Free cash flow		267.2	244.7

 

 

Underlying operating cash flow

This is a useful indicator of the Group's assets ability to generate cash flow to fund further investment in the business, reduce borrowings and provide returns to shareholders. Underlying operating cash flow is defined as net cash from operating activities less repayments of obligations under leases plus decommissioning expenditure.

Pre-financing cash flow

This is a useful indicator of the Group's ability to generate cash flow to reduce borrowings and provide returns to shareholders through dividends. Pre-financing free cash flow is defined as net cash from operating activities, and net cash used in investing activities, less repayment of obligations under leases and foreign exchange gain.

$m		2022	2021
Net cash from operating activities		1,077.8	786.9
Less
Decommissioning expenditure		57.7	52.8
Lease payments related to capital activities		40.2	26.8
Plus
Repayment of obligations under leases		(203.8)	(155.9)
Underlying operating cash flow		971.9	710.6
Net cash from/(used in) investing activities		(356.2)	(101.7)
Decommissioning expenditure		(57.7)	(52.8)
Lease payments related to capital activities		(40.2)	(26.8)
Pre-financing cash flow		517.8	529.3

 

Management Presentation - WEBCAST - 9:00 GMT

To access the webcast please use the following link and follow the instructions provided: https://web.lumiconnect.com/130749289

A replay will be available on the website from midday on 8 March 2023: https://www.tullowoil.com/investors/results-reports-and-presentations/

CONTACTS

Tullow Oil plc (London) (+44 20 3249 9000) Robert Hellwig Nicola Rogers Matthew Evans	Camarco (London) (+44 20 3781 9244) Billy Clegg Georgia Edmonds Rebecca Waterworth

Notes to editors

Tullow is an independent oil & gas, exploration and production group which is quoted on the London and Ghanaian stock exchanges

(symbol: TLW) and is a constituent of the FTSE250 index. The Group has interests in over 30 licences across eight countries. In March

2021, Tullow committed to becoming Net Zero on its Scope 1 and 2 emissions by 2030.

For further information, please refer to our website at www.tullowoil.com.

Follow Tullow on:

Twitter: www.twitter.com/TullowOilplc

YouTube: www.youtube.com/TullowOilplc

Facebook: www.facebook.com/TullowOilplc

LinkedIn: www.linkedin.com/company/Tullow-Oil