Half Year Results

RNS Number : 3569Z

Tullow Oil PLC

14 September 2022

Tullow oil PLC - 2022 Half Year Results

14 September 2022 - Tullow Oil (Tullow) announces its Half Year results for the six months ended 30 June 2022. Tullow will host a webcast presentation at 9am this morning, details of which can be found on the last page of this announcement and online atwww.tullowoil.com

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

"The turnaround of Tullow has gained momentum in the first half of 2022, with solid production from our West African portfolio driving stronger financial performance. We added material, unhedged production in Ghana through the pre-emption of the Kosmos-Oxy deal and took over the Operations & Maintenance (O&M) of the Jubilee FPSO to ensure that we can sustain the good operating performance and deliver further operating cost improvements. Our drilling programme has been very efficient and at current performance levels we will be able to deliver our planned programme of wells through next year with just one rig.

The Board of Tullow remains fully committed to the merger with Capricorn which continues to be recommended by both the Tullow and Capricorn Boards on the current terms. We firmly believe that the proposed merger has the potential for material value creation by implementing a combined business plan which accelerates investment in key projects and delivers very significant synergies.

We have a high quality, opportunity rich portfolio, a clear and disciplined growth strategy and an improving balance sheet. The Board looks to the future with confidence, and I look forward to sharing further details at a capital markets day."

2022 First half results summary

· Group working interest production for the first half of 2022 averaged 60.9 kboepd, in line with expectations.

· Ghanaian drilling programme ahead of schedule, having completed two previously drilled wells and drilled and completed another three wells. A further six wells are expected to be drilled and two of these completed by year-end.

· Operational delivery: continued strong FPSO uptime (Jubilee c.95% and TEN c.99%), gas export (averaging c.90 mmscfd) and water injection (Jubilee c.170 kbwpd and TEN c.65 kbwpd).

· Reserves of 242 million barrels as of 30 June, valued at c.$4.7 billion after hedging (c.$5.3 billion before hedging) [1] .

· Revenue of $846 million with realised oil price of $87/bbl after hedging; gross profit of $620 million; profit after tax of $264 million; underlying operating cash flow of $165 million.

· First half free cash flow of $(205) million (negative), which includes an arbitration payment of $76 million (outflow), Uganda FID payment of $75 million (inflow) and Ghana pre-emption consideration of $126 million (outflow), but excludes the benefit of over $200 million revenue relating to two Ghana liftings, which took place in early June but for which cash was received shortly after 30 June 2022, on 1 and 5 July respectively.

· Capital investment in the first half of 2022 was c.$156 million plus decommissioning costs of c.$29 million.

· Net debt at 30 June 2022 of c.$2.3 billion; Gearing reduced to 1.9x net debt/EBITDAX; liquidity headroom and free cash of $0.6 billion.

· Pre-emption of Deep Water Tano component of Kosmos Energy/Occidental Petroleum Ghana transaction successfully completed.

· Announcement of recommended all-share combination of Tullow Oil plc and Capricorn Energy plc.

[1] Note: The NPV10 valuation is calculated in accordance with the terms of the indenture for the issuance of 10.25% Senior Secured Notes due 2026 by Tullow Oil plc ("Tullow") dated 17 May 2021 (the "Indenture"). Tullow has agreed with the Takeover Panel that an independent valuation report prepared in accordance with Rule 29 of the City Code on Takeovers and Mergers (the "Takeover Code") will be included in the scheme document when published by Capricorn Energy plc in connection with its recommended merger with Tullow (the "Merger"). The publication of this independent reserves report in connection with the Merger, or any other independent reserves report required by the Takeover Code, should not be construed as a commitment to publish any such report in the future.

Key financial results

	1H 2022	1H 2021
Sales revenue ($m)	846	727
Gross profit ($m)	620	321
Underlying cash operating cost per barrel ($/bbl)	13.0	12.9
Profit after tax ($m)	264	93
Free cash flow¹ ($m)	(205)	86
Net debt¹ ($m)	2,336	2,290
Gearing¹ (times)	1.9	2.6

¹ Excludes the benefit of over $200 million revenue relating to two Ghana liftings which took place in early June but for which cash was received shortly after 30 June 2022, on 1 and 5 July respectively.

2022 Guidance

· Group working interest production narrowed to 60-64 kboepd.

· Full year capital investment and decommissioning spend of c.$380 million and c.$100 million, respectively. Increase of $30 million associated with additional equity following pre-emption in Ghana.

· Full year underlying operating cashflow expected to be c.$950 million, assuming an average oil price of $95/bbl. Post all costs, Tullow forecasts full year free cash flow of c.$200 million and gearing of <1.5x (net debt/EBITDAX) by year-end.

· Free cash flow guidance includes the c.$75 million contingent consideration in relation to Tullow's sale of its assets in Uganda to TotalEnergies, a payment of c.$76 million in relation to the arbitration award in favour of HiTec Vision regarding the purchase of Spring Energy in 2013 and a c.$126 million payment for the completion of the pre-emption related to the sale of Occidental Petroleum's interests in the Jubilee and TEN fields in Ghana to Kosmos Energy.

MERGER WITH CAPRICORN ENERGY

On 1 June 2022 Tullow announced that it had reached agreement with Capricorn Energy on the terms of an all-share merger to create a leading African energy company with a material and diversified asset base and a portfolio of investment opportunities delivering visible production growth. This recommended merger will enable the new company to develop and implement a new business plan that accelerates the development of new, material opportunities, realise meaningful cost synergies and deliver a combined group with robust cash generation and a resilient balance sheet. The combined group will also have a sustainable capital returns programme and a deep commitment to environmental stewardship, social investment, development of local content and its national workforces.

Tullow expects to host a Capital Markets Day for investors and issue a circular and prospectus in connection with the recommended merger in the fourth quarter, ahead of a shareholder vote, followed by completion of the transaction before the end of the year.

ESG

Net Zero 2030

Tullow is committed to becoming a Net Zero Company by 2030 on its Scope 1 and 2 emissions. This will be achieved through a number of decarbonising activities to eliminate flaring on its operated assets in Ghana, working closely with our partners to eliminate flaring on our non-operated assets, and pursuing a nature-based carbon removal programme to off-set hard to abate emissions.

Over the next few years, Tullow has defined plans to reduce its carbon emissions from its operations through an increase in the gas handling capacity on Jubilee and process modifications on TEN. These investments are included in the Group's Business Plan and will put the Group on track to eliminate routine flaring in Ghana by 2025. Project Oil Kenya will align with Tullow's Net Zero 2030 target through limiting carbon emissions and offsetting any hard to abate emissions. Through our Net Zero Task Force, Tullow also continues to track progress on initiatives being delivered, and funded, by non-operating partners.

To offset the residual hard-to-abate carbon emissions, progress continues to be made in identifying nature-based carbon removal projects. A Feasibility Study has been completed, identifying a significant scale opportunity covering the Western Transitional Zone in Ghana. Tullow is in the process of finalising a Letter of Intent with the Forestry Commission, detailing key activities and information requirements to inform a Final Investment Decision (FID).

Operational UPDATE

Production

Group working interest production averaged 60.9 kboepd in the first half of 2022, in line with expectations. Full year production guidance for 2022 has been narrowed from 59-65 kboepd to 60-64 kboepd.

Group average working interest production	1H 2022 actual (kboepd)	FY 2022 guidance (kboepd)
Ghana	43.3	45
Jubilee	30.8	32
TEN	12.5	13
Non-operated portfolio	17.6	17
Total production	60.9	60-64

Ghana

The ongoing drilling programme that started in April 2021 has delivered eight new wells, six at Jubilee and two at TEN, at an average cost of c.$50 million per well (more than 10% below the average expected cost for these wells) and ahead of schedule. In addition, two existing wells have been completed, one at Jubilee (J12-WI) and one at TEN (En16-WI).

The first of the two strategic riser base wells (Nt10-P) was drilled to define the extent of the Ntomme reservoir and found good quality reservoir sands, but was water bearing. The second well (Nt11-P) is planned to target a different objective later this year and will help define future drilling and infrastructure plans for the TEN Enhancement Project. The rig is currently drilling and completing a producer well on Enyenra (En21-P), before moving across to Nt11-P.

The drill programme is ahead of schedule. If the current pace of drilling continues, the next phase of drilling at Jubilee, which includes wells to be tied into Jubilee South East infrastructure, is expected to be accelerated into the fourth quarter of 2022. At current performance levels, we will be able to deliver the planned programme of wells through next year with one rig. Accordingly, the joint venture partners have agreed to defer a decision regarding a second rig in Ghana.

Gross production from the Jubilee field averaged c.82.4 kbopd (net: c.30.8 kbopd) in the first half of the year, representing an increase of more than 15% compared to the first half of 2021. This is due to good well and operational performance, which included the successful completion of the planned, biennial maintenance shutdown of the Jubilee FPSO in May. Full year net production guidance for Jubilee is 32kbopd. Gross production from the TEN field averaged c.24.3 kbopd (net: c.12.5 kbopd) in the first half of the year, in line with expectations. Full year net production guidance for TEN is 13kbopd, with the expectation of an increase in production rates when the En21-P well comes onstream in the fourth quarter.

On the Jubilee FPSO, a handover of Operations & Maintenance (O&M) from the O&M Contractor to Tullow was successfully completed at the end of June. This transition will allow Tullow to deliver sustained FPSO safety and reliability performance for the long term, as well as help deliver planned reductions in the operating cost base and emissions.

N on-operated portfolio

Net production from the non-operated portfolio averaged c.17.6 kboepd in the first half of 2022, in line with expectations. Full year net production guidance for the non-operated portfolio is c.17 kboepd.

Production from Gabon averaged c.15.5 kbopd in the first half of 2022, with Simba being the highest contributor. A long-term appraisal well test at the Tchatamba field is underway and expected to see first oil in September 2022. Infill drilling campaigns continue at the Ezanga Complex and Oba field.

Production from C ô te d'Ivoire averaged c.2.1 kboepd in the first half of 2022. A 45 day shutdown of the Espoir FPSO is now planned from October 2022, in which cargo tank maintenance and remediation work, which is required for vessel class certification, will be carried out. Tullow continues to engage with the operator, CNR International, to define the appropriate longer-term course of action for the FPSO.

Decommissioning

The Group's operated and non-operated decommissioning programmes in the UK and Mauritania are ongoing. The majority of operational work is expected to be completed by the end of 2025, with environmental and monitoring surveys to continue from 2026. The expected remaining UK and Mauritania decommissioning exposure over 2022-26 is c.$145 million, with c.$100 million forecasted in 2022. The final exposure may vary depending on the final required scope and work programmes agreed across the various projects.

Tullow expects to pay c.$30 million per annum for the decommissioning of producing assets in Ghana and parts of the non-operated producing portfolio.

Kenya

A process to secure a strategic partner for the development project in Kenya is ongoing and Tullow is confident that substantial progress will be made before the end of the year. Following the recent elections, Tullow and its joint venture partners will work with the new government to progress the project which has the potential to make a significant contribution to the Kenyan economy through taxation, revenue sharing, employment and local content.

Exploration

All of the Group's exploration activity is guided by an overlay of rigorous cost discipline. In Tullow's core area of West Africa, the exploration team is focused on maturing near-field and infrastructure-led exploration (ILX) opportunities around existing producing fields, to unlock additional value from the Group's asset base.

In Côte d'Ivoire, Tullow, together with its JV Partner PetroCi, has elected to proceed into the second exploration phase in Block CI-524. This block presents a unique opportunity to realise operational synergies during the exploration phase and in the event of discoveries due to Tullow's deep understanding of the area and its proximity to the Group's producing fields.

In Gabon, focus is on strengthening the prospective resource base within the Simba licence where several low-risk and compelling investment options adjacent to infrastructure have been identified and will be considered for future drilling programmes.

Tullow also continues to focus on unlocking value from its prospective resource base in the emerging basins of Guyana and Argentina, while seeking to mitigate capital exposure from historical work commitments in Argentina of c.$25 million through farm-down. In Argentina a two year extension has been granted in Block MLO-122.

Operational activity in the first half of 2022 included the drilling of the Beebei-Potaro exploration well in the Repsol operated Kanuku Block offshore Guyana. This commitment well encountered good quality reservoir in the primary and secondary targets, but both targets were water bearing and the well has been plugged and abandoned. Tullow is integrating the well results into its regional subsurface models and is working with its joint venture partners before deciding on next steps.

During the first half of 2022, the Group has written off exploration costs of $87 million (1H 2021: $49 million) which are predominantly driven by write-offs resulting from the Beebei Potaro well.

FINANCE REVIEW

Financial summary	1H 2022	1H 2021
Working interest production volume (boepd)	60,856	61,230
Sales volume (boepd)	53,500	65,800
Realised oil price ($/bbl)	86.5	60.8
Total revenue ($m)	846	727
Gross profit ($m)	620	321
Underlying cash operating costs per boe ($/boe)¹	13.0	12.9
Exploration costs written off ($m)	87	49
Impairment of property, plant and equipment, net ($m)	7	8
Operating profit ($m)	696	370
Profit before tax ($m)	548	213
Profit after tax ($m)	264	93
Basic earnings per share (cents)	18.4	6.5
Capital investment ($m)¹	156	101
Last 12 months adjusted EBITDAX ($m)¹	1,263	885
Net debt ($m)¹	2,336	2,290
Gearing (times)¹	1.9	2.6
Free cash flow ($m)¹	(205)	86
Underlying operating cash flow ($m)¹	165	218
Pre- Financing free cash flow ($m)¹	(75)	227

¹ Underlying cash operating costs per boe, capital investment, adjusted EBITDAX, net debt, gearing, free cash flow, underlying operating cash flow and pre-financing free cash flow are alternative performance measures (APM) and are explained and reconciled on pages 39 to 42.

Production and commodity prices

Total Group working interest production averaged 60,856 boepd (1H 2021: 61,230 boepd). The marginal decrease in production primarily resulted from the 15 day maintenance shutdown of the Jubilee facility, the natural decline in TEN and the sale of Equatorial Guinea and the Dussafu asset in Gabon in 1H21, offset by increased Jubilee production outside the maintenance shutdown period.

The realised oil price after hedging for the period was $86.5/bbl (1H 2021: $60.8/bbl) and before hedging $106.9/bbl (1H 2021: $65.2/bbl). The higher realised oil prices have been sustained during 2H21 and 1H22 offset by hedge losses, decreasing total revenue by $189.6 million (1H 2021: decrease of $52.4 million).

	1H 2022	1H 2021
Income Statement
Revenue ($m)	846	727
Underlift/(Overlift) and oil stock movements ($m)	120	(90)
Balance Sheet
Underlift ($m)	76	4
Overlift ($m)	(94)	(78)

The underlift in the income statement was mainly due to the increase in oil prices and stock positions in Gabon and Ghana as well as the delay in lifting due the Cap Lopez terminal spillage in Gabon.

Higher oil prices combined with oil entitlements have led to a 93% increase in gross profit for the period.

Operating costs, depreciation and expenses

Underlying cash operating costs amounted to $143 million; $13.0/boe (1H 2021: $143 million; $12.9/boe). The cash unit operating costs has remained unchanged against the comparative period. However this is due to disposal of Equatorial Guinea and Dussafu asset in Gabon in 1H21 offset by the shutdown in Jubilee in Ghana and the Simba expansion project costs in Gabon.

Normalised cash operating costs which exclude COVID-19 operating procedures, shuttle tanker operations, CSV campaign and shutdown costs were $11.6/boe (1H 2021: $12.5/boe). Refer to page 41 for the reconciliation as an APM.

Higher equities in Jubilee and TEN following the pre-emption in 1H22 also contributed to the increase in total operating costs.

DD&A charges before impairment on production and development assets amounted to $177 million; $16.1 /boe (1H 2021: $170 million:$15.3/boe). This increase in DD&A per barrel is mainly attributable to Ghana pre-emption which was effective 1Q22, offset by 2021 impairments.

Administrative expenses of $23 million (1H 2021: $23 million) has remained unchanged against the comparative period mainly due to an increase in professional fees offset by a favourable GBP:USD FX variance in 2022 and a decrease to the administrative assets' depreciation. Tullow delivered $238 million in net cash costs savings since mid-2020 to date.

Impairment of property, plant and equipment (PP&E)	1H 2022	1H 2021
Pre-tax impairment of PP&E, net ($m)	7	8
Associated deferred tax credit ($m)	(1)	(4)
Post-tax impairment of PP&E, net ($m)	6	4

The Group recognised a net impairment charge on PP&E of $7 million in respect of first half 2022 (1H 2021: $8million) due to changes to estimates on the cost of decommissioning for certain UK and Mauritania assets.

Exploration costs written off	1H 2022	1H 2021
Exploration cost written off ($m)	87	49

During the first half of 2022, the Group has written off exploration costs of $87 million (1H 2021: $49 million) which are predominantly driven by write-offs the Beebei Potaro commitment well in Guyana which has been plugged and abandoned following the completion of the well.

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 gain on bargain purchase of $197 million. Refer to note 18. Business combination.

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 30 June 202 2 , Tullow's hedge portfolio provides downside protection for 66 % of forecast production entitlements (after pre-emption) through to May 2023 and 41 % for a further 12 months to May 2024 with $51/bbl floors and weighted average sold calls of $78/bbl for the remainder of 2022, and $55/bbl floors and weighted average sold calls of c.$ 75 /bbl in 2023 and 2024.

At 30 June 2022, the Group's derivative instruments had a net negative fair value of negative $573 million (30 June 2021: negative $148 million).

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. 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.

All of the Group's derivatives are Level 2 (1H 2021: Level 2). There were no transfers between fair value levels during the year.

2H 2022 hedge position at 30 June 2022	Bopd	Bought put (floor)	Sold call
Collars	32,259	$54.73	$77.30
Zero cost collars	1,203	$55.00	$95.33
Straight puts	9,000	$38.84	-
Total/weighted average	42,462	$51.37	$77.95

Hedge position at 30 June 2022	2022	2023	2024
Hedged Volume (kbopd)	42,462	33,095	11,305
Weighted average bought put (floor) ($/bbl)	$51/bbl	$55/bbl	$55/bbl
Weighted average sold call ($/bbl)	$78/bbl	$75/bbl	$75/bbl

Borrowings

In May, the Group made a mandatory prepayment of $100 million of the Senior Secured Notes due 2026, which reduced total debt to $2.5 billion. As at 30 June 2022 net debt was $2,336 million (30 June 2021: $2,290 million). Management regularly reviews options for optimising the Group's capital structure and may purchase outstanding debt securities or repay debt from time to time in open-market purchases and/or privately negotiated transactions, and upon such terms and at such prices as it may determine.

Net financing costs

Net financing costs for the period were $149 million (1H 2021: $157 million). The decrease in financing costs is mainly due to $19 million fees incurred in 1H 2021 in relation to the refinancing of the RBL facility, a decrease of $5 million in interest on obligations under finance leases due to a decrease in lease liability position, offset by a $14 million increase in interest on borrowings.

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 9.

Taxation

The overall net tax expense of $284 million (1H 2021: $120 million) primarily relates to expenses in respect of Ghana and West Africa non-operated assets net of non-recurring deferred tax credits associated with exploration write-offs, impairments and onerous lease provisions. The tax charge has been calculated by applying the effective tax rate which is expected to apply to each jurisdiction for the year ending 31 December 2022.

The Group's statutory effective tax rate is 51.8% (1H 2021: 56.4%). After adjusting for the non-recurring amounts related to exploration write-offs, impairments, restructuring costs, disposals and onerous lease provisions and their associated tax benefit, the Group's underlying effective tax rate is 62.0% (1H 2021: (83.1%) ). The change in effective tax rate from 1H21 to 1H22 is due primarily to there being no tax benefit from net interest and hedging expenses, representing a smaller proportion of the Group's overall profits in 1H22 than in 1H21. Non-deductible expenditure in Ghana and a change to the mix of taxable and non-taxable profits in Gabon are additional contributing factors.

Analysis of effective tax rate ($'m)	Profit/(loss) before tax	Tax (expense)/credit	Effective tax rate
Ghana - 1H 2022	543.8	(192.8)	35.5%
1H 2021	200.3	(72.6)	36.2%
Gabon - 1H 2022	190.6	(84.3)	44.2%
1H 2021	79.1	(38.1)	48.2%
Equatorial Guinea - 1H 2022	-	-	-
1H 2021	15.5	(5.4)	35.0%
Corporate - 1H 2022	(299.7)	0.2	0.1%
1H 2021	(157.9)	(0.6)	-0.4%
Other non-operated & exploration - 1H 2022	13.7	(1.1)	7.7%
1H 2021	4.6	(0.9)	20.4%
Total - 1H 2022	448.5	(278.0)	62.0%
1H 2021	141.7	(117.7)	83.1%

Profit after tax from continuing activities and earnings per share

The profit after tax for the period amounted to $264 million (1H 2021: $93 million). Basic earnings per share was 18.4 cents (1H 2021: basic earnings per share of 6.5 cents).

Reconciliation of net debt	$m
Year-end 2021 net debt	2,130.9
Sales revenue	(845.7)
Operating costs	142.7
Other operating and administrative expenses	24.3
Operating cash flow before working capital movements	(678.7)
Movement in working capital	326.4
Tax paid	143.7
Purchases of intangible exploration and evaluation assets and property, plant and equipment	134.8
Purchase of additional interest in joint operation	126.8
Other investing activities	(69.7)
Other financing activities	218.1
Foreign exchange loss on cash	3.6
1H 2022 net debt	2,336.0

Capital investment

Capital expenditure amounted to $156 million (1H 2021: $101 million) with $135 million invested in production and development activities and $21 million invested in exploration and appraisal activities.

Capital investment will continue to be carefully controlled in the second half of 2022 and total 2022 capital expenditure is expected to be c.$380 million. The capital investment total is expected to comprise Ghana capex of c.$300 million, including an increase of $30 million associated with additional equity following pre-emption in Ghana, West African non-operated capex of c.$30 million, Kenya capex of c.$5 million and exploration spend of c.$45 million.

Going concern

The Directors consider the going concern assessment period to be up to 30 September 2023. The Group closely monitors and manages its liquidity headroom. Cash forecasts are regularly produced, and sensitivities run for different scenarios including, but not limited to, changes in commodity prices, different production rates from the Group's producing assets and different outcomes on ongoing disputes or litigation. For the assessment, management has excluded the liquidity enhancing impact of the recommended merger with Capricorn Energy PLC within its base case as it provides a more conservative assessment.

Management has applied the following oil price assumptions for the going concern assessment:

Base Case: $100/bbl for 2022, $90/bbl for 2023; and

Low Case: $80/bbl for 2022, $70/bbl for 2023.

The Low Case includes, amongst other downside assumptions, a 5 per cent production decrease compared to the Base Case as well as increased outflows associated with an ongoing dispute.

The Group had $0.6 billion liquidity headroom of unutilised debt capacity and free cash as at 30 June 2022. 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 half year results.

2022 principal risks and uncertainties

The Company risk profile has been closely monitored throughout the year, with consideration given to the risks to delivering the revised Business Plan, as well as whether external factors such as geo-political factors, global pandemics and oil price volatility have resulted in any new risks or changes to existing risks. The impact of these factors has been considered and managed across all principal risks. The principal risks and uncertainties facing the Group at half year remain unchanged from those disclosed in the 2021 Annual Report as listed below.

1. Risk of failure to deliver production targets

2. Risk of a major EHS incident

3. Risk of failure to unlock value

4. Risk of failure to manage geopolitical risks

5. Risk of failure to manage climate change risks

6. Risk of insufficient liquidity and funding capacity

7. Risk of failure to develop, retain and attract capability

8. Risk of compliance or regulatory breach

9. Risk of major cyber attack

Events since 30 June 2022

Tullow Ghana Limited has awarded a 5-year contract to Petrofac Ghana (Petrofac) to support Operations and Maintenance activities on the FPSO Kwame Nkrumah (KNK) following the expiry of Tullow's contract with MODEC Production Services Ghana JV Ltd (MODEC) which ended on 30 June 2022. Tullow and MODEC worked on a smooth transition of O&M services and achieved a seamless transition on 1 July 2022.

On 5 August 2022, it was announced that the Beebei Potaro well, offshore Guyana has been plugged and abandoned after encountering good quality reservoir in the primary and secondary targets, but both targets were water bearing.

Responsibility statement (DTR 4.2 and the Transparency (Directive 2004/109/EC) Regulations (as amended))

The Directors confirm that to the best of their knowledge:

a. the condensed set of financial statements has been prepared in accordance with IAS 34 'Interim Financial Reporting' as adopted by the UK and EU and IAS 34 'Interim Financial Reporting' as adopted by the EU, the Disclosure Guidance and Transparency Rules of the United Kingdom's Financial Conduct Authority (DTR) and the Transparency (Directive 2004/109/EC) Regulations 2007 as amended

b. the interim management report includes a fair review of the information required by DTR 4.2.7R and Regulation 8(2) (indication of important events during the first six months and description of principal risks and uncertainties for the remaining six months of the year); and

c. the interim management report includes a true and fair review of the information required by DTR 4.2.8R and Regulation 8(3) (disclosure of related parties' transactions and changes therein).

A list of the current Directors is maintained on the Tullow Oil plc website: www.tullowoil.com.

By order of the Board,

Rahul Dhir

Chief Executive Officer

13 September 2022

Richard Miller

Interim Chief Financial Officer

13 September 2022

Disclaimer

This statement contains certain forward-looking statements that are subject to the usual risk factors and uncertainties associated with the oil and gas exploration and production business. Whilst the Group believes the expectations reflected herein to be reasonable in light of the information available to them at this time, the actual outcome may be materially different owing to factors beyond the Group's control or within the Group's control where, for example, the Group decides on a change of plan or strategy. Accordingly, no reliance may be placed on the figures contained in such forward-looking statements.

Independent review report to Tullow Oil plc

Conclusion

We have been engaged by the Company to review the condensed set of financial statements in the half-yearly financial report for the six months ended 30 June 2022 which comprises Condensed consolidated income statement, Condensed consolidated statement of comprehensive income and expense, Condensed consolidated balance sheet, Condensed statement of changes in equity, Condensed consolidated cash flow statement and the related notes 1 to 25. We have read the other information contained in the half yearly financial report and considered whether it contains any apparent misstatements or material inconsistencies with the information in the condensed set of financial statements.

Based on our review, nothing has come to our attention that causes us to believe that the condensed set of financial statements in the half-yearly financial report for the six months ended 30 June 2022 is not prepared, in all material respects, in accordance with UK and EU adopted International Accounting Standard 34 and the Disclosure Guidance and Transparency Rules of the United Kingdom's Financial Conduct Authority.

Basis for Conclusion

We conducted our review in accordance with International Standard on Review Engagements 2410 (UK) "Review of Interim Financial Information Performed by the Independent Auditor of the Entity" (ISRE) issued by the Financial Reporting Council. A review of interim financial information consists of making enquiries, primarily of persons responsible for financial and accounting matters, and applying analytical and other review procedures. A review is substantially less in scope than an audit conducted in accordance with International Standards on Auditing (UK) and consequently does not enable us to obtain assurance that we would become aware of all significant matters that might be identified in an audit. Accordingly, we do not express an audit opinion.

As disclosed in note 2, the annual financial statements of the group are prepared in accordance with UK adopted international accounting standards and International Financial Reporting Standards adopted pursuant to Regulation (EC) No. 1606/2002 as it applies in the European Union. The condensed set of financial statements included in this half-yearly financial report has been prepared in accordance with UK adopted International Accounting Standard 34, "Interim Financial Reporting".

Conclusions Relating to Going Concern

Based on our review procedures, which are less extensive than those performed in an audit as described in the Basis of Conclusion section of this report, nothing has come to our attention to suggest that management have inappropriately adopted the going concern basis of accounting or that management have identified material uncertainties relating to going concern that are not appropriately disclosed.

This conclusion is based on the review procedures performed in accordance with this ISRE, however future events or conditions may cause the entity to cease to continue as a going concern.

Responsibilities of the directors

The directors are responsible for preparing the half-yearly financial report in accordance with the Disclosure Guidance and Transparency Rules of the United Kingdom's Financial Conduct Authority.

In preparing the half-yearly financial report, the directors are responsible for assessing the company's ability to continue as a going concern, disclosing, as applicable, matters related to going concern and using the going concern basis of accounting unless the directors either intend to liquidate the company or to cease operations, or have no realistic alternative but to do so.

Auditor's Responsibilities for the review of the financial information

In reviewing the half-yearly report, we are responsible for expressing to the Company a conclusion on the condensed set of financial statements in the half-yearly financial report. Our conclusion, including our Conclusions Relating to Going Concern, are based on procedures that are less extensive than audit procedures, as described in the Basis for Conclusion paragraph of this report.

Use of our report

This report is made solely to the company in accordance with guidance contained in International Standard on Review Engagements 2410 (UK) "Review of Interim Financial Information Performed by the Independent Auditor of the Entity" issued by the Financial Reporting Council. To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the company, for our work, for this report, or for the conclusions we have formed.

Ernst & Young LLP

London

13 September 2022

Condensed consolidated income statement

Six months ended 30 June 2022

	Notes	Six months ended 30.06.22 Unaudited $m	Six months ended 30.06.21 Unaudited $m	Year ended 31.12.21 Audited $m
Continuing activities
Revenue	6, 7	845.7	726.8	1,273.2
Cost of sales	8	(225.4)	(405.7)	(638.9)
Gross profit		620.3	321.1	634.3
Administrative expenses	8	(23.2)	(23.1)	(64.1)
Restructuring costs and other provisions	8	(4.6)	5.9	(61.8)
Gain on bargain purchase	18	196.8	-	-
Gain on disposals	11	-	122.9	120.3
Exploration costs written off	12	(86.6)	(49.3)	(59.9)
Impairment of property, plant and equipment, net	13	(6.5)	(8.0)	(54.3)
Operating profit		696.2	369.5	514.5
Gain on hedging instruments		-	0.2	-
Finance income	9	21.1	22.1	44.3
Finance costs	9	(169.7)	(178.7)	(356.1)
Profit from continuing activities before tax		547.6	213.1	202.7
Income tax expense	10	(283.7)	(120.4)	(283.4)
Profit/ (loss) for the year from continuing activities		263.9	92.7	(80.7)
Attributable to
Owners of the Company		263.9	92.7	(80.7)
Earnings/ (loss) per ordinary share from continuing activities		¢	¢	¢
Basic	3	18.4	6.5	(5.7)
Diluted	3	17.8	6.2	(5.7)

Condensed consolidated statement of comprehensive income and expense

Six months ended 30 June 2022

	Six months ended 30.06.22 Unaudited $m	Six months ended 30.06.21 Unaudited $m	Year ended 31.12.21 Audited $m
Profit/ (loss) for the period	263.9	92.7	(80.7)
Items that may be reclassified to the income statement in subsequent periods
Cash flow hedges
Loss arising in the period	(577.2)	(101.2)	(159.3)
Gains/ (losses) arising in the period - time value	4.0	(108.2)	(182.1)
Reclassification adjustments for items included in loss on realisation	174.4	30.8	112.3
Reclassification adjustments for items included in loss on realisation - time value	12.0	21.6	40.7
Exchange differences on translation of foreign operations	8.6	(2.0)	(1.4)
Other comprehensive expense	(378.2)	(159.0)	(189.8)
Tax relating to components of other comprehensive expense	-	2.8	2.7
Net other comprehensive expense for the period	(378.2)	(156.2)	(187.1)
Total comprehensive expense for the period	(114.3)	(63.5)	(267.8)
Attributable to
Owners of the Company	(114.3)	(63.5)	(267.8)

Condensed consolidated balance sheet

As at 30 June 2022

	Notes	Six months ended 30.06.22 Unaudited $m	Six months ended 30.06.21 Restated¹ Unaudited $m	Year ended 31.12.21 Audited $m
Assets
Non-current asset
Intangible exploration and evaluation assets	12	288.6	346.3	354.6
Property, plant and equipment	13	3,413.3	3,144.1	2,914.6
Other non-current assets	15	317.3	514.9	489.1
Derivative financial instruments		-	6.6	-
Deferred tax assets		343.5	490.4	354.4
		4,362.7	4,502.3	4,112.7
Current assets
Inventories	16	333.3	141.3	134.8
Trade receivables	14	290.2	256.4	99.8
Other current assets	15	726.6	1,044.0	704.5
Current tax assets		29.9	41.4	19.7
Cash and cash equivalents	17	164.1	301.8	469.1
		1,544.1	1,784.9	1,427.9
Total assets		5,906.8	6,287.2	5,540.6
Liabilities
Current liabilities
Trade and other payables	19	(828.8)	(818.7)	(751.1)
Borrowings	20	(100.0)	(297.8)	(100.0)
Provisions	21	(205.2)	(255.3)	(296.5)
Current tax liabilities		(189.5)	(95.1)	(115.1)
Derivative financial instruments		(378.5)	(104.5)	(80.9)
		(1,702.0)	(1,571.4)	(1,343.6)
Non-current liabilities
Trade and other payables	19	(882.3)	(1,082.2)	(987.1)
Borrowings	20	(2,370.7)	(2,565.5)	(2,468.7)
Provisions	21	(443.7)	(575.5)	(431.0)
Deferred tax liabilities		(889.9)	(709.4)	(677.3)
Derivative financial instruments		(194.2)	(50.2)	(99.0)
		(4,780.8)	(4,982.8)	(4,663.1)
Total liabilities		(6,482.8)	(6,554.2)	(6,006.7)
Net liabilities		(576.0)	(267.0)	(466.1)
Equity
Called-up share capital		214.9	213.8	214.2
Share premium		1,294.7	1,294.7	1,294.7
Equity component of convertible bonds		-	48.4	-
Foreign currency translation reserve		(240.2)	(249.4)	(248.8)
Hedge reserve		(442.1)	(62.6)	(39.3)
Hedge reserve - time value		(130.9)	(92.1)	(146.9)
Merger reserve		755.2	755.2	755.2
Retained earnings		(2,027.6)	(2,175.0)	(2,295.2)
Equity attributable to equity holders of the Company		(576.0)	(267.0)	(466.1)
Total equity		(576.0)	(267.0)	(466.1)

¹ Refer to note 19 for details on prior period restatement.

Condensed statement of changes in equity

As at 30 June 2022

	Share capital $m	Share premium $m	Equity component of convertible bonds $m	Foreign currency translation reserve¹ $m	Hedge reserve² $m	Hedge reserve - Time value $m	Merger reserve $m	Retained earnings $m	Total equity $m
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 period	-	-	-	-	-	-	-	92.7	92.7
Hedges, net of tax	-	-	-	-	(67.4)	(86.7)	-	-	(154.1)
Currency translation adjustments	-	-	-	(2.0)	-	-	-	-	(2.0)
Exercise of employee share options	2.1	-	-	-	-	-	-	(2.1)	-
Share-based payment charges	-	-	-	-	-	-	-	6.4	6.4
At 30 June 2021	213.8	1,294.7	48.4	(249.4)	(62.6)	(92.1)	755.2	(2,175.0)	(267.0)
Loss for the period	-	-	-	-	-	-	-	(173.4)	(173.4)
Hedges, net of tax	-	-	-	-	23.3	(54.8)	-	-	(31.5)
Derecognition of the convertible bond³	-	-	(48.4)	-	-	-	-	48.4	-
Currency translation adjustments	-	-	-	0.6	-	-	-	-	0.6
Exercise of employee share options	0.4	-	-	-	-	-	-	(0.4)	-
Share-based payment charges	-	-	-	-	-	-	-	5.2	5.2
At 1 January 2022	214.2	1,294.7	-	(248.8)	(39.3)	(146.9)	755.2	(2,295.2)	(466.1)
Profit for the period	-	-	-	-	-	-	-	263.9	263.9
Hedges, net of tax	-	-	-	-	(402.8)	16.0	-	-	(386.8)
Currency translation adjustments	-	-	-	8.6	-	-	-	-	8.6
Exercise of employee share options	0.7	-	-	-	-	-	-	(0.7)	-
Share-based payment charges	-	-	-	-	-	-	-	4.4	4.4
At 30 June 2022	214.9	1,294.7	-	(240.2)	(442.1)	(130.9)	755.2	(2,027.6)	(576.0)

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, and exchange gains or losses arising on long-term foreign currency borrowings which are a hedge against the Group's overseas investments.

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 (note 20). As the conversion option was not exercised, the equity component of $48.4 million has been transferred from the separate reserve to retained earnings.

Condensed consolidated cash flow statement

Six months ended 30 June 2022

	Notes	Six months ended 30.06.22 Unaudited $m	Six months ended 30.06.21 Unaudited $m	Year ended 31.12.21 Audited $m
Cash flows from operating activities
Profit from continuing activities before tax		547.6	213.1	202.7
Adjustments for
Depreciation, depletion and amortisation		183.5	178.7	378.9
Gain on bargain purchase	18	(196.8)	-	-
Gain on disposals	11	-	(122.9)	(120.3)
Exploration costs written off	12	86.6	49.3	59.9
Impairment of property, plant and equipment, net	13	6.5	8.0	54.3
Restructuring costs and other provisions	21	4.6	(5.9)	61.8
Payments under restructuring costs and other provisions	21	(77.5)	(8.9)	(12.6)
Decommissioning expenditure		(28.8)	(27.7)	(52.8)
Share-based payment charge		4.4	6.4	11.6
Gain on hedging instruments		-	(0.2)	-
Finance income	9	(21.1)	(22.1)	(44.3)
Finance costs	9	169.7	178.7	356.1
Operating cash flow before working capital movements		678.7	446.5	895.3
Increase in trade and other receivables		(118.0)	(143.2)	(17.9)
Increase in inventories		(198.6)	(50.2)	(41.9)
Increase in trade payables		(9.8)	42.3	7.5
Cash flows from operating activities		352.3	295.4	843.0
Income taxes paid		(143.7)	(37.3)	(56.1)
Net cash from operating activities		208.6	258.1	786.9
Cash flows from investing activities
Proceeds from disposals	11	68.6	132.4	132.8
Purchase of additional interest in joint operation	18	(126.8)	-	-
Purchase of intangible exploration and evaluation assets		(17.5)	(55.8)	(86.1)
Purchase of property, plant and equipment		(117.3)	(41.4)	(150.4)
Interest received		1.1	1.7	2.0
Net cash (used in)/ from in investing activities		(191.9)	36.9	(101.7)
Cash flows from financing activities
Debt arrangement fees		-	(57.8)	(56.6)
Repayment of borrowings	25	(100.0)	(2,080.0)	(2,379.9)
Payment into trust for repayment of convertible bond¹		-	(309.8)	-
Drawdown of borrowings	25	-	1,800.0	1,800.0
Repayment of obligations under leases		(91.9)	(68.3)	(155.9)
Finance costs paid		(126.2)	(86.9)	(234.9)
Net cash used in financing activities		(318.1)	(802.8)	(1,027.3)
Net decrease in cash and cash equivalents		(301.4)	(507.8)	(342.1)
Cash and cash equivalents at beginning of period		469.1	805.4	805.4
Foreign exchange (loss)/ gain		(3.6)	4.2	5.8
Cash and cash equivalents at end of period	17	164.1	301.8	469.1

¹ On 17 May 2021, as part of the refinancing transaction $309.8 million was agreed to be put into a trustee account for settlement of principal and accrued interest of the convertible loan notes on due date. On 12 July 2021 the convertible loan notes were settled by the trustees by utilising the amount kept in the trust account. This this has been disclosed as a financing activity within the cash flow statement.

Notes to the condensed financial statements

Six months ended 30 June 2022

1. General information

The condensed financial statements for the six-month period ended 30 June 2022 have been prepared in accordance with International Accounting Standard (IAS) 34 Interim Financial Reporting as adopted by UK and EU and the requirements of the Disclosure and Transparency Rules (DTR) of the Financial Conduct Authority (FCA) in the United Kingdom as applicable to interim financial reporting.

The Condensed financial statements represent a 'condensed set of financial statements' as referred to in the DTR issued by the FCA. Accordingly, they do not include all the information required for a full annual financial report and are to be read in conjunction with the Group's financial statements for the year ended 31 December 2021, which were prepared in accordance with UK-adopted international accounting standards (IFRSs) and International Financial Reporting Standards (IFRSs) adopted pursuant to Regulation (EC) No 1606/2002 as it applies in the European Union (EU). The Condensed financial statements are unaudited and do not constitute statutory accounts as defined in section 434 of the Companies Act 2006. The financial information for the year ended 31 December 2021 does not constitute statutory accounts as defined in section 434 of the Companies Act 2006. This information was derived from the statutory accounts for the year ended 31 December 2021, a copy of which has been delivered to the Registrar of Companies. The auditor's report on these accounts was unqualified, did not include a reference to any matters to which the auditor drew attention by way of an emphasis of matter and did not contain a statement under sections 498 (2) or (3) of the Companies Act 2006.

2. Accounting policies

The annual financial statements of Tullow Oil plc will be prepared in accordance with United Kingdom 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 condensed set of financial statements included in this half-yearly financial report has been prepared in accordance with International Accounting Standard (IAS) 34 Interim Financial Reporting as adopted by UK and EU , the Disclosure and Transparency Rules of the Financial Conduct Authority and the Transparency (Directive 2004/109/EC) Regulations 2007 as amended.

The accounting policies adopted in the 2022 half-yearly financial report are the same as those adopted in the Group's Annual Report and Accounts as at 31 December 2021, except business combinations which is disclosed in Note 18. There was no business combination in the previous year.

Going Concern

Management has applied the following oil price assumptions for the going concern assessment:

Base Case: $100/bbl for 2022, $90/bbl for 2023; and

Low Case: $80/bbl for 2022, $70/bbl for 2023.

The Low Case includes, amongst other downside assumptions, a 5 per cent production decrease compared to the Base Case as well as increased outflows associated with an ongoing dispute.

3. Earnings per ordinary share

The calculation of basic earnings per share is based on the profit for the period after taxation attributable to equity holders of the parent of $263.9 million (1H 2021: profit of $92.7 million) and a weighted average number of shares in issue of 1,435.3 million (1H 2021: 1,421.3 million).

The calculation of diluted earnings per share is based on the profit for the period after taxation as for basic earnings per share. The number of shares outstanding, however, is adjusted to show the potential dilution if employee share options are converted into ordinary shares. The weighted average number of ordinary shares is increased by 45.7 million resulting in a diluted weighted average number of shares of 1,481.0 million.

4. Dividends

The Directors intend to recommend that no 2022 interim dividend be paid.

5. Approval of accounts

These unaudited half year results were approved by the Board of Directors on 13 September 2022.

6. 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, profit and certain asset and liability information regarding the Group's reportable business segments for the period ended 30 June 2022, 30 June 2021 and 31 December 2021.

	Ghana $m	Non-Operated $m	Kenya $m	Exploration $m	Corporate $m	Total $m
Six months ended 30 June 2022
Sales revenue by origin¹	781.0	254.4	-	-	(189.7)	845.7
Segment result²	609.1	202.8	-	(86.9)	(197.8)	527.2
Other provisions³						(4.1)
Gain on bargain purchase						196.8
Unallocated corporate expenses⁴						(23.7)
Operating profit						692.6
Finance income						21.1
Finance costs						(169.7)
Profit before tax						547.6
Income tax expense						(283.7)
Profit after tax						263.9
Total assets	4,923.2	521.9	270.8	44.8	146.1	5,906.8
Total liabilities⁵	(2,742.0)	(494.4)	(16.9)	(11.6)	(3,217.9)	(6,482.8)
Other segment information
Capital expenditure:
Property, plant and equipment	135.5	20.5	-	-	0.5	156.5
Intangible exploration and evaluation assets	0.3	(1.5)	2.6	19.2	-	20.6
Depletion, depreciation and amortisation	(158.7)	(18.6)	(0.7)	-	(5.5)	(183.5)
Impairment of property, plant and equipment, net	-	(6.5)	-	-	-	(6.5)
Exploration costs written off	(0.3)	1.5	-	(87.8)	-	(86.6)

¹ The basis of allocation of the loss on realisation of the cash flow hedges presented in the "Sales revenue by origin" line was incorrectly classified within Ghana and Non-Operated segment in the prior period. This has now been allocated to the Corporate reportable segment. For the comparative periods, 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. For the six months ended 30 June 2021, revenue for Ghana and Non-Operated increased by $33.8 million, and $18.6 million, respectively, with the hedging loss of $52.4 million allocated to Corporate.

² 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.

³ This is included within the Restructuring costs and other provisions in the Group Income Statement.

⁴ Unallocated expenditure and net liabilities include amounts of a corporate nature and not specifically attributable to a geographic area.

⁵ Total liabilities - Corporate comprise of the Group's external debt, derivative financial instruments and other non-attributable liabilities.

6. Segmental reporting continued

Reconciliation of segment result

	Six months ended 30.06.22 Unaudited $m	Six months ended 30.06.21 Unaudited $m	Year ended 31.12.21 Audited $m
Segment result	527.2	263.8	520.1
Add back
Exploration costs written off	86.6	49.3	59.9
Impairment of Property, Plant and Equipment	6.5	8.0	54.3
Gross profit	620.3	321.1	634.3

		Ghana $m	Non-Operated $m	Kenya $m	Exploration $m	Corporate $m	Total $m
Six months ended 30 June 2021
Sales revenue by origin - restated¹	501.6		277.6	-	-	(52.4)	726.8
Segment result - restated¹	270.9		113.4	0.8	(63.3)	(58.0)	263.8
Gain on disposal							122.9
Unallocated corporate expenses²							(17.2)
Operating profit							369.5
Gain on hedging instruments							0.2
Finance income							22.1
Finance costs							(178.7)
Profit before tax							213.1
Income tax expense							(120.4)
Profit after tax							92.7
Total assets - restated²	4,813.9		546.5	283.4	125.9	517.5	6,287.2
Total liabilities - restated²	(2,817.1)		(495.8)	(19.9)	(20.5)	(3,200.9)	(6,554.2)
Other segment information
Capital expenditure:
Property, plant and equipment	95.7		9.7	-	0.3	0.7	106.4
Intangible exploration and evaluation assets³	0.8		(13.9)	4.4	36.1	-	27.4
Depletion, depreciation and amortisation	(155.7)		(15.3)	(0.7)	-	(7.0)	(178.7)
Impairment of property, plant and equipment, net	-		(8.0)	-	-	-	(8.0)
Exploration costs written off	(0.9)		14.1	0.8	(63.3)	-	(49.3)

¹ 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 six months ended 30 June 2021, revenue for Ghana and Non-Operated increased by $33.8 million, and $18.6 million, respectively, with the hedging loss of $52.4 million allocated to Corporate.

² 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 :

	Ghana $m	Non-Operated $m		Kenya $m	Exploration $m	Corporate $m	Total $m
Total assets - increase/ (decrease)	(113.1)		7.1	(6.0)	(22.0)	134.0	-
Total liabilities - (increase)/ decrease	45.3		(12.8)	6.0	24.0	(62.5)	-

³ Non-operated segment includes release of $15.3 million indirect tax provision following settlement.

6. Segmental reporting continued

	Ghana $m	Non-Operated $m		Kenya $m	Exploration $m	Corporate $m	Total $m
Year ended 31 December 2021
Sales revenue by origin - restated¹	1,020.4		405.7	-	-	(152.9)	1,273.2
Segment result - restated¹	469.8		286.5	-	(70.5)	(165.7)	520.1
Other provisions	6.6		-	(13.2)	-	(52.1)	(58.7)
Gain on disposal							120.3
Unallocated corporate expenses							(67.2)
Operating profit							514.5
Finance income							44.3
Finance costs							(356.1)
Profit before tax							202.7
Income tax expense							(283.4)
Loss after tax							(80.7)
Total assets - restated²	4,283.8		501.2	264.6	122.3	368.8	5,540.6
Total liabilities - restated²	(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 assets³	1.2		(11.8)	8.2	48.8	-	46.4
Depletion, depreciation and amortization	(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 off¹	(1.2)		11.8	-	(70.5)	-	(59.9)

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.

² 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:

	Ghana $m	Non-Operated $m		Kenya $m	Exploration $m	Corporate $m	Total $m
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	-

³ Non-operated segment includes release of $15.3 million indirect tax provision following settlement.

6. Segmental reporting continued

	Sales revenue six months ended 30.06.22¹ $m	Sales revenue six months ended 30.06.21 Restated¹ $m	Sales revenue Year ended 31.12.21 Restated¹ $m	Non-current assets 30.06.22 ² $m	Non-current assets 30.06.21² $m	Non-current assets 31.12.21² $m
Ghana	781.0	501.6	1,020.4	3,473.9	3,477.5	3,131.3
Total Ghana	781.0	501.6	1,020.4	3,473.9	3,477.5	3,131.3
Kenya	-	-	-	262.5	256.3	261.7
Total Kenya	-	-	-	262.5	256.3	261.7
Argentina	-	-	-	31.8	29.2	30.4
Guyana	-	-	-	-	64.9	69.1
Total Exploration	-	-	-	31.8	94.1	99.5
Gabon	225.7	190.8	305.9	137.0	61.5	148.7
Côte d'Ivoire	28.7	27.7	40.7	86.6	75.4	81.4
Equatorial Guinea	-	59.1	59.1	-	-	-
Total Non- Operated	254.4	277.6	405.7	223.6	136.9	230.1
Corporate	(189.7)	(52.4)	(152.9)	27.4	40.5	35.6
Total	845.7	726.8	1,273.2	4,019.2	4,005.3	3,758.2

¹ Segment revenue allocation between the reportable segments has 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.

For the comparative periods, 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. For the six months ended 30 June 2021, revenue for Ghana and Non-Operated increased by $33.8 million, and $18.6 million, respectively, with the hedging loss of $52.4 million allocated to Corporate.

² Excludes derivative financial instruments and deferred tax assets.

7. Total revenue

	Six months ended 30.06.22 Unaudited $m	Six months ended 30.06.21 Unaudited $m	Year ended 31.12.21 Audited $m
Revenue from contracts with customers
Revenue from crude oil sales	1,035.4	779.2	1,426.2
Total revenue from contracts with customers	1,035.4	779.2	1,426.2
Loss on realisation of cash flow hedges	(189.7)	(52.4)	(153.0)
Total revenue	845.7	726.8	1,273.2

8. Operating profit

	Six months ended 30.06.22 Unaudited $m	Six months ended 30.06.21 Unaudited $m	Year ended 31.12.21 Audited $m
Operating profit is stated after charging/(deducting):
Operating costs	142.7	143.3	268.7
Depletion and amortisation of oil and gas and leased assets¹	176.9	169.5	360.9
Underlift, overlift and oil stock movements²	(119.9)	89.5	(20.0)
Share-based payment charge included in cost of sales	0.2	0.4	0.5
Other cost of sales	25.5	3.0	28.8
Total cost of sales	225.4	405.7	638.9
Administrative expenses
Share-based payment charge included in administrative expenses	4.2	6.0	11.1
Depreciation of other property, plant and equipment¹	6.6	9.2	18.1
Other administrative costs	12.4	7.9	35.0
Total administrative expenses	23.2	23.1	64.1
Total restructuring costs and other provisions	4.6	(5.9)	61.8

¹ Depreciation expense on leased assets of $23.2 million as per note 13 includes a charge of $2.0 million on leased administrative assets, which is presented within administrative expenses in the income statement. The remaining balance of $21.2 million relates to other leased assets and is included within cost of sales.

² Refer to page 6 of Finance Review and Note 19 for detailed explanations.

9. Net financing costs

	Six months ended 30.06.22 Unaudited $m	Six months ended 30.06.21 Unaudited $m	Year ended 31.12.21 Audited $m
Interest on bank overdrafts and borrowings	127.1	113.0	243.0
Interest on obligations for leases	37.8	43.1	83.4
Total borrowing costs	164.9	156.1	326.4
Finance and arrangement fees	0.1	18.7	19.1
Other interest expense	1.5	0.2	3.0
Unwinding of discount on decommissioning provisions	3.2	3.7	7.6
Total finance costs	169.7	178.7	356.1
Interest income on amounts due from Joint Venture partners for leases	(15.7)	(19.8)	(38.8)
Other finance income	(5.4)	(2.3)	(5.5)
Total finance income	(21.1)	(22.1)	(44.3)
Net financing costs	148.6	156.6	311.8

10. Taxation on profit on ordinary activities

The overall net tax expense of $283.7 million (1H 2021: $120.4 million) primarily relates to expenses in respect of Ghana and West Africa non-operated assets net of non-recurring deferred tax credits associated with exploration write-offs, impairments and onerous lease provisions. The tax charge has been calculated by applying the effective tax rate which is expected to apply to each jurisdiction for the year ending 31 December 2022.

The Group's statutory effective tax rate is 51.8% (1H 2021: 56.4%). After adjusting for the non-recurring amounts related to exploration write-offs, impairments, restructuring costs, disposals and onerous lease provisions and their associated tax benefit, the Group's underlying effective tax rate is 62.0% (1H 2021: (83.1%)). The change in effective tax rate from 1H21 to 1H22 is primarily due to there being no UK tax benefit from net interest and hedging expenses, which represents a smaller proportion of the Group's overall profits in 1H22 than in 1H21. Non-deductible expenditure in Ghana and a change to the mix of taxable and non-taxable profits in Gabon are additional contributing factors.

Uncertain tax positions

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 other 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 with significant updates described in more detail below. 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 unprovided liabilities of $991.9 million (YE21: $1,025.5 million) which includes $33.0 million of interest and penalties (YE21: $34.1m).

Provisions of $106.5 million (YE21: $127.9 million) are included in income tax payable ($70.4 million (YE21: $34.1m)), deferred tax liability (nil (YE21: $41.0 million)) and provisions ($36.2 million (YE21: $52.4m)). Where these matters relate to expenditure which is capitalised within E&E and PP&E, 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 unprovided tax liabilities relating to these disputes have decreased following the conclusion of tax authority challenges, but have increased for the extrapolation of exposures, giving rise to an overall decrease in provision of $21.4m and decrease in unprovided tax liabilities of $33.6m.

Ghana tax assessments

In August 2018, Tullow Ghana Limited (TGL) received a direct tax assessment from the Ghana Revenue Authority (GRA) for the financial years 2014 to 2016. After discussions, a final assessment was issued in December 2019 for $407.3 million requesting that $397.7 million be paid by 13 January 2020. The GRA is seeking to apply branch profits remittance tax under a law which the Group considers is not applicable to TGL, since it falls outside the tax regime set out in TGL's Petroleum Agreements and relevant double tax treaties. The GRA has additionally assessed TGL for unpaid withholding taxes and corporate income tax arising from the disallowance of loan interest. The Group considers that these assessments also breach TGL's rights under its petroleum agreements, applicable Ghanaian law and double taxation treaties, and, in some cases, have arisen as the result of the errors in the GRA's calculations. In January 2020, TGL issued a Notice of Dispute with the Ministry of Energy (MoE), disputing the issues and suspending TGL's obligation to pay any taxes until the disputed issues have been resolved. In April 2020, the GRA issued a Demand Notice for $365.0 million ($337.6 million branch profits remittance tax and withholding tax, and $27.4 million corporate income tax) which was put on hold by the MoE. In September 2021 TGL received a revised final tax audit report for $471.2 million ($325.0 million branch profits remittance tax and withholding tax, and $146.1 million corporate income tax).

In October 2021 TGL filed a Request for Arbitration with the International Chamber of Commerce (ICC) disputing the US$320 million branch profits remittance tax assessment and an additional Notice of Dispute objecting against the disallowance of certain expenditure in the revised tax audit report. The Parties have agreed a procedural timetable for the arbitration under which hearing will commence in October 2023. In December 2021, TGL paid US$3 million on account in respect of a revised withholding tax assessment of $3 million. TGL received a revised assessment in March 2022 assessing a tax liability of $102 million together with a Demand Notice requiring full settlement of the assessed tax liability within seven days. TGL disputes the basis for the revised assessment and the payment obligation is suspended in view of the Notices of Dispute previously issued. The March 2022 revised assessment results in assessments totalling US$422 million including BPRT. The Group disputes the validity of the assessments issued to date and the tax liability arising from the March 2022 assessment and continues to engage with the GRA to seek settlement of the issues raised (excluding BPRT) on a mutually acceptable basis outside of the ongoing dispute process.

10. Taxation on profit on ordinary activities continued

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). In 2013, the High Court found in favour of Tullow such that the tax relief should be reinstated. However, in March 2017, the NBR won its appeal to the Supreme Court, which was not clear as to the position or liability of TBL. A review application against this judgment was filed in April 2018. The hearing took place in November 2019 and TBL was unsuccessful. The NBR subsequently issued a payment demand to TBL in February 2020 for Taka 3,094m (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. TBL secured an extension of the payment deadline to 15 June 2021 from the NBR to allow discussions with PB and the Government to take place. Such discussions have been delayed several times due to the COVID pandemic. 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 and subsequently, no further enforcement action has been undertaken or threatened by NBR. The procedural hearing was held on 28 June 2022 which set the timetable for the process going forward. The first submissions are being made in October 2022 with the hearing date in May 2024.

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 anticipate that there will not be material cash taxes paid in excess of the amounts provided for uncertain tax treatments in the next 12 months.

11. Disposals

There were no disposals in the six months ended 30 June 2022.

FID for the Tilenga Project in Uganda and the East African Crude Oil Pipeline (EACOP) as reported by Total Energies Ltd on 1 February 2022 triggered a contingent consideration of $75.0 million (offset by $7.1 million indemnity relating to tax audits) in relation to Tullow's sale of its assets in Uganda to Total in 2020 which was received on 16 February 2022.

Equatorial Guinea and Dussafu asset in Gabon

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.

11. Disposals continued

Book value of assets disposed	Equatorial Guinea Six months ended 30.06.21 Unaudited $m	Dussafu Six months ended 30.06.21 Unaudited $m	Total Six months ended 30.06.21 Unaudited $m
Property, plant and equipment	72.9	52.0	124.9
Inventories	6.9	3.2	10.1
Other current assets	68.5	1.7	70.1
Total assets disposed	148.3	56.9	205.1

Trade and other payables	(36.0)	(18.5)	(54.5)
Provisions	(118.2)	(4.7)	(122.9)
Current tax liabilities	(13.6)	-	(13.6)
Deferred tax liabilities	(17.9)	-	(17.8)
Total liabilities disposed	(185.7)	(23.2)	(208.8)
Net (liabilities)/ assets disposed	(37.4)	33.7	(3.7)
Cash consideration	93.8	39.0	132.8
Transaction costs	(8.4)	(0.3)	(8.7)
Gain on disposal¹	122.8	5.0	127.8

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 of 30 June 2022.

¹ In addition to $127.8 million gain on disposal recognised following the Equatorial Guinea and Dussafu disposals, the Group recognised a loss of $5.0 million relating to its sale of Dutch assets to Hague and London Oil plc (HALO) in 2017, and a gain of $0.1 million relating to other transactions during the period (1H21: 122.9 million).

12. Intangible exploration and evaluation assets

	Six months ended 30.06.22 Unaudited $m	Six months ended 30.06.21 Unaudited $m	Year ended 31.12.21 Audited $m
At 1 January	354.6	368.2	368.2
Additions	20.6	27.4	46.3
Exploration costs written off	(86.6)	(49.3)	(59.9)
At 30 June/31 December	288.6	346.3	354.6

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

Exploration costs written off	Rationale for write-off six months ended 30.06.22	Write-off 30.06.22 Unaudited $m	Remaining recoverable amount 30.06.22 Unaudited $m
Guyana	a,d	84.2	-
Cote d'Ivoire	b	2.0	-
Other	a, b, c	0.4	-
Exploration costs written off		86.6	-

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

b. Current year expenditure on assets previously written off

c. New Ventures expenditure is written off as incurred

d. Unsuccessful well costs written off

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. At 31 December 2021, in line with its accounting policy, the Group has performed a VIU assessment of Kenya asset following identification of triggers for impairment reversal. This resulted in an NPV significantly in excess of the book value of $255.2 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 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 was no impairment or impairment reversal as at 31 December 2021.

Since 1 Jan 2022, there have been ongoing discussions with Government of Kenya on the approval of FDP and securing government deliverables. The FDP is currently under review with Government of Kenya with review period extended to 6 November 2022. In addition, Company continues to progress with the farm down process with approvals being sought. However, as at 30 June 2022 the uncertainties are largely unchanged and hence, no trigger for impairment/impairment reversal was identified.

12. Intangible exploration and evaluation assets continued

Exploration costs written off	Rationale for write-off six months ended 30.06.21	Write-off 30.06.21 Unaudited $m	Remaining recoverable amount 30.06.21 Unaudited $m
Suriname	b,c	56.9	-
Uganda	d	(15.3)	-
Gabon	c	1.7	-
Peru	b	1.0	-
Cote d'Ivoire	b	4.2	-
Other	a,c	0.8	-
Exploration costs written off		49.3	-

a. Current year expenditure on assets previously written off

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

c. Unsuccessful well costs written off

d. Release of indirect tax provision following settlement

Exploration costs written off	Rationale for write- off year ended 31.12.21	Write-off 31.12.21 Unaudited $m	Remaining recoverable amount 31.12.21 Unaudited $m
Suriname	b,d	58.9	-
Uganda	c	(15.3)	-
Gabon	d	2.2	-
Peru	b	1.8	-
Cote d'Ivoire	b	6.6	-
Other	a	5.7	-
Total write-off		59.9

a. Current year expenditure on assets previously written off

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

c. Pre-licence exploration expenditure is written off as incurred

d. Unsuccessful well costs written off

e. Following VIU assessment as a result of reduction in long term oil price assumption, using a pre-tax discount rate of 18%

f. Written down to the value of the transaction consideration.

13. Property, plant and equipment

	Oil and gas assets six months ended 30.06.22 Unaudited $m	Right of use assets six months ended 30.06.22 Unaudited $m	Other property, plant and equipment six months ended 30.06.22 Unaudited $m	Total six months ended 30.06.22 Unaudited $m	Oil and gas assets six months ended 30.06.21 Unaudited $m	Right of use assets six months ended 30.06.21 Unaudited $m	Other property, plant and equipment six months ended 30.06.21 Unaudited $m	Total six months ended 30.06.21 Unaudited $m	Oil and gas assets Year ended 31.12.21 Audited $m	Right of use assets Year ended ended 31.12.21 Audited $m	Other property, plant and equipment six months ended 31.12.21 Audited $m	Total Year ended 31.12.21 Audited $m
Cost
At 1 January	10,521.7	1,091.7	69.5	11,682.9	10,460.2	1,018.6	69.6	11,548.4	10,460.2	1,018.6	69.6	11,548.4
Additions	142.8	12.9	0.8	156.5	45.4	59.8	1.2	106.4	73.0	73.5	1.6	148.1
Acquisitions¹	473.2	-	-	473.2	-	-	-	-	-	-	-	-
Transfer²	-	86.6	-	86.6	-	-	-	-	-	-	-	-
Disposals	-	-	-	-	-	-	(0.8)	(0.8)	-	-	(1.4)	(1.4)
Currency translation adjustments	(113.5)	(3.2)	(3.7)	(120.4)	15.4	0.4	0.5	16.3	(11.5)	(0.4)	(0.3)	(12.2)
At 30 June/31 December	11,024.2	1,188.0	66.6	12,289.2	10,521.0	1,078.8	70.5	11,670.3	10,521.7	1,091.7	69.5	11,682.9
Depreciation, depletion and amortization and impairment
At 1 January	(8,263.7)	(450.8)	(53.8)	(8,768.3)	(7,915.9)	(352.3)	(42.3)	(8,310.5)	(7,915.9)	(352.3)	(42.3)	(8,310.5)
Charge for the year	(155.7)	(23.2)	(4.6)	(183.5)	(145.4)	(26.0)	(7.3)	(178.7)	(304.9)	(60.6)	(13.4)	(378.9)
Impairment loss	(6.5)	-	-	(6.5)	(8.0)	-	-	(8.0)	(54.3)	-	-	(54.3)
Capitalised depreciation	-	(23.4)	-	(23.4)	-	(14.2)	-	(14.2)	-	(38.0)	-	(38.0)
Disposal	-	-	-	-	-	-	0.8	0.8	-	-	1.4	1.4
Currency translation adjustments	112.5	0.8	2.9	116.2	(15.4)	-	(0.2)	(15.6)	11.4	0.1	0.5	12.0
At 30 June/31 December	(8,313.4)	(496.6)	(55.5)	(8,865.5)	(8,084.7)	(392.5)	(49.0)	(8,526.2)	(8,263.7)	(450.8)	(53.8)	(8,768.3)
Net book value at 30 June/31 December	2,710.8	691.4	11.1	3,413.3	2,436.3	686.3	21.5	3,144.1	2,258.0	640.9	15.7	2,914.6

¹ This relates to an acquisition through business combination discussed in Note 18.

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.

	Trigger for impairment/ (reversal) six months ended 30.06.22	Impairment/ (reversal) 30.06.22 (unaudited) $m	30.06.22 Remaining recoverable amount (unaudited) $m
Mauritania	a	4.9	-
UK 'CGU'	a, b	1.6	-
Impairment		6.5	-

a. Change to decommissioning estimate.

b. The fields in the UK are grouped into one CGU as all fields share critical gas infrastructure.

13. Property, plant and equipment continued

	Trigger for impairment six months ended 30.06.21	Impairment 30.06.21 (unaudited) $m	30.06.21 Remaining recoverable amount (unaudited) $m
Limande and Turnix CGU (Gabon)	a	(0.5)	6.7
UK 'CGU'	a, b	8.5	-
Impairment		8.0	6.7

a. Change to decommissioning estimate.

b. The fields in the UK are grouped into one CGU as all fields share critical gas infrastructure.

	Trigger for impairment/ (reversal) year ended 31.12.21	Impairment/ (reversal) 31.12.21 (audited) $m	Pre-tax discount rate assumption	31.12.21 Remaining recoverable amount (audited) $m
Limande and Turnix CGU (Gabon)	a,c	(40.8)	13%	50.8
Ezanga (Gabon)	a,c	(17.0)	15%	22.4
Oba and Middle Oba CGU (Gabon)	a,c	(3.2)	15%	10.5
Espoir (Cote d'Ivoire)	a,c	(8.7)	10%	81.4
TEN (Ghana)	a,b,c	119.1	10%	1,171.4
Mauritania	b	2.1	n/a	-
UK 'CGU'	b,d	2.8	n/a	-
Impairment		54.3

a. Increase to short, medium and long-term oil price assumptions.

b. Change to decommissioning estimate.

c. Revision of value based on revision to reserves.

d. The fields in the UK are grouped into one CGU as all fields share critical gas infrastructure.

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

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
FY 2021	$76/bbl	$71/bbl	$68/bbl	$65/bbl	$65/bbl	$65/bbl inflated by 2%

14. Trade receivables

Trade receivables comprise amounts due for the sale of oil and gas. They are generally due for settlement within 30-60 days and are therefore all classified as current. The Group holds the trade receivable with the objective of collecting the contractual cash flows and therefore measures them subsequently at amortised cost using the effective interest method.

The balance of trade receivables as of 30 June 2022 of $290.2 million (1H 2021: $256.4 million; FY21: $99.8 million) mainly relates to June 2022 oil liftings in Ghana, Gabon and Cote d'Ivoire which were settled in July 2022. The increase is also due to increased oil prices as well as an additional interest in Ghana following the pre-emption effective 17 March 2022.

15. Other assets

	30.06.22 Unaudited $m	30.06.21 Unaudited $m	31.12.21 Audited $m
Non-current
Amounts due from joint venture partners¹	314.4	514.9	486.0
VAT recoverable	2.9	-	3.1
	317.3	514.9	489.1
Current
Amounts due from joint venture partners	584.0	586.3	554.7
Underlifts²	76.0	3.8	26.7
Prepayments	59.8	57.8	49.6
Other current assets³	6.8	396.1	73.5
	726.6	1,044.0	704.5
	1,043.9	1,558.9	1,193.6

¹ The decrease in non-current receivables from JV Partners compared to June 2021 and December 2021 mainly relate to reduction in time remaining on the TEN FPSO lease, and to reduction in partner share following Ghana pre-emption.

² Underlifts of $76.0 million as at 30 June 2022 are due to the timing of liftings and are mainly attributable to Jubilee field in Ghana.

³ The decrease in other current assets compared to June 2021 and December 2021 is mainly due to a collection of the deferred consideration relating to the Uganda disposal in March 2022 ($67.9 million net) and a release of $309.8 million of funds held in a trust to settle principal plus interest of the Convertible Bond, which was subsequently repaid in July 2021 .

16. Inventories

	30.06.22 Unaudited $m	30.06.21 Unaudited $m	31.12.21 Audited $m
Warehouse stock and materials	53.7	71.5	55.5
Oil stock	279.6	69.8	79.3
	333.3	141.3	134.8

The increase in oil stock is mainly associated with the timing of liftings in Ghana ($86 million) as well as Gabon due to Cap Lopez spillage which delayed lifting by a month ($112 million).

17. Cash and cash equivalents

	30.06.22 Unaudited $m	30.06.21 Unaudited $m	31.12.21 Audited $m
Cash at bank	90.4	138.0	226.1
Short- term deposits and other cash equivalents	73.7	163.8	243.0
	164.1	301.8	469.1

Cash and cash equivalents include an amount of $51.8 million (1H 2021: $72.0 million; FY21: $92.4 million) which the Group holds as operator in joint venture bank accounts. Included within cash at bank is $3.8 million (1H 2021: $67.4 million; FY21: $0.8 million) as the Group's share of security for the Letters of Credit (LC) issued in relation to decommissioning activities.

18. Business combination

Accounting policy

The acquisition method of accounting is used to account for all business combinations, regardless of whether equity instruments or other assets are acquired. The consideration transferred for the acquisition comprises of:

· fair values of the assets transferred

· liabilities incurred to the former owners of the acquired business

· equity interests issued by the group

· fair value of any asset or liability resulting from a contingent consideration arrangement, and

· fair value of any pre-existing equity interest in the subsidiary.

The Group determines that it has acquired a business when the acquired set of activities and assets include an input and a substantive process that together significantly contribute to the ability to create outputs. The acquired process is considered substantive if it is critical to the ability to continue producing outputs, and the inputs acquired include an organised workforce with the necessary skills, knowledge, or experience to perform that process or it significantly contributes to the ability to continue producing outputs and is considered unique or scarce or cannot be replaced without significant cost, effort, or delay in the ability to continue producing outputs.

Identifiable assets acquired and liabilities and contingent liabilities assumed when control is obtained over a business, and when an interest or an additional interest is acquired in a joint operation which is a business are, with limited exceptions, measured initially at their fair values at the acquisition date.

Acquisition-related costs are expensed as incurred.

The excess of the consideration transferred, amount of any non-controlling interest in the acquired entity, and acquisition-date fair value of any previous equity interest in the acquired entity over the fair value of the net identifiable assets acquired is recorded as goodwill. If those amounts are less than the fair value of the net identifiable assets of the business acquired, the difference is recognised directly in profit or loss as a bargain purchase.

Summary of acquisition

On 17 March 2022 the Group completed the pre-emption related to the sale of Occidental Petroleum's ("Oxy") 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.

18. Business combination continued

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

	Fair value recognised on acquisition Unaudited $m
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 six months ended 30 June 2021 and 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 the 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 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 Oxy acquired the interests from, received a provisional assessment for AOE for US$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 financial years 2006 - 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 Ghana Revenue Authority ("GRA") for the 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 30 June 2022.

18. Business combination continued

Revenue and net profit contribution

The acquired business contributed revenues of $nil and net profit of $15.8 million to the group for the period from 17 March 2022 to 30 June 2022. If the acquisition had occurred on 1 January 2022, consolidated pro-forma revenues would have been $nil and consolidated pro-forma profit for the period ended 30 June 2022 would have been $18.4 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 flows 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 Peteroleum 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 portfolio which it had acquired from Anadarko Petroleum in August 2019.

19. Trade and other payables

	30.06.22 Unaudited $m	30.06.21 Unaudited Restated¹ $m	31.12.21 Audited $m
Non-current
Other non-current liabilities²	45.1	81.2	75.2
Non-current portion of leases	837.2	1,001.0	911.9
	882.3	1,082.2	987.1
Current
Trade payables	54.8	53.4	60.2
Other payables	62.0	56.7	57.4
Overlift	93.9	77.7	0.7
Accruals³	403.2	388.0	381.3
Current portion of leases	214.9	242.9	251.5
	828.8	818.7	751.1

¹ Non-current and current portion of leases amounts as at 30 June 2021 have been restated to correct a balance sheet classification error. The non-current portion of leases was understated, and current portion of leases was overstated by $68.9 million, which equates to the present value of the current finance costs.

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

³ Accruals mainly relate to capital expenditure, interest expense on bonds and loans and staff related expenses.

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

Payables related to operated joint ventures (primarily related to Ghana and Kenya) are recorded gross with the debit representing the partners' share recognised in amounts due from joint venture partners (note 15). The change in trade payables and in other payables predominantly represents timing differences and levels of work activity.

The overlift position of $93.9 million as at 30 June 2022 are due to the timing of liftings and are attributable to TEN ($37.7 million), and Gabon ($56.2 million). This is an increase of $93.2 million and $16.2 million from December 2021 and June 2021, respectively.

19. Trade and other payables continued

On 2 April 2021 the Group contracted Maersk Venturer offshore drilling rig to undertake the drilling work programme for Jubilee and TEN fields in Ghana. As at 30 June 2022, Tullow carries a right of use assets of $9.8 million (1H 21: $43.0 million; FY21: $25.8 million), and gross lease liability of $20.6 million (1H 21: $97.3 million; FY21: $59.9 million) as Tullow entered the lease on behalf of the JV. A receivable from JV Partners of $10.2 million (1H 21: $53.5 million; FY21: $33.0 million has been recognised in other assets to reflect the value of future payments that will be met by cash calls from JV Partners (see note 15). The lease has been recognised for an 18-month term, in line with the early termination option included in the contract and approvals received by the JV Partners. In July 2022 the contract has been extended for a 12-month term ending September 2023. Refer to note 24. Events since 30 June 2022.

20. Borrowings

	30.06.22 Unaudited $m	30.06.21 Unaudited $m	31.12.21 Audited $m
Current
Borrowings - within one year
6.625% Convertible Bonds due 2021 ($300 million)	-	297.8	-
10.25% Senior Notes due 2026 ($1,800 million)	100.0	-	100.0
Carrying value of total current borrowings	100.0	297.8	100.0
Non-current
Borrowings - after one year but within five years
7.00% Senior Notes due 2025 ($800 million)	792.5	791.6	792.1
10.25% Senior Notes due 2026 ($1800 million)	1,578.2	1,773.9	1,676.6
Carrying value of total non-current borrowings	2,370.7	2,565.5	2,468.7
Carrying value of total borrowings	2,470.7	2,863.3	2,568.7

In May 2021, the Group completed a comprehensive refinancing of its debt with the issuance of a five-year $1.8 billion Senior Secured Notes ("2026 Notes") and $500 million Super Senior Revolving Credit Facility (SSRCF) which will primarily be used for working capital purposes. The 2026 Notes, maturing in May 2026, require an annual prepayment of $100 million, in May, of the outstanding principal amount plus accrued and unpaid interest and payment of $1.3 billion on 2026. On 13 May 2022, the Group made the mandatory prepayment of $100 million of the 2026 Notes, which reduced total debt to $2.5 billion. As at 30 June 2022, net debt was $2,336 million (1H21: $2,290 million). Management regularly reviews options for optimising the Group's capital structure and may purchase outstanding debt securities or repay debt from time to time in open-market purchases and/or privately negotiated transactions, upon such terms and at such prices as it may determine.

The Convertible Bonds due 2021 were settled on 12 July 2021.

The Senior Notes due 2025 are payable in a single payment in March 2025.

The SSRCF, maturing in December 2024, comprises of (i) a $500 million revolving credit facility and (ii) a $100 million letter of credit facility. The revolving credit facility remains undrawn as at 30 June 2022. Letters of credit amounting to $50.4 million have been issued under the facility.

Unamortised debt arrangement fees for the 2026 Notes, the Senior Notes due 2025 and the SSRCF are $21.8 million, $7.5 million and $6.1 million respectively.

The 2026 Notes and the SSRCF are senior secured obligations of Tullow Oil Plc and are guaranteed by certain of the Group's subsidiaries.

Capital management

The Group defines capital as the total equity and net debt of the Group. Capital is managed in order to provide returns for shareholders and benefits to stakeholders and to safeguard the Group's ability to continue as a going concern. Tullow is not subject to any externally imposed capital requirements. To maintain or adjust the capital structure, the Group may put in place new debt facilities, issue new shares for cash, repay debt, engage in active portfolio management, adjust the dividend payment to shareholders, or undertake other such restructuring activities as appropriate. No significant changes were made to the capital management objectives, policies or processes during the half year ended 30 June 2022. The Group monitors capital on the basis of the gearing, being net debt divided by adjusted EBITDAX, and maintains a target of less than 1x.

20. Borrowings continued

SSRCF covenants

The SSRCF does not have any financial maintenance covenants. Availability under the $500 million cash tranche of the facility is determined on an annual basis with reference to the Net Present Value of the 2P reserves of the Group (2P NPV) at the end of the preceding calendar year. SSRCF debt capacity is calculated as 2P NPV divided by 1.1x less senior secured debt outstanding.

Senior Notes covenants

The Senior Notes due 2025 and the 2026 Notes are subject to customary high yield covenants including limitations on debt incurrence, asset sales and restricted payments such as dividends. The key debt incurrence covenant is the Fixed Charge Cover Ratio ("FCCR").

The FCCR is the ratio of the Consolidated Cash Flow to the Fixed Charges for the previous twelve months. The 'Consolidated Cash flow' essentially represents an Adjusted EBITDAX calculation. The Fixed Charges represent the aggregate financial charges related to the Company's indebtedness i.e. interest on all of the Group's borrowings and interests under capital leases less any finance revenues. The Company may incur additional financial indebtedness if the F CCR for the Company's most recently ended two full fiscal half-years immediately preceding the date on which such additional indebtedness is incurred would have been at least 2.25 to 1.0 on a proforma basis. Drawdowns under the SSRCF are not subject to the FCCR covenant and are always permitted subject to the availability calculation set out above. There has been no debt incurrence event since the 2026 Notes have been issued.

21. Provisions

	Decommissioning 30.06.22 Unaudited $m	Other provisions 30.06.22 Unaudited $m	Total 30.06.22 Unaudited $m	Decommissioning 30.06.21 Unaudited $m	Other provisions 30.06.21 Unaudited $m	Total 30.06.21 Unaudited $m	Decommissioning 31.12.21 Audited $m	Other provisions 31.12.21 Audited $m	Total 31.12.21 Audited $m
At 1 January	498.7	228.8	727.5	696.1	154.6	850.7	696.1	154.6	850.7
New provisions, changes in estimates and reclassifications	(2.4)	(18.8)	(21.2)	(17.3)	36.5	19.2	(134.8)	90.0	(44.8)
Acquisitions¹	24.8	36.8	61.6	-	-	-	-	-	-
Payments	(32.5)	(77.5)	(110.0)	(36.6)	(8.9)	(45.5)	(69.3)	(15.7)	(85.0)
Unwinding of discount	3.2	-	3.2	3.7	-	3.7	7.6	-	7.6
Currency translation adjustment	(10.5)	(1.7)	(12.2)	2.3	0.4	2.6	(0.9)	(0.1)	(1.0)
At 30 June/31 December	481.3	167.6	648.9	648.2	182.6	830.8	498.7	228.8	727.5
Current provisions	106.1	99.1	205.2	116.9	138.4	255.3	101.2	195.3	296.5
Non-current provisions	375.2	68.5	443.7	531.3	44.2	575.5	397.5	33.5	431.0

¹ This relates to an acquisition through business combination discussed in Note 18.

Other provisions include non-income tax provision and disputed cases and claims.

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 0.5% from 31 December 2021 (2021: increase by 0.5% from 31 December 2020) due to movement in the risk-free rate. This resulted in a decrease of the provision by $8.7 million in Ghana (2021: 23.7 million), $4.2 million in Gabon (2021: $4.3 million) and $3.6 million in Cote d'Ivoire (2021: $3.7 million).

Above includes 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.

In January 2013, the Group acquired Spring Energy Norway AS (Spring) from HitecVision V (Hitec), a Norwegian private equity company, and Spring employee minority shareholders. In addition to the initial consideration payable under the sale and purchase agreement for Spring, the Group undertook to make contingent bonus payments to Hitec and the Spring employee minority shareholders in the event of the discovery on or before 31 December 2016 of commercially viable reserves from four identified drilling prospects (including the Wisting prospect in licence PL537).

HiTec previously claimed that the conditions for a bonus payment under the Spring SPA had been met in respect of the Wisting prospect in PL537 as at 31 December 2016. Tullow disputed this position. In 2016, the Group sold its interest in PL537 to Equinor but remained responsible for this dispute. An arbitration took place in Norway in Q4 2021 to resolve this issue.

On 15 February 2022, the arbitration panel delivered an award in favour of 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 was settled in March 2022.

22. Called up share capital and share premium

As at 30 June 2022, the Group had in issue 1,438.3 million allotted and fully paid ordinary shares of GBP 10 pence each (1H 21: 1,429.0 million, FY21: 1,432.1 million).

In the six months ended 30 June 2022, the Group issued 6.2 million shares in respect of employee share options (1H 21: 14.9 million; FY21: 18.0 million new shares in respect of employee share options).

23. Contingent Liabilities

	30.06.22 Unaudited $m	30.06.21 Unaudited $m	31.12.21 Audited $m
Contingent liabilities
Performance guarantees	89.6	102.8	100.8
Other contingent liabilities	60.2	83.6	14.0
	149.8	186.4	114.8

Performance guarantees are in respect of abandonment obligations, committed work programmes and certain financial obligations.

Other contingent liabilities

This includes amounts for ongoing legal disputes with third parties where we consider the likelihood of cash outflow to be higher than remote but not probable. The timing of any economic outflow if it were to occur would likely range between one and five years.

24. Events since 30 June 2022

Adjusting events

On 5 August 2022, the Beebei-Potaro commitment well, offshore Guyana, has been plugged and abandoned after encountering good quality reservoir in the primary and secondary targets, but both targets were water bearing . This will be treated as an adjusting post balance sheet event as it represents confirmation of the subsurface position being tested by the well as at 30 June. As a result, the well and residual costs have been written off on Kanuku ($62 million) and the Orinduik ($22 million) blocks.

Non-adjusting events

In July 2022 the Group extended the contract for Maersk Venturer offshore drilling rig initially hired in April 2021 to undertake the drilling work programme for Jubilee and TEN fields in Ghana. The extension has been recognised for a 12-month term ending September 2023, in line with the approvals received by the JV Partners. This resulted in a $80.2 million increase to a gross lease liability, and a corresponding uplift to a lease asset of $41.2 million. A receivable from JV Partners of $39.0 million has been recognised in other assets to reflect the value of future payments that will be met by cash calls from JV Partners.

25. Cash flow statement reconciliations

Movement in borrowings	1H 22 $m	FY 21 $m	1H 21 $m	FY 20 $m	1H22 Movement	1H21 Movement	2021 Movement
Borrowings	2,470.7	2,568.7	2,863.3	3,170.5	(98.0)	(307.2)	(601.8)
Associated cash flows
Debt arrangement fees					-	(57.8)	(56.6)
Repayment of borrowings¹					(100.0)	(2,080.0)	(2,379.9)
Drawdown of borrowings					-	1,800	1,800
Non-cash movements/presented in other cash flow lines
Amortisation of arrangement fees and accrued interest					2.0	30.6	34.7

¹ Refer to note 19 for the detailed explanation of the repayment of borrowings in 2021 related to a comprehensive refinancing of the Group's debt.

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	Total mmboe
COMMERCIAL RESERVES¹
1 January 2022	168.3	138.9	38.8	7.1	-	-	-	-	207.1	145.9	231.4
Revisions^,3,4	-	-	0.2	-	-	-	-	-	0.2	-	21.8
Acquisitions ²	19.2	13.7	-	-	-	-	-	-	19.2	13.7	21.6
Production	(7.8)	-	(3.0)	(0.9)	-	-	-	-	(10.8)	(0.9)	(11.0)
30 June 2022	179.7	152.6	36.0	6.2	-	-	-	-	215.7	158.8	242.2
CONTINGENT RESOURCES¹
1 January 2022	212.1	585.2	29.7	0.9	231.4	-	54.5	-	527.7	586.1	625.4
Revisions³	-	-	(0.2)	-	-	-	-	-	(0.2)	-	42.9
Acquisitions ²	29.0	84.2	-	-	-	-	-	-	29.0	84.2
30 June 2022	241.1	669.4	29.5	0.9	231.4	-	54.5	-	556.5	670.3	668.2
TOTAL
30 June 2022	420.7	822.0	65.5	7.1	231.4	-	54.5	-	772.1	829.0	910.4

¹ Proven and Probable Reserves & Contingent Resources above are as audited and reported by independent third-party reserve auditors as of 31 December 2021 and adjusted for Working Interest changes in Ghana assets and production to 30 June 2022.

² Reserves and resources acquisitions in Ghana relates to increase in interest from successful pre-emption right in both Jubilee and TEN Assets on 17th March 2022.

³ Reserves revision in Non-Operated (Gabon & CDI) relates to booking of reserves in Etame which represents Tullow's share in future productions following licence extension.

⁴ No revision on Kenya and Guyana Resources.

The Group provides for depletion and amortisation of tangible fixed assets on a net entitlement basis, which reflects the terms of the Production Sharing Contracts related to each field. Total net entitlement reserves were 231.8 mmboe at 30 June 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 which 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 free 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, additions to administrative assets 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 decommissioning asset adjustments.

	1H 2022	1H 2021
Additions to property, plant and equipment	156.5	106.4
Additions to intangible exploration and evaluation assets	20.6	27.4
Less
Decommissioning asset adjustments	22.4	(17.3)
Right-of-use asset additions	12.9	59.8
Lease payments related to capital activities	(19.5)	(8.7)
Additions to administrative assets	0.8	1.2
Other non-cash capital expenditure	4.5	(2.4)
Capital investment	156.0	101.2
Movement in working capital	(22.0)	(5.2)
Additions to administrative assets	0.8	1.2
Cash capital expenditure per the cash flow statement	134.8	97.2

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 payments to convertible bond trustees and cash and cash equivalents. Non-cash adjustments include unamortised arrangement fees, adjustment to convertible bonds, and other adjustments. The Group's definition of net debt does not include the Group's leases as the Group's focus is the management of cash borrowings and a lease is viewed as deferred capital investment. The value of the Group's lease liabilities as at 30 June 2022 was $214.9 million current and $837.2 million non-current; it should be noted that these balances are recorded gross for operated assets and are therefore not representative of the Group's net exposure under these contracts.

	1H 2022	1H 2021
Current borrowings	100.0	297.8
Non- current borrowings	2,370.7	2,565.5
Non-cash adjustments¹	29.4	38.3
Payment to Convertible Bond trustees²	-	(309.8)
Less cash and cash equivalents³	(164.1)	(301.8)
Net debt	2,336.0	2,290.0

¹ Non-cash adjustments include unamortised arrangement fees which are incurred on creation or amendment of borrowing facilities. as well as the Convertible Bonds which were measured at fair value. The difference between the fair value and the principal of the bond was included as a component of equity and a decrease to borrowings. Over the life of the Convertible Bond, the fair value reduces until the carrying value of the borrowings is equal to the principal outstanding for repayment on maturity.

² As part of the refinancing, it was agreed that Tullow would pay $300 million plus coupon of $10 million to the Convertible Bonds Paying Agent (Deutsche Bank) on 17 May 2021. This amount was held in Trust until repayment on maturity date of 12 July 2021.

³ Cash and cash equivalents include an amount of $51.8 million (1H 2021: $72.0 million) which the Group holds as operator in JV bank accounts. Included within cash at bank is $3.8 million (1H 2021: $67.4 million) as the Group's share of security for the Letters of Credit (LC) issued in relation to decommissioning activities.

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. This definition of gearing differs from the one included in the RBL facility agreements. Adjusted EBITDAX is defined as profit/(loss) from continuing activities adjusted for income tax (expense)/credit, finance costs, finance revenue, gain on hedging instruments, depreciation, depletion and amortisation, share-based payment charge, restructuring costs, gain/(loss) on disposal, gain on bargain purchase, exploration cost written off, impairment of property, plant and equipment net, and provision for onerous service contracts.

	1H 2022	1H 2021
Adjusted EBITDAX¹	1,262.6	884.9
Net debt	2,336.0	2,290.0
Gearing (times)	1.9	2.6

¹ Last 12 months (LTM). Refer to the 2021 Annual Report and Accounts and 2021 Half year results for a full reconciliation of 2021 and 1H2021 Adjusted EBITDAX.

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, depletion and amortisation of oil and gas assets, underlift, overlift and oil stock movements, share-based payment charge included in cost of sales, and certain other cost of sales. Underlying cash operating costs are divided by production to determine underlying cash operating costs per boe.

	1H 2022	1H 2021
Cost of sales	225.4	405.7
Add
Lease payments related to operating activity	7.9	9.2
Less
Depletion and amortisation of oil and gas and leased assets¹	176.9	169.5
Underlift, overlift and oil stock movements²	(119.9)	89.5
Share-based payment charge included in cost of sales³	0.2	0.4
Other cost of sales⁴	33.4	12.2
Underlying cash operating costs	142.7	143.3
Non-recurring costs⁵	(14.4)	(4.9)
Total normalised operating costs	128.3	138.4
Production (MMboe)	11.0	11.1
Underlying cash operating costs per boe ($/boe)	13.0	12.9
Normalised cash operating costs per boe ($/boe)	11.6	12.5

¹ Depletion and amortisation of oil and gas assets is the depreciation and amortisation of the Group's oil and gas assets over the life of an asset on a unit of production basis.

² Under lifting or offtake arrangements for oil and gas produced in certain operations in which the Group has interests with other commercial partners, each participant may not receive and sell its precise share of the overall production in each period. The resulting imbalance between cumulative entitlement and cumulative production less stock constitutes "underlift" or "overlift". Underlift and overlift are valued at market value and included within other current assets and other current payables on the Group's balance sheet, respectively. Movements during an accounting period are charged to cost of sales rather than charged through revenue, and as a result gross profit is recognised on an entitlements basis.

³ Share-based payment charge included in cost of sales relates to the portion of the non-cash share-based payment charge that relates to employees who work on operational projects.

⁴ Other cost of sales includes purchases of gas from third parties to fulfil gas sales contracts and royalties paid in cash.

⁵ Non-recurring costs include COVID-19 costs, OOSYS (Oil offloading system) costs, CSV (Construction Support Vessel) campaign costs and shutdown costs.

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 used in investing activities, less debt arrangement fees, repayment of obligations under leases, finance costs paid and foreign exchange gain/ (loss).

	1H 2022	1H 2021
Net cash from operating activities	208.6	258.1
Net cash (used) in/from investing activities	(191.9)	36.9
Debt arrangement fees	-	(57.8)
Repayment of obligations under leases	(91.9)	(68.3)
Finance costs paid	(126.2)	(86.9)
Foreign exchange (loss)/ gain	(3.6)	4.2
Free cash flow	(205.0)	86.2

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 free cash flow

This is a useful indicator of the Group's assets 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.

	1H 2022	1H 2021
Net cash from operating activities	208.6	258.1
Less
Decommissioning expenditure	28.8	27.7
Lease payments related to capital activities	19.5	8.7
Plus
Repayment of obligations under leases	(91.9)	(68.3)
Underlying operating cash flow	165.0	217.5
Net cash (used) in/ from investing activities	(191.9)	36.9
Decommissioning expenditure	(28.8)	(27.7)
Lease payments related to capital activities	(19.5)	(8.7)
Pre-financing free cash flow	(75.2)	226.7

WEBCAST - 9:00 BST

To access the webcast please use the following link and follow the instructions provided: https://web.lumiconnect.com/145-356-205

A replay will be available on the website from midday on 14 September 2022: https://www.tullowoil.com/investors/results-reports-and-presentations/

Contacts

Tullow Oil plc

(London)

(+44 20 3249 9000)

George Cazenove (Media)

Robert Hellwig (Investors)

Matthew Evans (Investors)

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, Irish and Ghanaian stock exchanges (symbol: TLW) and is a constituent of the FTSE250 index. The Group has interests in over 35 exploration and production licences across seven 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

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END

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Tullow Oil (TLW)

Friday, 20th December 2024

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Half Year Results

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

2022 First half results summary

Key financial results

2022 Guidance

MERGER WITH CAPRICORN ENERGY

ESG

Net Zero 2030

Operational UPDATE

Production

Ghana

N on-operated portfolio

Decommissioning

Exploration

Production and commodity prices

The underlift in the income statement was mainly due to the increase in oil prices and stock positions in Gabon and Ghana as well as the delay in lifting due the Cap Lopez terminal spillage in Gabon.

Higher oil prices combined with oil entitlements have led to a 93% increase in gross profit for the period.

Operating costs, depreciation and expenses

Gain on bargain purchase

Derivative financial instruments

Borrowings

Net financing costs

Taxation

Profit after tax from continuing activities and earnings per share

Reconciliation of net debt

Capital investment

Going concern

2022 principal risks and uncertainties

Events since 30 June 2022

Responsibility statement (DTR 4.2 and the Transparency (Directive 2004/109/EC) Regulations (as amended))

Disclaimer

Independent review report to Tullow Oil plc

Conclusion

Basis for Conclusion

Conclusions Relating to Going Concern

Responsibilities of the directors

Use of our report

Condensed consolidated income statement

Condensed consolidated statement of comprehensive income and expense

Condensed consolidated balance sheet

Condensed statement of changes in equity

Condensed consolidated cash flow statement

Notes to the condensed financial statements

1. General information

2. Accounting policies

Going Concern

3. Earnings per ordinary share

4. Dividends

5. Approval of accounts

6. Segmental reporting

6. Segmental reporting continued

6. Segmental reporting continued

2 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:

6. Segmental reporting continued

7. Total revenue

8. Operating profit

9. Net financing costs

10. Taxation on profit on ordinary activities

Uncertain tax positions

10. Taxation on profit on ordinary activities continued

Bangladesh litigation

Timing of cash-flows

11. Disposals

Equatorial Guinea and Dussafu asset in Gabon

11. Disposals continued

13. Property, plant and equipment

13. Property, plant and equipment continued

14. Trade receivables

15. Other assets

16. Inventories

17. Cash and cash equivalents

18. Business combination

Accounting policy

Summary of acquisition

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.

18. Business combination continued

Contingent liabilities recognised in a business combination

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 30 June 2022.

18. Business combination continued

Revenue and net profit contribution

² 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: