2019 Half Year Results

RNS Number : 4860G

Tullow Oil PLC

24 July 2019

Tullow Oil plc - 2019 Half Year Results

Group delivers $0.9bn revenue; $0.1bn profit after tax; $0.2bn free cash flow

Kenya oil development Heads of Terms signed; FID targeted for second half of 2020

Three-well Guyana exploration campaign under way; Jethro result expected in August

24 July 2019 - Tullow Oil plc (Tullow), the independent oil and gas exploration and production group, announces its Half Year results for the six months ended 30 June 2019. Details of a presentation in London, webcast and conference calls are available on the last page of this announcement or visit the Group's website www.tullowoil.com.

COMMENTING TODAY, PAUL McDADE, CHIEF EXECUTIVE OFFICER, SAID:

"Today's results demonstrate strong financial delivery in the first half of 2019 with robust profits and free cash flow. We are disappointed that a mechanical issue at our latest TEN well has caused us to reduce our 2019 production outlook; however, our overall portfolio of low-cost West African production continues to provide a solid financial base for the business, allowing the Group to invest for future growth, continue to reduce debt and pay dividends to shareholders. Elsewhere, our exciting three-well Guyana exploration campaign is now under way and I am particularly pleased to see the good progress being made in Kenya with the first ever lifting of East Africa crude expected in the coming months."

2019 HALF YEAR RESULTS summary

· Revenue of $872 million; gross profit of $527 million; post tax profit of $103 million; free cash flow of $181 million

· Board confirms interim dividend of 2.35 cents/share (c. $33 million) in line with the Group's Capital Returns Policy

· Net debt and gearing reduced to $2.9 billion and 1.8x; no near-term debt maturities

· First half 2019 capex of $248 million; 2019 capex forecast remains unchanged at $570 million

· West Africa first half 2019 working interest oil production averaged 88,700 bopd¹

· Full year 2019 oil production guidance revised down to 89-93,000 bopd reflecting delays in TEN well completion

· Kenya oil development progressing well; Heads of Terms signed with the Government; FID targeted for second half of 2020

· Uganda farm-down continues to make limited progress; discussions between JV Partners and Government continue

· Three-well Guyana exploration campaign under way; Jethro result expected in first half of August

· New exploration acreage accessed in Argentina, Peru and Namibia; withdrawn from Zambia and Mauritania C-18 licence

FINANCIAL OVERVIEW

	1H 2019	1H 2018
Sales revenue ($m)²	872	905
Gross profit ($m)	527	521
Profit after tax ($m)	103	55
Free cash flow ($m)³	181	390
Gearing (times) ³	1.8	2.0
Net debt ($m)³	2,948	3,082

¹Includes 2,700 bopd of production-equivalent insurance payments

² Revenue does not include proceeds for Tullow's Corporate Business Interruption insurance of $29 million (1H 2018: $129 million)

³Free cash flow, gearing and net debt are non-IFRS measures and are explained in the finance review

Corporate Governance matters

Board changes

Tutu Agyare retired from Tullow after nine years on the Board following the Group's Annual General Meeting (AGM) on
25 April 2019. Sheila Khama and Genevieve Sangudi joined Tullow's Board as Non-Executive Directors on 26 April 2019.

Dividend

The Board has approved an interim dividend of 2.35 cents/share (c.$33 million) which will be paid on 4 October 2019. This is in line with the Group's Capital Returns Policy of intending to pay shareholders at least $100 million per year. The Record Date will be 30 August 2019 and the relevant exchange rate used to determine the payment of dividends will be announced on
18 September 2019.

Investor Relations contacts

Following these Results, Chris Perry, VP of IR & Communications, will be taking up another senior role in Tullow as Corporate Head of Value and Risk, after leading Tullow's Investor Relations & Communications team for the past 10 years. Going forward, Tullow's primary Investor Relations contacts will be Julia Ross, Corporate Head of Strategy & Performance, and Nicola Rogers, Head of Investor Relations. Please get in touch with the team directly or use ir@tullowoil.com for queries.

Operations review

GROUP PRODUCTION

Tullow's West Africa oil production averaged 88,700 bopd in the first half of 2019. This includes 2,700 bopd of production-equivalent insurance payments relating to the Jubilee field which have been realised under Tullow's Corporate Business Interruption insurance policy. First half 2019 working interest gas production averaged 300 boepd.

Tullow's 2019 full year working interest oil production forecast, including production-equivalent insurance payments, has been revised down to 89-93,000 bopd due to mechanical issues experienced completing the Enyenra-14 production well which has not been brought on-stream as planned (see more details below). Working interest gas production is expected to average around 1,000 boepd, resulting in total Group production guidance for the full year of 90-94,000 boepd.

WEST AFRICA

Kweku Awotwi, Executive Vice President for Ghana, commented today:

"This has been a mixed half year for Tullow's Ghana Business. It is disappointing that we have encountered mechanical issues with a well completion at Enyenra. However, the underlying performance of our Ghana fields remains strong, and I am confident in the long-term potential of these high-quality assets. Tullow's non-operated Central and West African portfolio continues to make a solid contribution to Group production, with the portfolio outperforming initial expectations, especially in Gabon."

GHANA

In the first half of the year, the Stena Forth and Maersk Venturer drillships worked in tandem on the Group's drilling programme in Ghana and so far this year, Tullow has drilled four wells and completed three wells. Following the completion of its work programme, the Stena Forth left Ghana in June and is now drilling the Jethro well offshore Guyana. The Maersk Venturer remains in Ghana and is currently completing a Jubilee production well, due on stream in August. The schedule for the remainder of the year is being adjusted following the suspension of the Enyenra-14 well completion.

Jubilee

In the first half of 2019, gross production from the Jubilee field averaged 88,500 bopd (net: 31,400 bopd). Production was below expectations due to gas compression constraints during February which have now been resolved.

Tullow's net production increased to 34,100 bopd with the inclusion of 2,700 bopd of net production-equivalent insurance payments. The insured period associated with Tullow's Corporate Business Interruption insurance claim ended in May 2019, three years after cover commenced. Tullow continues to insure against Business Interruption. The final phase of the Turret Remediation Project is the installation of a Catenary Anchor Leg Mooring (CALM) buoy to assist with offloading, with installation likely to take place in 2020, with no associated shut-downs expected.

Tullow forecasts full year gross production from the Jubilee field to average around 96,000 bopd (net: 34,000 bopd) and full year net production-equivalent insurance payments to be around 1,300 bopd.

TEN

The TEN fields have produced 61,500 bopd gross (net: 29,000 bopd) in the first half of 2019. This was lower than expected due to a delay in completing the Enyenra-10 production well in the first quarter. This well has now been brought on stream and has been producing in line with expectations. In the second quarter of 2019, the TEN fields produced in line with expectations and the FPSO was shut down for 11 days for planned routine maintenance which was completed successfully. Tullow has also completed 4D seismic acquisition around the TEN fields to identify areas for future drilling, and this data will be ready for interpretation later
in 2019.

As previously disclosed in June, mechanical issues have been encountered with the completion of the Enyenra-14 well. It was not possible to fully resolve these issues and a decision was taken to suspend the well and move the rig to the next Jubilee completion while next steps are being considered. Accordingly, Tullow has reduced its TEN gross full year production forecast to around
63,500 bopd (net: 30,000 bopd).

Over the first half of the year, Tullow averaged 300 boepd of gas production from the TEN fields. The Group expects to average 1,000 boepd of gas production for the full year.

WEST AFRICA NON-OPERATED PORTFOLIO

Production from Tullow's Central and West African non-operated portfolio in the first half of 2019 has been strong with net production averaging 25,600 bopd. The non-operated portfolio is expected to deliver around 26,000 bopd net for the full year.

Production from Gabon has been strong in the first half of 2019, especially from the Ruche and Simba fields. In Côte d'Ivoire, the next phase of Espoir drilling is expected to commence in the second half of 2019 and will continue during 2020. In Equatorial Guinea, production has been in line with expectations and planned activities for the remainder of 2019 will be the upgrading of the Okume facility power and water systems to accommodate a workover campaign which is planned for 2020.

Decommissioning

The decommissioning programme for the remaining Tullow-operated licences in the UK North Sea is progressing as planned and under budget. The plugging and abandonment of the last operated wells is complete, and the Group will now undertake final removal and seabed clearance activities. In Mauritania, the permanent abandonment programme for the wells in the Chinguetti field is scheduled to commence in the third quarter of 2019.

EAST AFRICA

Mark MacFarlane, Executive Vice President for East Africa, commented today:

"Good progress in Kenya has been a highlight of the first half. We have seen how a Joint Venture Partnership working closely and co-operatively with the host government can obtain results. We continue to discuss our farm-down in Uganda with both Joint Venture Partners and the Government and remain optimistic that we can make progress."

Kenya

Full Field Development

The Joint Venture Partners and the Government of Kenya concluded negotiations around key fiscal and commercial principles for Project Oil Kenya with agreements between the parties documented in Heads of Terms which were signed by the Joint Venture Partners and the Government of Kenya in Nairobi on 25 June 2019. This represented a material and encouraging step forward which gives all parties confidence that the project will be robust at low oil prices.

The development plan envisages that the Foundation Stage of Project Oil Kenya will include the Amosing, Ngamia and Twiga fields, with a 60,000-80,000 bopd Central Processing Facility and an export pipeline to Lamu. The infrastructure installed for the Foundation Stage will be utilised for the development of the remaining oil fields and future oil discoveries in the region, allowing the incremental development of these fields to be completed at a lower unit cost.

In the first half of the year, Front End Engineering Design (FEED) studies for both the upstream and midstream have been finalised. These studies, together with recent market soundings, have given the Joint Venture Partners greater confidence in the project's estimated capital expenditure and construction timetable that is expected to see first oil three years after FID. Upstream and midstream Environmental and Social Impact Assessments (ESIAs) are expected to be submitted to the National Environmental Management Agency by the end of the third quarter 2019. The Government of Kenya, via the National Lands Commission, has gazetted the land required for the upstream development in Turkana and pipeline land surveys by the National Lands Commission began in the first week of July. An Upstream Water Framework agreement has been drafted by Tullow and submitted to the Government of Kenya for their review. Given this significant progress, the FID of the Development is now targeted for the second half of 2020.

Early Oil Pilot Scheme

The Early Oil Pilot Scheme (EOPS) continues to perform well and the trucking operations, which transport oil from Turkana to Mombasa, are running smoothly. The reservoirs, wells and associated facilities at both Amosing and Ngamia have been performing in line with expectations. In May 2019, EOPS production was increased from 600 bopd to 2,000 bopd and, to date, over
200,000 barrels of oil have been safely delivered to Mombasa. Tullow expects East Africa's first export cargo of oil to be sold and lifted in the third quarter of 2019.

Uganda

Following meetings in January 2019 between the CEOs of Tullow and Total, and H.E. President Museveni of Uganda, where principles for the tax treatment of the farm-down to CNOOC and Total were agreed, the Joint Venture Partners have worked to finalise an agreement based on these principles. Tullow and its Joint Venture Partners, have, so far, been unable to finalise this agreement with the Government of Uganda. We continue to work constructively with our Joint Venture Partners and the Government of Uganda to agree a way forward to complete the farm-down and determine the subsequent timing of FID. Nevertheless, although negotiations continue, Tullow is now also considering all options in pursuing the sale of its interests
in Uganda.

The Joint Venture Partners continue to target FID for the development project at the end of 2019 with the project's major technical aspects now completed. The Tilenga Project ESIA has been approved by the National Environment Management Agency and the Kingfisher ESIA public hearing has concluded. Geotechnical and geophysical surveys for the East Africa pipeline (EACOP) have been completed for the entire route across both Uganda and Tanzania. There are ongoing EACOP discussions between the Joint Venture Partners and the Governments of Uganda and Tanzania regarding key commercial agreements which are required prior to FID.

NEW VENTURES

Ian Cloke, Executive Vice President for New Ventures, commented today:

"Tullow's New Ventures team continues to make good progress across the entirety of its portfolio. We are currently anticipating results in early August from the Jethro wildcat well, the first of our three 2019 exploration wells in Guyana, all of which have the potential to make new oil discoveries in the world's latest exploration hotspot. New licences in Argentina, Peru and Namibia have been accessed in the first half of the year and we continue to evaluate and mature opportunities for potential drilling in 2020, including wells in Peru and Suriname."

Africa

Comoros

Tullow's entry into the Comoros Islands has completed and Tullow is now the operator of Blocks 35, 36 and 37. A 3D seismic contract award has been approved by Tullow's Joint Venture Partners and by the Government. With the ESIA now approved, acquisition of a 3,000 sq km 3D seismic survey is expected to commence in September 2019.

Côte d'Ivoire

In Côte d'Ivoire, the farm-in by Cairn Energy has completed and planning for a 2D seismic programme and associated stakeholder engagement is under way. Seismic acquisition is expected to start in September 2019, subject to receiving regulatory approvals.

Namibia

In June 2019, Tullow entered into an agreement to acquire a 56% operated interest in the 5,000 sq km PEL-90 offshore licence from Calima Energy. The transaction remains subject to Government approval. This licence is located in Southern Namibia, contains Cretaceous aged turbidite stratigraphic traps and is adjacent to the Venus-1 wildcat planned to be drilled by Total
in 2020.

Mauritania

Following interpretation of 3D seismic acquired over Block C-18 in Mauritania, Tullow has decided not to proceed into the next exploration phase and has withdrawn from the licence. Tullow's remaining acreage in Mauritania is the C-3 licence which will expire in early 2020.

Zambia

Tullow has decided to withdraw from Zambia Block 31 after the interpretation of the gravity survey and the Group is currently making the necessary preparations to exit the country.

South America

Guyana

In Guyana, Tullow is drilling two consecutive exploration wells in the second half of 2019 on its operated Orinduik licence with the Stena Forth drillship. The first well, which has been spudded, is targeting the Lower Tertiary age Jethro prospect. Drilling is underway with a result expected in the first half of August. The drillship will then move to drill the Upper Tertiary age Joe prospect. The Rowan EXL II jack-up rig has been contracted to drill the Cretaceous Carapa prospect in the non-operated Kanuku licence. This is expected to commence drilling in September with a result expected in the fourth quarter of 2019.

Argentina

In April 2019, Tullow won three blocks as operator in the highly competitive offshore Argentina bidding round and formal awards are expected be made later this year. The blocks, located in the Malvinas West Basin, comprise 100% equity in Block MLO-122 and 40% equity in Blocks MLO-114 and MLO-119, in partnership with Pluspetrol and Wintershall. The shallow water Tertiary and Cretaceous age turbidite plays in this underexplored acreage complement Tullow's existing South America portfolio. The multi-year low-cost, low-commitment work programmes also adhere to Tullow's strict commercial criteria. Tullow plans to start initial geological studies, 2D reprocessing and 3D acquisition in 2020.

Peru

The Government of Peru has approved Tullow's entry into two licences, Z-38 and Z-64 and work continues to secure the other four licences in which Tullow is interested. The Marina exploration well will be drilled by Karoon Energy in the non-operated Z-38 licence in early 2020. Stakeholder engagement and operational planning are under way.

The Marina prospect is located in the Tumbes Basin, approximately 30 kilometres from the coast of Northern Peru, and adjacent to the prolific, onshore Talara Basin. The prospect, which is located in 350 metres of water, has been identified on a high-quality 3D seismic survey. The Marina well will be the first well to target the deeper water plays in the Tumbes Basin.

Suriname

Tullow has interests in three blocks in Suriname, Blocks 54, 62 and 47. Tullow and its Joint Venture Partners have decided to enter the second phase of operations in Block 47. Following recent meetings, the Joint Venture Partners have chosen to drill the Goliathberg-Voltzberg North prospect in 2020. The prospect lies approximately 260 kilometres off the coast of Suriname, in
1,900 metres of water and is one of a series of leads and prospects on the flank of the Demerara High.

Jamaica

Tullow continues to process seismic data on the Walton-Morant licence and is assessing its options with regards to future drilling.

Finance review

Les Wood, Chief Financial Officer, commented today:

"Tullow has delivered a good set of financial results in the first half of 2019, with further reductions in net debt and gearing underpinned by strong cash flow generation from our assets despite the lower than expected production. We continue to maintain financial discipline as we allocate our capital, allowing us to confirm our interim 2019 dividend and establish a robust platform for growth."

Financial results summary	1H 2019	1H 2018
Working interest production volume (boepd)¹	86,300	79,100
Sales volume (boepd)	75,200	74,700
Realised oil price ($/bbl)	64.3	67.5
Total revenue ($m)²	872	905
Gross profit ($m)	527	521
Underlying cash operating costs per boe ($/boe)³	9.0	10.9
Exploration costs written off ($m)	81	9
Impairment of property, plant and equipment, net ($m)	12	8
Operating profit ($m)	388	300
Profit before tax ($m)	268	150
Profit after tax ($m)	103	55
Basic earnings per share (cents)	7.4	3.9
Capital investment ($m)^{3, 4}	248	145
Adjusted EBITDAX (last twelve months basis) ($m) ³	1,623	1,579
Net debt ($m)³	2,948	3,082
Gearing (times) ³	1.8	2.0
Free cash flow ($m)³	181	390

1. Including the impact of production-equivalent insurance payments from the Jubilee field, Group working interest production was 89,000 boepd (1H 2018: 91,000 boepd).

2. Total revenue does not include receipts for Tullow's Corporate Business Interruption Insurance of $29 million (1H 2018: $129 million). This is included in Other Operating Income which is a component of Gross Profit.

3. Underlying cash operating costs per boe, capital investment, adjusted EBITDAX, net debt, gearing and free cash flow are non-IFRS measures and are explained later in this section.

4. Capital investment excludes Ugandan expenditure of $16 million (1H 2018: $23 million) that will be recovered on completion of the farm-down.

Production and commodity prices

Total Group working interest production for the period, including production-equivalent insurance payments, averaged 89,000 boepd (1H 2018: 91,000 boepd), a decrease of 2% for the period. The realised oil price after hedging for the period was $64.3/bbl (1H 2018: $67.5/bbl). Market oil prices led to a loss on the realisation of hedges entered into by the Group, reducing total revenue. However, hedging remains a key element of the Group's risk management strategy.

Operating costs, depreciation and expenses

Underlying cash operating costs (defined in the non-IFRS measures section), amounted to $145 million; $9.0/boe (1H 2018: $181million; $10.9/boe). The decrease in operating costs per barrel is largely as a result of the phasing of non-routine activity in the second half of 2019.

DD&A charges before impairment on production and development assets amounted to $287 million; $17.9/boe (1H 2018: $290 million; $17.5/boe), the increase in DD&A per barrel is attributed to 2018 impairment reversals.

Administrative expenses of $55 million (1H 2018: $59 million) were in line with the prior period.

Impairment of property, plant and equipment, net	1H 2019	1H 2018
Pre-tax impairment of property, plant and equipment, net ($m)	12	8
Associated deferred tax credit ($m)	-	-
Post-tax impairment of property, plant and equipment, net ($m)	12	8

The Group incurred a non-cash impairment of property, plant, and equipment due to minor changes to estimates on the cost of decommissioning certain UK assets.

Exploration costs written off	1H 2019	1H 2018
Exploration costs written off ($m)	81	9

During the first half of 2019 the Group recorded exploration write-off costs of $81 million which predominantly related to Mauritania Block C3, Kenya Block 12A and ongoing New Venture activities.

Derivative financial instruments

Tullow continues to undertake hedging activities as part of its ongoing financial risk management to protect against oil price volatility and to ensure the availability of cashflow for reinvestment in capital programmes that are driving business growth.

At 30 June 2019, the Group's derivative instruments had a net negative fair value of $2.4 million (1H 2018: negative $142 million), inclusive of deferred premium.

2H 2019 Hedge position At 30 June 2019	Bopd	Bought put(floor)	Sold call	Bought call
Hedge structure
Collars	21,500¹	$57.27	$82.13	-
Three- way collars (call spread)	25,500¹	$53.99	$72.33	$78.59
Straight puts	4,000	$69.24	-	-
Total/weighted average	51,000	$56.56	-	-

1. In 1H 2019, there were 11 trades. In 2H 2019, the number of bopd hedged decreases when compared to whole year.

The 2020 and 2021 hedging position at 30 June 2019 was 36,997 bopd and 11,500 bopd hedged with an average floor price protected of $58.28/bbl and $54.57/bbl respectively.

Net financing costs

Net financing costs for the period were $120 million (1H 2018: $145 million). The decrease in financing costs is associated with the reduction in interest on borrowings due to a reduction in the average level of net debt in the first half of 2019 compared to 2018 and foreign exchange gains. This was partially offset by an increased interest charge following the implementation of IFRS 16 Leases accounted for from 1 January 2019 as set out in Note 18. 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 finance lease assets, offset by interest earned on cash deposits and capitalised borrowing costs. A reconciliation of net financing costs is included in Note 8.

Taxation

The overall net tax expense of $165 million (1H 2018: $96 million) primarily relates to expenses in respect of Ghana and West Africa non-operated assets and non-recurring deferred tax credits associated with exploration write-offs, impairments and onerous lease provisions.

The Group's statutory effective tax rate is 61.6%. After adjusting for the non-recurring amounts related to exploration write-offs, impairments, disposals and onerous lease provisions and their associated deferred tax benefit, the Group's underlying effective tax rate is 49% (1H 2018: 48%). The underlying tax rate has remained similar due to the comparable geographical mix of profits largely generated in production territories of Ghana, Gabon and Equatorial Guinea.

Profit after tax from continuing activities and basic earnings per share

The profit from continuing activities for the period amounted to $103 million (1H 2018: $55 million). Basic profit per share was 7.4 cents (1H 2018: 3.9 cents).

Reconciliation of net debt	$m
Year-end 2018 net debt	3,060
Sales revenue	(872)
Other operating income - lost production insurance proceeds	(29)
Operating costs	144
Operating expenses	16
Cash flow from operations	(741)
Movement in working capital	21
Tax paid	123
Dividends paid	68
Purchases of intangible exploration and evaluation assets and property, plant, and equipment	251
Other investing activities	(12)
Other financing activities	176
Foreign exchange gain on cash and debt	2
1H 2019 net debt	2,948

Capital investment

Capital expenditure amounted to $248 million (1H 2018: $145 million) with $212 million invested in development activities and $36 million in exploration and appraisal activities. More than 56% of the total was invested in Ghana and 92% was invested in Africa.

The Group's 2019 capital investment associated with operating activities is expected to total approximately $570 million. This total excludes c.$60 million of forecast Uganda expenditure which is expected to be repaid from either the working capital completion adjustment or deferred consideration following the completion of the Uganda farm-down. The capex total comprises Ghana capex of c.$250 million, West Africa non-operated capex of c.$100 million, Kenya pre-development expenditure of c.$75 million and Exploration and Appraisal expenditure of c.$145 million. At completion of the Uganda farm-down, Tullow is also due to receive $100 million of cash consideration along with re-imbursement of capex of c.$115 million. As part of the Uganda farm-down, a further $50 million of cash consideration is due to be received when FID is achieved.

Liquidity risk management and going concern

The Group closely monitors and manages its liquidity risk. Cash forecasts are regularly produced and sensitivities run for different scenarios including, but not limited to, changes in commodity prices and different production rates from the Group's producing assets. The Group had approximately $1.0 billion of debt liquidity headroom and free cash at 30 June 2019. The Group's forecasts show that the Group will have sufficient financial headroom for the 12 months from the date of approval of the half year results. Therefore, the Directors have a reasonable expectation that the Company has adequate resources to continue in operational existence for the foreseeable future. Thus, they continue to adopt the going concern basis of accounting in preparing the Half Year Results.

2019 principal financial risks and uncertainties

The Board determines the key risks for the Group and monitors mitigation plans and performance on a monthly basis. Details of the principal risks and uncertainties facing the Group at the half year results are unchanged from the risks disclosed in the 2018 Annual Report and are listed below. The Group's risk mitigation activities also remain unchanged.

1. Risk of inability to make new significant oil discoveries and replenish exploration and subsurface portfolio

2. Risk of failure to deliver commercially attractive and timely Kenya development

3. Risk of failure to deliver commercially attractive and timely Uganda development

4. Risk of disruption to business due to political/regulatory influence in Ghana

5. Risk of disruption to business due to community and political influence in Kenya

6. Risk of major process safety or EHS failure in Ghana

7. Risk of major cyber or information security incident

8. Insufficient liquidity and funding capacity

9. Risk of failure to have a sustainable, balanced, diverse workforce and attractive employee proposition

10. Risk of major breach of business conduct standards or non-compliance with major contracts or legal /regulatory obligations

Events since 30 June 2019

There have not been any events since 30 June 2019 that have resulted in a material impact on the Half Year Results.

Non-IFRS measures

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

The following notes describe why the group has selected these non-IFRS measures and reconciles them to the nearest equivalent IFRS measure.

Capital investment

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

	1H 2019 $m	1H 2018 $m
Additions to property, plant, and equipment	317.7	106.7
Additions to intangible exploration and evaluation assets	112.2	105.5
Less
Lease asset additions¹	127.1	-
Decommissioning asset additions ²	22.7	14.1
Lease payments related to capital activities¹	(1.4)	-
Capitalised share-based payment charge ³	0.6	0.6
Capitalised finance costs ⁴	12.1	32.7
Additions to administrative assets⁵	5.2	2.0
Norwegian tax refund ⁶	-	0.2
Uganda capital investment ⁷	16.3	23.1
Other non-cash capital expenditure⁸	(0.7)	(5.5)
Capital investment	248.0	145.0
Movement in working capital	(18.4)	16.9
Additions to administrative assets	5.2	2.0
Norwegian tax refund	-	0.2
Uganda capital investment	16.3	23.1
Cash capital expenditure per the cash flow statement	251.1	187.2

Notes:

1. Lease asset additions relate to additions to property, plant and equipment required by IFRS 16 Leases. This standard was adopted as of 1 January 2019. As a result, an adjustment to the figures reported for 1H 2018 is not required. Lease payments related to capital activity relate to costs considered to be capital costs in nature. This adjustment is intended to ensure that all capital investments are included in this metric.

2. Decommissioning assets are recorded as an equal and opposite amount to the Group's decommissioning provisions. Decommissioning assets are depreciated over the life of the relevant asset until the point of decommissioning. Any increases in a provision due to a change in scope of the obligation results in an increase in the decommissioning asset. The asset is recorded under the property, plant and equipment line item in the balance sheet. Any new decommissioning assets, or increases in decommissioning assets, from the previous year are shown as additions to that line item.

3. Capitalised share-based payment charge relates to the portion of the non-cash share-based payment charge that relates to employees who work on capital projects.

4. Capitalised finance costs relate to the portion of the Group's borrowing costs that is deemed to fund development activities.

5. Administrative assets represent fixtures, fittings and office equipment such as computers. Because they are not directly attributable to the exploration or development of oil and gas, the Group excludes their costs from its definition of capital investment.

6. Capital expenditure is adjusted for the Norwegian tax refunds. The Norwegian tax refund represents 78% of the Group's qualifying exploration expenditure in Norway during each of each period. The refund is paid in the year following the year in which the expense is incurred.

7. Capital investment excludes Ugandan expenditure that will be recovered, subject to completion of the farm-down.

8. Other adjustments include cash re-imbursements for capital expenditure under sale and purchase agreements between their effective date and completion date and exclusion of other non-cash adjustments to fixed asset additions made in accordance with IFRS.

Net debt

Net debt is a useful indicator of the Group's indebtedness, financial flexibility and capital structure because it indicates the level of cash borrowings after taking account of cash and cash equivalents within the Group's business that could be utilised to pay down the outstanding cash borrowings. Net debt is defined as current and non-current borrowings plus non-cash adjustments, less cash and cash equivalents. Non-cash adjustments include unamortised arrangement fees, adjustment to convertible bonds, and other adjustments. The Group's definition of net debt does not include the Group's lease liabilities as the Group's focus is the management of cash borrowings and leases are viewed as deferred capital investment. The value of the Group's lease liabilities as at 30 June 2019 was $290.8 million current and $1,216.7 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.

	30 June 2019 $m	30 June 2018 $m
Current borrowings	-	-
Non-current borrowings	3,285.4	3,475.3
Non-cash adjustments¹	24.9	0.1
Less cash and cash equivalents²	(362.3)	(393.4)
Net debt	2,948.0	3,082.0

Notes:

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 Bonds, the fair value reduces until the carrying value of the borrowings are equal to the principal outstanding for repayment on maturity.

2. Cash and cash equivalents includes an amount of $231 million (1H 2018: $224 million) which the Group holds as operator in joint venture bank accounts. In addition to the cash held in joint venture bank accounts the Group had $31 million (1H 2018: $51 million) held in restricted bank accounts.

Gearing and adjusted EBITDAX

Gearing is a useful indicator of the Group's indebtedness, financial flexibility and capital structure and can assist securities analysts, investors and other parties to evaluate the Group. Gearing is defined as net debt divided by Adjusted EBITDAX. Adjusted EBITDAX is defined as profit from continuing activities adjusted for income tax (expense)/credit, finance costs, finance revenue, depreciation, depletion, amortisation, share-based payment charge, restructuring costs, gain/(loss) on disposal, goodwill impairment, exploration costs written off, impairment of property, plant and equipment net, provisions for inventory, provision for onerous service contracts and including operating lease costs to be consistent with its calculation before the introduction of IFRS 16.

Detailed reconciliation of adjusted EBITDAX to figures reported within the half year results has not been presented as the figures reported within the Half Year Results are not presented on a last twelve months basis.

		As at 1H 2019 $m		As at 1H 2018 $m
Adjusted EBITDAX (last twelve months basis)	1,623.2		1,579.0
Net debt	2,948.0		3,082.0
Gearing (times)	1.8		2.0

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. Underlying cash operating costs is defined as cost of sales less 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 2019 $m	1H 2018 $m
Cost of sales	375.1	513.6
Add
Lease payments related to operating activity¹	0.9	-
Less
Depletion and amortisation of oil and gas assets ²	290.8	289.9
Underlift, overlift, and oil stock movements ³	(86.4)	27.4
Share-based payment charge included in cost of sales ⁴	0.5	0.8
Other cost of sales ⁴	26.1	14.5
Underlying cash operating costs	145.0	181.0
Working Interest Production (MMboe)	16.1	16.54
Underlying cash operating costs per boe ($/boe)	9.0	10.9

Notes:

1. Lease payments related to operating activity are costs considered to be operating costs in nature. This adjustment is intended to ensure that all cash operating costs are included in this metric. IFRS 16 Leases requires that the present value of contracted cash flows is recorded as a property, plant and equipment asset, with the related depreciation and amortisation of oil and gas assets recording the expense related to these contracts. An adjustment is therefore required to include the cash costs related to leases entered for operating activities. This also ensures consistent presentation with prior years.

2. 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.

3. 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.

4. 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.

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

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, foreign exchange gains or losses, and distribution to non-controlling interests.

	1H 2019 $m	1H 2018* $m
Net cash from operating activities	597.4	759.5
Net cash used in investing activities	(239.1)	(185.9)
Net cash generated by financing activities	(175.8)	(468.7)
Repayment of bank loans	160.0	1,210.1
Drawdown of bank loans	(230.0)	(930.0)
Foreign exchange (gain)/loss	-	4.5
Dividends paid	68.3	-
Free cash flow	180.8	389.5
Dividends paid	(68.3)	-
Free cash flow after dividend payment	112.5	389.5

*Free cash flow for 1H 2018 has been represented to exclude debt arrangement fees to be consistent with the disclosure in the Annual Report and Accounts.

Responsibility statement

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';

b. the interim management report includes a fair review of the information required by DTR 4.2.7R (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 (disclosure of related parties' transactions and changes therein).

The Directors of Tullow Oil plc are as listed in the Group's 2018 Annual Report and Accounts. A list of the current Directors is maintained on the Tullow Oil plc website: www.tullowoil.com.

By order of the Board,

Paul McDade Les Wood

Chief Executive Officer Chief Financial Officer

23 July 2019 23 July 2019

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

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 2019 which comprises the Income Statement, the Balance Sheet, the Statement of Changes in Equity, the Cash Flow Statement and related notes 1 to 18. 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.

This report is made solely to the company in accordance with International Standard on Review Engagements (UK and Ireland) 2410 "Review of Interim Financial Information Performed by the Independent Auditor of the Entity" issued by the Financial Reporting Council. Our work has been undertaken so that we might state to the company those matters we are required to state to it in an independent review report and for no other purpose. To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the company, for our review work, for this report, or for the conclusions we have formed.

Directors' responsibilities

The half-yearly financial report is the responsibility of, and has been approved by, 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.

As disclosed in note 2, the annual financial statements of the group are prepared in accordance with IFRSs as adopted by 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 34 "Interim Financial Reporting" as adopted by the European Union.

Our responsibility

Our responsibility is to express to the Company a conclusion on the condensed set of financial statements in the half-yearly financial report based on our review.

Scope of review

We conducted our review in accordance with International Standard on Review Engagements (UK and Ireland) 2410 "Review of Interim Financial Information Performed by the Independent Auditor of the Entity" issued by the Financial Reporting Council for use in the United Kingdom. A review of interim financial information consists of making inquiries, 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.

Conclusion

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 2019 is not prepared, in all material respects, in accordance with International Accounting Standard 34 as adopted by the European Union and the Disclosure Guidance and Transparency Rules of the United Kingdom's Financial Conduct Authority.

Deloitte LLP

Statutory Auditor

London

23 July 2019

Condensed consolidated income statement Six months ended 30 June 2019
		Notes	6 months ended 30.06.19 Unaudited $m	6 months ended 30.06.18 Unaudited $m	Year ended 31.12.18 Audited $m
Continuing activities
Sales revenue			872.3	905.1	1,859.2
Other operating income - lost production insurance proceeds			29.3	129.3	188.4
Cost of sales		7	(375.1)	(513.6)	(966.0)
Gross profit			526.5	520.8	1,081.6
Administrative expenses		7	(55.1)	(59.5)	(90.3)
Restructuring costs		7	(1.2)	(1.5)	(3.4)
Gain on disposal			8.8	4.9	21.3
Exploration costs written off		10	(81.2)	(8.6)	(295.2)
Impairment of property, plant and equipment, net		11	(11.5)	(7.9)	(18.2)
Provision for onerous service contracts, net			1.3	(149.3)	(167.4)
Operating profit			387.6	298.9	528.4
Gain/(loss) on hedging instruments			0.9	(3.5)	2.4
Finance revenue		8	38.7	31.7	58.4
Finance costs		8	(158.8)	(176.6)	(328.7)
Profit from continuing activities before tax			268.4	150.5	260.5
Income tax expense		9	(165.2)	(96.0)	(175.1)
Profit for the year from continuing activities			103.2	54.5	85.4
Attributable to:
Owners of the Company			103.2	53.9	84.8
Non-controlling interest			-	0.6	0.6
			103.2	54.5	85.4
Earnings per ordinary share from continuing activities			¢	¢	¢
Basic		3	7.4	3.9	6.1
Diluted		3	7.1	3.7	5.9
Condensed consolidated statement of comprehensive income and expense Six months ended 30 June 2019
			6 months ended 30.06.19 Unaudited $m	6 months ended 30.06.18 Unaudited $m	Year ended 31.12.18 Audited $m
Profit for the period			103.2	54.5	85.4
Items that may be reclassified to the income statement in subsequent periods
Cash flow hedges
(Losses)/gains arising in the period			(120.2)	(67.1)	100.7
(Losses)/gains arising in the period - time value			(43.9)	(34.7)	16.2
Reclassification adjustments for items included in profit on realisation			1.2	13.4	32.7
Reclassification adjustments for items included in profit on realisation - time value			31.5	26.0	52.7
Exchange differences on translation of foreign operations			0.3	2.5	(15.4)
Other comprehensive expense			(131.1)	(59.9)	186.9
Tax relating to components of other comprehensive expense			-	-	-
Net other comprehensive expense for the period			(131.1)	(59.9)	186.9
Total comprehensive expense for the period			(27.9)	(5.4)	272.3
Attributable to:
Owners of the Company			(27.9)	(6.0)	271.7
Non-controlling interest			-	0.6	0.6
			(27.9)	(5.4)	272.3
Condensed consolidated balance sheet As at 30 June 2019
	Notes		30.06.19 Unaudited $m	30.06.18 Unaudited $m	31.12.18 Audited $m
ASSETS
Non-current assets
Intangible exploration and evaluation assets	10		1,860.3	2,010.6	1,898.6
Property, plant and equipment	11		4,902.8	5,052.8	4,916.4
Investments			-	1.0	-
Other non-current assets	12		666.4	751.6	696.4
Derivative financial instruments			11.2	-	51.2
Deferred tax assets			614.2	783.1	649.4
			8,054.9	8,599.1	8,212.0
Current assets
Inventories			243.9	187.8	134.8
Trade receivables			225.6	87.2	159.4
Other current assets	12		879.1	829.2	969.0
Current tax assets			133.7	56.1	60.5
Derivative financial instruments			1.8	1.3	79.7
Cash and cash equivalents			362.3	393.4	179.8
Assets classified as held for sale	13		912.0	893.9	840.2
			2,758.4	2,448.9	2,423.4
Total assets			10,813.3	11,048.0	10,635.4
LIABILITIES
Current liabilities
Trade and other payables	14		(1,305.5)	(1,112.4)	(1,204.3)
Provisions	15		(220.2)	(391.0)	(198.5)
Borrowings			-	-	-
Current tax liabilities			(86.7)	(37.5)	(83.0)
Derivative financial instruments			(15.2)	(98.8)	(2.7)
Liabilities classified as held for sale	13		-	-	-
			(1,627.6)	(1,639.7)	(1,488.5)
Non-current liabilities
Trade and other payables	14		(1,298.0)	(1,355.3)	(1,282.3)
Borrowings			(3,285.4)	(3,475.3)	(3,219.1)
Provisions	15		(638.6)	(741.1)	(677.0)
Deferred tax liabilities			(1,152.0)	(1,207.6)	(1,075.3)
Derivative financial instruments			(0.2)	(44.7)	-
			(6,374.2)	(6,824.0)	(6,253.7)
Total liabilities			(8,001.8)	(8,463.7)	(7,742.2)
Net assets			2,811.5	2,584.3	2,893.2
EQUITY
Called up share capital	16		210.3	208.9	209.1
Share premium	16		1,371.9	1,340.3	1,344.2
Equity component of convertible bonds			48.4	48.4	48.4
Foreign currency translation reserve			(238.3)	(220.7)	(238.6)
Hedge reserve			11.8	(56.3)	130.8
Hedge reserve - Time value			(17.3)	(82.5)	(4.9)
Other reserves			755.2	740.9	755.2
Retained earnings			669.5	594.3	649.0
Equity attributable to equity holders of the Company			2,811.5	2,573.3	2,893.2
Non-controlling interest			-	11.0	-
Total equity			2,811.5	2,584.3	2,893.2

Condensed statement of changes in equity

As at 30 June 2019

	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	Other reserves³ $m	Retained earnings $m	Total $m	Non-controlling interest $m	Total Equity $m
At 1 January 2018	208.2	1,326.8	48.4	(223.2)	(2.6)	(73.8)	740.9	681.3	2,706.0	10.4	2,716.4
Adjustment on adoption of IFRS 9, net of tax	-	-	-	-	-	-	-	(143.5)	(143.5)	-	(143.5)
Profit for the period	-	-	-	-	-	-	-	53.9	53.9	0.6	54.5
Hedges, net of tax	-	-	-	-	(53.7)	(8.7)	-	-	(62.4)	-	(62.4)
Currency translation adjustments	-	-	-	2.5	-	-	-	-	2.5	-	2.5
Issue of shares	0.7	13.5	-	-	-	-	-	-	14.2	-	14.2
Transfers	-	-	-	-	-	-	-	(14.2)	(14.2)	-	(14.2)
Share-based payment charges	-	-	-	-	-	-	-	16.8	16.8	-	16.8
At 30 June 2018	208.9	1,340.3	48.4	(220.7)	(56.3)	(82.5)	740.9	594.3	2,573.3	11.0	2,584.3
Adjustment on adoption of IFRS 9, net of tax	-	-	-	-	-	-	-	32.7	32.7	-	32.7
Profit for the period	-	-	-	-	-	-	-	30.9	30.9	-	30.9
Hedges, net of tax	-	-	-	-	187.1	77.6	-	-	264.7	-	264.7
Currency translation Adjustments	-	-	-	(17.9)	-	-	-	-	(17.9)	-	(17.9)
Issue of shares	0.2	3.9	-	-	-	-	-	-	4.1	-	4.1
Vesting of employee share options	-	-	-	-	-	-	-	(18.2)	(18.2)	-	(18.2)
Transfers	-	-	-	-	-	-	14.3	-	14.3	-	14.3
Share-based payment charges	-	-	-	-	-	-	-	9.3	9.3	-	9.3
Acquisition of non-controlling interests	-	-	-	-	-	-	-	-	-	(11.0)	(11.0)
At 1 January 2019	209.1	1,344.2	48.4	(238.6)	130.8	(4.9)	755.2	649.0	2,893.2	-	2,893.2
Profit for the period								103.2	103.2	-	103.2
Hedges, net of tax	-	-	-	-	(119.0)	(12.4)	-	-	(131.4)	-	(131.4)
Currency translation adjustments	-	-	-	0.3	-	-	-	-	0.3	-	0.3
Issue of shares	1.2	27.7	-	-	-	-	-	-	28.9	-	28.9
Vesting of PSP shares	-	-	-	-	-	-	-	(28.9)	(28.9)	-	(28.9)
Share-based payment charges	-	-	-	-	-	-	-	14.5	14.5	-	14.5
Dividends paid	-	-	-	-	-	-	-	(68.3)	(68.3)	-	(68.3)
At 30 June 2019	210.3	1,371.9	48.4	(238.3)	11.8	(17.3)	755.2	669.5	2,811.5	-	2,811.5

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

Condensed consolidated cash flow statement Six months ended 30 June 2019
	Notes	6 months ended 30.06.19 Unaudited $m	6 months ended 30.06.18 Unaudited $m	Year ended 31.12.18 Audited $m
Cash flows from operating activities
Profit before taxation		268.4	150.5	260.5
Adjustments for:
Depreciation, depletion, and amortisation		303.3	298.9	584.1
Gain on disposal		(8.8)	(4.9)	(21.3)
Exploration costs written off	10	81.2	8.6	295.2
Impairment of property, plant and equipment, net	11	11.5	7.9	18.2
Provision for onerous service contracts, net		(1.3)	149.3	167.4
Payment under onerous service contracts		(13.8)	-	(208.6)
Decommissioning expenditure		(30.6)	(59.0)	(99.1)
Share-based payment charge		12.0	12.7	23.8
(Gain)/loss on hedging instruments		(0.9)	3.5	(2.4)
Finance revenue	8	(38.7)	(31.7)	(58.4)
Finance costs	8	158.8	176.6	328.7
Operating cash flow before working capital movements		741.1	712.4	1,288.1
Decrease/(increase) in trade and other receivables		93.9	43.0	(100.2)
(Increase)/decrease in inventories		(108.9)	(20.5)	32.5
(Decrease)/increase in trade payables		(6.1)	82.1	86.9
Cash flows from operating activities		720.0	817.0	1,307.3
Taxes paid		(122.6)	(57.5)	(103.3)
Net cash from operating activities		597.4	759.5	1,204.0
Cash flows from investing activities
Proceeds from disposals		8.8	-	9.9
Purchase of intangible exploration and evaluation assets		(104.8)	(93.1)	(202.1)
Purchase of property, plant and equipment		(146.3)	(94.1)	(238.4)
Interest received		3.2	1.3	2.9
Net cash used in investing activities		(239.1)	(185.9)	(427.7)
Cash flows from financing activities
Debt arrangement fees		-	(11.5)	(15.0)
Repayment of borrowings		(160.0)	(1,210.1)	(1,755.1)
Drawdown of borrowings		230.0	930.0	1,240.0
Repayment of obligations under leases		(82.5)	(57.4)	(117.4)
Finance costs paid		(95.0)	(119.7)	(234.5)
Dividends paid		(68.3)	-	-
Net cash used in financing activities		(175.8)	(468.7)	(882.0)
Net increase/(decrease) in cash and cash equivalents		182.5	104.9	(105.7)
Cash and cash equivalents at beginning of period		179.8	284.0	284.0
Foreign exchange (loss)/gain		-	4.5	1.5
Cash and cash equivalents at end of period		362.3	393.4	179.8

Notes to the preliminary financial statements

Six months ended 30 June 2019

1. General information

The condensed financial statements for the six month period ended 30 June 2019 have been prepared in accordance with International Accounting Standard (IAS) 34 Interim Financial Reporting 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 2018, which were prepared in accordance with International Financial Reporting Standards (IFRS) adopted for use by 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 2018 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 2018, 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 are prepared in accordance with IFRSs as issued by the International Accounting Standards Board and as adopted by 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 34 'Interim Financial Reporting', as adopted by the European Union and the Disclosure and Transparency Rules of the Financial Services Authority.

Basis of preparation

The condensed set of financial statements included in this half-yearly financial report has been prepared on a going concern basis as the Directors consider that the Group has adequate resources to continue in operational existence for the foreseeable future as explained in the Finance Review.

The accounting policies adopted in the 2019 half-yearly financial report are the same as those adopted in the 2018 Annual report and accounts other than the implementation of new International Financial Reporting Standards adopted:

IFRS 16 Leases

The Group implemented IFRS 16 Leases effective from 1 January 2019. Refer to note 18 for further details.

3. Earnings per 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 $103.2 million (1H 2018: $53.9 million) and a weighted average number of shares in issue of 1,399.2 million (1H 2018: 1,389.5 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 48.6 million (1H 2018: 49.7 million) resulting in a diluted weighted average number of shares of 1,447.8 million (1H 2018: 1,439.2 million).

4. Dividends

The Directors have approved an interim dividend of 2.35 cents/share (2018 interim dividend: Nil). A final 2018 dividend of 4.8 cents/share totalling $68 million (2017 final dividend: Nil) was paid in 2019.

5. Approval of accounts

These unaudited Half year results were approved by the Board of Directors on 23 July 2019.

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 three business delivery teams, West Africa (including non-operated producing European assets), East Africa and New Ventures. The Group has one class of business, being the exploration, development, production and sale of hydrocarbons and therefore the Group's reportable segments under IFRS 8 are West Africa; East Africa; and New Ventures. The following tables present revenue, profit and certain asset and liability information regarding the Group's business segments for the six months ended 30 June 2019, the six months ended 30 June 2018, and the year ended 31 December 2018.

	West Africa $m	East Africa $m	New Ventures $m	Unallocated $m	Total $m
Six months ended 30 June 2019 Sales revenue by origin	872.3	-	-	-	872.3
Other operating income - lost production insurance proceeds	-	-	-	29.3	29.3
Segment result	474.6	(34.1)	(37.6)	32.2	435.1
Gain on disposal					8.8
Unallocated corporate expenses					(56.3)
Operating profit					387.6
Gain on hedging instruments					0.9
Finance revenue					38.7
Finance costs					(158.8)
Profit before tax					268.4
Income tax expense					(165.2)
Profit after tax					103.2
Total assets	7,698.1	2,731.0	263.5	120.7	10,813.3
Total liabilities	(4,445.3)	(163.8)	(48.4)	(3,344.3)	(8,001.8)
Other segment information
Capital expenditure:
Property, plant and equipment	267.8	12.8	2.1	35.0	317.7
Intangible exploration and evaluation assets	6.7	67.1	38.4	-	112.2
Depletion, depreciation and amortisation	(291.9)	(0.7)	(0.2)	(10.5)	(303.3)
Impairment of property, plant and equipment, net	(11.5)	-	-	-	(11.5)
Exploration costs written off	(8.4)	(34.3)	(38.5)	-	(81.2)

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

6. Segmental reporting contd.
	West Africa $m	East Africa $m	New Ventures $m	Unallocated $m	Total $m
Six months ended 30 June 2018 Sales revenue by origin	905.1	-	-	-	905.1
Other operating income - lost production insurance proceeds	-	-	-	129.3	129.3
Segment result	385.0	(0.5)	(7.1)	(22.4)	355.0
Gain on disposal					4.9
Unallocated corporate expense					(61.0)
Operating profit					298.9
Loss on hedging instruments					(3.5)
Finance revenue					31.7
Finance costs					(176.6)
Profit before tax					150.5
Income tax expense					(96.0)
Profit after tax					54.5
Total assets	7,690.9	2,650.9	308.7	397.5	11,048.0
Total liabilities	(4,397.4)	(147.1)	(71.7)	(3,847.5)	(8,463.7)

Other segment information
Capital expenditure:
Property, plant and equipment	104.6	0.8	0.3	1.0	106.7
Intangible exploration and evaluation assets	1.5	84.3	19.7	-	105.5
Depletion, depreciation and amortization	(291.4)	(0.1)	-	(7.4)	(298.9)
Impairment of property, plant and equipment, net	(7.9)	-	-	-	(7.9)
Exploration costs written off/(reversed)	-	-	(8.6)	-	(8.6)
Year ended 31 December 2018 Sales revenue by origin	1,859.2	-	-	-	1,859.2
Other operating income - lost production insurance proceeds	-	-	-	188.4	188.4
Segment result	528.0	(74.5)	(100.7)	(248.0)	(600.8)
Gain on disposal					21.3
Unallocated corporate expenses					(93.7)
Operating profit					528.4
Gain on hedging instruments					2.4
Finance revenue					58.4
Finance costs					(328.7)
Profit before tax					260.5
Income tax expense					(175.1)
Profit after tax					85.4
Total assets	7,618.9	2,662.0	280.8	73.7	10,635.4
Total liabilities	(4,252.7)	(141.8)	(96.9)	(3,250.8)	(7,742.2)
Other segment information
Capital expenditure: Property, plant and equipment	257.1	1.4	4.3	5.3	268.1
Intangible exploration and evaluation assets	2.1	168.3	60.0	-	230.4
Depletion, depreciation and amortization	(569.2)	(0.2)	-	(14.7)	(584.1)
Impairment of property, plant and equipment	(18.2)	-	-	-	(18.2)
Exploration costs written off	(139.9)	(74.5)	(80.8)	-	(295.2)

	Sales revenue 6 months ended 30.06.19 $m	Sales revenue 6 months ended 30.06.18 $m	Sales revenue Year ended 31.12.18 $m	*Non-current assets 30.06.19 $m	*Non-current assets 30.06.18 $m	*Non-current assets 31.12.18 $m
Congo	-	-	1.1	-	-	-
Côte d'Ivoire	44.1	41.6	44.9	84.8	68.0	86.7
Equatorial Guinea	58.8	72.4	146.6	65.9	109.9	72.2
Gabon	101.5	105.0	213.6	155.9	149.5	171.1
Ghana	667.9	655.2	1,404.1	5,112.5	5,498.3	5,171.5
Mauritania	-	2.2	2.1	-	-	-
UK	-	28.7	46.8	-	-	-
Total West Africa	872.3	905.1	1,859.2	5,419.1	5,825.7	5,501.5
Kenya	-	-	-	1,135.9	1,093.6	1,131.2
Uganda	-	-	-	603.3	608.2	631.9
Total East Africa	-	-	-	1,739.2	1,701.8	1,763.1
Norway	-	-	-	11.7	13.0	12.3
Other	-	-	-	170.0	205.4	169.7
Total New ventures	-	-	-	181.7	218.4	182.0
Unallocated	-	-	-	89.6	70.1	63.8
Total	872.3	905.1	1,859.2	7,429.6	7,816.0	7,511.4

*Excludes derivative financial instruments and deferred tax assets.

7. Operating profit

	6 months ended 30.06.19 Unaudited $m	6 months ended 30.06.18 Unaudited $m	Year ended 31.12.18 Audited $m
Cost of sales
Operating costs	144.1	181.0	327.0
Depletion and amortisation of oil and gas assets	290.8	289.9	567.7
Underlift, overlift and oil inventory movement	(86.4)	27.4	40.7
Share-based payment charge included in cost of sales	0.5	0.8	1.0
Other cost of sales	26.1	14.5	29.6
Total cost of sales	375.1	513.6	966.0
Administrative expenses
Share-based payment charge included in administrative expenses	3.5	11.9	22.8
Depreciation of other fixed assets	12.5	9.0	16.4
Relocation costs associated with restructuring	-	(0.9)	(1.3)
Other administrative costs	39.1	39.5	52.4
Total administrative expenses	55.1	59.5	90.3
Restructuring costs
Total restructuring costs	1.2	1.5	3.4

8. Net financing costs

	6 months ended 30.06.19 Unaudited $m	6 months ended 30.06.18 Unaudited $m	Year ended 31.12.18 Audited $m
Interest on bank overdrafts and borrowings	108.6	145.5	276.0
Interest on obligations for leases	53.3	49.3	101.5
Total borrowing costs	161.9	194.8	377.5
Less amounts included in the cost of qualifying assets	(12.1)	(32.7)	(65.3)
	149.8	162.1	312.2
Finance and arrangement fees	0.4	-	(0.6)
Other Interest expense	1.2	-	2.7
Foreign exchange losses	-	6.4	-
Unwinding of discount on decommissioning provisions	7.4	8.1	14.4
Total finance costs	158.8	176.6	328.7
Interest income on amounts due from joint venture partners for leases	(35.6)	(24.2)	(52.7)
Other finance revenue	(3.1)	(7.5)	(5.7)
Total finance revenue	(38.7)	(31.7)	(58.4)
Net financing costs	120.1	144.9	270.3

9. Taxation on profit on ordinary activities

10. Intangible exploration and evaluation assets

		6 months ended 30.06.19 Unaudited $m	6 months ended 30.06.18 Unaudited $m		Year ended 31.12.18 Audited $m
At 1 January		1,898.6	1,933.4		1,933.4
Additions		112.2	105.5		230.4
Disposals		-	-		(4.0)
Amounts written off		(81.2)	(8.6)		(295.2)
Net transfer to assets held for sale		(71.5)	(21.2)		32.2
Currency translation adjustments		2.2	1.5		1.8
At 30 June/31 December		1,860.3	2,010.6		1,898.6
Exploration costs written off/(reversed)	Rationale for write-off 6 months ended 30.06.19	Write off 30.06.19 Unaudited $m		Remaining recoverable amount 30.06.19 Unaudited $m
Kenya Block 12A	b	36		-
Mauritania Block C3	b	29		-
Other	a	6		-
New ventures	c	10		-
Exploration costs written off		81		-

a. Current year expenditure/(credits) on assets previously written off

b. Licence relinquishments

c. New ventures expenditure is written off as incurred

11. Property, plant and equipment

	Oil and gas assets 6 months ended 30.06.19 Unaudited $m	Leased assets 6 months ended 30.06.19 Unaudited $m	Other fixed assets 6 months ended 30.06.19 Unaudited $m	Total 6 months ended 30.06.19 Unaudited $m	Oil and gas assets 6 months ended 30.06.18 Unaudited $m	Other fixed assets 6 months ended 30.06.18 Unaudited $m	Total 6 months ended 30.06.18 Unaudited $m	Oil and gas assets Year ended 31.12.18 Audited $m	Other fixed assets Year ended 31.12.18 Audited $m	Total Year ended 31.12.18 Audited $m
Cost
At 1 January	11,794.0	-	271.0	12,065.0	11,592.6	279.7	11,872.3	11,592.6	279.7	11,872.3
Adjustment on adoption of IFRS 16 leases¹	(907.7)	907.7	-	-	-	-	-	-	-	-
Additions²	185.4	127.1	5.2	317.7	104.7	2.0	106.7	261.5	6.6	268.1
Disposals	-	-	-	-	-	(0.4)	(0.4)	-	(0.7)	(0.7)
Currency translation adjustments	(3.6)	-	(0.7)	(4.3)	(22.4)	(6.0)	(28.4)	(60.1)	(14.6)	(74.7)
At 30 June/31 December	11,068.1	1,034.8	275.5	12,378.4	11,674.9	275.3	11,950.2	11,794.0	271.0	12,065.0
Depreciation, depletion and amortisation
At 1 January	(6,951.1)	-	(197.5)	(7,148.6)	(6,425.3)	(192.3)	(6,617.6)	(6,425.3)	(192.3)	(6,617.6)
Adjustment on adoption of IFRS 16 leases¹	64.8	(64.8)	-	-	-	-	-	-	-	-
Charge for the year	(287.1)	(7.4)	(8.8)	(303.3)	(289.9)	(9.0)	(298.9)	(567.7)	(16.4)	(584.1)
Impairment loss	(11.5)	-	-	(11.5)	(7.9)	-	(7.9)	(55.8)	-	(55.8)
Reversal of impairment loss	-	-	-	-	-	-	-	37.6	-	37.6
Capitalised depreciation	-	(15.8)	-	(15.8)	-	-	-	-	-	-
Disposal	-	-	-	-	-	0.4	0.4	-	0.7	0.7
Currency translation adjustments	3.2	-	0.4	3.6	22.0	4.6	26.6	60.1	10.5	70.6
At 30 June/31 December	(7,181.7)	(88.0)	(205.9)	7,475.6	(6,701.1)	(196.3)	(6,897.4)	(6,951.1)	(197.5)	(7,148.6)
Net book value at 30 June/31 December	3,886.4	946.8	69.6	4,902.8	4,973.8	79.0	5,052.8	4,842.9	73.5	4,916.4

1. Items reclassed from oil and gas assets to lease assets on adoption of IFRS 16.

2. Additions during the period reflect the impact of IFRS 16 and amounts capitalised in 1H 2019 and the treatment of previous finance lease balances.

12. Other assets

	30.06.19 Unaudited $m	30.06.18 Unaudited $m	31.12.18 Audited $m
Non-current
Amounts due from joint venture partners	561.3	667.7	614.9
Uganda VAT recoverable	32.4	34.9	33.1
Other non-current assets	72.7	49.0	48.4
	666.4	751.6	696.4
Current
Amounts due from joint venture partners	630.4	502.9	670.8
Amounts due from joint venture partners related to current portion of leases	28.7	-	-
Underlifts	27.5	18.4	22.9
Prepayments	67.5	42.0	73.4
VAT & WHT recoverable	2.8	4.5	3.8
Other current assets	122.2	261.4	198.1
	879.1	829.2	969.0

13. Assets and liabilities classified as held for sale

In 2017, Tullow announced that it had agreed a substantial farm-down of its assets in Uganda. Under the Sale and Purchase Agreement, Tullow has agreed to transfer 21.57% of its 33.33% Uganda interests for a total consideration of $900 million subject to completion adjustments. Upon completion, the farm-down will leave Tullow with an 11.76% interest in the upstream and pipeline projects. This is expected to reduce to a 10% interest in the upstream project when the Government of Uganda formally exercises its back-in right. Although it has not yet been determined what interests the Governments of Uganda and Tanzania will take in the pipeline project, Tullow expects its interests in the upstream and pipeline projects to be aligned. The consideration is split into $200 million in cash, consisting of $100 million payable on completion of the transaction, $50 million payable at FID and $50 million payable at First Oil. The remaining $700 million is in deferred consideration and represents reimbursement in cash of a proportion of Tullow's past exploration and development costs. The deferred consideration is payable to Tullow as the upstream and pipeline projects progress and these payments will be used by Tullow to fund its share of the development costs. Tullow expects the deferred consideration to cover its share of upstream and pipeline development capex to First Oil and beyond. Completion of the transaction is subject to certain conditions, including the approval of the Government of Uganda, after which Tullow will cease to be an operator in Uganda. The disposal is expected to complete in the second half of 2019.

14. Trade and other payables

	30.06.19 Unaudited $m	30.06.18 Unaudited $m	31.12.18 Audited $m
Current
Trade payables	127.6	112.2	97.1
Other payables	138.2	163.7	105.1
Overlifts	37.0	56.9	16.6
Accruals	696.6	547.1	747.8
VAT and other similar taxes	15.3	18.9	16.5
Current portion of leases	290.8	213.6	221.2
	1,305.5	1,112.4	1,204.3
Non-current
Other non-current liabilities	81.3	101.1	91.3
Non-current portion of leases	1,216.7	1,254.2	1,191.0
	1,298.0	1,355.3	1,282.3

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 12). The change in trade payables and in other payables predominantly represents timing differences and levels of work activity.

The increase in the current and non-current portion of leases related to the implementation of IFRS 16 Leases. Refer to note 18 for further details.

15. Provisions

	30.06.19 Unaudited $m	30.06.18 Unaudited $m	31.12.18 Audited $m
Current
Decommissioning	158.2	119.5	121.6
Other	62.0	271.5	76.9
	220.2	391.0	198.5
Non-current
Decommissioning	635.0	734.6	672.4
Other	3.6	6.5	4.6
	638.6	741.1	677.0

16. Called up share capital and share premium

As at 30 June 2019, the Group had in issue 1,403.3 million allotted and fully paid ordinary shares of GBP 10 pence each (30 June 2018: 1,391.8 million).

In the six months ended 30 June 2019, the Group issued 9.9 million shares in respect of employee share options (1H 2018: 5.2 million new shares in respect of employee share options).

17. Contingencies

	30.06.19 Unaudited $m	30.06.18 Unaudited $m	31.12.18 Audited $m
Contingent liabilities
Performance guarantees	52.1	99.9	60.8
Other contingent liabilities	98.0	130.3	66.0
	150.1	230.2	126.8

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

Other contingent liabilities include amounts for ongoing legal disputes with third parties where we consider the likelihood of a cash outflow to be higher than remote but not probable.

18. Adoption of new accounting standards

The group adopted IFRS 16 Leases, for the year commencing 1 January 2019. On adoption of IFRS 16, the Group has recognised lease liabilities in relation to leases which were previously classified as 'operating leases' under the principles of IAS 17 Leases. These liabilities have been measured at the present value of the remaining lease payments, discounted using the interest rate implicit in the lease (if available), or the Group's incremental borrowing rate as of 1 January 2019, which was 6.9 per cent. The determination of whether there is an interest rate implicit in the lease, the calculation of the Group's incremental borrowing rate, and whether any adjustments to this rate are required for certain portfolios of leases involves some judgement and is subject to change over time.

In accordance with the transition provisions in IFRS 16 the modified retrospective approach has been adopted, with the cumulative effect of initially applying the new standard recognised on 1 January 2019. Comparatives for the 2018 financial year have not be restated. The financial impact of transition to IFRS 16 for the first half of financial year 2019 has been summarised within this note.

Lease liabilities related to operated Joint Ventures are disclosed gross with the debit representing the partner's share disclosed in amounts due from Joint Venture Partners.

The Group has identified lease portfolios for property, oil and gas production and support equipment, transportation equipment, and other equipment.

Lease portfolio	Examples	Gross value on transition $m
Property leases	Offices, staff rental property, warehouses, airport space	63.6
Oil and gas production and support equipment leases	Drilling rigs, support vessels	105.2
Transportation equipment leases	Cars and aircraft	26.2
Other equipment	Non-material equipment such as IS equipment	0.1
		195.1

Financial impact of the transition

Balance sheet

The Group impact of the transition has resulted in higher property, plant and equipment, current and non-current other assets and current and non-current lease liabilities.

For short term leases (lease term less than 12 months) and leases of low value assets the Group has opted to recognise a lease expense on a straight-line basis as permitted by IFRS 16. Depending on the nature of the lease, this is either recognised as additions to property, plant and equipment, operating costs or administrative costs.

30.06.19

Unaudited
$mm

Property, plant and equipment
Non Current	102.4
Other assets
Non current	23.8
Current	24.8
Lease Liabilities
Non Current	86.3
Current	68.9

Income statement

The Group impact of the transition resulted in a small net increase in operating costs and administrative expenses, along with a $5.7m increase in finance costs. The Group has recognised depreciation on right-of-use assets for the first half of 2019 of $17.1m, of which $14.8m has subsequently been capitalised through the Group's normal operations in accordance with relevant accounting policy. Interest on the Group's finance lease liabilities for the first half of 2019 was $5.7m, partly offset by interest on amounts due from Joint Venture Partners of $2.0m.

30.06.2019

Unaudited
$mm

Cost of Sales	(0.1)
Gross Profit	(0.1)
Admin Expenses	(0.4)
Operating Profit	(0.5)
Finance Revenue	2.0
Finance Costs	(5.7)
Profit /Loss	(4.2)
Deferred tax credit	1.2

Cash flow statement

Lease payments are now split between financing cash flows and operating cash flows in the cash flow statement. Financing cash flows represent repayment of principal, and operating cash flow payments of interest. In prior periods operating lease payments were all presented as operating cash flows under IAS 17. During the first half of 2019, the Group has a total cash outflow of $45.6m on qualifying leases.

Non-IFRS measures

As described above the implementation of IFRS 16 impacts operating costs and capital expenditure. However, Tullow has adjusted its definition of EBITDAX, cash operating costs and capital investment including expenditure previously recognised as operating lease costs and associated capital expenditure in the first half of 2019.

19. Commercial Reserves and Contingent Resources summary working interest basis

	West Africa		East Africa		New Ventures		TOTAL
	Oil mmbbl	Gas bcf	Oil mmbbl	Gas bcf	Oil mmbbl	Gas bcf	Oil mmbbl	Gas bcf	Petroleum mmboe
COMMERCIAL RESERVES
1 January 2019	236.2	259.9	-	-	-	-	236.2	259.9	279.5
Revisions	3.1	(19.9)	-	-	-	-	3.1	(19.9)	(0.1)
Disposals	-	-	-	-	-	-	-	-	-
Transfers	-	-	-	-	-	-	-	-	-
Production	(15.4)	(1.4)	-	-	-	-	(15.4)	(1.4)	(15.6)
30 June 2019	223.9	238.6	-	-	-	-	223.9	238.6	263.8
CONTINGENT RESOURCES
1 January 2019	137.3	436.0	656.7	42.7	-	-	794.0	478.7	873.6
Revisions	18.2	58.4	12.4		-	-	30.6	58.4	40.3
Disposals	-	-	-	-	-	-	-	-	-
Transfers	-	-	-	-	-	-	-	-	-
30 June 2019	155.5	494.4	669.1	42.7	-	-	824.6	537.1	913.9
TOTAL
30 June 2019	379.4	733.0	669.1	42.7	-	-	1,048.5	775.7	1,177.7

1. Proven and Probable Commercial Reserves are based on a Group reserves report produced by an independent engineer. Reserves estimates for each field are reviewed by the independent engineer based on significant new data or a material change with a review of each field undertaken at least every two years.

2. Proven and Probable Contingent Resources are based on both Tullow's estimates and the Group reserves report produced by an independent engineer.

The Group provides for depletion and amortisation of tangible fixed assets on a net entitlements basis, which reflects the terms of the Production Sharing Contracts related to each field. Total net entitlement reserves were 256.0 mmboe at 30 June 2019 (31 December 2018: 264.9 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 development within the foreseeable future.

About Tullow Oil plc

Tullow is a leading independent oil & gas, exploration and production group, quoted on the London, Irish and Ghanaian stock exchanges (symbol: TLW). The Group has interests in over 80 exploration and production licences across 15 countries which are managed as three business teams: West Africa, East Africa and New Ventures.

HALF YEAR RESULTS - EVENTS ON THE DAY

In conjunction with these Results, Tullow is conducting a Presentation in London that can be watched live or on replay.

09.00 GMT - UK/European conference call

To access the call please dial the appropriate number below shortly before the call and ask for the Tullow Oil plc conference call. The telephone numbers and access codes are:

Live event
All participants		+44 (0) 20 7192 8000
UK Freephone		0800 376 7922
Access Code		77 88 431

Webcast

To join the live video webcast or play the on-demand version, please use this link:
https://edge.media-server.com/mmc/p/otx94sdj. The replay will be available from noon on 24 July 2019.

FOR FURTHER INFORMATION, CONTACT:

Tullow Oil plc

(London)

+44 20 3249 9000

Julia Ross / Nicola Rogers (Investors)

ir@tullowoil.com

George Cazenove (Media)

Murray Consultants

(Dublin)

+353 1 498 0300

Pat Walsh

Joe Heron

Shareholder information

The Company offers a Dividend reinvestment plan ('DRIP') that gives shareholders on the UK share register the opportunity to use their cash dividends to buy Tullow Oil plc shares in the market. Shareholders wishing to elect to receive shares in lieu of cash dividend can access the downloadable documents and elect on-line at www.investorcentre.co.uk alternatively, contact our registrar, Computershare using the shareholder helpline telephone number +44 (0) 370 703 6242. Please note elections for the forthcoming dividend need to be received by Computershare by 13 September 2019.

Tullow shareholders with registered addresses in the UK will receive payment of their dividend in pounds sterling. Those with registered addresses in European countries which have adopted the Euro will receive payment of their dividend in Euros and those holding through the Ghana Stock Exchange will receive payment of their dividend in Ghanaian cedi. Shareholders with registered addresses in all other countries will be paid in pounds sterling. Most shareholders may elect to change the currency in which their dividend will be paid by contacting our registrar, Computershare, using the shareholder helpline telephone number +44 (0) 370 703 6242. Any such currency elections must be made by 13 September 2019.

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

Website: www.tullowoil.com

This information is provided by RNS, the news service of the London Stock Exchange. RNS is approved by the Financial Conduct Authority to act as a Primary Information Provider in the United Kingdom. Terms and conditions relating to the use and distribution of this information may apply. For further information, please contact rns@lseg.com or visit www.rns.com.

END

IR BRGDRSGDBGCX

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