# Tullow Oil plc $1.9 billion sales revenue; $411 million free cash flow

- Link: https://www.directorstalkinterviews.com/tullow-oil-plc-1-9-billion-sales-revenue-411-million-free-cash-flow/412767061
- Published: 2019-02-13T07:39:30+00:00
- Author: Charlotte Edwards

**Tullow Oil plc** (LON:TLW), the independent oil and gas exploration and production
group, announced its Full Year Results for the year ended 31 December 2018. 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:**
> “Tullow has worked hard over the past few years to become a self-funding, cash-
> generating business with a robust balance sheet, low-cost assets and a rigorous
> focus on cost and capital discipline. This has allowed us to set a clear capital
> returns policy which will start with the 2018 final dividend announced today. 
> Our high-margin producing assets in West Africa, substantial development assets
> in East Africa and exploration licences in industry hotspots provide Tullow with
> a strong foundation for growth in the years ahead.”

**2018 FULL YEAR RESULTS SUMMARY**

· Revenue of $1.9 billion; corporate Business Interruption insurance proceeds of
$188 million

· Gross profit of $1.1 billion; profit after tax of $85 million; free cash flow 
of $411 million; opex reduced to $10/barrel

· Year-end net debt of $3.1 billion, $1 billion headroom; gearing of 1.9x; no near-
term maturities

· 2018 capital investment of $423 million; 2019 forecast of $570 million

· Sustainable capital returns policy announced in November; 2018 final recommended
dividend of 4.8¢/share (c.$67 million)

· West Africa 2018 net oil production averaged 88,200 bopd; 2019 forecast 93,000–
101,000 bopd

· Principles agreed with Government of Uganda on CGT; completion of farm-down to
follow

· JV Partners targeting Uganda development FID around mid-year; Kenya development
targeting end 2019 FID

· Guyana exploration drilling to commence in mid-2019 with a three-well programme
planned

**FINANCIAL OVERVIEW**

  |

 |

FY 2018

  |

FY 2017

  |  
 |

Total revenue ($m)

  |

1,859

  |

1,723

  |  
 |

Other operating income – corporate Business Interruption insurance proceeds ($m)

  |

188

  |

162

  |  
 |

Gross profit ($m)

  |

1,082

  |

815

  |  
 |

Administrative expenses ($m)

  |

(90)

  |

(95)

  |  
 |

Restructuring costs ($m)

  |

(3)

  |

(15)

  |  
 |

Gain/(loss) on disposal ($m)

  |

21

  |

(2)

  |  
 |

Exploration costs written off ($m)

  |

(295)

  |

(143)

  |  
 |

Impairment of property, plant and equipment, net ($m)

  |

(18)

  |

(539)

  |  
 |

Provision for onerous service contracts, net ($m)

  |

(167)

  |

1

  |  
 |

Operating profit ($m)

  |

528

  |

22

  |  
 |

Profit/(loss) after tax ($m)

  |

85

  |

(175)

  |  
 |

Free cash flow ($m)

  |

411

  |

543

  |

Note: Underlying cash operating costs per boe, capital investment, net debt, gearing
and free cash flow are non-IFRS measures and are explained in the Finance Review.

**Corporate Governance Matters**

**Board changes**

On 17 April 2018, Tullow announced that Dorothy Thompson CBE had been appointed 
as an independent non-executive Director and Chair-designate of Tullow with effect
from the conclusion of the Group’s Annual General Meeting (AGM). Dorothy Thompson
then succeeded Aidan Heavey, Tullow’s founder, as Chair of the Group, at the end
of the Board meeting on 20 July 2018.

Kevin Massie stepped down as Company Secretary to pursue another role in Tullow 
at the end of the 2018 AGM. The Board appointed Adam Holland, then Deputy Company
Secretary & Senior Legal Advisor, to the role of Company Secretary.

On 6 February 2018, Anne Drinkwater informed the Board that she had decided not 
to stand for re-election at the 2018 AGM.

**Dividend**

Tullow held a Capital Markets Day in London on 29 November 2018 and announced a 
capital returns policy to start from the 2019 financial year. The policy states 
that the Group intends to pay an annual ordinary dividend based on its free cash
flow generation, while ensuring an appropriate balance with debt reduction and investment
in the business. It is expected that the total ordinary dividend in any year will
be no less than $100 million and will be payable semi-annually, split between the
interim and final dividend (1/3:2/3). In periods of particularly strong free cash
flow generation, the Board will also look to supplement the ordinary dividend with
additional returns to shareholders.

With respect to the 2018 financial year, following another strong year of free cash
flow generation, the Board has decided to recommend a final dividend of 4.8¢/share(
representing a total shareholder return of c.$67 million) which will be payable 
in May 2019 if approved at the 2019 AGM.

Change of external auditor

Following a competitive process, the Board have appointed Ernst & Young LLP as Tullow’s
external auditors. The appointment will be subject to a vote by shareholders at 
the Group’s 2020 AGM and, if passed, will take effect from the end of the meeting.

Annual General Meeting

Tullow’s AGM will take place on Thursday 25 April 2019 at 12pm at the Company’s 
offices at Building 9, Chiswick Park, 566 Chiswick High Road, London, W4 5XT.

Ian Springett

The Board regrets to announce that Ian Springett, formerly Chief Financial Officer
and a Director of Tullow from 2009-2017, passed away on 16 January 2019. Ian was
a great friend and colleague to many at Tullow and beyond and he will be hugely 
missed. The thoughts and condolences of the Board and all Tullow staff go out to
Ian’s family and friends.

**Operations review**

**Production**

Tullow’s West Africa oil assets performed strongly in 2018 and delivered net production
of 88,200 bopd. This includes production-equivalent insurance payments of 8,600 
bopd received under Tullow’s Corporate Business Interruption insurance. Working 
interest gas production averaged 1,800 boepd giving overall Group net production
of 90,000 boepd.

In 2019, overall working interest oil production, including production-equivalent
insurance payments, is expected to increase and is forecast to average between 93,000
and 101,000 bopd. Working interest gas production from TEN is expected to average
1,000 boepd.

Overall Group net production is therefore expected to be in the range of 94,000 
to 102,000 boepd.

**WEST AFRICA**

> **Gary Thompson, Executive Vice President for West Africa, commented today:**
> “Tullow’s West African business continues to underpin the Group with strong production
> performance across all our assets. The TEN fields and the West African non-operated
> business outperformed substantially in 2018 and with further growth in production
> to come in 2019, this business is well-positioned to deliver on its full potential.”

**Ghana**

**Drilling programme**

Tullow returned to drilling in Ghana in 2018 following the conclusion of proceedings
at the ITLOS tribunal in Hamburg in September 2017 and after gaining Government 
approval of the Greater Jubilee Full Field Development Plan. Tullow began a new 
drilling programme in March with the Maersk Venturer and a second rig, the Stena
Forth, was contracted during the year to work alongside the Maersk Venturer. The
second rig was contracted for an initial three-well campaign with flexible extension
options reflecting conditions in the rig market which continue today. The Stena 
Forth began drilling in October 2018 and the additional rig capacity enabled Tullow
to carry out simultaneous drilling and completion activity, allowing the tie-in 
of new wells to be brought forward. The results from this programme, which was completed
within budget, were in line with, or exceeded, pre-drill expectations. In 2019, 
Tullow expects to drill and complete seven new wells across the TEN and Jubilee 
fields allowing gross oil production from Ghana to rise to around 180,000 bopd.

**Jubilee**

Gross production for 2018 averaged 78,000 bopd (net: 27,700 bopd) which increases
to 36,300 bopd (net) after including 8,600 bopd of net production-equivalent insurance
payments. Production from Jubilee was slightly lower than expected. This was due
to downtime related to work on the gas compression system in the first half of 2018
and some minor facilities issues towards the end of the year, which have since been
resolved. Over the year, two new Jubilee production wells, J51-P and J53-P, were
drilled and successfully met all pre-drill expectations. The completion of a water
injector, drilled during the previous campaign, was also carried out. These wells
were brought on stream in the second half and are accessing highly productive parts
of the reservoir.

Tullow expects 2019 average gross oil production from the Jubilee field to increase
to around 96,000 bopd (net: 34,000 bopd). Tullow’s corporate Business Interruption
insurance is expected to provide around 1,000 bopd of net production-equivalent 
insurance payments, resulting in expected total 2019 Jubilee full year net production
of around 35,000 bopd.

**Turret Remediation Project**

The Turret Remediation Project is close to completion. This pioneering and unique
project, which included the first ever remediation of this type at sea, required
the FPSO Kwame Nkrumah to be shut down twice in the first half of 2018 for work 
to stabilise the turret bearing for periods of 19 days and 21 days respectively.
In December 2018, the FPSO was successfully rotated to its new heading of 205 degrees
and subsequently spread-moored.

The JV Partners have also agreed to install a Catenary Anchor Leg Mooring (CALM)
buoy for offtake from the FPSO and a contract award has been made. The installation
of the CALM buoy is likely to take place in 2020 and is not expected to affect production.

**TEN**

The TEN fields performed well in 2018, with gross production averaging 64,500 bopd(
net: 30,400 bopd) reflecting good results from the drilling programme. The first
additional Ntomme well, NT05-P, was successfully drilled in the first half of the
year and started producing in August 2018. A second new producer, EN10-P, is currently
being completed and is expected to be online in February.

Tullow expects 2019 gross oil production from the TEN fields to average around 83,000
bopd (net: 39,000 bopd). Tullow is confident of this growth in production following
strong performance in 2018, good results from recently drilled wells in both the
Ntomme and Enyenra fields and production testing that has seen the TEN FPSO deliver
in excess of its design capacity. The forecast includes a two-week shutdown of the
TEN FPSO for routine maintenance which is currently scheduled for the second quarter
of 2019. Gross gas production is expected to be around 2,100 boepd (net: 1,000 boepd).

**Exploration**

Tullow has successfully pre-qualified for Ghana’s maiden licensing round with bids
due by mid-May 2019. The licensing process is expected to conclude by the end of
August 2019.

**Seadrill and Kosmos litigation**

Following a trial in the English Commercial Court in May 2018, the court ruled on
3 July 2018 that Tullow was not entitled to terminate its West Leo rig contract 
with Seadrill on 4 December 2016 by invoking the contract’s force majeure provisions.
Following advice from counsel, Tullow decided not to appeal this ruling. Tullow 
paid Seadrill a contractual termination fee, other standby fees that accrued in 
the 60 days prior to termination of the contract and interest amounting to $248 
million in aggregate.

Although Tullow regards these as JV Partner costs, Kosmos disputed separately, through
an International Chamber of Commerce arbitration against Tullow, its share of the
liability (c. 20%) of any costs related to the use of the West Leo rig beyond 1 
October 2016. On 17 July 2018, the arbitration tribunal delivered a final and binding
award in favour of Kosmos which determined that Kosmos is not liable for its share
of these costs. As a result of both litigation results, Tullow’s net exposure in
2018 was a cash outflow of $208 million.

**Non-operated Portfolio and gas production**

In 2018, production was strong across the West Africa non-operated portfolio and
averaged 21,500 bopd, well ahead of the Group’s initial 2018 forecast of 19,000 
bopd. The Equatorial Guinea fields performed particularly well in the first half
of the year following a change of operator. In Gabon, the Simba development in Gabon
has been completed and came on-stream in January. Production in 2019 from the West
Africa non-operated portfolio is forecast to be between 22,000 and 24,000 bopd.

**Gas production**

In 2018, full year net gas production from the TEN fields and the UK averaged 1,700
boepd. In 2019, Tullow will solely produce gas in Ghana following the cessation 
of production in Tullow’s UK assets in 2018.

**Decommissioning**

The decommissioning programme for the remaining Tullow operated wells in the UK 
North Sea is expected to have been completed by the third quarter of 2019. Tullow
will then undertake final removal and clearance activities to restore the seabed.
Tullow ceased production from its non-operated UK North Sea assets during the third
quarter of 2018. The decommissioning programme for these assets is expected to be
completed by 2025.

In Mauritania, the Chinguetti FPSO (non-operated) was disconnected and demobilised
in the first half of 2018. The permanent abandonment programme for the wells in 
the field will start in mid-2019.

**EAST AFRICA**

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

“This year the East Africa team will be driving hard towards two Final Investment
Decisions on our East African projects which have the potential to deliver over 
50,000 bopd of net production to Tullow by the early 2020s. We are making good progress
in both Uganda and Kenya and are focused on delivering on the growth potential that
these projects offer.”

**Kenya**

**Development**

The Kenya development plan is progressing well, and the project continues to target
a Final Investment Decision (FID) in late 2019 and First Oil in 2022.

In February 2018, Tullow announced that following a full assessment of all the exploration
and appraisal data, Tullow estimates that the South Lokichar basin contains 240 –
560 – 1,230 million barrels (1C-2C-3C) of recoverable resources from overall discovered
oil in place of up to 4 billion barrels. The additional remaining conventional undrilled
prospect inventory of the basin is approximately 230 million barrels risked mean
recoverable resources, not including further potential in under-explored plays.

Tullow and its JV Partners also proposed to the Government of Kenya that the Amosing,
Ngamia and Twiga fields should be developed as the Foundation Stage of the South
Lokichar Development. This Foundation Stage includes a 60,000 to 80,000 bopd Central
Processing Facility (CPF) and an export pipeline to Lamu. The installed infrastructure
from this initial phase is expected to be utilised for the optimisation of the remaining
South Lokichar oil fields and future oil discoveries, allowing the incremental development
of these fields to be completed at a lower unit cost post First Oil.

**Total gross capex associated with the Foundation Stage is expected to be c.$3 
billion.**

In 2018, the development project gained momentum. Key workstreams relating to Front-
end Engineering and Design (FEED) and the Environmental Social Impact Assessments(
ESIAs) of the upstream and pipeline commenced in mid-2018. Extended injection and
production testing also took place with results in line with expectations. Dynamic
data from these tests has materially assisted with the development plan for the 
Foundation Stage. Key upstream components such as well count, well spacing and CPF
design are now well defined.

In 2019, several critical tasks must be completed to reach a Final Investment Decision
by year end. These tasks include completing commercial framework agreements with
the Government of Kenya and finalising FEED studies in the first quarter of 2019
and concluding agreements over land title and water supply with the Government of
Kenya and submitting both the upstream and the mid-stream ESIAs in the second quarter.

**Early Oil Pilot Scheme (EOPS)**

The transfer of stored crude oil from Turkana to Mombasa by road commenced on 3 
June 2018. This milestone was marked by a ceremony attended by H.E. President Uhuru
Kenyatta, H.E. Deputy President H.E. William Ruto, the Turkana County Governor, 
Turkana MPs as well as many other Government Ministers and officials. The first 
truck arrived at the refinery in Mombasa on 7 June 2018, where the oil is being 
stored for future export.

The trucks are currently transporting approximately 600 bopd and this is expected
to increase to 2,000 bopd once the EOPS is fully operational in April 2019. So far,
over 70,000 barrels of oil have been transported to Mombasa. A maiden lifting of
Kenyan crude oil is expected in mid-2019. Tullow has begun to market Kenya’s low
sulphur oil ahead of this first lifting with initial market reactions being very
positive.

**Uganda**

Following meetings in January 2019 between the CEOs of both Tullow and Total and
H.E. President Museveni of Uganda, Tullow has agreed the principles for Capital 
Gains Tax on its $900 million Uganda farm-down to CNOOC and Total. The Government
and the JV Partners are now engaged in discussions to finalise an agreement reflecting
this tax treatment that will enable completion of the farm-down to take place. Any
Capital Gains Tax is expected to be phased and partly linked to project progress.
At completion of the farm-down, Tullow anticipates receiving a cash payment of $
100 million and a payment of the working capital completion adjustment and deferred
consideration for the pre-completion period of $108 million. A further $50 million
of cash consideration is due to be received when FID is taken on the development
project.

The JV Partners continue to work towards reaching FID for the development project
around mid-2019. During 2018, the upstream and pipeline FEED were completed in preparation
for the award of Engineering, Procurement and Construction (EPC) contracts in 2019.
Drilling and well construction designs and contracting activities are complete and
contracts are ready to be awarded. ESIAs for both Tilenga and Kingfisher were submitted
to the National Environmental Management Authority for review with approval expected
in the first half of 2019. Land access activities have progressed with the active
support of the Government in line with project requirements. In addition, critical
transport infrastructure, including roads and an airport within the development 
area is being improved by the Government in support of the development.

Project financing for the pipeline is progressing well with the development of the
financial model ongoing. In the first half of 2019, the JV Partners anticipate completing
key commercial, technical and land agreements with the Governments of Uganda and
Tanzania as well as the submission of an ESIA for the pipeline to both Governments.

**NEW VENTURES**

> **Ian Cloke, Executive Vice President for New Ventures, commented today:**
> “In 2019, Tullow will drill three wildcat wells in Guyana. These are high-potential,
> high-risk wells in the world’s newest oil hot spot and we are excited about the
> opportunity that our licences in Guyana offer. In addition, we continue to work
> up other drilling prospects in highly prospective areas across Africa and South
> America for drilling in 2020 and beyond.”

**Africa**

Côte d’Ivoire

In Côte d’Ivoire, Tullow began its work programme across its new onshore blocks 
in April 2018 with a full tensor gravity gradiometry (FTG) survey covering 8,600
sq km. This survey was completed in May 2018 and the data is being used to optimise
the location of a 2D seismic survey planned to commence in the third quarter of 
2019. Tullow continues to reprocess 3D seismic data for the offshore Block CI-524
which sits alongside the maritime border with Ghana, next to Tullow’s operated TEN
fields.

Tullow signed a farm-out agreement for a 30% interest in all seven onshore licences
to Cairn Energy Plc. This farm-out is subject to obtaining Government approval and
will leave Tullow with a 60% operated interest in each licence with most of the 
pre-drilling exploration costs carried.

**Namibia**

In September 2018, Tullow drilled the Cormorant-1 well offshore Namibia. The well
encountered non-commercial hydrocarbons and was plugged and abandoned. Gas signatures,
indicative of oil, were encountered in the overlying shale section, supporting the
concept of a working oil system in the area. The combination of a simple well design,
efficient operations and a farm-out in 2017 resulted in net expenditure on this 
well of less than $3 million. Data gained from the well, in combination with high
quality 3D seismic data, will be used to evaluate the next steps for the Group’s
Namibian acreage in PEL-37. Separately, Tullow has decided to exit block PEL-30 
in Namibia.

**Mauritania**

In 2018, a 9,300 sq km 3D seismic survey was completed over Block C18, in which 
Tullow holds a 15% non-operated stake. Tullow’s share of the cost was carried under
previous farm-down agreements. The data is currently being interpreted ahead of 
a drill or drop decision in April. In Block C3, in which Tullow holds a 100% operated
stake, the Group has been interpreting the 3D seismic survey captured in 2017 to
identify prospects for a potential 2020 well.

**Zambia**

In 2018, interpretation of a FTG survey and modelling of passive seismic data recorded
in 2017 has indicated that this rift basin may be higher risk than originally anticipated.
Tullow is therefore evaluating its next steps in Zambia.

**The Comoros**

Tullow announced on 29 November 2018 that it had agreed with Discover Exploration
Ltd to farm into Blocks 35, 36 and 37, offshore the Union of the Comoros (“the Comoros”)
in the Indian Ocean. Following the completion of this transaction, which requires
Government approval, Tullow will operate the three blocks and hold a working interest
of 35%. The Blocks comprise an area of 16,063 sq km with a gross un-risked resource
potential of up to 7 billion barrels of oil. A 3D seismic survey is planned for 
the third quarter of 2019.

**South America**

**Guyana**

Guyana will be the focus for Tullow’s exploration drilling programme in 2019. Tullow
plans to drill the Jethro prospect in the second quarter of 2019 as the first of
two planned wells on the Orinduik block. Prospect selection amongst the JV Partners
is ongoing for the second planned well on the Orinduik Block. The success of the
neighbouring Hammerhead-1 well in August 2018, only seven kilometres from the Orinduik
block boundary, has further de-risked this acreage. Tullow and its partners are 
in the final stages of contracting a Drillship for the Orinduik drilling programme.

The Carapa prospect will be tested on the Kanuku licence in the third quarter of
2019. In 2018, Tullow increased its equity share in the Kanuku licence, offshore
Guyana, from 30% to 37.5% through a farm-in deal with Repsol.

Jamaica

Interpretation of a 2,200 sq km 3D seismic survey recorded in 2018 continues as 
Tullow matures prospects that can compete for capital for drilling in 2020.

**Peru**

In Peru, Tullow agreed the terms to acquire a 100% stake in offshore Blocks Z-64,
Z-65, Z-66, Z-67 and Z-68 in early 2018. However, in May 2018, the Supreme Decrees,
authorizing PeruPetro, the state regulator, to execute licence contracts for these
blocks, were revoked by the Peruvian Government. Tullow was disappointed by this
outcome as the Group complied with all the processes and procedures required under
Peruvian law to agree new exploration licences.

Since the revocation, Tullow expressed its continued interest in the licences and
has worked closely with PeruPetro towards execution of these licences. In January
2019, a new Supreme Decree was issued which detailed how oil exploration licences
are to be awarded in Peru and included clear regulations around public consultation.

Separately, Tullow agreed to acquire a 35% interest in Block Z-38 through a farm-
down from Karoon Gas Australia. This agreement also remains subject to Government
approval. This acreage complements the Group’s current position in South America
and contains several attractive prospects and leads for potential drilling in 2020.

**Suriname**

In October, Tullow was awarded Block 62 in which it has a 100% operated interest.
This block contains similar deep-water plays to Block 47. In addition, Tullow completed
a farm-out of a 30% interest in the Block 47 licence to Pluspetrol for a carry on
a future well. Work has continued maturing prospects in Block 47 for potential drilling
in 2020. In Block 54, Tullow has continued to examine results from the Araku well
ahead of any potential drilling.

**Uruguay**

Tullow has decided that it will not enter the next term of the Block 15 exploration
licence with potential prospects being deemed too high risk. Tullow will exit the
licence in March 2019.

**Pakistan**

In December 2018, Tullow agreed to sell its 30% interest in the Kohlu licence, Pakistan
to OPL. Government approval is anticipated in the first half of 2019. This is Tullow’s
last remaining licence in Pakistan.

**Finance review**

> **Les Wood, Chief Financial Officer, commented today:**
> “Tullow has made excellent progress in 2018, significantly deleveraging the balance
> sheet and generating high levels of underlying free cash flow. The confidence 
> we have in the performance of the business allowed us to establish a sustainable
> capital returns policy at the end of last year and our strong 2018 results have
> allowed us to announce a final dividend that will be payable in May 2019. We have
> developed a very firm foundation for growth over the last few years and I am confident
> that we can deliver significant shareholder returns in the years ahead.”

  |

Financial results summary

  |

2018

  |

2017

  |  
 |

Working interest production volume (boepd)^(1)

  |

81,400

  |

87,300

  |  
 |

Sales volume (boepd)

  |

74,200

  |

82,200

  |  
 |

Realised oil price ($/bbl)

  |

68.5

  |

58.3

  |  
 |

Total revenue ($m)^(2)

  |

1,859

  |

1,723

  |  
 |

Gross profit ($m)

  |

1,082

  |

815

  |  
 |

Underlying cash operating costs per boe ($/boe) ^(3)

  |

10.0

  |

11.1

  |  
 |

Exploration costs written off ($m)

  |

295

  |

143

  |  
 |

Impairment of property, plant and equipment, net ($m)

  |

18

  |

539

  |  
 |

Operating profit ($m)

  |

528

  |

22

  |  
 |

Profit/(loss) before tax ($m)

  |

261

  |

(286)

  |  
 |

Profit/(loss) after tax ($m)

  |

85

  |

(175)

  |  
 |

Basic profit/(loss) per share (cents)

  |

6.1

  |

(13.7)

  |  
 |

Capital investment ($m)^(3,4)

  |

423

  |

225

  |  
 |

Adjusted EBITDAX ($m) ^(3)

  |

1,600

  |

1,346

  |  
 |

Net debt ($m) ^(3)

  |

3,060

  |

3,471

  |  
 |

Gearing (times) ^(3)

  |

1.9

  |

2.6

  |  
 |

Free cash flow ($m) ^(3)

  |

411

  |

543

  |

 

 

1. Including the impact of production-equivalent insurance payment barrels from 
the Jubilee field, Group working interest production was 90,000 boepd.

2. Total revenue does not include receipts for Tullow’s corporate Business Interruption
insurance of $188 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 $50 million in 2018 that will,
subject to completion of the farm-down, be offset by either the working capital 
completion adjustment or deferred consideration.

**Production and commodity prices**

Working interest production averaged 81,400 boepd, a decrease of 7% for the year(
2017: 87,300 boepd). Including the impact of production-equivalent insurance payments
from the Jubilee field, working interest production averaged 90,000 boepd (2017:
94,700 boepd), a decrease of 5%. The decrease resulted from the impact of turret
remediation work at Jubilee, and the cessation of production at higher cost non-
operated assets. This was partially offset by strong production from the TEN fields
and the remainder of the non-operated West Africa portfolio.

The Group’s realised oil price after hedging was $68.5/bbl and $71.8/bbl before 
hedging (2017: $58.3/bbl and $54.2/bbl respectively). The increase in underlying
oil prices reduced the net contribution of the realisation of hedges entered into
by the Group to total revenue.

**Underlying cash operating costs, depreciation, impairments, write-offs, and administrative
expenses**

Underlying cash operating costs amounted to $327 million; $10.0/boe (2017: $386 
million; $11.1/boe). Underlying cash operating costs were net of $46 million of 
insurance proceeds (2017: $51 million). The 10% decrease in unit cash operating 
costs was principally due to the impact of ongoing cost saving initiatives and the
cessation of production from higher cost assets in the non-operated portfolio.

DD&A charges before impairment on production and development assets amounted to 
$568 million; $17.2/boe (2017: $574 million; $16.6/boe). A full year of amortisation
of the TEN FPSO finance lease asset was recorded for the first time in 2018, as 
the asset was only recognised in the second half of 2017. This was offset by the
impact of impairment recorded at the end of 2017.

The Group recognised a net impairment charge of $18 million in respect of 2018 (
2017: $539 million). Impairments in Gabon were largely driven by the lower Dated
Brent forward curve at 31 December 2018, whilst impairments in the UK related to
increased decommissioning cost estimates. Impairment reversals were recorded in 
Côte d’Ivoire and Ghana as a result of reserves upgrades and improved cost forecasts,
respectively.

During 2018, exploration costs write-offs were $295 million (2017: $143 million)
and included $140 million for the Wawa and Akasa assets in Ghana, $75 million associated
with capitalised interest on Uganda assets held for sale, and $25 million of New
Ventures activity. The total exploration costs written off, net of tax, were $246
million (2017: $143 million).

Administrative expenses of $90 million (2017: $95 million) included an amount of
$23 million (2017: $33 million) associated with share-based payment charges. In 
June 2015 the Group set a target to remove $500 million of cash costs from the business
over a three-year period. During 2017 this target was increased to $650 million.
The three-year period concluded on 30 June 2018, with the Group delivering $708 
million of savings. The ongoing cost of running the business has reduced significantly
and will continue to be a key area of focus.

**Provision for onerous service contracts**

Changes to provisions for onerous service contracts in 2018 resulted in an income
statement charge in 2018 of $167 million (2017: credit of $1 million). This primarily
resulted from the adverse litigation outcome related to the West Leo rig contract
with Seadrill.

**Derivative financial instruments**

Tullow undertakes hedging activities as part of the ongoing management of its business
risk to protect against volatility and to ensure the availability of cash flow for
re-investment in capital programmes that are driving business growth.

At 31 December 2018, the Group’s derivative instruments had a net positive fair 
value of $128 million (2017: negative $76 million), net of deferred premium.

  |

2019 hedge position at 31 December 2018

  |

Bopd

  |

Bought put (floor)

  |

Sold call

  |

Bought call

  |  
 |

Hedge structure

  |

 |

 |

 |

 |  
 |

Collars

  |

22,244

  |

$56.80

  |

$81.68

  |

–

  |  
 |

Three-way collars (call spread)

  |

29,488

  |

$54.06

  |

$74.60

  |

$79.81

  |  
 |

Straight puts

  |

4,000

  |

$69.24

  |

–

  |

–

  |  
 |

Total/weighted average

  |

55,732

  |

$56.24

  |

–

  |

–

  |

The 2020 hedging position at 31 December 2018 was 25,000 bopd hedged with an average
floor price protected of $59.00/bbl.

**Net financing costs**

Net financing costs for the year were $270 million (2017: $310 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 2018 compared to 2017. Further,
in 2017 a foreign exchange loss of $29 million was incurred in relation to the hedging
of the proceeds from the Rights Issue. 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.

**Taxation**

The net tax expense of $175 million (2017: credit of $111 million) primarily relates
to tax charges in respect of the Group’s production activities in West Africa, as
well as UK decommissioning assets, reduced by deferred tax credits associated with
exploration write-offs, impairments and provisions for onerous service contracts.

The Group’s statutory effective tax rate for 2018 is 67.2 per cent (2017: 37.0 per
cent). After adjusting for non-recurring amounts related to exploration write-offs,
disposals, impairments and provisions for onerous service contracts and their associated
deferred tax benefit, the Group’s adjusted tax rate is 40.7 per cent (2017: 23.8
per cent). The adjusted tax rate has increased due to changes in the geographical
mix of profits, particularly the impact of increased profits from West Africa production
taxed at higher rates, and lower tax credits due to reduced Norwegian exploration
activities and the disposal of the Netherlands business during 2017.

The Group’s future statutory effective tax rate is sensitive to the geographic mix
in which pre-tax profits and exploration costs written off arise. Unsuccessful exploration
is often incurred in jurisdictions where the Group has no taxable profits such that
no related tax benefit results. Consequently, the Group’s tax charge will continue
to vary according to the jurisdictions in which pre-tax profits and exploration 
costs write offs-occur.

Profit/(loss) after tax from continuing activities and profit/(loss) per share

The profit after tax for the year from continuing activities amounted to $85 million(
2017: $175 million loss). Basic earnings per share was 6.1 cents (2017: 13.7 cents
loss).

  |

Reconciliation of net debt

  |

$m

  |  
 |

Year-end 2017 net debt

  |

        3,471

  |  
 |

Sales revenue      

  |

 (1,859)

  |  
 |

Other operating income – lost production insurance proceeds

  |

(188)

  |  
 |

Operating costs

  |

           327

  |  
 |

Operating expenses

  |

           432

  |  
 |

Cash flow from operations               

  |

(1,288)

  |  
 |

Movement in working capital

  |

 (19)

  |  
 |

Tax paid

  |

           103

  |  
 |

Purchases of intangible exploration and evaluation assets and property, plant, and equipment

  |

           441

  |  
 |

Other investing activities

  |

(13)

  |  
 |

Other financing activities

  |

           367

  |  
 |

Foreign exchange gain on cash

  |

             (2)

  |  
 |

Year-end 2018 net debt

  |

        3,060

  |

**Capital investment**

2018 capital investment (net of Uganda expenditure which will be repaid from either
the working capital completion adjustment or deferred consideration post the completion
of the Uganda farm-down) amounted to $423 million (2017: $225 million) with $353
million invested in development activities and $70 million invested in Exploration
and Appraisal activities. More than 60% of the total was invested in Kenya and Ghana
and over 95% was invested in Africa.

Capital expenditure will continue to be carefully controlled during 2019. The Group’s
2019 capital expenditure is expected to total approximately $570 million. This total
excludes c.$170 million of forecast Uganda expenditure which will be repaid from
either the working capital completion adjustment or deferred consideration post 
the completion of the Uganda farm-down, which is expected in the first half of 2019.
The capital investment total comprises Ghana capex of c.$250 million, West Africa
non-operated capex of c.$90 million, Kenya pre-development expenditure of c.$70 
million, Uganda post-completion Tullow costs of c.$10m, and Exploration and Appraisal
expenditure of c.$140 million.

At completion of the Uganda farm-down, Tullow is also due to receive $100 million
cash consideration along with re-imbursement of 2017 and 2018 capex of c.$108 million.
A further $50 million cash consideration is due to be received when FID is taken
on the development project.

**Borrowings**

On 23 March 2018, Tullow completed its offering of $800 million of senior notes,
due in 2025. The offering was significantly oversubscribed and increased from the
initial offering of $650 million. Proceeds were used to redeem, in full, senior 
notes due in 2020 and repay drawings on the Reserve Based Lending facility. The 
senior notes offering further extended Tullow’s debt maturities, with no scheduled
debt repayments until 2021. On 4 April 2018, commitments under Tullow’s Revolving
Corporate Facility (RCF) amortised in line with the schedule to $500 million, on
18 April 2018 Tullow voluntarily cancelled a further $150 million of commitments
under the facility, and in November 2018, given the strength of the balance sheet,
the Board decided to cancel the Group’s undrawn $350 million RCF, four months before
maturity, to realise cost savings from reduced commitment fees. Following the cancellation
of this facility, liquidity headroom of unutilised debt capacity and free cash were
$1 billion at the end of 2018, maintaining flexibility for future opportunities.

As a result of the implementation of IFRS 9: Financial instruments, the Group’s 
opening non-current borrowings on 1 January 2018 increased by $111 million. Refer
to note 1 for further details.

**Credit Ratings**

Tullow maintains corporate credit ratings with Standard & Poor’s and Moody’s Investors
Service. During the year, Standard & Poor’s upgraded Tullow’s corporate credit rating
to B+ from B, and assigned a positive outlook; in addition, Standard & Poor’s raised
the rating of Tullow’s corporate bonds to B+, in line with the corporate credit 
rating. Moody’s Investors Service upgraded Tullow’s Corporate Family Rating to B1
from B2, and consequently the rating of Tullow’s corporate bonds was raised to B3
from Caa1.

Liquidity risk management and going concern

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 and different production rates from 
the Group’s producing assets. The Group had $1 billion liquidity headroom of unutilised
debt capacity and free cash at the end of 2018. 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 12 months from the date of approval of the 2018 Annual
Report and Accounts.

Based on the analysis above, the Directors have a reasonable expectation that the
Company has adequate resources to continue in operational existence for the foreseeable
future. Thus, they continue to adopt the going concern basis of accounting in preparing
the annual Financial Statements.

**Brexit**

It is the view of the Board that, given the Group’s focus on Africa and South America,
Tullow’s business, assets and operations will not be materially affected by Brexit.
Tullow also derives its income from crude oil, a globally-traded commodity which
is priced in US dollars.

Nevertheless, Tullow employs a number of EU nationals in the UK and the Board is
concerned about the uncertainty that a No Deal Brexit would cause these much-valued
members of staff. To help address this concern, Tullow has established a Brexit 
Focus Group to share information with affected employees and ensure they are up 
to date with the latest developments.

The Board also recognises that a No Deal Brexit could cause significant regulatory,
legal and financial uncertainty with regard to our decommissioning programme in 
the UK North Sea. Operators would have to be carefully guided by the Department 
for Business, Energy and Industrial Strategy as to exactly how decommissioning programmes
should be executed and what tariffs or fees, if any, should be applied to non-UK
service providers.

**Events since 31 December 2018**

There has not been any event since 31 December 2018 that has resulted in a material
impact on the year end 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.

 

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