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RNS Number : 1466E
Tullow Oil PLC
07 February 2018
Tullow Oil plc - 2017 Full Year Results
$1.7 billion sales revenue; $543 million free cash flow; 2.6x
gearing ratio
Kenya's potential confirmed; proposed First Oil in early
2020s
Exploration portfolio fully re-set: multiple high impact
campaigns over next three years
7 February 2018 - Tullow Oil plc (Tullow), the independent oil
and gas exploration and production group, announces its full year
results for the year ended 31 December 2017. 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:
"I am pleased to report that Tullow made excellent progress in
2017 as demonstrated by our substantial free cash flow generation
and significantly reduced gearing. Strong production and
disciplined cost management has allowed us to continue to both
reduce debt and invest in our high-return production assets in
Ghana. The assessment of the results from our appraisal campaign in
Kenya also fully supports progress towards a major development of
the South Lokichar Basin. As we continue to retain a keen focus on
the financial discipline that has served us so well, we are now
also looking to grow the value of our business both through
exploration, following a full re-set of the portfolio, and through
other opportunities that the recovery in the sector will
present."
2017 FULL YEAR RESULTS summary
-- Revenue of $1.7 billion plus lost production insurance
proceeds of $162 million; gross profit of $815 million; post tax
loss of $189 million after write-offs and non-cash impairments;
free cash flow of $543 million
-- $2.5 billion RBL re-financed in November 2017; year-end 2017
net debt of $3.5 billion with facility headroom including free cash
of $1.1 billion; net debt to adjusted EBITDAX gearing ratio of
2.6x
-- 2017 capex of $225 million; 2018 capex forecast of $460
million (excluding Uganda expenditure of $110 million which will be
repaid following completion of the Uganda farm-down)
-- West Africa 2017 net working interest oil production,
including production-equivalent insurance payments, averaged 89,100
bopd; 2018 production is expected to average between 82,000 and
90,000 bopd
-- Incremental drilling programme due to start in February 2018;
this additional well capacity combined with current strong
production from both Jubilee and TEN fields will maximise and
sustain production in the coming years
-- Kenya resources assessment completed: 240 - 560 - 1,230 mmbo
(1C-2C-3C) contingent recoverable resources from an overall
discovered STOIIP of up to 4 billion barrels. Phased development is
planned with FID in 2019 and First Oil in 2021/22
-- Uganda deal completion expected in H1 2018; JV Partners working towards FID around mid-year
-- Exploration portfolio now reset through disposals, farm-downs
and the addition of significant new positions in Côte d'Ivoire and
Peru. Multiple high impact exploration campaigns planned over next
three years, starting with the high-impact Cormorant well in
Namibia in H2 2018
FINANCIAL OVERVIEW
FY 2017 FY 2016
========================================= ======= =======
Total revenue ($m) 1,723 1,270
========================================= ======= =======
Gross profit ($m) 815 547
========================================= ======= =======
Administrative expenses ($m) (95) (116)
========================================= ======= =======
Restructuring costs ($m) (15) (12)
========================================= ======= =======
Loss on disposal ($m) (2) (3)
========================================= ======= =======
Goodwill impairment ($m) - (164)
========================================= ======= =======
Exploration costs written off ($m) (143) (723)
========================================= ======= =======
Impairment of property, plant and
equipment, net ($m) (539) (168)
========================================= ======= =======
Provision for onerous service contracts,
net ($m) 1 (115)
========================================= ======= =======
Operating profit/(loss) ($m) 22 (755)
========================================= ======= =======
Loss after tax ($m) (189) (597)
========================================= ======= =======
Free cash flow ($m) 543 (792)
========================================= ======= =======
Board changes, AGM and dividend
On 11 January 2017, Tullow announced that Paul McDade, then
Chief Operating Officer, was to be appointed as Chief Executive
Officer (CEO) and Aidan Heavey, then CEO, was to be appointed as
Chairman, effective after the Group's AGM on 26 April 2017. Simon
Thompson, Chairman, and Ann Grant, Senior Independent Director
(SID), retired at the AGM with Jeremy Wilson replacing Ms Grant as
SID. Aidan Heavey was appointed Chairman of Tullow for a maximum of
two years from taking office. Accordingly, the Nominations
Committee have begun the process of finding a new Chairman and
expect to make an appointment by the end of 2018. Ian Springett,
Chief Financial Officer, retired from the Board in June 2017 due to
ill-health and was replaced by Les Wood, previously Interim CFO
and, before that, Vice-President, Commercial and Finance. On 6
February 2018, Anne Drinkwater informed the Board that she has
decided not stand for re-election at the 2018 AGM and will
therefore cease to be a Director with effect from the end of the
AGM.
Tullow's AGM will take place on 26 April 2018 at 12pm at the
Company's offices at Building 9, Chiswick Park, 566 Chiswick High
Road, London, W4 5XT.
While significantly improved free cash flow is creating a
broader range of options for Tullow in how it allocates capital,
the Group is currently focused on investing in its portfolio of
assets and debt reduction. Therefore, after careful consideration,
the Board has recommended that no dividend is paid for 2017.
Operations review
Production
Tullow's West Africa 2017 oil production exceeded expectations
for the year averaging 89,100 bopd. This includes 7,400 bopd of net
production-equivalent payments received under Tullow's Corporate
Business Interruption insurance for the Jubilee field. In Europe,
working interest gas production performed in line with expectations
with full year net production averaging 5,600 boepd. This brings
Tullow's total average working interest production in 2017 to
94,700 boepd.
In 2018, working interest oil production, including
production-equivalent insurance payments, is expected to average
between 82,000 and 90,000 bopd. Working interest gas production,
which includes TEN associated gas sales and the impact of the
Netherlands assets sales in 2017, is expected to average between
3,500 and 4,500 boepd. This brings overall Group production
guidance, for both oil and gas, to between 86,000 and 95,000
boepd.
WEST AFRICA
Gary Thompson, Executive Vice President for West Africa,
commented today:
"Tullow's West African operations remain at the core
of Tullow. In 2017, West Africa delivered over 89,000
bopd of high-margin, low-cost oil and in 2018 we
will invest in Ghana to sustain this impressive performance
over the coming years. Drilling is due to commence
on the Ntomme field by the end of this month and
we continue to evaluate the business case of procuring
additional rig capacity. I have been particularly
pleased by the performance of the TEN fields, with
production exceeding 70,000 bopd for the last three
months, especially given the delays on completing
the development wells which resulted from the ITLOS
drilling moratorium. I look forward to similarly
strong performances from Jubilee, TEN and our other
West African oil fields in 2018."
================================================================
Ghana
Jubilee
Full year 2017 gross production from the Jubilee field averaged
89,600 bopd (net: 31,800 bopd). Tullow's Corporate Business
Interruption insurance has reimbursed 7,400 bopd of net
production-equivalent insurance payments, bringing expected full
year effective net production from Jubilee to 39,200 bopd. Gross
production in the latter part of 2017 was consistently above 90,000
bopd and we expect to build on this as we commence drilling in
2018.
Turret Remediation Project
Following the discovery of the issue with the turret bearing of
the Jubilee FPSO Kwame Nkrumah in 2016, Tullow has been able to
continue efficient production operations while working on the
permanent solution which involves converting the FPSO to a
spread-moored vessel. The first phase of this work, involving the
installation of a stern anchoring system, was completed in February
2017, after which the tugs maintaining the FPSO on heading control
were removed.
Preparations continue in advance of the planned turret bearing
stabilisation work in the first quarter of 2018. This work is
expected to take place over two shut-down periods, totalling
four-to-six weeks. A further planned shut-down of approximately
three weeks is expected around year end 2018 to rotate the FPSO to
its permanent heading and install the final spread mooring
anchoring system.
Greater Jubilee Full Field Development Plan
The Government of Ghana approved the Greater Jubilee Full Field
Development Plan in October 2017, allowing Tullow and its Joint
Venture Partners to prepare for a multi-year incremental drilling
programme to maximise and sustain oil production and gas export.
The initial focus will be the drilling and completion of new wells
in the Jubilee unit area that will make use of existing
infrastructure, and the completion of a well previously drilled in
the Mahogany discovery. 4D seismic acquired in the first half of
2017 is being used to optimise well locations and ongoing reservoir
management.
Production in 2018
Tullow expects 2018 gross production from the Jubilee field to
average 75,800 bopd (net: 26,900 bopd), which takes into account
the planned shut-downs associated with the turret remediation work.
Tullow's Corporate Business Interruption insurance cover, which
compensates Tullow for lost production associated with the
remediation works, is expected to reimburse Tullow 10,200 bopd of
net production-equivalent insurance payments. Jubilee effective net
production is therefore expected to average around 37,100 bopd for
2018.
TEN
The TEN fields performed well in 2017 with gross production
exceeding initial guidance, averaging 56,000 bopd (net: 26,400
bopd). This strong performance was as a result of production and
water injection optimisation which continues to be effective and
the field has performed consistently above 70,000 bopd for the last
three months. Production from the 11 wells drilled so far, indicate
reserves estimates for both Ntomme and Enyenra to be in line with
previous guidance.
In June 2017, a commissioning capacity test and facility
blowdown was completed demonstrating that the FPSO can operate at
its design capacity of 80,000 bopd and at higher rates as indicated
by a 24-hour test conducted around 100,000 bopd. Final
commissioning of the TEN FPSO was completed in the second half of
2017. The TEN gas manifold was also installed and commissioned in
2017 and a gas export trial to Ghana National Gas Company
facilities was successfully completed. This connection will allow
for the export and sale of TEN gas as well as the ability to supply
gas in substitution for Jubilee gas during the planned Jubilee
turret remediation shut-downs in 2018.
On 23 September 2017, the International Tribunal for the Law of
the Sea (ITLOS) made its decision with regard to the maritime
boundary dispute between Ghana and Côte d'Ivoire. The new maritime
boundary, as determined by the tribunal, does not affect the TEN
fields. Tullow subsequently received notification from the
Government of Ghana to recommence drilling in the TEN fields and a
multi-year incremental drilling programme will start this year,
seeking to ramp up production from the TEN fields to utilise the
full capacity of the FPSO and sustain this over a number of
years.
In the last quarter of 2017, Tullow signed the TEN Associated
Gas (TAG) Gas Sales Agreement with the Ghana National Petroleum
Corporation and Tullow anticipates the start of gas sales from TEN
in the first half of 2018. Gross gas sales equivalent to 4,200
boepd (net: 2,000 boepd) have been forecast for the year.
Production in 2018
Tullow expects 2018 gross oil production from the TEN fields to
average 64,000 bopd (net: 30,200 bopd). During the year, the rig
schedule and timing of drilling and completion operations will be
optimised, providing upside potential to this initial estimate.
Ghana drilling in 2018
Tullow has secured the Maersk Venturer rig which is expected to
start drilling later this month. The rig will be used across the
TEN and Jubilee fields and has been contracted for up to four years
with early termination provisions. The first well planned is an
Ntomme production well in the TEN fields followed by a Jubilee
production well located in the north-eastern area of the field.
Work is ongoing to finalise the sequence of further wells to
optimise output from both the Jubilee and TEN fields. Tullow and
its Joint Ventures Partners continue to evaluate the business case
for contracting a second rig that would allow the acceleration of
drilling across both fields.
Non-operated Portfolio and Europe gas production
2017 West Africa net non-operated production exceeded
expectations at 23,500 bopd. Net production in 2018 is expected to
be around 19,100 bopd. The reduced year-on-year forecast is
primarily due to natural decline as a result of sustained low
investment levels during a period of low oil prices, combined with
the exit from the M'Boundi field, Congo (Brazzaville), effective
from July 2017, and the cessation of production at the Chinguetti
field in Mauritania.
Full year gas production from Europe averaged 5,600 boepd in
2017, which includes production from Tullow's Netherlands assets
prior to the completion of their sale in November 2017. In mid-2017
Tullow started the planning, engineering and procurement processes
to decommission up to 10 operated wells in the UK Continental Shelf
during 2018. Site surveys and other preparatory works will be
undertaken during the first quarter of 2018, which will be followed
by approximately six months of well plug and abandonment
operations. Tullow expects annual production from its UK assets to
average around 1,900 boepd in 2018, which takes into account
cessation of production at the end of the third quarter of 2018,
ahead of decommissioning activities.
EAST AFRICA
Mark MacFarlane, Executive Vice President for East Africa,
commented today:
"The exploration and appraisal campaign in Kenya
has confirmed the presence of substantial oil resources
in the South Lokichar Basin. After over six years
of hard work, we can now move forward to commercialising
these low cost resources through a phased development
of the basin involving a central processing facility
and an export pipeline to the Kenyan coast. In 2018,
we will focus on taking the project towards FID in
2019 with a prudent and flexible plan of execution
that can take advantage of low oil services costs
and deliver first oil and cash flow as soon as possible.
With good progress being made in Uganda towards FID,
East Africa is on the verge of becoming a major oil
exporting region."
=============================================================
Kenya
The South Lokichar basin appraisal programme has confirmed
material oil resources to support substantial oil production and an
export pipeline to the Kenyan coast pending a Final Investment
Decision (FID) which is planned for 2019. The proposed development
plan reflects the Partnership's desire to sanction the project in a
manner that is commercially robust, ensures the earliest possible
FID and First Oil and supports the required infrastructure given
the location of the South Lokichar basin some 750 km from the
Kenyan coast.
Appraisal campaign and resource estimates
A total of 21 appraisal wells have been drilled in the South
Lokichar basin. Tullow has also conducted extended well tests,
water injection tests, well interference tests and water-flood
trials, all of which have proved invaluable for planning the
development of the oil fields. The appraisal campaign has firmed up
the Group's resource estimates and improved Tullow's understanding
of the subsurface at the key producing fields.
Following a full assessment of all the exploration and appraisal
data, Tullow estimates that the South Lokichar basin contains the
following recoverable resources: 240 - 560 - 1,230 mmbo (1C-2C-3C)
from an overall discovered STOIIP of up to 4 billion barrels. This
estimate of recoverable resources is consistent with previous
guidance provided during the exploration and appraisal phase (Pmean
of 750 mmbo). The additional remaining conventional undrilled
prospect inventory of the basin is approximately 230 mmbo risked
mean recoverable, not including further potential in tight-oil
plays in the future.
Development
Tullow and its Joint Venture Partners have proposed to the
Government of Kenya that the Amosing and Ngamia fields should be
developed as the Foundation Stage of the South Lokichar
development. This stage would include a 60,000 to 80,000 bopd
Central Processing Facility (CPF) and an export pipeline to Lamu.
This approach brings significant benefits as it enables an early
FID of the Amosing and Ngamia fields taking full advantage of the
current low-cost environment for both the field and infrastructure
development and provides the best opportunity to deliver First Oil
in a timeline that meets the Government of Kenya (GoK)
expectations. The installed infrastructure from this initial phase
can then be utilised for the optimisation of the remaining South
Lokichar oil fields, allowing the incremental development of these
fields to be completed at a lower unit cost post-First Oil.
The Foundation Stage is currently planned to involve an initial
210 wells through 18 well pads at Ngamia and 70 wells through seven
well pads at Amosing. This stage will target volumes of around 210
mmbo of the total estimated 2C resources of 560 mmbo and a plateau
rate of 60,000 to 80,000 bopd. The incremental development of the
remaining 2C resources and the significant upside potential is
expected to increase plateau production to 100,000 bopd or greater.
It is anticipated that the FEED and baseline Environmental and
Social Impact Assessments (ESIA) for the foundation development
will commence in the second quarter of 2018, with FID targeted for
2019 and First Oil for 2021/22. Total gross capex associated with
the Foundation Stage is expected to be $2.9 billion, of which $1.8
billion is investment in the upstream and $1.1 billion is for the
pipeline.
Tullow and its Joint Venture Partners, following the extended
election period, have re-engaged with representatives of the
Government of Kenya on the overall approach and timelines for
progressing the development.
Early Oil Pilot Scheme (EOPS)
The EOPS Agreement between the Joint Venture Partners and the
Government of Kenya was signed on 14 March 2017 allowing all EOPS
upstream contracts to be awarded. Initial injectivity testing has
started at Ngamia-11 and oil production and water injection
facilities are being constructed in the field ready to commence
production/injection in the first quarter of 2018. Oil produced is
being initially stored until all necessary consents and approvals
are granted and work is completed for the transfer of crude oil to
Mombasa by road.
Uganda
Farm-down to Total and CNOOC
On 9 January 2017, Tullow announced that it had agreed to
transfer 21.57% of its 33.33% Uganda interests to Total for a total
consideration of $900 million. CNOOC subsequently exercised its
pre-emption rights under the joint operating agreements to acquire
50% of the interests being transferred to Total on the same terms
and conditions. Having signed pre-emption documents with its Joint
Venture Partners and officially notified the Government of Uganda
of the transaction, Tullow and its Joint Venture Partners are
awaiting approval of the transaction from the Government of
Uganda.
As previously disclosed, Tullow anticipates that the farm-down
with Total and CNOOC will complete in the first half of 2018 with a
cash payment of $100 million on completion and payment of the
working capital completion adjustment and deferred consideration
for the pre-completion period (including $60 million for the whole
of 2017) being received at this time. A further $50 million cash
consideration is due to be received when FID is achieved.
The Joint Venture Partners are also working towards reaching FID
around mid-year 2018; at which point Tullow's second cash
instalment from the farm-down will be due. In line with its
post-transaction status, Tullow has been reducing its operational
footprint in Uganda and is now fully prepared for a non-operated
presence only.
Operational activity is continuing as planned, with FEED and
ESIAs for both the upstream and pipeline progressing in line with
the FID schedule. Discussions on the pipeline project continue
amongst Joint Venture Partners and with both the Ugandan and
Tanzanian Governments regarding the key commercial and
transportation agreements.
East Africa Crude Oil Export Pipeline (EACOP)
The Governments of Uganda and Tanzania signed an
Intergovernmental Agreement (IGA) for the pipeline, the critical
infrastructure for this project, on 26 May 2017. This has secured
the pipeline routing and allowed discussions to commence with the
Governments of Uganda and Tanzania on the Host Government
Agreements and other key commercial agreements.
NEW VENTURES
Ian Cloke, Executive Vice President for New Ventures, commented
today:
"The New Ventures team has worked exceptionally hard
over the past three years to re-set the exploration
portfolio for the new industry environment. Through
a series of farm-downs, country exits and large-scale
licence acquisitions, we now have a prospect and
lead inventory that sits in industry hot spots and
in under-explored or emergent petroleum systems in
geographies and geologies that we know well. Our
high-impact, low-cost, basin-testing prospects across
Africa and South America have been carefully screened,
both technically and commercially, and we look forward
to starting this new exploration cycle with the Cormorant
well, offshore Namibia, later this year."
==============================================================
Africa
Côte d'Ivoire
Tullow has agreed terms to add a further two exploration
licences in Côte d'Ivoire to its portfolio, CI-524 and CI-520.
These licence awards have been approved by the Ivorian cabinet and
formal signing is anticipated in the first quarter of 2018.
Block CI-524 sits alongside the maritime border with Ghana, next
to Tullow's operated TEN fields. The initial work programme will
include re-processing of the 3D seismic data before a decision is
made whether to drill a well.
Block CI-520, once signed, completes the Group's coverage of a
transform basin fault play built during 2017 when the Group was
awarded a 90% interest in six onshore licences (CI-521, CI-522,
CI-518, CI-519, CI-301 and CI-302). The Group plans to conduct a
full tensor gradiometry gravity survey (FTG) across the 8,600 sq km
onshore area in the first half of 2018, before acquiring 2D seismic
in 2019.
Mauritania
In the second half of 2017, Tullow completed farm-downs in
respect of its 90% interest in Block C-18 in Mauritania to Total,
Kosmos and BP leaving Tullow with a 15% non-operated interest. This
followed a 600 sq km 3D survey completed earlier in 2017. A
two-year extension to the licence term was also granted. In
December 2017, the new operator, Total, commenced a large 9,000 sq
km 3D seismic survey which is expected to be completed in the first
quarter of 2018. A further 3D survey in Block C-3 to cover new
shallow water plays was completed in the fourth quarter of 2017.
Both blocks offer potential drilling candidates for late 2019.
Finally, Tullow relinquished its interest in Block C-10 at the end
of November as insufficient commercial justification could be made
to enter into a third phase of the licence.
Namibia
Tullow plans to drill the high-impact Cormorant prospect in the
PEL37 licence in Namibia in the second half of 2018 and
preparations for drilling are under way. The well will target light
oil and there are a number of similarly-sized follow-up prospects
in close proximity. Also in Namibia, Tullow agreed a farm-down of a
15% interest in the neighbouring PEL30 licence to ONGC Videsh in
November 2017. The farm-down is subject to Government and partner
approvals with completion expected in the first quarter of 2018.
This followed the farm-down of a 30% interest in PEL37 in October
2017, also to ONGC Videsh.
Zambia
In Zambia, a 20,000 sq km FTG survey and passive seismic survey
to cover frontier Tertiary age rift basins finished in October 2017
and the next steps are being evaluated.
South America
Peru
Tullow has agreed terms to add six new licences covering 28,000
sq km, offshore Peru, to its portfolio. The Group has concluded
negotiations with Perupetro and agreed to acquire a 100% stake in
Blocks Z-64, Z-65, Z-66, Z-67 & Z-68. The agreements are
subject to final approval by the Peruvian Ministry of Energy and
Mines and Ministry of Economy and Finance, with formal signing of
the licences anticipated in the first quarter of 2018. Tullow has
also agreed to acquire a 35% interest in Block Z-38 through a
farm-down from Karoon Gas Australia, also subject to Government
approval. The new oil prone acreage will complement the Group's
South America position and contains a number of attractive
prospects and leads. Block Z-38 is already covered by high quality
3D seismic and includes the Marina prospect which is a potential
candidate for drilling in 2019.
Guyana
Tullow has agreed to increase its equity share in the Kanuku
licence, offshore Guyana, from 30% to 37.5% in a farm-in deal with
Repsol. The deal is subject to Government approval. Following
acquisition of new 3D seismic on the licence in 2017, the JV
Partnership is interpreting the data to firm up prospects for
possible drilling in 2019 in this exciting area, up-dip from
Exxon's Liza discovery.
Processing 3D seismic data acquired during 2017 on the Orinduik
licence is also ongoing to mature and rank identified
prospects.
Uruguay
In Uruguay, a 2,555 sq km 3D seismic survey was completed in
2017. The data from this survey is currently being processed.
Suriname
The Araku-1 well drilled in October 2017 in Block 54 in Suriname
was unsuccessful, but did prove the presence of a new petroleum
system in the Demerara plateau which is now being followed up. At a
gross cost of $35 million (net: $11 million), Tullow demonstrated
its ability to drill high-risk, wildcat frontier wells at
appropriate equity and at low cost. A two-year extension was
granted for the adjacent Block 47 where the Goliathberg prospect is
a potential drilling candidate for 2019.
Jamaica
In November 2017, Tullow agreed, subject to Government approval,
a farm-down of 20% of its 100% interest in the Walton Morant
licence in Jamaica to United Oil & Gas plc. A nine-month
extension to the licence term was also granted, enabling a 2,100 sq
km 3D survey to commence in April 2018. This follows a successful
667 km 2D seismic survey in Jamaica in the first half of 2017.
Asia
Tullow is in the process of selling its Pakistan assets and
expects to complete this process in 2018.
Europe
The Group completed its exit from Norway in 2017 allowing the
New Ventures team to focus on Africa and South America
Finance review
Les Wood, Chief Financial Officer, commented today:
"Tullow's balance sheet is considerably stronger
at the start of 2018 following the $0.75 billion
Rights Issue, strong free cash flow generation of
$543 million and delivery of key objectives, including
the successful $2.5 billion refinancing. Our gearing
is approaching our target level of below 2.5x Net
Debt/EBITDAX providing the financial and operational
flexibility we need to invest in our business. We
have also driven down both our corporate and asset
costs and have embedded financial discipline across
the Group. Tullow is well placed to build on this
strong financial platform in 2018."
================================================================
Financial results summary 2017 2016 Change
========================================== ========= ========= ======
Working interest production
volume (boepd)(1) 87,300 67,100 30%
========================================== ========= ========= ======
Sales volume (boepd) 82,200 59,900 37%
========================================== ========= ========= ======
Realised oil price ($/bbl) 58.3 61.4 (5%)
========================================== ========= ========= ======
Realised gas price (p/therm) 43 34 26%
========================================== ========= ========= ======
Total revenue ($m)(2) 1,723 1,270 36%
========================================== ========= ========= ======
Gross profit ($m) 815 547 49%
========================================== ========= ========= ======
Underlying cash operating
costs per boe ($/boe) (3,4) 11.1 14.3 22%
========================================== ========= ========= ======
Exploration costs written
off ($m) 143 723 80%
========================================== ========= ========= ======
Impairment of property, plant
and equipment, net ($m) 539 168 -
========================================== ========= ========= ======
Operating profit/(loss) ($m) 22 (755) -
========================================== ========= ========= ======
Loss before tax ($m) (299) (908) 67%
========================================== ========= ========= ======
Loss after tax ($m) (189) (597) 68%
========================================== ========= ========= ======
Basic loss per share (cents) (14.7) (55.8) 74%
========================================== ========= ========= ======
Capital investment ($m)(3,5) 225 857 74%
========================================== ========= ========= ======
Adjusted EBITDAX ($m) (3) 1,346 941 43%
========================================== ========= ========= ======
Net debt ($m) (3) 3,471 4,782 27%
========================================== ========= ========= ======
Gearing (times) (3) 2.6 5.1 2.5
========================================== ========= ========= ======
Free cash flow ($m) (3) 543 (792) -
========================================== ========= ========= ======
1. Including the impact of production-equivalent insurance
payment barrels from the Jubilee field, Group working interest
production was 94,700 boepd.
2. Total revenue does not include receipts for Tullow's
corporate Business Interruption insurance of $162 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. Excluding prior year accrual reversals, the underlying cash
operating costs were $11.7/boe.
5. Capital investment excludes Ugandan expenditure of $58
million in 2017 that will, subject to completion of the farm-down,
be offset by either the working capital completion adjustment or
deferred consideration. It is also net of the reversal of $69
million of prior year accruals due to change in estimates.
Production and commodity prices
Working interest production averaged 87,300 boepd, an increase
of 30% for the year (2016: 67,100 boepd). Including the impact of
production-equivalent insurance payment barrels from the Jubilee
field, working interest production averaged 94,700 boepd (2016:
71,700 boepd), an increase of 32%. The increase resulted from the
first full year of production from the TEN fields and improved
operational performance at Jubilee in response to implementation of
the first phases of remediating the turret. This was offset by
declines due to the disposal of the Netherlands assets during the
year, as well as reductions across the non-operated West Africa
portfolio.
The Group's realised oil price after hedging was $58.3/bbl and
$54.2/bbl before hedging (2016: $61.4/bbl and $41.7/bbl
respectively). The increase in underlying oil prices reduced the
net contribution of the realisation of hedges entered in to by the
Group to total revenue. However, hedging remains a key element of
the Group's risk management strategy. The Group's realised European
gas price after hedging was 43 pence/therm (2016: 34 pence/therm),
an increase of 27% driven by improvements in underlying European
gas prices.
Underlying cash operating costs, depreciation, impairments,
write-offs, and administrative expenses
Underlying cash operating costs amounted to $386 million;
$11.1/boe (2016: $377 million; $14.3/boe). Underlying cash
operating costs were net of $51 million of insurance proceeds
(2016: $32 million). The decrease of 22% in underlying cash
operating costs per boe was principally due to the impact of
ongoing cost saving initiatives and increased working interest
production volumes.
DD&A charges before impairment on production and development
assets amounted to $574 million; $16.6/boe (2016: $449 million;
$17.0/boe).
The Group recognised an impairment charge of $539 million in
respect of 2017 (2016: $168 million) which reflects lower long-term
oil and gas price forecasts than previous years. This is lower than
the impairment charge of $642 million reported at the Half Year
results, due to the lower Dated Brent forward curve at that time.
The Group did not recognise any impairment of goodwill during the
year as it was fully impaired in 2016 (2016: $164 million).
During 2017, exploration costs written off were $143 million and
included $71 million in Mauritania due to a licence that was not
renewed, $36 million due to the decision to exit Pakistan, $6
million on disposals of assets in the Netherlands, $10 million on
unsuccessful drilling costs in Suriname, and $17 million of New
Ventures activity. The total exploration costs written off, net of
tax, were $139 million (2016: $424 million).
Administrative expenses of $95 million (2016: $116 million)
include an amount of $33 million (2016: $41 million) associated
with share-based payment charges. The Group is on track to generate
savings, over three years to mid-2018, in excess of $650 million,
ahead of the Company's original target of $500 million. Savings of
$581 million have been achieved as at 31 December 2017.
During 2017, the Group recognised an income statement charge for
restructuring costs of $15 million (2016: $12 million) relating to
headcount reductions associated with organisation simplifications
and certain country exits. This has been presented separately from
administrative expenses in the income statement.
Provision for onerous service contracts
At the end of 2017, Tullow had provided $131 million (2016: $133
million) for onerous service contracts due to the reduction in
planned future activity under those contracts. The changes in
estimates for the provision resulted in an income statement credit
in 2017 of $1 million (2016: charge of $115 million).
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 reinvestment in capital
programmes that are driving business growth. From 2015 to 2017,
this approach generated net revenue of c. $0.85 billion and the
systematic approach will continue even as oil prices appear to be
stabilising. The 2018 hedging programme protects 60% of group
production at an average floor of $52/bbl, with 40% of group
production capped through collars at an average of $75/bbl, 20%
uncapped and fully exposed to the upside and the remaining 40% of
production unhedged.
At 31 December 2017, the Group's derivative instruments had a
net negative fair value of $76 million (2016: positive $91
million), net of deferred premium. While all of the Group's
commodity derivative instruments currently qualify for hedge
accounting, a pre-tax charge of $12 million (2016: credit of $18
million) in relation to the change in time value of the Group's
commodity derivative instruments has been recognised within finance
costs in the income statement for 2017.
Hedge position at 31 December 2017 2018 2019 2020
====================================== ====== ====== =====
Oil hedges
====================================== ====== ====== =====
Volume - bopd 45,000 22,232 997
====================================== ====== ====== =====
Average floor price protected ($/bbl) 52.23 48.87 50.00
====================================== ====== ====== =====
Net financing costs
Net financing costs for the year were $310 million (2016: $172
million). The increase in financing costs is associated with a
decrease in the value of capitalised interest due to the completion
of the TEN development in 2016, and the commencement of recording
interest on obligations under the TEN FPSO finance lease. This was
offset by a reduction in interest on borrowings due to a reduction
in the average level of net debt in 2017 compared to 2016. 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 credit of $111 million (2016: credit of $311 million)
relates to a tax charge in respect of hedging profits, Gabon and
Equatorial Guinea production activities offset by credits in
respect of the Group's North Sea and Ghana production activities
and non-recurring deferred tax credits associated with exploration
write-offs and impairments.
The group's statutory effective tax rate for 2017 is 37.0 per
cent (2016: 34.2 per cent). The increase in the tax rate for 2017
is mainly due to deferred tax credits associated with the
impairment of property, plant, and equipment.
After adjusting for non-recurring amounts related to exploration
write-offs, disposals, impairments and onerous lease provisions and
their associated deferred tax benefit, the Group's adjusted tax
rate is 23.8 per cent (2016: 23.3 per cent). The adjusted tax rate
has remained relatively consistent due to the mix of profits,
notably the impact of increased profits from overseas production
taxed at higher rates offset by hedging profits and business
interruption insurance proceeds taxed at the UK's effective
corporate tax rate of 19.25%.
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. It is however expected that the adjusted tax
rate should again broadly follow the UK's standard rate of
corporation tax as more of the Group's profit is forecast to arise
in the UK.
Loss after tax from continuing activities and loss per share
The loss for the year from continuing activities amounted to
$189 million (2016: $597 million loss). Basic loss per share was
14.7 cents (2016: 55.8 cents loss).
Reconciliation of net debt $m
=================================================== =======
Year-end 2016 net debt 4,782
--------------------------------------------------- =======
Sales revenue (1,723)
--------------------------------------------------- =======
Other operating income - lost production insurance
proceeds (162)
--------------------------------------------------- =======
Operating costs 386
=================================================== =======
Operating expenses 199
=================================================== =======
Cash flow from operations (1,300)
=================================================== =======
Movement in working capital 135
=================================================== =======
Tax received, net (65)
=================================================== =======
Purchases of intangible exploration and evaluation
assets and property, plant, and equipment 308
=================================================== =======
Other investing activities (11)
=================================================== =======
Rights issue proceeds (721)
=================================================== =======
Other financing activities 340
=================================================== =======
Foreign exchange gain on cash and debt 4
=================================================== =======
Year-end 2017 net debt 3,471
=================================================== =======
Capital investment
2017 capital investment (net of Uganda expenditure) amounted to
$225 million, net of prior year accrual reversals of $69 million,
(2016: $0.9 billion) with $127 million invested in development
activities and $98 million invested in exploration and appraisal
activities. More than 80% of the total was invested in Kenya and
Ghana and over 90% was invested in Africa. Capital expenditure will
continue to be carefully controlled during 2018. The Group's 2018
capital expenditure associated with operating activities is
expected to total approximately $460 million. This total excludes
$110 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 the year. The capex total comprises
Ghana capex of c.$250 million, West Africa non-operated capex of
c.$40 million, Kenya pre-development expenditure of c.$80 million
and Exploration and Appraisal spend of c.$90 million.
At completion of the Uganda farm-down, Tullow is also due to
receive $100 million cash consideration along with re-imbursement
of 2017 capex of c.$60 million. A further $50 million cash
consideration is due to be received when FID is achieved.
Portfolio management
Tullow's farm-down in Uganda continues to progress and the Joint
Venture Partners await approval of the transaction from the
Government of Uganda.
During 2017 Tullow also completed the sale of its remaining
Dutch and Norwegian assets.
Credit Ratings
Tullow maintains corporate credit ratings with Standard &
Poor's and Moody's Investors Service. In early January, Standard
& Poor's announced that they had revised the outlook on
Tullow's 'B' corporate credit rating to positive from stable.
Moody's Investors Service upgraded Tullow's Corporate Family Rating
to B1 from B2. Moody's Investors Service upgraded their ratings of
Tullow's corporate bonds to B3 from Caa1.
Balance sheet
On 29 November 2017, Tullow announced that it had completed the
refinancing of $2.5 billion of Reserves Based Lending ("RBL")
credit facilities. The $2.5 billion of credit facilities are split
between a commercial bank facility of $2.4 billion and an IFC
facility of $100 million. The fully committed facilities are
revolving with a three-year grace period and final maturity of
November 2024. Tullow also decided to reduce the commitments of its
Revolving Corporate Credit Facility to $600 million from $800
million, ahead of the scheduled amortisation that was due to occur
in January 2018. As of year-end 2017, Tullow has total headroom
including free cash of $1.1 billion with no material near-term debt
maturities, and net debt of $3.5 billion.
During 2017, the Group's net debt to adjusted EBITDAX gearing
ratio has reduced from 5.1x to 2.6x. This reduction has been driven
by increased adjusted EBITDAX generated by the business of $1,346
million compared to $941 million in 2016 and lower net debt as a
result of the significant free cash flow generated in 2017 and the
$721m net proceeds from the Rights Issue. This takes Tullow close
to its target gearing position of below 2.5x.
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 $1.1 billion of debt liquidity
headroom and free cash at the end of 2017. 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 2017 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.
2018 principal financial risks and uncertainties
The principal financial risks to performance identified for 2018
are:
-- Inability to progress major portfolio options
-- Disruption to business due to community/political/regulatory influence
-- Failure to manage oil price risk
-- Major process safety/equipment/EHS failures
Events since 31 December 2017
There has not been any event since 31 December 2017 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.
Capital investment
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. Capital investment is defined as
additions to property, plant and equipment and intangible
exploration and evaluation assets less decommissioning asset
additions, capitalised share-based payment charge, capitalised
finance costs, additions to administrative assets, Norwegian tax
refund, and certain other non-cash capital expenditure.
2017 2016
$m $m
==================================== === ====== ========
Additions to property, plant and
equipment 887.7 818.5
----------------------------------------- ------ --------
Additions to intangible exploration
and evaluation assets 319.0 291.4
----------------------------------------- ------ --------
Less
------------------------------------ --- ------ --------
Decommissioning asset additions (33.6) 57.1
----------------------------------------- ------ --------
Finance lease asset additions 837.6 -
----------------------------------------- ------ --------
Capitalised share-based payment
charge 0.3 2.7
----------------------------------------- ------ --------
Capitalised finance costs 66.5 138.8
----------------------------------------- ------ --------
Additions to administrative assets 7.0 1.6
----------------------------------------- ------ --------
Norwegian tax refund 2.1 50.5
----------------------------------------- ------ --------
Uganda capital investment 57.5 -
----------------------------------------- ------ --------
Other non-cash capital expenditure 44.7 2.2
========================================= ====== ========
Capital investment 224.6 857.0
----------------------------------------- ------ --------
Movement in working capital 16.3 122.1
----------------------------------------- ------ --------
Additions to administrative assets 7.0 1.6
----------------------------------------- ------ --------
Norwegian tax refund 2.1 50.5
----------------------------------------- ------ --------
Uganda capital investment 57.5 -
========================================= ====== ========
Cash capital expenditure per the
cash flow statement 307.5 1,031.2
========================================= ====== ========
Net debt
Net debt is a useful indicator of the Group's indebtedness,
financial flexibility and capital structure because it indicates
the level of cash borrowings after taking account of cash and cash
equivalents within the Group's business that could be utilised to
pay down the outstanding cash borrowings. Net debt is defined as
current and non-current borrowings plus unamortised arrangement
fees and the equity component of any compound debt instrument less
cash and cash equivalents. The Group's definition of net debt does
not include the Group's finance leases as the Group's focus is the
management of cash borrowings and a finance lease is viewed as
deferred capital investment. The value of the Group's Finance Lease
liabilities as at 31 December 2017 was $228.1 million current and
$1,317.5 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.
2017 2016
$m $m
================================ === ======= =======
Current borrowings - 591.5
------------------------------------- ------- -------
Non-current borrowings 3,606.4 4,388.4
------------------------------------- ------- -------
Unamortised arrangement fees 100.2 35.5
------------------------------------- ------- -------
Equity component of convertible
bonds 48.4 48.4
------------------------------------- ------- -------
Less cash and cash equivalents (284.0) (281.9)
------------------------------------- ------- -------
Net debt 3,471.0 4,781.9
===================================== ======= =======
Gearing and Adjusted EBITDAX
Gearing is a useful indicator of the Group's indebtedness,
financial flexibility and capital structure and can assist
securities analysts, investors and other parties to evaluate the
Group. Gearing is defined as net debt divided by Adjusted EBITDAX.
Adjusted EBITDAX is defined as loss from continuing activities less
income tax credit, finance costs, finance revenue, (loss)/gain on
hedging instruments, 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 and provision for onerous service contracts. Adjusted
EBITDAX therefore excludes interest on obligations under finance
leases of $46.1 million, and interest income on amounts due from
joint venture partners for finance leases of $21.0 million, as in
assessing business performance, management considers lease payments
in substance to represent deferred capital expenditure. Had these
been included in the calculation of Adjusted EBITDAX, calculated
Gearing would have been unchanged at 2.6x.
2017 2016
$m $m
========================================= === ======= =======
Loss from continuing activities (188.5) (597.3)
---------------------------------------------- ------- -------
Less
----------------------------------------- --- ------- -------
Income tax credit (110.6) (311.0)
---------------------------------------------- ------- -------
Finance costs 351.7 198.2
---------------------------------------------- ------- -------
Finance revenue (42.0) (26.4)
---------------------------------------------- ------- -------
Loss/(gain) on hedging instruments 11.8 (18.2)
---------------------------------------------- ------- -------
Depreciation, depletion and amortisation 592.2 466.9
---------------------------------------------- ------- -------
Share-based payment charge 33.9 43.9
---------------------------------------------- ------- -------
Restructuring costs 14.5 12.3
---------------------------------------------- ------- -------
Loss on disposal 1.6 3.4
---------------------------------------------- ------- -------
Goodwill impairment - 164.0
---------------------------------------------- ------- -------
Exploration costs written off 143.4 723.0
---------------------------------------------- ------- -------
Impairment of property, plant and
equipment, net 539.1 167.6
---------------------------------------------- ------- -------
Provision for onerous service contracts,
net (1.0) 114.9
============================================== ======= =======
Adjusted EBITDAX 1,346.1 941.3
============================================== ======= =======
Net debt 3,471.0 4,781.9
============================================== ======= =======
Gearing (times) 2.6 5.1
============================================== ======= =======
Underlying cash operating costs
Underlying cash operating costs is a useful indicator of the
Group's underlying cash costs incurred to produce oil and gas.
Underlying cash operating costs eliminates certain non-cash
accounting adjustments to the Group's cost of sales to produce oil
and gas. Underlying cash operating costs is defined as cost of
sales less operating lease expense, depletion and amortisation of
oil and gas assets, underlift, overlift and oil stock movements,
share-based payment charge included in cost of sales, and certain
other cost of sales. Underlying cash operating costs are divided by
production to determine underlying cash operating costs per
boe.
2017 2016
$m $m
==================================== === ======= ======
Cost of sales 1,069.3 813.1
----------------------------------------- ------- ------
Less
------------------------------------ --- ------- ------
Operating lease expense 62.5 21.0
----------------------------------------- ------- ------
Depletion and amortisation of oil
and gas assets 574.3 448.5
----------------------------------------- ------- ------
Underlift, overlift and oil stock
movements (2.3) (76.5)
----------------------------------------- ------- ------
Share-based payment charge included
in cost of sales 1.1 2.7
----------------------------------------- ------- ------
Other cost of sales 47.5 40.2
========================================= ======= ======
Underlying cash operating costs 386.2 377.2
========================================= ======= ======
Production (MMboe) 34.7 26.4
========================================= ======= ======
Underlying cash operating costs
per boe ($/boe) 11.1 14.3
----------------------------------------- ------- ------
Excluding prior year accrual reversals, the underlying cash
operating costs were $11.7/boe.
Free cash flow
Free cash flow is a useful indicator of the Group's ability to
generate organic cash flow to fund the business and strategic
acquisitions, reduce borrowings and available to return to
shareholders through dividends. Free cash flow is defined as net
cash from operating activities, net cash used in investing
activities, net cash generated by financing activities and foreign
exchange loss less repayment of bank loans, drawdown of bank loans
and issue of convertible bonds.
2017 2016
$m $m
====================================== === ======= =========
Net cash from operating activities 1,222.9 512.5
------------------------------------------- ------- ---------
Net cash used in investing activities (296.4) (967.2)
------------------------------------------- ------- ---------
Net cash (used in)/generated by
financing activities (927.9) 399.3
------------------------------------------- ------- ---------
Foreign exchange gain/(loss) 3.5 (18.4)
------------------------------------------- ------- ---------
Net proceeds from issue share capital (768.1) -
------------------------------------------- ------- ---------
Repayment of bank loans 1,613.6 769.1
------------------------------------------- ------- ---------
Drawdown of bank loans (305.0) (1,187.5)
------------------------------------------- ------- ---------
Issue of convertible bonds - (300.0)
=========================================== ======= =========
Free cash flow 542.6 (792.2)
=========================================== ======= =========
Group income statement
Year ended 31 December 2017
2017 2016
Notes $m $m
========================================== ============ ========== =========
Continuing activities
Sales revenue 1,722.5 1,269.9
Other operating income - lost
production insurance proceeds 7 162.1 90.1
Cost of sales 5 (1,069.3) (813.1)
========================================== ============ ========== =========
Gross profit 815.3 546.9
========================================== ============ ========== =========
Administrative expenses 5 (95.3) (116.4)
Restructuring costs 5 (14.5) (12.3)
Loss on disposal (1.6) (3.4)
Goodwill impairment - (164.0)
Exploration costs written off 9 (143.4) (723.0)
Impairment of property, plant
and equipment, net 10 (539.1) (167.6)
Provision for onerous service
contracts, net 1.0 (114.9)
========================================== ============ ========== =========
Operating profit/(loss) 22.4 (754.7)
========================================== ============ ========== =========
(Loss)/gain on hedging instruments (11.8) 18.2
Finance revenue 6 42.0 26.4
Finance costs 6 (351.7) (198.2)
========================================== ============ ========== =========
Loss from continuing activities
before tax (299.1) (908.3)
========================================== ============ ========== =========
Income tax credit 8 110.6 311.0
========================================== ============ ========== =========
Loss for the year from continuing
activities (188.5) (597.3)
========================================== ============ ========== =========
Attributable to:
Owners of the Company (189.5) (599.9)
Non-controlling interest 1.0 2.6
========================================== ============ ========== =========
(188.5) (597.3)
========================================== ============ ========== =========
Loss per ordinary share from c c
continuing activities
========================================== ============ ========== =========
Basic 2 (14.7) (55.8)
Diluted 2 (14.7) (55.8)
========================================== ============ ========== =========
Comparative basic and diluted loss per ordinary share
from continuing activities have been re-presented
as a result of the Rights Issue
Group statement of comprehensive income and expense
Year ended 31 December 2017
2017 2016
$m $m
========================================== ======== =======================
Loss for the year (188.5) (597.3)
========================================== ======== =======================
Items that may be reclassified to
the income statement in subsequent
periods
========================================== ======== =======================
Cash flow hedges
Gain/(loss) arising in the year 6.7 (135.3)
Reclassification adjustments for
items included in loss on realisation (161.8) (415.2)
Exchange differences on translation
of foreign operations 9.0 17.1
========================================== ======== =======================
Other comprehensive loss (146.1) (533.4)
========================================== ======== =======================
Tax relating to components of other
comprehensive loss 24.3 108.8
========================================== ======== =======================
Net other comprehensive loss for
the year (121.8) (424.6)
========================================== ======== =======================
Total comprehensive expense for
the year (310.3) (1,021.9)
========================================== ======== =======================
Attributable to:
========================================== ======== =======================
Owners of the Company (311.3) (1,024.5)
Non-controlling interest 1.0 2.6
========================================== ======== =======================
(310.3) (1,021.9)
========================================== ======== =======================
Group balance sheet
As at 31 December 2017
2017 2016
Notes $m $m
======================================= ===== ========== ==========
ASSETS
Non-current assets
Intangible exploration and evaluation
assets 9 1,933.4 2,025.8
Property, plant and equipment 10 5,254.7 5,362.9
Investments 1.0 1.0
Other non-current assets 11 789.8 175.7
Derivative financial instruments 0.8 15.8
Deferred tax assets 724.5 758.9
======================================= ===== ========== ==========
8,704.2 8,340.1
======================================= ===== ========== ==========
Current assets
Inventories 168.0 155.3
Trade receivables 171.4 118.4
Other current assets 11 768.3 838.9
Current tax assets 57.7 138.3
Derivative financial instruments 1.8 91.7
Cash and cash equivalents 284.0 281.9
Assets classified as held for sale 12 873.1 837.1
======================================= ===== ========== ==========
2,324.3 2,461.6
======================================= ===== ========== ==========
Total assets 11,028.5 10,801.7
======================================= ===== ========== ==========
LIABILITIES
Current liabilities
Trade and other payables 13 (1,025.6) (916.1)
Provisions 14 (230.8) (51.9)
Borrowings - (591.5)
Current tax liabilities (45.0) (83.1)
Derivative financial instruments (53.1) (5.9)
(1,354.5) (1,648.5)
======================================= ===== ========== ==========
Non-current liabilities
Trade and other payables 13 (1,422.6) (112.3)
Borrowings (3,606.4) (4,388.4)
Provisions 14 (801.6) (1,106.7)
Deferred tax liabilities (1,101.2) (1,292.4)
Derivative financial instruments (25.8) (10.9)
======================================= ===== ========== ==========
(6,957.6) (6,910.7)
======================================= ===== ========== ==========
Total liabilities (8,312.1) (8,559.2)
======================================= ===== ========== ==========
Net assets 2,716.4 2,242.5
======================================= ===== ========== ==========
EQUITY
Called up share capital 208.2 147.5
Share premium 1,326.8 619.3
Equity component of convertible
bonds 48.4 48.4
Foreign currency translation reserve (223.2) (232.2)
Hedge reserve (2.6) 128.2
Other reserves 740.9 740.9
Retained earnings 607.5 778.0
======================================= ===== ========== ==========
Equity attributable to equity holders
of the Company 2,706.0 2,230.1
Non-controlling interest 10.4 12.4
======================================= ===== ========== ==========
Total equity 2,716.4 2,242.5
======================================= ===== ========== ==========
Group statement of changes in equity
Year ended 31 December 2017
Equity
component
of
Called convertible
up share Share bonds Total
$m Foreign
currency
translation Hedge Other Retained Non-controlling
capital premium reserve(1) reserve(2) reserves(3) earnings Total interest Equity
$m $m $m $m $m $m $m $m $m
================= ========= ========= =========== =========== ========== ================================== =========== ========== =============== ==========
At 1 January
2016 147.2 609.8 - (249.3) 569.9 740.9 1,336.4 3,154.9 19.8 3,174.7
Loss for the
year - - - - - - (599.9) (599.9) 2.6 (597.3)
Hedges, net
of tax - - - - (441.7) - - (441.7) - (441.7)
Currency
translation
adjustments - - - 17.1 - - - 17.1 - 17.1
Issue of
convertible
bonds - - 48.4 - - - - 48.4 - 48.4
Issue of
employee
share options 0.3 9.5 - - - - - 9.8 - 9.8
Vesting of
PSP shares - - - - - - (9.4) (9.4) - (9.4)
Share-based
payment charges - - - - - - 50.9 50.9 - 50.9
Distribution
to
non-controlling
interests - - - - - - - - (10.0) (10.0)
================= ========= ========= =========== =========== ========== ================================== =========== ========== =============== ==========
At 1 January
2017 147.5 619.3 48.4 (232.2) 128.2 740.9 778.0 2,230.1 12.4 2,242.5
Loss for the
year - - - - - - (189.5) (189.5) 1.0 (188.5)
Hedges, net
of tax - - - - (130.8) - - (130.8) - (130.8)
Currency
translation
adjustments - - - 9.0 - - - 9.0 - 9.0
Rights Issue 60.0 693.8 - - - - - 753.8 - 753.8
Issue of
employee
share options 0.7 13.7 - - - - - 14.4 - 14.4
Vesting of
PSP shares - - - - - - (15.2) (15.2) - (15.2)
Share-based
payment charges - - - - - - 34.2 34.2 - 34.2
Distribution
to
non-controlling
interests - - - - - - - - (3.0) (3.0)
================= ========= ========= =========== =========== ========== ================================== =========== ========== =============== ==========
At 31 December
2017 208.2 1,326.8 48.4 (223.2) (2.6) 740.9 607.5 2,706.0 10.4 2,716.4
================= ========= ========= =========== =========== ========== ================================== =========== ========== =============== ==========
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 and the treasury
shares reserve which represents the cost of shares in Tullow Oil
plc purchased in the market and held by the Tullow Oil Employee
Trust to satisfy awards held under the Group's share incentive
plans.
Group cash flow statement
Year ended 31 December 2017
2017 2016
Notes $m $m
========================================== ====== ========== =========
Cash flows from operating activities
Loss before taxation (299.1) (908.3)
Adjustments for:
Depreciation, depletion and amortisation 592.2 466.9
Loss on disposal 1.6 3.4
Goodwill impairment - 164.0
Exploration costs written off 9 143.4 723.0
Impairment of property, plant
and equipment, net 10 541.1 167.6
Provision for onerous service
contracts, net 14 (1.0) 114.9
Payments under onerous service
contracts 14 - (132.0)
Decommissioning expenditure 14 (25.7) (23.0)
Share-based payment charge 33.9 43.9
Loss/(gain) on hedging instruments 11.8 (18.2)
Finance revenue 6 (42.0) (26.4)
Finance costs 6 351.7 198.2
========================================== ====== ========== =========
Operating cash flow before working
capital movements 1,307.9 774.0
Decrease/(increase) in trade
and other receivables 122.0 (99.4)
Increase in inventories (20.8) (47.8)
Decrease in trade payables (251.4) (29.8)
========================================== ====== ========== =========
Cash flows from operating activities 1,157.7 597.0
Income taxes received/(paid) 65.2 (84.5)
========================================== ====== ========== =========
Net cash from operating activities 1,222.9 512.5
========================================== ====== ========== =========
Cash flows from investing activities
Proceeds from disposals 8.0 62.8
Purchase of intangible exploration
and evaluation assets (189.7) (275.2)
Purchase of property, plant and
equipment (117.8) (756.0)
Interest received 3.1 1.2
========================================== ====== ========== =========
Net cash used in investing activities (296.4) (967.2)
========================================== ====== ========== =========
Cash flows from financing activities
Net proceeds from issue of share
capital 768.1 9.9
Debt arrangement fees (56.4) (31.7)
Repayment of bank loans (1,613.6) (769.1)
Drawdown of bank loans 305.0 1,187.5
Issue of convertible bonds - 300.0
Repayment of obligations under
finance leases (62.6) (3.3)
Finance costs paid (265.4) (284.0)
Distribution to non-controlling
interests (3.0) (10.0)
========================================== ====== ========== =========
Net cash (used in)/provided by
financing activities (927.9) 399.3
========================================== ====== ========== =========
Net decrease in cash and cash
equivalents (1.4) (55.4)
Cash and cash equivalents at
beginning of year 281.9 355.7
Foreign exchange gain/(loss) 3.5 (18.4)
========================================== ====== ========== =========
Cash and cash equivalents at
end of year 284.0 281.9
========================================== ====== ========== =========
Notes to the preliminary financial statements
Year ended 31 December 2017
1. Basis of Accounting and Presentation of Financial Information
Whilst the financial information in this preliminary
announcement has been prepared in accordance with International
Financial Reporting Standards (IFRS) and International Financial
Reporting Interpretation Committee (IFRIC) interpretations adopted
for use by the European Union, with those parts of the Companies
Act 2006 applicable to companies reporting under IFRS and with the
requirements of the United Kingdom Listing Authority (UKLA) Listing
Rules, this announcement does not contain sufficient information to
comply with IFRS. The Group will publish full financial statements
that comply with IFRS in March 2018.
The financial information for the year ended 31 December 2017
does not constitute statutory accounts as defined in sections 435
(1) and (2) of the Companies Act 2006. Statutory accounts for the
year ended 31 December 2016 have been delivered to the Registrar of
Companies and those for 2017 will be delivered following the
Company's annual general meeting. The auditor has reported on these
accounts; their reports were unqualified, did not include a
reference to any matters to which the auditor drew attention by way
of emphasis of matter and did not contain a statement under section
498 (2) or (3) of the Companies Act 2006.
The accounting policies applied are consistent with those
adopted and disclosed in the Group's financial statements for the
year ended 31 December 2016. There have been a number of amendments
to accounting standards and new interpretations issued by the
International Accounting Standards Board which were applicable from
1 January 2017, however these have not had a material impact on the
accounting policies, methods of computation or presentation applied
by the Group.
2. Loss per Share
Basic loss per ordinary share amounts are calculated by dividing
net loss for the year attributable to ordinary equity holders of
the parent by the weighted average number of ordinary shares
outstanding during the year.
Diluted loss per ordinary share amounts are calculated by
dividing net loss for the year attributable to ordinary equity
holders of the parent by the weighted average number of ordinary
shares outstanding during the year plus the weighted average number
of ordinary shares that would be issued if employee and other share
options or the convertible bonds were converted into ordinary
shares. Due to losses incurred in 2017 and 2016 all potential
ordinary shares are antidilutive.
Comparative basic and diluted earnings per share and weighted
average number of shares have been re-presented as a result of the
Rights Issue. The shares in issue have been amended by an
adjustment factor to reflect the bonus element inherent in a
discounted Rights Issue, and to allow meaningful comparison between
periods.
3. 2017 Annual Report and Accounts
The Annual Report and Accounts will be mailed in March 2018 only
to those shareholders who have elected to receive it. Otherwise,
shareholders will be notified that the Annual Report and Accounts
is available on the Group's website (www.tullowoil.com). Copies of
the Annual Report and Accounts will also be available from the
Company's registered office at Building 9, Chiswick Park, 566
Chiswick High Road, London W4 5XT.
4. Segmental reporting
The information reported to the Group's Chief Executive Officer
for the purposes of resource allocation and assessment of segment
performance is focused on three Business Delivery Teams, West
Africa (including non-operated producing European assets), East
Africa and New Ventures. Therefore the Group's reportable segments
under IFRS 8 are West Africa; East Africa; and New Ventures. The
following tables present revenue, loss and certain asset and
liability information regarding the Group's reportable business
segments for the years ended 31 December 2017 and 31 December
2016.
East
West Africa Africa New Ventures Unallocated Total
$m $m $m $m $m
============================== =========== ======= ============ =========== =========
2017
Sales revenue by origin 1,722.5 - - - 1,722.5
Other operating income
- lost production insurance
proceeds - - - 162.1 162.1
============================== =========== ======= ============ =========== =========
Segment result 86.9 (2.2) (133.9) 183.0 133.8
============================== =========== ======= ============ =========== =========
Loss on disposal of
other assets (1.6)
Unallocated corporate
expenses (109.8)
============================== =========== ======= ============ =========== =========
Operating profit 22.4
Loss on hedging instruments (11.8)
Finance revenue 42.0
Finance costs (351.7)
============================== =========== ======= ============ =========== =========
Loss before tax (299.1)
Income tax credit 110.6
============================== =========== ======= ============ =========== =========
Loss after tax (188.5)
============================== =========== ======= ============ =========== =========
Total assets 7,857.2 2,585.2 306.0 280.1 11,028.5
============================== =========== ======= ============ =========== =========
Total liabilities (4,295.6) (169.2) (97.1) (3,750.2) (8,312.1)
============================== =========== ======= ============ =========== =========
Other segment information
Capital expenditure:
Property, plant and
equipment 43.1 1.1 0.3 5.6 50.1
Intangible exploration
and evaluation assets 5.5 257.5 56.0 - 319.0
Depreciation, depletion
and amortisation (577.1) (0.5) - (14.6) (592.2)
Impairment of property,
plant and equipment,
net (539.1) - - - (539.1)
Exploration costs written
off (6.9) (2.3) (134.2) - (143.4)
============================== =========== ======= ============ =========== =========
Capital expenditure on property, plant, and equipment excludes
the addition of the TEN FPSO right of use asset of $837.6
million.
East
West Africa Africa New Ventures Unallocated Total
$m $m $m $m $m
============================== ============== ============== ============== ============== =============
2016
Sales revenue by origin 1,269.9 - - - 1,269.9
Other operating income
- lost production insurance
proceeds - - - 90.1 90.1
============================== ============== ============== ============== ============== =============
Segment result 269.9 (341.0) (512.3) (39.2) (622.6)
============================== ============== ============== ============== ============== =============
Loss on disposal of
other assets (3.4)
Unallocated corporate
expenses (128.7)
============================== ============== ============== ============== ============== =============
Operating loss (754.7)
Gain on hedging instruments 18.2
Finance revenue 26.4
Finance costs (198.2)
============================== ============== ============== ============== ============== =============
Loss before tax (908.3)
============================== ============== ============== ============== ============== =============
Income tax credit 311.0
Loss after tax (597.3)
============================== ============== ============== ============== ============== =============
Total assets 7,701.7 2,383.5 467.2 249.3 10,801.7
============================== ============== ============== ============== ============== =============
Total liabilities (3,200.9) (157.6) (142.0) (5,058.7) (8,559.2)
============================== ============== ============== ============== ============== =============
Other segment information
Capital expenditure:
Property, plant and
equipment 817.0 0.3 0.4 0.8 818.5
Intangible exploration
and evaluation assets 9.9 137.4 144.1 - 291.4
Depreciation, depletion
and amortisation (450.4) (0.9) (1.0) (14.6) (466.9)
Impairment of property,
plant and equipment,
net (167.2) - (0.4) - (167.6)
Exploration costs written
off (7.7) (341.0) (374.3) - (723.0)
Goodwill impairment - - (164.0) - (164.0)
============================== ============== ============== ============== ============== =============
Unallocated expenditure and net liabilities include amounts of a
corporate nature and not specifically attributable to a reportable
segment. The liabilities comprise the Group's external debt and
other non-attributable corporate liabilities.
5. Other costs
2017 2016
Notes $m $m
===================================== ===== ======= ======
Cost of sales
Operating costs 386.2 377.2
Operating lease payments 62.5 21.0
Depletion and amortisation of
oil and gas assets 10 574.3 448.5
Underlift, overlift and oil
stock movements (2.3) (76.5)
Share-based payment charge included
in cost of sales 1.1 2.7
Other cost of sales 47.5 40.2
===================================== ===== ======= ======
Total cost of sales 1,069.3 813.1
===================================== ===== ======= ======
Administrative expenses
Share-based payment charge included
in administrative expenses 32.8 41.2
Depreciation of other fixed
assets 10 17.9 18.4
Relocation costs associated
with major simplification project 1.6 (0.5)
Other administrative costs 43.0 57.3
===================================== ===== ======= ======
Total administrative expenses 95.3 116.4
===================================== ===== ======= ======
Restructuring costs 14.5 12.3
===================================== ===== ======= ======
6. Net financing costs
2017 2016
$m $m
========================================== === ====== =======
Interest on bank overdrafts
and borrowings 290.7 304.7
Interest on obligations under
finance leases 46.1 1.8
=============================================== ====== =======
Total borrowing costs 336.8 306.5
Less amounts included in the
cost of qualifying assets (66.5) (138.8)
=============================================== ====== =======
270.3 167.7
Finance and arrangement fees 2.8 5.4
Other interest expense 1.8 -
Foreign exchange losses 57.1 -
Unwinding of discount on decommissioning
provisions 19.7 25.1
=============================================== ====== =======
Total finance costs 351.7 198.2
Interest income on amounts due
from joint venture partners
for finance leases (21.0) -
Other finance revenue (21.0) (26.4)
=============================================== ====== =======
Total finance revenue (42.0) (26.4)
=============================================== ====== =======
Net financing costs 309.7 171.8
=============================================== ====== =======
7. Insurance proceeds
During 2017 the Group continued to issue insurance claims in
respect of the Jubilee turret remediation project. Insurance
proceeds of $220.9 million were recorded in the year ended 31
December 2017 (2016: $145.0 million). Proceeds related to lost
production under the Business Interruption insurance policy of
$162.1 million (2016 $90.1 million) were recorded as other
operating income - lost production insurance proceeds in the income
statement. Proceeds related to compensation for incremental
operating costs under the Business Interruption and Hull and
Machinery insurance policies of $50.9 million (2016: $31.8 million)
were recorded within the operating costs line of cost of sales (see
note 5). Proceeds related to compensation for capital costs under
the Hull and Machinery insurance policy of $7.9 million (2016:
$23.1 million) were recorded within additions to property, plant
and equipment (see note 10).
8. Taxation on loss on ordinary activities
a. Analysis of tax credit for the year
2017 2016
$m $m
=================================== ======= =======
Current tax
UK corporation tax 30.1 67.3
Foreign tax 6.2 (18.5)
=================================== ======= =======
Total corporate tax 36.3 48.8
UK petroleum revenue tax (2.1) (1.1)
=================================== ======= =======
Total current tax 34.2 47.7
=================================== ======= =======
Deferred tax
UK corporation tax (8.7) 9.4
Foreign tax (114.6) (369.8)
=================================== ======= =======
Total deferred corporate tax (123.3) (360.4)
Deferred UK petroleum revenue tax (21.5) 1.7
=================================== ======= =======
Total deferred tax (144.8) (358.7)
=================================== ======= =======
Total tax credit (110.6) (311.0)
=================================== ======= =======
b. Factors affecting tax credit for period
The tax rate applied to profit on ordinary activities in
preparing the reconciliation below is the UK corporation tax rate
applicable to the Group's non-upstream UK profits. The difference
between the total tax credit shown above and the amount calculated
by applying the standard rate of UK corporation tax applicable to
UK profits of 19% (2016: 20%) to the loss before tax is as
follows:
2017 2016
$m $m
========================================== ======== =========
Group loss on ordinary activities
before tax (299.1) (908.3)
========================================== ======== =========
Tax on Group loss on ordinary activities
at the standard UK corporation
tax rate of 19% (2016: 20%) (56.8) (181.7)
========================================== ======== =========
Effects of:
Non-deductible exploration expenditure 21.6 25.8
Other non-deductible expenses 12.6 22.7
Derecognition of deferred tax previously
recognised - 30.2
Recognition of deferred tax previously
unrecognised (21.5) -
Impairment of goodwill - 127.9
Utilisation of tax losses not previously
recognised (0.3) (9.5)
Net losses not recognised 18.4 61.7
Petroleum revenue tax (PRT) - (6.7)
Adjustment relating to prior years 1.9 (2.1)
Adjustments to deferred tax relating
to change in tax rates 12.6 (0.8)
Higher rate of taxation on Norway
losses 13.1 (286.4)
Other tax rates applicable outside
the UK and Norway (88.0) (86.8)
PSC income not subject to corporation
tax (15.4) (1.6)
Tax incentives for investment (2.8) (3.7)
Other income not subject to corporation
tax (6.0) -
------------------------------------------ -------- ---------
Group total tax credit for the year (110.6) (311.0)
========================================== ======== =========
The Finance Act 2016 further reduced the main rate of UK
corporation tax applicable to all companies subject to corporation
tax, except for those within the oil and gas ring fence, to 19%
from 1 April 2017 and 17% from 1 April 2020. These changes were
substantively enacted on 6 September 2016 and hence the effect of
the change on the deferred tax balances has been included,
depending upon when deferred tax is expected to reverse.
The Group's profit before taxation will continue to arise in
jurisdictions where the effective rate of taxation differs from
that in the UK, such as Ghana (35%), Gabon (55%), and Equatorial
Guinea (35%). Furthermore, unsuccessful exploration expenditure is
often incurred in jurisdictions where the Group has no taxable
profits, such that no related tax benefit arises. Accordingly, the
Group's tax charge will continue to vary according to the
jurisdictions in which pre-tax profits and exploration costs
written off arise.
The Group has tax losses of $3,642.0 million (2016: $2,844.0
million) that are available for offset against future taxable
profits in the companies in which the losses arose. Deferred tax
assets have not been recognised in respect of these losses as they
may not be used to offset taxable profits elsewhere in the Group
due to uncertainty of recovery.
The Group has recognised deferred tax assets of $530.0 million
(2016: $535.0 million) in relation to tax losses only to the extent
of anticipated future taxable income or gains in relevant
jurisdictions.
No deferred tax liability is recognised on temporary differences
of $7.9 million (2016: $8.2 million) relating to unremitted
earnings of overseas subsidiaries as the Group is able to control
the timing of the reversal of these temporary differences and it is
probable that they will not reverse in the foreseeable future.
Tax relating to components of other comprehensive income
During 2017 $24.3 million (2016: $108.8 million) of tax has been
recognised through other comprehensive income
of which $24.9 million (2016: $107.8 million) is current and
$0.6 million (2016: $1.0 million) is deferred tax relating to all
debit (2016: credits) on cash flow hedges arising in the year.
Current tax assets
As at 31 December 2017, current tax assets were $57.7 million
(2016: $138.3 million) of which $44.6m relates to the UK (2016:
$29.0 million) and $3.1 million relates to Norway (2016: $90.0
million), where 78% of exploration expenditure is refunded as a tax
refund in the year following the incurrence of such
expenditure.
9. Intangible exploration and evaluation assets
2017 2016
$m $m
============================================= ======== ========
At 1 January 2,025.8 3,400.0
Additions 319.0 291.4
Disposals (40.0) -
Amounts written off (143.4) (723.0)
Write-off associated with Norway contingent
consideration - (36.5)
Transfer to assets held for sale (43.4) (912.3)
Transfer to property, plant and equipment (188.7) -
Currency translation adjustments 4.1 6.2
============================================= ======== ========
At 31 December 1,933.4 2,025.8
============================================= ======== ========
Included within 2017 additions is $66.5 million of capitalised
interest (2016: $50.2 million). The Group only capitalises interest
in respect of intangible exploration and evaluation assets where it
is considered that development is ongoing.
Transfers to property, plant, and equipment related to the
Greater Jubilee Full Field Development plan of development approval
and the cost associated with the Mahogany and Teak discoveries.
The below table provides a summary of the exploration costs
written-off on a pre-and post-tax basis by country.
Rationale 2017 2017 2017
for 2017 Pre-tax write-off /(reversal) Post-tax write-off /(reversal) Remaining recoverable amount
Country CGU write-off $m $m $m
------------- --------- --- ------------ ------------------------------- -------------------------------- -----------------------------
Kenya Country a 2.3 2.3 1,058.2
Madagascar Various d (4.0) (4.0) -
Blocks C6,
Mauritania C10 & C18 b,c 71.1 71.1 22.4
Licence E18 &
Netherlands F16 e 6.2 3.2 -
Pakistan Various e 36.1 36.1 5.5
Block 31 &
Suriname Coronie a 10.3 10.3 30.7
Other Various b 4.3 2.8 -
New Ventures Various f 17.1 17.1 -
------------- -------------- ----------- ------------------------------- -------------------------------- -----------------------------
Total write-off 143.4 138.9
=========================================== =============================== ================================ =============================
a.Current year unsuccessful drilling results.
b.Current year expenditure and actualisation of accruals
associated with CGUs previously written off.
c.Licence relinquishments.
d.Country exit.
e.Revision of value based on disposal/farm-down activities
f.New Ventures expenditure is written off as incurred.
10. Property, plant and equipment
2017 2016
2017 Other 2016 Other
Oil and fixed 2017 Oil and fixed 2016
gas assets assets Total gas assets assets Total
$m $m $m $m $m $m
========================== =========== ======= ========= =========== ======= =========
Cost
At 1 January 10,772.5 251.9 11,024.4 10,439.9 289.5 10,729.4
Additions 880.7 7.0 887.7 816.9 1.6 818.5
Disposals (362.6) (1.6) (364.2) (276.1) (2.7) (278.8)
Transfer from intangible
assets 188.7 - 188.7 - - -
Currency translation
adjustments 113.3 22.4 135.7 (208.2) (36.5) (244.7)
========================== =========== ======= ========= =========== ======= =========
At 31 December 11,592.6 279.7 11,872.3 10,772.5 251.9 11,024.4
========================== =========== ======= ========= =========== ======= =========
Depreciation, depletion
and amortisation
At 1 January (5,500.8) (160.7) (5,661.5) (5,360.0) (165.0) (5,525.0)
Charge for the year (574.3) (17.9) (592.2) (448.5) (18.4) (466.9)
Impairment loss (584.5) - (584.5) (184.3) (0.4) (184.7)
Reversal of impairment
loss 43.4 - 43.4 10.9 - 10.9
Disposal 300.0 1.7 301.7 276.1 2.6 278.7
Currency translation
adjustments (109.1) (15.4) (124.5) 205.0 20.5 225.5
========================== =========== ======= ========= =========== ======= =========
At 31 December (6,425.3) (192.3) (6,617.6) (5,500.8) (160.7) (5,661.5)
========================== =========== ======= ========= =========== ======= =========
Net book value at
31 December 5,167.3 87.4 5,254.7 5,271.7 91.2 5,362.9
========================== =========== ======= ========= =========== ======= =========
The 2017 additions include capitalised interest of $nil (note 6)
in respect of the TEN development project (2016: $88.6 million).
The carrying amount of the Group's oil and gas assets includes an
amount of $816.7 million (2016: $17.8 million) in respect of assets
held under finance leases. The currency translation adjustments
arose due to the movement against the Group's presentation
currency, USD, of the Group's UK and Dutch assets which have
functional currencies of GBP and EUR respectively. The 2017 income
statement impairment charge includes $2.0 million of insurance
proceeds (2016: $6.2 million).
2017
Trigger for 2017 Impairment/(reversal)
impairment/(reversal) $m Pre-tax discount rate assumption
--------------------------------- ------------------------ ----------------------- --------------------------------
Limande and Turnix CGU (Gabon) a 23.5 13%
Echira, Niungo, and Igongo CGU
(Gabon) b (12.8) 15%
M'boundi (Congo) c (16.1) n/a
Espoir (Côte d'Ivoire) a 18.3 10%
Ceiba and Okume (Equatorial
Guinea) b (7.0) 10%
TEN (Ghana) a,c 535.4 10%
Jubilee (Ghana) d (2.0) n/a
Netherlands CGU e 7.2 n/a
UK "CGU"([f]) b (7.4) n/a
--------------------------------- ------------------------ ----------------------- --------------------------------
Impairment 539.1
=========================================================== ======================= ================================
a.Decrease to long-term price assumptions (refer to accounting
policy on significant estimates).
b.Increase to short-term price assumptions (Dated Brent forward
curve)
c.Change to decommissioning estimate.
d.Impairment of a component of the asset which is covered by
insurance proceeds. This cash item does not impact the
carrying value of property, plant, and equipment.
e.Revision of value based on disposal/farm-down activities.
f. The fields in the UK are grouped into one CGU as all fields
within those countries share critical gas infrastructure.
During 2017 and 2016 the Group applied the following nominal oil
price assumptions for impairment tests:
Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 onwards
===== ======= ======= ======= ======= =========== ================
2017 Forward Forward $59/bbl $66/bbl $68/bbl $75/bbl inflated
curve curve at 2%
2016 Forward Forward $70/bbl $70/bbl $70/bbl $90/bbl
curve curve
===== ======= ======= ======= ======= =========== ================
The prices assumed in 2017 decreased due to downward revisions
by expert forecasters. Oil prices stated above are benchmark prices
to which an individual field price differential is applied. All
impairment assessments are prepared on a value-in-use basis using
discounted future cash flows based on 2P reserves profiles.
11. Other assets
2017 2016
$m $m
========================================= ===== ======
Non-current
Amounts due from joint venture partners 731.7 127.3
Uganda VAT recoverable 34.9 35.9
Other non-current assets 23.2 12.5
========================================= ===== ======
789.8 175.7
========================================= ===== ======
Current
Amounts due from joint venture partners 567.8 560.4
Underlifts 37.1 34.9
Prepayments 38.2 26.3
VAT recoverable 5.4 5.7
Other current assets 119.8 211.6
========================================= ===== ======
768.3 838.9
========================================= ===== ======
The increase in amounts due from joint venture partners relates
to the recognition of the TEN FPSO finance lease. Other current
assets have decreased due to the increased timeliness of the
receipt of funds from insurers.
12. Assets 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. CNOOC
subsequently exercised its pre-emption rights under the joint
operating agreements to acquire 50% of the interests being
transferred on the same terms and conditions. This led to Tullow
signing pre-emption documents with its Joint Venture Partners. 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.
Following signature of the pre-emption documents by the Joint
Venture Partners, the Government of Uganda was officially notified
of the transaction and its approval was sought. The disposal is
expected to complete in mid-2018.
The estimated fair value of the consideration was $829.7 million
on recognition which, when compared to the carrying value of the
Group's interest in Uganda, resulted in an exploration write-off of
$330.4 million in 2016. The fair value of the deferred
consideration was calculated using expected timing of receipts
based on management's best estimate of the expected capital profile
of the project discounted at the relevant counterparty's cost of
borrowing. Additions to this value have been recognised in relation
to capitalised interest. The present value of the consideration
will be determined on completion and assessed against the carrying
value of the net assets of the disposal group. This represents a
level 3 financial asset.
The divestment of the Norway business was completed during 2017
with $7.3 million of assets held for sale at 31 December 2016 being
disposed in full during 2017. Consequently, there were no Norwegian
assets held for sale at 31 December 2017.
The divestment of the Netherlands business was completed during
2017 with $113.1 million of assets held for sale at 30 June 2017
being disposed in full. Consequently, there were no Netherlands
assets held for sale at 31 December 2017.
The major classes of assets and liabilities comprising the
assets classified as held for sale as at 31 December 2017 were as
follows:
Uganda Total Uganda Norway Total
2017 2017 2016 2016 2016
$m $m $m $m $m
------------------------- ------ ------ ------ ------ ------
Intangible exploration
and evaluation assets 873.1 873.1 829.7 7.4 837.1
------------------------- ------ ------ ------ ------ ------
Total assets classified
as held for sale 873.1 873.1 829.7 7.4 837.1
------------------------- ------ ------ ------ ------ ------
Net assets of disposal
groups 873.1 873.1 829.7 7.4 837.1
========================= ====== ====== ====== ====== ======
13. Trade and other payables
Current liabilities
2017 2016
$m $m
================================== ======= ======
Trade payables 83.3 46.9
Other payables 114.5 124.6
Overlifts 30.4 6.9
Accruals 552.0 721.2
VAT and other similar taxes 17.3 14.6
Current portion of finance lease 228.1 1.9
================================== ======= ======
1,025.6 916.1
================================== ======= ======
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 11). The change in trade payables and in other
payables predominantly represents timing differences and levels of
work activity.
Non-current liabilities
2017 2016
$m $m
====================================== ======== ======
Other non-current liabilities 105.1 87.7
Non-current portion of finance lease 1,317.5 24.6
====================================== ======== ======
1,422.6 112.3
====================================== ======== ======
The Group's finance leases are the TEN FPSO and the Espoir FPSO
(2016: Espoir FPSO). The finance lease for the TEN FPSO met the
criteria for recognition on 1 August 2017. A finance lease
liability has been recorded at a gross value of $1,521.0 million as
Tullow entered the lease on behalf of the TEN Joint Venture. The
present value of the lease liability unwinds over the expected life
of the lease and is reported within finance costs as interest on
obligations under finance leases. A receivable from Joint Venture
partners of $719.0 million has been recognised in other assets to
reflect the value of future payments that will be met by cash calls
from partners. The present value of the receivable from Joint
Venture Partners unwinds over the expected life of the lease and is
reported within finance revenue. The net cash outflows of $62.6
million related to the lease agreement since its recognition as a
finance lease have been reported in the repayment of obligations
under finance leases line in the cash flow statements. A right of
use property, plant, and equipment asset of $775.8 million was also
recorded at 31 December 2017. Prior to recognition as a finance
lease, it was accounted for as an operating lease, and included as
operating lease payments within cost of sales (note 5).
14. Provisions
Other Other
Decommissioning provisions Total Decommissioning provisions Total
2017 2017 2017 2016 2016 2016
$m $m $m $m $m $m
======================== =============== =========== ======= =============== =========== ========
At 1 January 1,014.4 144.2 1,158.6 1,008.8 243.3 1,252.1
New provisions
and changes in
estimates (33.6) (9.2) (42.8) 57.1 71.4 128.5
Disposals (100.7) - (100.7) - - -
Payments (33.7) - (33.7) (23.0) (132.0) (155.0)
Transfer to accruals - - - - (35.0) (35.0)
Unwinding of
discount 19.7 - 19.7 25.1 - 25.1
Currency translation
adjustment 31.3 - 31.3 (53.6) (3.5) (57.1)
------------------------ --------------- ----------- ------- --------------- ----------- --------
At 31 December 897.4 135.0 1,032.4 1,014.4 144.2 1,158.6
======================== =============== =========== ======= =============== =========== ========
Current provisions 103.2 127.6 230.8 49.0 2.9 51.9
======================== =============== =========== ======= =============== =========== ========
Non-current provisions 794.2 7.4 801.6 965.4 141.3 1,106.7
------------------------ --------------- ----------- ------- --------------- ----------- --------
Included within other provisions is provision for onerous
service contracts and provision for restructuring costs. Due to the
historical reduction in original planned future work programmes the
Group identified a number of onerous service contracts in prior
years. The expected unutilised capacity has been provided for in
2016 and 2017 resulting in an income statement credit of $1.0
million (2016: charge of $114.9 million).
The decommissioning provision represents the present value of
decommissioning costs relating to the European and African oil and
gas interests.
2017 2016
Cessation
Inflation Discount of production
assumption rate assumption assumption $m $m
============= =========== ================ ============== ===== ========
Congo n/a n/a n/a - 18.3
------------- ----------- ---------------- -------------- ----- --------
Côte
d'Ivoire 2% 3% 2026 49.7 48.1
------------- ----------- ---------------- -------------- ----- --------
Equatorial
Guinea 2% 3% 2028-2029 133.9 130.0
------------- ----------- ---------------- -------------- ----- --------
Gabon 2% 3% 2021-2034 55.8 54.2
------------- ----------- ---------------- -------------- ----- --------
Ghana 2% 3% 2034-2036 278.0 267.6
------------- ----------- ---------------- -------------- ----- --------
Mauritania 2% 3% 2018 120.7 130.9
------------- ----------- ---------------- -------------- ----- --------
Netherlands n/a n/a n/a - 100.7
------------- ----------- ---------------- -------------- ----- --------
UK 2% 3% 2018-2020 259.3 264.6
============= =========== ================ ============== ===== ========
897.4 1,014.4
============= =========== ================ ============== ===== ========
15. Commercial Reserves and Contingent Resources summary
(unaudited) working interest basis
West Africa East Africa New Ventures TOTAL
================= =============== =============== ==============================
Oil Gas Oil Gas Oil Gas Oil Gas Petroleum
mmbbl bcf mmbbl bcf mmbbl bcf mmbbl bcf mmboe
================== ======= ======== ======= ====== ======== ===== ======== ======== ==========
COMMERCIAL RESERVES
===================================== ======= ====== ======== ===== ======== ======== ==========
1 January
2017 272.1 189.7 - - - - 272.1 189.7 303.7
Revisions 3.2 14.3 - - - - 3.2 14.3 5.5
Transfer
from contingent
resources - 79.0 - - - - - 79.0 13.2
Disposals - - - - - - - - -
Production (29.6) (14.1) - - - - (29.6) (14.1) (31.9)
================== ======= ======== ======= ====== ======== ===== ======== ======== ==========
31 December
2017 245.7 268.9 - - - - 245.7 268.9 290.5
================== ======= ======== ======= ====== ======== ===== ======== ======== ==========
CONTINGENT RESOURCES
===================================== ======= ====== ======== ===== ======== ======== ==========
1 January
2017 128.1 730.5 632.5 42.7 - 4.2 760.6 773.2 890.1
Revisions (0.2) (186.4) - - - - (0.2) (186.4) (31.3)
Additions 1.7 - 5.3 - - - 7.0 - 7.0
Disposals (8.2) - - - - - (8.2) - (8.2)
Transfers
to commercial
reserves - (79.0) - - - - - (79.0) (13.2)
================== ======= ======== ======= ====== ======== ===== ======== ======== ==========
31 December
2017 121.4 465.1 637.8 42.7 - 4.2 759.1 507.8 844.4
================== ======= ======== ======= ====== ======== ===== ======== ======== ==========
TOTAL
31 December
2017 367.1 734.0 637.8 42.7 - 4.2 1,004.8 776.7 1,134.9
================== ======= ======== ======= ====== ======== ===== ======== ======== ==========
1. Proven and Probable Commercial Reserves are as audited and
reported 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, with the exception of minor
assets contributing less than 5% of the Group's reserves.
2. Proven and Probable Contingent Resources are as audited and
reported by an independent engineer. Resources estimates are
reviewed by the independent engineer based on significant new data
received following exploration or appraisal drilling.
3. The West Africa revisions to reserves (+5 mmboe) relate
mainly to audits of Jubilee, TEN, Okume and Echira.
4. The Kenya addition to oil contingent resources relates to the
booking of the Erut discovery announced 17 January 2017. The West
Africa addition to oil contingent resources relates to Simba.
5. The West Africa revision to gas contingent resources relates
to a reduction in the estimate of the size of the Gas cap in Ntomme
and reduction of injected gas blow-down volume for Jubilee.
6. The West Africa transfer of gas from contingent resources to
reserves relates to Jubilee sales gas.
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 284.1 mmboe at 31 December 2017 (31
December 2016: 283.2 mmboe).
Contingent Resources relate to resources in respect of which
development plans are in the course of preparation or further
evaluation is under way with a view to future development.
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 90 exploration
and production licences across 16 countries which are managed as
three business delivery teams: West Africa, East Africa and New
Ventures.
EVENTS ON THE DAY
In conjunction with these results, Tullow is conducting a London
Presentation and a number of events for the financial
community.
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
================== ==============
+44 (0)330 336
All participants 9411
================== ==============
UK Freephone 0800 279 7204
================== ==============
Access
Code 7292383
================== ==============
Webcast
To join the live video webcast or play the on-demand version,
please use this link: https://edge.media-server.com/m6/p/xzdogikb.
The replay will be available from noon on 7 February 2018.
FOR FURTHER INFORMATION, CONTACT:
Tullow Oil plc Murray Consultants
(London) (Dublin)
+44 20 3249 9000 +353 1 498 0300
Chris Perry / Nicola Pat Walsh
Rogers (Investors) Joe Heron
George Cazenove
/ Anna Brog (Media)
====================== ===================
Follow Tullow on:
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Website: www.tullowoil.com
This information is provided by RNS
The company news service from the London Stock Exchange
END
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