We could not find any results for:
Make sure your spelling is correct or try broadening your search.
Register for streaming realtime charts, analysis tools, and prices.
| Share Name | Share Symbol | Market | Type | Share ISIN | Share Description |
|---|---|---|---|---|---|
| Tullow Oil Plc | LSE:TLW | London | Ordinary Share | GB0001500809 | ORD 10P |
| Price Change | % Change | Share Price | Bid Price | Offer Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
|---|---|---|---|---|---|---|---|---|---|---|
| -0.92 | -2.59% | 34.60 | 34.64 | 34.76 | 36.46 | 34.22 | 36.46 | 3,976,514 | 16:35:16 |
| Industry Sector | Turnover | Profit | EPS - Basic | PE Ratio | Market Cap |
|---|---|---|---|---|---|
| Crude Petroleum & Natural Gs | 1.63B | -109.6M | -0.0754 | -4.59 | 503.71M |
From Apr 2019 to Apr 2024
TIDMTLW TIDMTTM TIDMTTM
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 $110 million which will be repaid following completion of the Uganda farm-down)
-- West Africa 2017 net working interest oil production, including production-equivalent insurance payments, averaged 89,100 bopd; 2018 production is expected to average between 82,000 and 90,000 bopd
-- Incremental drilling programme due to start in February 2018; this additional well capacity combined with current strong production from both Jubilee and TEN fields will maximise and sustain production in the coming years
-- Kenya resources assessment completed: 240 - 560 - 1,230 mmbo (1C-2C-3C) contingent recoverable resources from an overall discovered STOIIP of up to 4 billion barrels. Phased development is planned with FID in 2019 and First Oil in 2021/22
-- Uganda deal completion expected in H1 2018; JV Partners working towards FID around mid-year
-- Exploration portfolio now reset through disposals, farm-downs and the addition of significant new positions in Côte d'Ivoire and Peru. Multiple high impact exploration campaigns planned over next three years, starting with the high-impact Cormorant well in Namibia in H2 2018
FINANCIAL OVERVIEW
Hot Features
Premium
FY 2017 FY 2016
========================================= ======= =======
Total revenue ($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:
Twitter: www.twitter.com/TullowOilplc
YouTube: www.youtube.com/TullowOilplc
Facebook: www.facebook.com/TullowOilplc
LinkedIn: www.linkedin.com/company/Tullow-Oil
Website: www.tullowoil.com
This information is provided by RNS
The company news service from the London Stock Exchange
END
FR UBUVRWVAURRR
(END) Dow Jones Newswires
February 07, 2018 02:00 ET (07:00 GMT)
1 Year Tullow Oil Chart |
1 Month Tullow Oil Chart |
It looks like you are not logged in. Click the button below to log in and keep track of your recent history.
Support: +44 (0) 203 8794 460 | support@advfn.com
By accessing the services available at ADVFN you are agreeing to be bound by ADVFN's Terms & Conditions
