Final Results
Tullow Oil plc - 2013 Full Year Results
222 mmboe of Contingent Resources added through successful exploration and appraisal
Revenue, gross profit and cash flow increase; funding sources diversified
Major development progress in East and West Africa
12 February 2014 - Tullow Oil plc (Tullow), the independent oil and gas exploration and production Group, announces its results for the year ended 31 December 2013. Presentation, webcast and conference calls details are on page 27 of this document and on the Group's website: www.tullowoil.com
FULL YEAR RESULTS HIGHLIGHTS
· Group 2013 average working interest production of 84,200 boepd generates strong operating cash flow of $1.9 billion; 2014 Group average working interest production is expected to be in the range 79,000-85,000 boepd
· 2013 Revenue and gross profit increase compared to prior year; profit after tax of $216 million was impacted by both a decrease in profit on disposals of $670 million and a $200 million increase in exploration write-offs
· Balance sheet substantially strengthened through $650 million debut bond issue in November 2013; net debt at year-end 2013 of $1.9 billion with unutilised debt capacity of $2.4 billion
· Government of Kenya supports development studies following commercial discoveries of at least 600 mmbo gross; Government of Uganda signs MoU with partners in relation to the Lake Albert Rift Basin Development Project
· TEN Plan of Development approved by Government of Ghana and project is on schedule for first oil in mid-2016
· Frégate-1 wildcat well offshore Mauritania opens a new oil play in Late Cretaceous turbidites, after encountering up to 30 metres of net gas-condensate and oil pay in multiple sands
· Exploration and appraisal success, particularly in East Africa and Norway, adds 222 mmboe to Contingent Resources in 2013; new acreage acquired in Suriname, Norway, Namibia and Guyana adds to high-quality portfolio
· Significant E&A campaign planned for 2014 with high-impact campaigns onshore in Kenya and Ethiopia and offshore in Norway, Mauritania and Guinea
FINANCIAL OVERVIEW
|
|
2013 |
2012 |
Change |
|
Sales revenue ($m) |
2,647 |
2,344 |
13% |
|
Gross profit ($m) |
1,440 |
1,345 |
7% |
|
Operating profit ($m) |
381 |
1,185 |
-68% |
|
Profit before tax ($m) |
313 |
1,116 |
-72% |
|
Profit after tax ($m) |
216 |
666 |
-68% |
|
Basic earnings per share (cents) |
18.6 |
68.8 |
-73% |
|
Full year dividend per share (pence) |
12.0 |
12.0 |
0% |
|
Operating cash flow before working capital ($m) |
1,901 |
1,777 |
7% |
|
Working interest production (boepd) |
84,200 |
79,200 |
6% |
|
Realised oil price per barrel ($) |
105.7 |
108.0 |
-2% |
|
Realised gas price per therm (pence) |
65.6 |
58.5 |
12% |
COMMENTING TODAY, AIDAN HEAVEY, CHIEF EXECUTIVE, SAID:
"Tullow performed well in 2013. The business generated almost $2 billion of operating cash flow and has established a flexible and strong balance sheet. The Group delivered another year of exploration and appraisal success and production growth and made significant progress with its key developments in Ghana, Kenya and Uganda which will deliver major increases in cash flow over the next 3-5 years. An ambitious exploration and appraisal programme is planned for 2014 which is targeting opportunities in our core plays in Africa and the Atlantic margins. As with previous years, we are aiming for resource additions of over 200 mmboe and we are well placed for an exciting year of growth in 2014 with an enviable portfolio of assets and opportunities."
2013 Full Year Results overview
Tullow's 2013 financial results delivered solid revenue, gross profit and cash flow growth, principally due to increased production from the Jubilee field in Ghana and firm oil and gas prices. Profit from continuing activities after tax decreased 68% to $216 million (2012: $666 million) and basic earnings per share were similarly impacted, mainly as a result of a combination of the following:
· A decrease in profits on disposal of $670 million compared with 2012, which included the gain on the $2.9 billion Uganda farm-down announced in February 2012;
· An increase in exploration write-offs of $200 million to $871 million (2012: $671 million);
· A reduction in the income tax charge of $353 million to $97 million (2012: $450 million) reflecting lower profit before tax, the $142 million tax charge in 2012 on the Uganda farm-down and the benefit of Norwegian deferred tax credits in relation to exploration write-offs; and
· A $100 million, 7% increase in gross profit to $1.4 billion (2012: $1.3 billion) reflecting a 9% increase in sales volumes and a 13% increase in sales revenue to $2.6 billion in 2013 (2012: $2.3 billion).
Significant exploration success
Tullow had significant exploration success onshore in East Africa and offshore Norway during the year. The Group surpassed its target of contingent resource additions of 200 mmboe per annum. In Kenya, Tullow has now discovered upwards of 600 mmbo gross from seven out of seven successful wells in one basin since March 2012 and has ten further Tertiary Rift Basins to explore across Kenya and Ethiopia. Major offshore wells were less successful in 2013, particularly offshore French Guiana. In 2014, Tullow is planning to invest around $1 billion in exploration and appraisal with major campaigns in Mauritania, Norway, Kenya and Ethiopia and a first well offshore Guinea.
Strong cash flow and production
In 2013, operating cash flow before working capital movements increased by 7% to $1.9 billion (2012: $1.8 billion) as the Group continued to grow its high margin West Africa production. Average working interest production increased 6% to 84,200 boepd during the year. Delays in 2013 to the Ghana National Gas Company's onshore gas processing plant will require alternative gas disposal options to be considered in order to achieve an average gross production rate of around 100,000 bopd from the Jubilee field in 2014. Group average working interest production in 2014 is expected to be in the range 79,000-85,000 boepd.
Major development projects
The TEN development offshore Ghana is on track for first oil in mid-2016, based around a FPSO facility with a production capacity of 80,000 bopd. Tullow continues to progress a farmdown of TEN to reduce equity in the project whilst retaining operatorship. In preparation for the next phase of investment in the Jubilee field, discussions are continuing with the Government of Ghana on the approval of the Jubilee Full Field Development (FFD) plan. In February 2014, a Memorandum of Understanding (MoU) was signed between the Government of Uganda and Tullow, CNOOC Ltd and Total which outlines the framework for the Lake Albert Rift Basin development which is targeting over 200,000 bopd gross production. In Kenya, the Government gave its support for development studies to commence and the joint venture partnership is aiming to reach project sanction for development, including an export pipeline in 2015/2016.
Diversified balance sheet
The Group strengthened its balance sheet by diversifying its sources of funding with the issue of $650 million of 6% senior notes due 2020 at par in November 2013. In 2013, Tullow spent $1.8 billion on capital expenditure. 2014 capital expenditure is forecast to be $2.2 billion. As at the end of December 2013, the Group had net debt of $1.9 billion, with unutilised debt capacity of $2.4 billion.
Board changes, AGM, Dividend
At the Annual General Meeting (AGM) on 30 April 2014, David Bamford will retire after nine years of outstanding service. Ann Grant will replace him as Senior Independent Director. Jeremy Wilson joined the Board in October 2013 after a successful career at J. P. Morgan. He will become chairman of the Remuneration Committee after the 2014 AGM. In view of Tullow's work commitments in 2014 and the steady state of the Group's production, the Board is recommending an unchanged final dividend of 8.0 pence per share, bringing the total payment for the year to 12.0 pence per share.
Operations review
WEST AND NORTH AFRICA
|
2013 production 65,000 boepd |
Total reserves and resources 665.6 mmboe |
2013 sales revenue $2,247.5 million |
2013 investment $811 million |
Ghana
Tullow has interests in two licences offshore Ghana. The Jubilee field straddles both the Deepwater Tano and West Cape Three Points licences, whilst the Tweneboa-Enyenra-Ntomme (TEN) cluster development is wholly located in the Deepwater Tano licence. In 2013, the Jubilee field averaged approximately 100,000 bopd gross production and Government of Ghana approval was received for the TEN Plan of Development (PoD), the Group's second major operated development in Ghana. In 2014, Tullow expects gross production from the Jubilee field to average 100,000 bopd.
Jubilee
The Jubilee field is Tullow's flagship operated offshore asset which contributed around 40% of the Group's overall production in 2013. The reservoir performance continues to be strong and the Phase 1A infill wells are being completed as required. Planning work also continues on additional development and drilling opportunities that will significantly extend the field plateau. The first planned maintenance shutdown of the Jubilee FPSO Kwame Nkrumah was successfully completed in late September 2013. The field production was impacted during the second half of 2013 due to a number of unplanned shutdowns of the FPSO's water injection system. The system is now fully operational and reservoir pressure and well capacity have been restored to over 130,000 bopd.
During 2013, the Ghana National Gas Company announced further delays to the start up of the onshore gas processing plant that is required to enable the export of Jubilee associated gas. The gas plant is now expected to be fully operational in the second half of 2014. As a consequence of this ongoing delay in gas export, the Jubilee partners have had to pursue various alternative gas handling options. In the fourth quarter of 2013, a third gas injection well was drilled and brought online. However, this well has had a limited impact. Discussions are ongoing with the Government of Ghana on other alternatives, including limited flaring, that will enable the field to average 100,000 bopd gross in 2014.
TEN
On 29 May 2013, the Government of Ghana formally approved the TEN PoD. This paved the way for Tullow and its partners to proceed with the development. The project is on target to deliver first oil in mid-2016 which will be followed by a steady ramp up to an expected FPSO gross production capacity of 80,000 bopd.
Development of the TEN Project will require the drilling and completion of up to 24 development wells which will be connected through subsea infrastructure to a FPSO vessel, moored in approximately 1,500 metres of water. The overall cost of the development is estimated to be $4.9 billion, excluding FPSO lease costs. All major contracts, including the FPSO and subsea infrastructure have been awarded and the West Leo rig has been secured to carry out the drilling and completion of the development wells. In October 2013, the Centennial Jewel trading tanker arrived in the Jurong Shipyard in Singapore, where it has begun its conversion into the TEN FPSO. The appraisal of the TEN fields was completed in 2013 with the drilling of the Enyenra-6A well. Development drilling commenced in 2014 with the drilling of the Nt-04 and En-01 water injection wells.
Following approval of the PoD, Tullow sought consent from the Government to farm down its interest in the TEN project whilst remaining operator. The farm down process is continuing in parallel to the development project. Gross capex spend for 2014 on the TEN project is expected to be approximately $1.2 billion.
Exploration and Appraisal
The Sapele-1 exploration well, which was completed in February 2013, was plugged and abandoned as a dry hole. This completed our drill-out of the Deepwater Tano licence which expired on 18 May 2013 with the remaining, non-prospective acreage being relinquished. The Jubilee Unit Area, the TEN Development and Production Area and the Wawa Discovery Area are being retained.
In the second half of 2013, the Akasa-2A appraisal well was drilled and successfully tested the down-dip extent of the Akasa accumulation. The partnership is planning some additional appraisal activities in 2014 in the West Cape Three Points licence that will assist in identifying the optimum development plan for the Mahogany, Teak and Akasa fields. In January 2013, the discovery area associated with the Banda discovery on the West Cape Three Points licence was relinquished.
Mauritania
In Mauritania, Tullow commenced its exploration drilling campaign in August 2013 targeting new, deeper plays in the offshore Mauritanian basin. The first well, Frégate-1, in the C-7 licence, was drilled to a depth of 5,426 metres and has encountered up to 30 metres of net gas-condensate and oil pay in multiple sands and the data will now be integrated with Tullow's regional 3D seismic surveys. The well is being plugged and abandoned and the rig will move to drill the Tapendar prospect in Block C-10. This wildcat well has achieved an important technical breakthrough by establishing a new oil play in deepwater Late Cretaceous turbidites. Whilst encouraging, further assessment and analysis will be required before follow up activities.
The approval of a Field Development Plan by the Government of Mauritania has allowed good progress to be made on the Banda gas to power development. The Engineering, Procurement and Construction bids have been received and pre-award negotiations are ongoing with contractors. Commercial discussions on the Gas Sales Agreement and associated Power Purchase Agreements are ongoing and are critical to the final sanction of this project.
Net production from the Chinguetti field in Mauritania, which is a separate play type from the Group's exploration interests, averaged just over 1,300 boepd in 2013, which is in line with expectations.
Gabon
Gabon net production averaged 13,300 bopd in 2013, slightly lower than expectations due to the impact of an oil sector workers strike in March 2013 and delays to the planned infill drilling programmes at Tchatamba. The Tchatamba drilling programme re-commenced in December 2013 with plans to drill four wells, plus two contingent infill wells, and this will be followed by a three well campaign on the Turnix field. The Limande field continues to outperform expectations due to two wells drilled in the South of the field during the year.
A modest carbonates oil discovery was made by the MOBA-1 well in October 2013, in the DE-7 licence. A flow test is being carried out to determine the potential size of the discovery. The Perroquet exploration well in the Kiarsseny Marine licence was completed in December 2013 and has been plugged and abandoned as a dry hole. Interpretation of data acquired from a 3D survey over the pre-salt Sputnik prospect in the complex Arouwe Block was completed in mid-2013, with drilling scheduled to commence in the first half of 2014.
Equatorial Guinea
The Ceiba field has performed strongly in 2013 following the completion of a successful workover and infill drilling programme in the first half of the year, with the final two producers coming online in July and September 2013 respectively. The programme has increased production, with net production averaging 3,500 bopd for the full year. A new 4D seismic survey is planned for 2014 in anticipation of a further drilling campaign in 2017.
Net production from the Okume Complex has been stable but marginally below expectations, averaging 6,200 bopd for the full year. A major infill drilling programme of 14 wells commenced in October 2013 and is expected to continue until mid-2016 which should significantly enhance production and the life of this asset.
Côte d'Ivoire
The Calao-1X exploration well in Block CI-103 was completed in May 2013, with the well encountering non-commercial gas condensate. In December 2013, Tullow announced that the Paon-2A appraisal well in the CI-103 licence offshore Côte d'Ivoire had determined the down-dip extent of the Paon oil accumulation. The well encountered the water below the oil accumulation discovered at the Paon-1X well and pressure logging has located the likely oil water contact and an estimated hydrocarbon column of 700 metres. Tullow and the block partners are currently reviewing options for the way forward.
The infill drilling campaign in the East and West Espoir fields was delayed in 2013 due to performance problems with the drilling contractor. The delay to this activity was partially offset by good facilities uptime and gas production performance from the field resulting in net production for the year of 3,500 boepd. The operator is currently well advanced in procuring an alternative drilling unit for the 11-well campaign which is now expected to commence in the second half of 2014. This campaign will have a significant impact on field production in the latter part of 2014 and future years.
Congo (Brazzaville)
M'Boundi field production was stable throughout 2013, averaging 2,600 boepd net, with a strong contribution from the southeast region of the field following the discovery of a southeast extension in 2012. To optimise performance, four infill wells have been completed in the past six months and the rig count for 2014 will increase from one to three, allowing up to 16 wells to be delivered per year as part of the field redevelopment strategy.
Guinea
Tullow and its partners are processing 4,000 sq km of 3D data as preparations continue to begin drilling the deepwater Fatala prospect (formerly named Eos) in the second quarter of 2014. Tullow took over operatorship of the exploration concession in April 2013.
Liberia and Sierra Leone
In June 2013, Tullow relinquished its interests in Blocks LB-16 and LB-17 offshore Liberia following a detailed review of the results to date from our West Africa Transform Margin acreage. Tullow retains its interests in Block 15 in Liberia and block SL-07B-11 in Sierra Leone, and is currently evaluating options for these blocks with partners.
SOUTH AND EAST AFRICA
|
2013 production NIL |
Total reserves and resources 579.8 mmboe |
2013 sales revenue NIL |
2013 investment $515 million |
Kenya
In Kenya, Tullow operates five onshore blocks in the East African Tertiary Rift system covering around 65,000 sq km and has between 50% and 65% interests in these licences. The Group has continued to make excellent progress with its exploration campaign in Northern Kenya with seven out of seven discoveries drilled since the start of the Tertiary Rift Basins exploration programme. In January 2014, as a result of the significant discoveries made to date, Tullow updated its estimate of discovered resources in this one Northern Kenya basin to over 600 mmbo gross with a potential of over one billion barrels of oil. Given the results to date in this single basin, Tullow considers that its acreage in Northern Kenya has the potential to be a significant new oil province.
The onshore acreage covers multiple rift basins which have similar characteristics to the Lake Albert Rift Basin in Uganda. A significant inventory of leads and prospects has been identified, to date, across this acreage following the acquisition of 60,000 sq km of FTG and 5,840 km of 2D seismic. Exploration drilling and testing activity in the region commenced in January 2012 with the drilling of the Ngamia-1 well followed by the Twiga South-1 well on the Basin Bounding Fault Play. These initial discoveries were both successfully flow tested in February and July 2013 respectively. Both wells flowed at constrained rates of around 3,000 bopd of 25 to 35 degree API sweet waxy oil with no indication of pressure depletion, and unconstrained rates of over 5,000 bopd per well are considered possible.
In May 2013, drilling commenced on the Etuko prospect, 14 km east of Twiga South-1 in Block 10BB. The well successfully opened the Basin Flank Play in the eastern part of the South Lokichar Basin. Ekales-1 commenced drilling in July 2013 and continued the successful run of discoveries on the Basin Bounding Fault Play, on trend with Ngamia and Twiga South. The Ekales-1 well was followed by two further discoveries at Agete-1 in November 2013 and Amosing-1 in January 2014. The seventh discovery in the basin to date also came in January 2014 at Ewoi-1 which continued to de-risk the Basin Flank Play opened by Etuko-1 earlier in 2013. Well testing at Etuko-1 has been completed and flowed at a combined rate of over 550 boepd. Additional potential pay zones were unable to be tested due to the large hole size and so the rig is now drilling a 650 metre well, Etuko-2, to evaluate and potentially test this shallower interval.
Ongoing activities include the testing of the Ekales-1 well and the drilling of Emong-1 and Twiga South-2 exploration and appraisal wells.
A significant programme of some 40 exploration and appraisal wells in the coming two years will assess not only the South Lokichar Basin but up to a further six separate Tertiary Rift Basins across Tullow's Kenyan acreage. Tullow is currently operating three rigs, the PR Marriott 46, Weatherford 804 and Sakson PR5 rigs and a workover unit, the SMP-5.
Given the significant volumes discovered and the extensive exploration, appraisal and seismic programme planned to fully assess the upside potential of the South Lokichar Basin, Tullow and its partner have agreed with the Government of Kenya to commence development studies. In addition, the partnership is involved in a comprehensive pre-FEED study for an export pipeline. The current ambition of the Government of Kenya and the joint venture partnership is to reach project sanction for development, including an export pipeline, in 2015/2016. If further exploration success opens additional basins there will be scope for the development to be expanded.
In the onshore Anza Basin, Block 10A, Tullow tested a Mesozoic Play with the Paipai-1 commitment well in March 2013, encountering light hydrocarbon shows. The licence has subsequently been relinquished as the partnership focuses its activities on the main Tertiary Rift Play across Kenya and Ethiopia.
Tullow also had a 15% interest in offshore Block L8, targeting a separate Transform Margin Play, but the licence was relinquished in January 2014.
Ethiopia
In Ethiopia, Tullow has a 50% operated interest in the South Omo block, its most northerly interest in the Kenya-Ethiopia Tertiary Rift system. At least three independent basins have been identified. In January 2013, Tullow commenced drilling Sabisa-1, the first ever well in this frontier acreage in the South Omo Basin. The well encountered reservoir quality sands containing heavy gas shows and a thick shale section. Tullow then drilled the Tultule-1 well in the same basin four kilometres east of Sabisa-1. In December 2013, the well was abandoned as a dry hole with gas shows recorded. The presence of source rocks, reservoir sands and good seals is encouraging for the numerous fault bounded traps identified elsewhere in the basin where some 10 prospects have been identified.
The OGEC rig is currently moving to the Chew Bahir Basin to drill the Shimela prospect in the eastern portion of the South Omo block where new seismic has delineated a number of exciting new prospects, some of which have encouraging seismic amplitude anomalies. The well is expected to spud at the end of the first quarter of 2014 with the aim of derisking some further 15 prospects and leads across the basin.
Uganda
Tullow has a one-third interest in each of four licences in the Lake Albert Rift Basin. Operating responsibilities within the basin are divided between the Partners: Total operates EA-1 and EA-1A; Tullow operates EA-2; and CNOOC Limited operates the Kingfisher Production Licence.
Operational activities have focused on completing numerous appraisal wells and flow tests with results achieving or exceeding expectations. These included the Waraga-3 well which discovered 93 metres of net oil pay, the largest pay tally since the start of the campaign, and the Jobi-6 well which successfully tested horizontal drilling techniques, resulting in enhanced well productivity. In addition, a 352 sq km 3D seismic acquisition across EA1 continues with over half of the programme now completed. These successful activities continue to support our estimates of gross recoverable resources of around 1.7 billion barrels of oil.
A Memorandum of Understanding (MoU) agreeing a commercialisation plan with the Government of Uganda was signed on 5 February 2014. The MoU concept involves an integrated development of the upstream, an export pipeline and a refinery of 60,000 bopd to be developed in a modular manner starting with 30,000 bopd. A lead investor to develop the refinery is expected be selected by the Government of Uganda by the end of first half of 2014. The partnership is progressing a comprehensive pre-FEED study for the crude oil export pipeline.
The partnership submitted Production Licence Applications (PLAs), including Field Development Plans (FDPs), for seven of the fields in line with the agreed commercialisation plan in the MoU. Remaining PLAs and FDPs will be submitted during 2014. The FDP for the Kingfisher discovery area was approved and the Production Licence conditions have been met.
The development planning work has continued with a significant focus placed on reducing the overall cost of the development. This work has resulted in multi-billion dollar cost savings, mainly due to the optimisation of well design and numbers and the design of the surface infrastructure.
In June 2013, Tullow received judgment in its favour in the High Court tax case proceedings against Heritage Oil and Gas Ltd and Heritage Oil plc (together 'Heritage'). When taking into account interest charges, Tullow received a total payment of approximately $346 million in August 2013. Heritage made a direct application to the Court of Appeal for permission to appeal the judgment which was granted on 20 September 2013. An appeal hearing is scheduled for 7 and 8 May 2014 with judgment due by the autumn.
Tullow has also been assessed by the Uganda Revenue Authority for Capital Gains Tax on the farm-down to CNOOC Limited and Total. The assessment of $473 million is disputed by Tullow. Following the payment of $142 million to the URA on account, being 30% of the assessed amount that Tullow was required to pay under Ugandan law in order to dispute the assessment, the case has been heard before the Tax Appeals Tribunal in Kampala with a decision expected by May 2014. On the advice of leading counsel, the Group believes it has a strong case under both international and Ugandan law and currently views the most probable outcome to be that any liability will be at a similar level to the amount already paid on account.
The Ngassa discovery, which extends beneath Lake Albert, has been written off due to offshore appraisal and development being currently uneconomic.
Namibia
There was continued progress on the Kudu Gas to Power Project during 2013. The revised development plan received government approval, front end engineering design was completed and contractual tenders are being progressed for a FPSO and the subsea equipment. Gas Sales Agreement negotiations are also progressing in parallel. Tullow's partner, Namibian national oil company NAMCOR, is seeking to farm-out equity and has appointed Deloitte to manage this process. Tullow expects to consider a final investment decision in 2014.
In October 2013, Tullow completed a farm-in to Namibia Licence EL 0037, taking over Operatorship from Pancontinental. Acquisition of 3,000 sq km of 3D and 1,000 km of 2D seismic data commenced in January 2014 across the licence.
Mozambique
In July 2013, the Cachalote-1 well and sidetrack, located in Area 2 offshore Mozambique, discovered 38 metres of wet gas bearing sandstone in the upper target. The Buzio well was also drilled in September 2013, but failed to encounter hydrocarbons. Further seismic reprocessing is being undertaken to establish additional potential prospectivity in Area 5 and this is planned to be completed by the second quarter of 2014, allowing for an exploration well potentially to commence before the licence expires in July 2014.
Madagascar
Negotiations for a farm-down of Bocks 3109 and 3111 in Madagascar are expected to conclude before the end of February 2014. Planning is underway to execute a seismic program in Block 3109 and to drill a well in Block 3111.
EUROPE, SOUTH AMERICA & ASIA
|
2013 production 19,200 boepd |
Total reserves and resources 163.4 mmboe |
2013 sales revenue $399.4 million |
2013 investment $474 million |
Norway
Tullow began its high-impact exploration campaign in Norway during 2013 and in early September 2013 the Group made a play opening light oil discovery at the Wisting Central well in the Hoop-Maud Basin in the Barents Sea. The Wisting Alternative well targeted a deeper, unrelated formation and was drilled in October 2013, but encountered oil shows in poor quality reservoir rock and has been plugged and abandoned. The Wisting Central discovery will be appraised in 2014 and this discovery significantly de-risks similar shallow prospects in the licence.
Other well results during the year included the 31/3-4 exploration well on the Mantra prospect in December 2013, which encountered reservoir quality sands but all intervals were water wet. Encouragingly, the well potentially penetrated the far down dip extent of the Kuro prospect, where hydrocarbon traces have been identified. In June 2013, the 7/34 well on the Carlsberg prospect was completed, but did not encounter hydrocarbons. The Mjøsa well in Block PL 511 was also completed in June 2013 and discovered uncommercial gas volumes in reservoir quality sandstone. Future activity in Norway includes the Butch East well in PL405 which commenced drilling at the end of 2013 with a result expected in the first quarter of 2014. Tullow plans to drill its next operated well, the Gotama prospect in Block PL 550, during the first quarter of 2014.
Tullow was successfully awarded three new licences in the 22nd Norwegian Licensing Round in June 2013. The licences lie in frontier areas of the west, north and central Barents Sea and Tullow will hold non-operated equities of 20-40%.
Production from the Brage field in Norway was in line with expectations, averaging 300 boepd net for the full year.
UK and Netherlands
Full year production in Tullow's Southern North Sea assets has been in line with expectations with 9,200 boepd in the UK and 5,300 boepd in the Netherlands. UK production was supplemented by the successful drilling and completion of the Schooner-11 well which came on stream in October 2013 at a rate of 35 mmscfd. Performance in the Netherlands has been sustained due to the K8 A 308 and K12 B11 wells which were brought on stream in April 2013.
In the UK, Tullow relinquished the operated Cameron discovery within block 44/19b, prior to the licence expiring.
In the Netherlands, the Tullow-operated Vincent exploration well commenced drilling in October 2013 and was successfully drilled to a TD of 4,027 metres. The well encountered a gas column of 72 metres and net pay of 25 metres and has been tested at a stable rate of 64 mmscfd. The Vincent well has therefore successfully opened the under-explored Netherlands Carboniferous sub-crop play that has proved so successful in the UK Continental Shelf. These results will now be incorporated into our regional geological model.
As previously announced, the Southern North Sea asset sale has been restructured.
Greenland
Tullow's farm-in to Block 9 (Tooq licence) was completed in December 2013 and a very material oil prospect, perhaps the largest in the region, has been mapped from recently processed 3D seismic data. Throughout 2013, Tullow and its joint venture partners have worked on a technical and non-technical work programme in order to decide whether to drill an exploration well in 2015. This decision will be made only if Tullow is satisfied that all necessary technical, environmental, safety and social standards have been reached.
French Guiana
The French Guiana drilling programme was completed in 2013. Priodontes-1 (GM-ES-3) was declared unsuccessful in April 2013 due to a trap-specific issue with no material consequences for prospectivity elsewhere in the block. GM-ES-4 on the Cebus prospect was completed in July 2013 and whilst there was extensive development of the targeted sands, no hydrocarbons were found and the well was plugged and abandoned.The final well in the drilling programme, GM-ES-5, was drilled into the water leg of the Zaedyus-1 oil pool and delineated the oil-water contact. The Stena IceMax rig was demobilised and left the Block in early December 2013. Tullow is currently incorporating the results from the 2013 wells into our geological model so we can better understand the considerable remaining prospectivity and determine the future licence work programme.
Suriname
In Suriname, seismic interpretations from a 3,000 sq km 3D survey taken over Block 47 in late 2012 confirm the presence of major deepwater turbidite systems. An attractive prospect inventory has been completed and ranked, with the Goliathberg/Votzberg South prospect identified for a potential exploration well for 2015.
In the first half of 2013, Tullow agreed terms with Teikoku Oil (Suriname) Co., Ltd, a subsidiary of INPEX CORPORATION, to farm in to offshore Block 31. Tullow acquired a 30% stake (INPEX to retain 70%), subject to sanction from the state oil company, Staatsolie which is expected in the first quarter of 2014.
Tullow and Statoil made a successful joint bid for offshore Block 54, in the Suriname International Bid Round 2013. Tullow will be the operator with a 50% interest.
Guyana
In the second quarter of 2013, Tullow reached an agreement with Repsol to secure a 30% interest in the newly defined Kanuku Block offshore Guyana. The transaction was completed in December 2013 following Government approval. Repsol is the Operator with 70% equity and Tullow 30% equity. 2D (857 kms) and 3D (3,175sq kms) seismic was acquired in December 2013.
Uruguay
Tullow signed an agreement in April 2013 to farm out 30% working interest to INPEX Uruguay Ltd on Block 15. This transaction was completed in December 2013. A 2,000 sq km 3D seismic programme was completed in September 2013, with interpretation of the data underway, fulfilling the licence's Phase 1 commitments.
Bangladesh & Pakistan
As part of planned divestments, Tullow completed the sale of its Bangladesh assets to KrisEnergy Asia Holdings Ltd in December 2013. Tullow is awaiting Government consent to complete the sale of its Pakistan assets to Ocean Pakistan Ltd.
Finance review
2013 RESULTS OVERVIEW
Production and commodity prices
Working interest production averaged 84,200 boepd, an increase of 6% for the year (2012: 79,200 boepd). This is primarily due to increased production from the Jubilee field offset by decline in mature fields in Europe and Asia. Sales volumes averaged 74,400 boepd, up 9% compared to 2012.
On average, oil prices in 2013 were slightly lower than in 2012. Realised oil price after hedging for 2013 was US$105.7/ bbl (2012: US$108.0/bbl), a decrease of 2%. European gas prices in 2013 were higher than 2012. The realised European gas price after hedging for 2013 was 65.6 pence/therm (2012: 58.5 pence/therm), an increase of 12%.
Operating costs, depreciation, impairments and expenses
Underlying cash operating costs, which excludes depletion and amortisation and movements in underlift/overlift, amounted to $524 million; $16.5/boe (2012: $437 million; $14.6/boe). The increase of 13% in underlying cash operating costs per barrel is principally due to the impact of lower production on fixed costs on mature assets and Jubilee well workover activity during 2013.
DD&A charges before impairment on production and development assets amounted to $565 million; $17.8/boe (2012: $537 million; $17.9/boe). The Group recognised an impairment charge of $53 million; $1.7/ boe (2012: $31 million; $1.0/boe) in respect of an increase in anticipated future decommissioning costs on the Thames field ($44 million), the difference between the disposal proceeds and net book value of Tullow Bangladesh Limited ($5 million) and on the Brage field in Norway ($4 million). The impairment charge net of tax amounted to $32 million.
Administrative expenses of $219 million (2012: $191 million) include an amount of $40 million (2012: $31 million) associated with IFRS 2 - Share-based Payments. The increase in total general and administrative costs is primarily due to the continued growth of the Group during 2013 with Tullow's total employees increasing by 10% to 1,553 people.
Total Costs Written-Off
|
|
2013 |
2012 |
|
Exploration costs written off ($m) |
(871) |
(671) |
|
Associated deferred tax credit ($m) |
174 |
70 |
|
Net exploration costs written off ($m) |
(697) |
(601) |
During 2013 the Group spent $1.1 billion, including Norway exploration costs on a post-tax basis, on exploration and appraisal activities and has written off $417 million in relation to this expenditure. This included write-offs in French Guiana ($101 million), Norway ($28 million), Gabon ($28 million), Ethiopia ($45 million) and Mozambique ($77 million) and new venture costs were $75 million. In addition the Group has written off $280 million in relation to prior years expenditure and fair value adjustments as a result of licence relinquishments and changes to future work programmes. This included write-offs in Kenya ($79 million) due to the relinquishment of Block 10A, Uganda ($67 million) in respect of the offshore block containing the Ngassa discoveries and UK ($30 million) due to the relinquishment of the Cameron discovery.
Derivative instruments
Tullow continues to undertake 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.
At 31 December 2013, the Group's derivative instruments had a net negative fair value of $70 million (2012: negative $59 million), inclusive of deferred premium. While all of the Group's commodity derivative instruments currently qualify for hedge accounting, a pre-tax charge of $20 million (2012: charge of $20 million) in relation to the change in time value of the Group's commodity derivative instruments has been recognised in the income statement for 2013.
At 7 February 2014 the Group's commodity hedge position to the end of 2016 was as follows:
|
Hedge position |
2014 |
2015 |
2016 |
|
Oil hedges |
|
|
|
|
Volume (bopd) |
35,500 |
27,500 |
13,000 |
|
Current price hedge ($/bbl) |
106.74 |
101.99 |
97.57 |
|
Gas hedges |
|
|
|
|
Volume (mmscfd) |
14.46 |
4.87 |
0.61 |
|
Current price hedge (p/therm) |
62.51 |
64.81 |
69.30 |
Net financing costs
The net interest charge for the year was $48 million (2012: $49 million) and reflects an increase in finance revenue associated with the interest received on settlement of the Heritage Oil and Gas High Court case offset by an increase in finance costs. The increase in finance costs is associated with the increase in net debt, but partially offset by an increase in capitalised interest due to commencement of the TEN development. The 2013 net interest charge includes interest incurred on the Group's debt facilities and the decommissioning finance charge offset by interest earned on cash deposits and borrowing costs capitalised principally against the Ugandan assets.
Taxation
The tax charge of $97 million (2012: $450 million) relates to the Group's North Sea, Gabon, Equatorial Guinea and Ghanaian production activities offset by the tax refund in relation to Norwegian exploration and deferred tax credits associated with exploration write-offs. After adjusting for exploration write-offs, the related deferred tax benefit in relation to the exploration write-offs and profits/losses on disposal, the Group's underlying effective tax rate is 32% (2012: 41%). The decrease in underlying effective tax rate is primarily a result of higher PSC income.
Profit from continuing activities and basic earnings per share
Profit for the year from continuing activities decreased by 68% to $216 million (2012: $666 million). Basic earnings per share decreased by 73% to 18.6 cents (2012: 68.8 cents).
Dividend per share
The Board is proposing a final dividend of 8.0 pence per share (2012: 8.0 pence per share). The dividend will be paid on 9 May 2014 to shareholders on the register on 4 April 2014 subject to the approval of shareholders at the Annual General Meeting to be held on 30 April 2014. Shareholders with registered addresses in the UK will be paid their dividends in pounds Sterling. Those with registered addresses in European countries which have adopted the Euro will be paid their dividends in Euro. Such shareholders may, however, elect to be paid their dividends in either pounds Sterling or Euro, provided such election is received at the Company's registrars by 15 April 2014. Shareholders on the Ghana branch register will be paid their dividends in Ghana Cedis. The conversion rate for the dividend payments in Euro or Ghana Cedis will be determined using the applicable exchange rate on 16 April 2014. A dividend re-investment plan (DRIP) is available to shareholders on the UK register who would prefer to invest their dividends in the shares of the Company. The last date to elect for the DRIP and to qualify for the share alternative in respect of this dividend is 15 April 2014.
Operating cash flow
Operating cash flow before working capital movements increased by 7% to $1.9 billion (2012: $1.8 billion) as a result of increased sales volumes from Jubilee, offset by higher cash operating costs. In 2013, this cash flow together with increased debt facilities helped fund $2.0 billion capital expenditure in exploration and development activities, $298 million payment of dividends and the servicing of debt facilities.
Capital expenditure
2013 capital expenditure amounted to $1.8 billion (2012: $1.9 billion) (net of Norwegian tax) with 38% invested in development activities, 12% in appraisal activities and 50% in exploration activities. More than 40% of the total was invested in Kenya, Ghana and Uganda and over 70%, more than $1.3 billion, was invested in Africa. Based on current estimates and work programmes, 2014 capital expenditure is forecast to reach $2.2 billion (net of Norwegian tax).
Portfolio management
During December 2013 the Bangladesh asset sale completed resulting in receipt of $41 million in proceeds. On 11 October 2013, Tullow signed a Sales and Purchase agreement with Ocean Pakistan Limited, a part of the Hashoo Group, for the sale of Tullow's 100% owned Pakistan subsidiary (TPDL). Government and regulatory approval has been requested and is expected in early 2014. The Southern North Sea asset sale is being restructured and sales of parts of this portfolio are expected to occur gradually. Following the receipt of initial bids, it became clear that the sales strategy needed to be adjusted to reflect current market conditions and to ensure that Tullow receives appropriate value from assets that are performing well with strong cash flows and have further exploration upside. The process to farm down Tullow's interest in the TEN Development is ongoing with proposals being evaluated.
Net debt and financing
On 6 November 2013, Tullow completed an offering of $650 million of 6% senior notes due in 2020 having originally offered $500 million. The net proceeds have been used to repay existing indebtedness under the Company's credit facilities but not cancel commitments under such facilities. This inaugural bond issue was an important step in the evolution of Tullow's capital structure and reduced the dependence on commercial bank lending by opening up access to a new source of debt capital. Commitments under the Reserves Based Lending credit facility remain unchanged at $3.5 billion from 2012 as do commitments under the Revolving credit facility of $0.5 billion. At 31 December 2013, Tullow had net debt of $1.9 billion (2012: $1.0 billion). Unutilised debt capacity at year-end amounted to approximately $2.4 billion. Gearing was 35% (2012: 19%) and EBITDA interest cover decreased to 40.2 times (2012: 48.3 times). Total net assets at 31 December 2013 amounted to $5.4 billion (31 December 2012: $5.3 billion) with the increase in total net assets principally due to the profit for the year from continuing activities.
|
|
$m |
|
Year end 2012 net debt |
(989) |
|
Revenue |
2,647 |
|
Operating costs |
(524) |
|
Operating expenses |
(222) |
|
Cash flow from operations |
1,901 |
|
Movement in working capital |
97 |
|
Tax paid |
(252) |
|
Capital expenditure |
(2,009) |
|
Acquisitions |
(481) |
|
Disposals |
80 |
|
Other investing activities |
34 |
|
Financing activities |
(298) |
|
Cash held for sale |
1 |
|
Foreign exchange gain on cash and debt |
7 |
|
Year end 2013 net debt |
(1,909) |
Uganda tax and legal issues
In 2012, we included $142 million in the Group's tax charge in relation to disputed capital gains tax on the Uganda farm-down to Total and CNOOC. This is currently going through a legal process and on the advice of leading senior counsel, both in international and Ugandan law, we believe we have a strong case and expect the most probable outcome to be that any liability will be similar to the amount already paid on account. Also in relation to the Uganda farm-down we continue to have a receivable on our balance sheet at 31 December 2013 of $358 million contingent consideration due on the 2012 Ugandan farm down from Total and CNOOC. The actual amount recoverable is dependent on the timing of the receipt of certain project approvals and is expected to be settled in full.
Liquidity risk management and going concern
The Group closely monitors and manages its liquidity risk. Cash forecasts are regularly produced and sensitivities run for different scenarios including, but not limited to, changes in commodity prices, different production rates from the Group's producing assets and delays to development projects. In addition to the Group's operating cash flows, portfolio management opportunities are reviewed potentially to enhance the financial capacity and flexibility of the Group. The Group's forecasts, taking into account reasonably possible changes as described above, show that the Group will be able to operate within its current debt facilities and have significant financial headroom for the 12 months from the date of approval of the 2013 Annual Report and Accounts.
2014 principal risks and uncertainties
The principal financial risks to performance identified for 2014 are:
· Continued delivery of financial strategy to maintain appropriate liquidity;
· Ensuring cost and capital discipline and effective supply chain management;
· Oil price and overall market volatility; and
· Delivery of planned portfolio activity.
Events since year-end
Since the balance sheet date Tullow has continued its exploration and appraisal, development and portfolio management activities.
In January 2014, Tullow announced oil discoveries at the Amosing-1 and Ewoi-1 exploration wells in Block 10BB onshore northern Kenya. As a result of these latest successes, Tullow updated its estimate of discovered resources in this basin to over 600 mmbo gross.
On 5 February 2014 a Memorandum of Understanding was signed between the Government of Uganda and Tullow, Total and CNOOC agreeing a basin wide commercialisation plan for the Lake Albert Basin.
2014 outlook
Tullow has a large asset base diversified across high-value production, selective developments and high-impact exploration. The business generates strong operating cash flow through high margin production and ongoing portfolio management. We fund our activities through disciplined capital management and maintaining a strong financial profile. Overall, we expect 2014 to be another year of progress for Tullow with further growth in the business, continued exploration success and headway being made with major developments and portfolio management.
ENDS
Disclaimer
This results announcement contains certain forward-looking statements that are subject to the risk factors and uncertainties associated with the oil and gas exploration and production business. Whilst the Group believes the expectations reflected herein to be reasonable in light of the information available to them at this time, the actual outcome may be materially different owing to a variety of factors including specific factors identified in this statement and other factors outlined in the Group's 2013 Annual Report.
|
Condensed consolidated income statement Year ended 31 December 2013 |
|
|
|
||
|
|
Notes |
2013 |
2012 |
||
|
Continuing activities |
|
|
|
||
|
Sales revenue |
6 |
2,646.9 |
2,344.1 |
||
|
Cost of sales |
|
(1,206.5) |
(999.3) |
||
|
Gross profit |
|
1,440.4 |
1,344.8 |
||
|
Administrative expenses |
|
(218.5) |
(191.2) |
||
|
Profit on disposal |
9 |
29.5 |
702.5 |
||
|
Exploration costs written off |
10 |
(870.6) |
(670.9) |
||
|
Operating profit |
|
380.8 |
1,185.2 |
||
|
Loss on hedging instruments |
|
(19.7) |
(19.9) |
||
|
Finance revenue |
|
43.7 |
9.6 |
||
|
Finance costs |
|
(91.6) |
(59.0) |
||
|
Profit from continuing activities before tax |
|
313.2 |
1,115.9 |
||
|
Income tax expense |
7 |
(97.1) |
(449.7) |
||
|
Profit for the year from continuing activities |
|
216.1 |
666.2 |
||
|
Attributable to: |
|
|
|
||
|
Owners of the Company |
|
169.0 |
624.3 |
||
|
Non-controlling interest |
|
47.1 |
41.9 |
||
|
|
|
216.1 |
666.2 |
||
|
Earnings per ordinary share from continuing activities |
|
¢ |
¢ |
||
|
Basic |
2 |
18.6 |
68.8 |
||
|
Diluted |
2 |
18.5 |
68.4 |
||
|
Condensed consolidated statement of comprehensive income and expense Year ended 31 December 2013 |
|
|
|
|
|
|
2013 $m |
2012 $m |
|
Profit for the year |
|
216.1 |
666.2 |
|
Items that may be reclassified to the income statement in subsequent periods |
|
|
|
|
Cash flow hedges |
|
|
|
|
Gains/(losses) arising in the year |
|
3.4 |
(3.3) |
|
Reclassification adjustments for items included in profit on realisation |
|
5.3 |
11.0 |
|
|
|
8.7 |
7.7 |
|
Exchange differences on translation of foreign operations |
|
12.7 |
7.7 |
|
Other comprehensive income Tax relating to components of other comprehensive income |
|
21.4 0.1 |
15.4 0.1 |
|
Other comprehensive income for the year |
|
21.5 |
15.5 |
|
Total comprehensive income for the year |
|
237.6 |
681.7 |
|
|
|
|
|
|
Owners of the Company |
|
190.5 |
639.8 |
|
Non-controlling interest |
|
47.1 |
41.9 |
|
|
|
237.6 |
681.7 |
|
Condensed consolidated balance sheet As at 31 December 2013 |
|
|
|
|
|
Notes |
2013 $m |
2012 $m |
|
ASSETS |
|
|
|
|
Non-current assets |
|
|
|
|
Goodwill |
8 |
350.5 |
- |
|
Intangible exploration and evaluation assets |
10 |
4,148.3 |
2,977.1 |
|
Property, plant and equipment |
|
4,862.9 |
4,407.9 |
|
Investments |
|
1.0 |
1.0 |
|
Other non-current assets |
11 |
68.7 |
696.7 |
|
Derivative financial instruments |
|
6.8 |
- |
|
Deferred tax assets |
|
1.1 |
4.9 |
|
|
|
9,439.3 |
8,087.6 |
|
Current assets |
|
|
|
|
Inventories |
|
193.9 |
163.7 |
|
Trade receivables |
|
308.7 |
238.7 |
|
Other current assets |
11 |
944.4 |
416.6 |
|
Current tax assets |
|
226.2 |
28.6 |
|
Cash and cash equivalents |
|
352.9 |
330.2 |
|
Assets classified as held for sale |
|
43.2 |
116.4 |
|
|
|
2,069.3 |
1,294.2 |
|
Total assets |
|
11,508.6 |
9,381.8 |
|
LIABILITIES |
|
|
|
|
Current liabilities |
|
|
|
|
Trade and other payables |
|
(1,041.1) |
(848.1) |
|
Borrowings |
|
(159.4) |
- |
|
Current tax liabilities |
|
(165.5) |
(292.4) |
|
Derivative financial instruments |
|
(48.1) |
(39.4) |
|
Liabilities directly associated with assets classified as held for sale |
|
(18.2) |
(48.9) |
|
|
|
(1,432.3) |
(1,228.8) |
|
Non-current liabilities |
|
|
|
|
Trade and other payables |
|
(29.4) |
(30.6) |
|
Borrowings |
|
(1,995.0) |
(1,173.6) |
|
Derivative financial instruments |
|
(28.3) |
(19.3) |
|
Provisions |
12 |
(989.2) |
(531.6) |
|
Deferred tax liabilities |
|
(1,588.0) |
(1,076.3) |
|
|
|
(4,629.9) |
(2,831.4) |
|
Total liabilities |
|
(6,062.2) |
(4,060.2) |
|
|
|
5,446.4 |
5,321.6 |
|
EQUITY |
|
|
|
|
Called up share capital |
13 |
146.9 |
146.6 |
|
Share premium |
|
603.2 |
584.8 |
|
Foreign currency translation reserve |
|
(155.1) |
(167.8) |
|
Hedge reserve |
|
2.3 |
(6.5) |
|
Other reserves |
|
740.9 |
740.9 |
|
Retained earnings |
|
3,984.7 |
3,931.2 |
|
Equity attributable to equity holders of the Company |
|
5,322.9 |
5,229.2 |
|
Non-controlling interest |
|
123.5 |
92.4 |
|
|
|
5,446.4 |
5,321.6 |
|
Condensed statement of changes in equity Year ended 31 December 2013 |
|||||||||
|
|
Share |
Share |
Foreign currency translation reserve $m |
Hedge Reserve $m |
Other reserves $m |
Retained earnings |
Total |
Non-controlling interest |
Total |
|
At 1 January 2012 |
146.2 |
551.8 |
(175.5) |
(14.3) |
740.9 |
3,441.3 |
4,690.4 |
75.6 |
4,766.0 |
|
Profit for the year |
- |
- |
- |
- |
- |
624.3 |
624.3 |
41.9 |
666.2 |
|
Hedges, net of tax |
- |
- |
- |
7.8 |
- |
- |
7.8 |
- |
7.8 |
|
Currency translation adjustments |
- |
- |
7.7 |
- |
- |
- |
7.7 |
- |
7.7 |
|
Issue of shares |
- |
4.9 |
- |
- |
- |
- |
4.9 |
- |
4.9 |
|
Issue of employee share options |
0.4 |
28.1 |
- |
- |
- |
- |
28.5 |
- |
28.5 |
|
Vesting of PSP shares |
- |
- |
- |
- |
- |
(9.1) |
(9.1) |
- |
(9.1) |
|
Share-based payment charges |
- |
- |
- |
- |
- |
47.9 |
47.9 |
- |
47.9 |
|
Dividends paid |
- |
- |
- |
- |
- |
(173.2) |
(173.2) |
- |
(173.2) |
|
Distribution to non-controlling interests |
- |
- |
- |
- |
- |
- |
- |
(25.1) |
(25.1) |
|
At 1 January 2013 |
146.6 |
584.8 |
(167.8) |
(6.5) |
740.9 |
3,931.2 |
5,229.2 |
92.4 |
5,321.6 |
|
Profit for the year |
- |
- |
- |
- |
- |
169.0 |
169.0 |
47.1 |
216.1 |
|
Hedges, net of tax |
- |
- |
- |
8.8 |
- |
- |
8.8 |
- |
8.8 |
|
Currency translation adjustments |
- |
- |
12.7 |
- |
- |
- |
12.7 |
- |
12.7 |
|
Issue of employee share options |
0.3 |
18.4 |
- |
- |
- |
- |
18.7 |
- |
18.7 |
|
Vesting of PSP shares |
- |
- |
- |
- |
- |
(12.7) |
(12.7) |
- |
(12.7) |
|
Share-based payment charges |
- |
- |
- |
- |
- |
64.6 |
64.6 |
- |
64.6 |
|
Dividends paid |
- |
- |
- |
- |
- |
(167.4) |
(167.4) |
- |
(167.4) |
|
Distribution to non-controlling interests |
- |
- |
- |
- |
- |
- |
- |
(16.0) |
(16.0) |
|
At 31 December 2013 |
146.9 |
603.2 |
(155.1) |
2.3 |
740.9 |
3,984.7 |
5,322.9 |
123.5 |
5,446.4 |
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.
|
Condensed consolidated cash flow statement Year ended 31 December 2013 |
|||
|
|
Notes |
2013 |
2012 |
|
Cash flows from operating activities |
|
|
|
|
Profit before taxation |
|
313.2 |
1,115.9 |
|
Adjustments for: |
|
|
|
|
Depletion, depreciation and amortisation |
|
591.9 |
561.9 |
|
Impairment loss |
|
52.7 |
31.3 |
|
Exploration costs written off |
|
870.6 |
670.9 |
|
Profit on disposal |
9 |
(29.5) |
(702.5) |
|
Decommissioning expenditure |
|
(6.7) |
(2.4) |
|
Share-based payment charge |
|
41.3 |
32.6 |
|
Loss on hedging instruments |
|
19.7 |
19.9 |
|
Finance revenue |
|
(43.7) |
(9.6) |
|
Finance costs |
|
91.6 |
59.0 |
|
Operating cash flow before working capital movements |
|
1,901.1 |
1,777.0 |
|
Decrease/(increase) in trade and other receivables |
|
75.8 |
(11.3) |
|
(Increase)/ decrease in inventories |
|
(28.9) |
11.3 |
|
Increase in trade payables |
|
49.6 |
7.5 |
|
Cash flows from operating activities |
|
1,997.6 |
1,784.5 |
|
Income taxes paid |
|
(252.3) |
(264.1) |
|
Net cash from operating activities |
|
1,745.3 |
1,520.4 |
|
Cash flows from investing activities |
|
|
|
|
Disposal of subsidiaries |
9 |
41.4 |
- |
|
Disposal of exploration and evaluation assets |
9 |
38.2 |
2,568.2 |
|
Disposal of oil and gas assets |
|
0.7 |
0.3 |
|
Disposal of other assets |
|
- |
1.3 |
|
Purchase of subsidiaries |
8 |
(392.8) |
- |
|
Purchase of intangible exploration and evaluation assets |
|
(1,268.5) |
(1,196.6) |
|
Purchase of property, plant and equipment |
|
(740.8) |
(652.8) |
|
Finance revenue |
|
34.3 |
1.3 |
|
Net cash (used in)/generated by investing activities |
|
(2,287.5) |
721.7 |
|
Cash flows from financing activities |
|
|
|
|
Net proceeds from issue of share capital |
|
6.0 |
24.5 |
|
Debt arrangement fees |
|
(13.5) |
(77.2) |
|
Repayment of bank loans |
|
(1,236.5) |
(2,407.5) |
|
Drawdown of bank loan |
|
1,447.7 |
565.0 |
|
Issue of senior loan notes |
|
650.0 |
- |
|
Repayment of obligations under finance leases |
|
(3.3) |
(1.8) |
|
Finance costs |
|
(103.5) |
(103.2) |
|
Dividends paid |
|
(167.4) |
(173.2) |
|
Distribution to non controlling interests |
|
(16.0) |
(25.1) |
|
Net cash generated by/(used in) financing activities |
|
563.5 |
(2,198.5) |
|
Net increase in cash and cash equivalents |
|
21.3 |
43.6 |
|
Cash and cash equivalents at beginning of year |
|
330.2 |
307.1 |
|
Cash transferred to held for sale |
|
0.6 |
(18.0) |
|
Foreign exchange gain/(loss) |
|
0.8 |
(2.5) |
|
Cash and cash equivalents at end of year |
|
352.9 |
330.2 |
Notes to the preliminary financial statements
Year ended 31 December 2013
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 2014.
The financial information for the year ended 31 December 2013 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 2012 have been delivered to the Registrar of Companies and those for 2013 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 2012. 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 2013; however these have not had a material impact on the accounting policies, methods of computation or presentation applied by the Group.
2. Earnings per Share
The calculation of basic earnings per share is based on the profit for the year after taxation attributable to equity holders of the parent of $169.0 million (2012: $624.3 million) and a weighted average number of shares in issue of 908.3 million (2012: 906.8 million).
The calculation of diluted earnings per share is based on the profit for the year after taxation as for basic earnings per share. The number of shares outstanding, however, is adjusted to show the potential dilution if employee share options are converted into ordinary shares. The weighted average number of ordinary shares is increased by 6.1 million (2012: 5.5 million) in respect of employee share options, resulting in a diluted weighted average number of shares of 914.4 million (2012: 912.4 million).
3. Dividends
During the year the Company paid a final 2012 dividend of 8.0 pence per share and an interim 2013 dividend of 4.0 pence per share, a total dividend of 12.0 pence per share (2012: 12.0 pence per share). The Directors intend to recommend a final 2013 dividend of 8.0 pence per share, which, if approved at the AGM, will be paid on 9 May 2014 to shareholders on the register of the Company on 4 April 2014.
4. 2013 Annual Report and Accounts
The Annual Report and Accounts will be mailed on 24 March 2014 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 website (www.tullowoil.com). Copies of the Annual Report and Accounts will also be available from the Company's registered office at 9, Chiswick Park, 566 Chiswick High Road, London W4 5XT.
5. Annual General Meeting
The Annual General Meeting is due to be held at Haberdashers' Hall, 18 West Smithfield, London EC1A 9HQ on Wednesday 30 April 2014 at 12 noon.
6. Segmental Reporting
Information reported to the Group's Chief Executive Officer for the purposes of resource allocation and assessment of segment performance is focused on the three geographical regions within which the Group operates. The Group has one class of business, being the exploration, development, production and sale of hydrocarbons and therefore the Group's reportable segments under IFRS 8 are West and North Africa; South and East Africa; and Europe, South America and Asia. The following tables present revenue, profit and certain asset and liability information regarding the Group's business segments for the year ended 31 December 2013 and 31 December 2012.
|
|
West |
South |
Europe, South America |
Unallocated |
Total |
|
2013 |
2,247.5 |
- |
399.4 |
- |
2,646.9 |
|
Segment result |
1,285.5 |
(339.6) |
(376.1) |
- |
569.8 |
|
Profit on disposal of other assets |
|
|
|
|
29.5 |
|
Unallocated corporate expenses |
|
|
|
|
(218.5) |
|
Operating profit |
|
|
|
|
380.8 |
|
Loss on hedging instruments |
|
|
|
|
(19.7) |
|
Finance revenue |
|
|
|
|
43.7 |
|
Finance costs |
|
|
|
|
(91.6) |
|
Profit before tax |
|
|
|
|
313.2 |
|
Income tax expense |
|
|
|
|
(97.1) |
|
Profit after tax |
|
|
|
|
216.1 |
|
Total assets |
5,940.4 |
2,173.3 |
3,212.0 |
182.9 |
11,508.6 |
|
Total liabilities |
(1,943.6) |
(276.4) |
(1,771.6) |
(2,070.6) |
(6,060.2) |
|
Other segment information |
|
|
|
|
|
|
Capital expenditure: |
|
|
|
|
|
|
Property, plant and equipment |
876.7 |
2.3 |
164.2 |
27.2 |
1,070.4 |
|
Intangible exploration and evaluation |
262.9 |
570.0 |
669.8 |
- |
1,502.7 |
|
Depletion, depreciation and amortisation |
(425.5) |
(0.5) |
(142.2) |
(23.7) |
(591.9) |
|
Impairment losses recognised in income statement |
- |
- |
(52.7) |
- |
(52.7) |
|
Exploration costs written off |
(113.4) |
(334.9) |
(422.3) |
- |
(870.6) |
|
|
West |
South |
Europe, South America |
Unallocated |
Total |
|
2012 |
1,963.5 |
- |
380.6 |
- |
2,344.1 |
|
Segment result |
974.1 |
(176.2) |
(124.0) |
- |
673.9 |
|
Profit on disposal of oil and gas assets |
|
|
|
|
702.5 |
|
Unallocated corporate expenses |
|
|
|
|
(191.2) |
|
Operating profit |
|
|
|
|
1,185.2 |
|
Gain on hedging instruments |
|
|
|
|
(19.9) |
|
Finance revenue |
|
|
|
|
9.6 |
|
Finance costs |
|
|
|
|
(59.0) |
|
Profit before tax |
|
|
|
|
1,115.9 |
|
Income tax expense |
|
|
|
|
(449.7) |
|
Profit after tax |
|
|
|
|
666.2 |
|
Total assets |
5,148.3 |
2,185.6 |
1,868.0 |
179.9 |
9,381.8 |
|
Total liabilities |
(1,531.9) |
(285.1) |
(999.4) |
(1,243.8) |
(4,060.2) |
|
Other segment information |
|
|
|
|
|
|
Capital expenditure: |
|
|
|
|
|
|
Property, plant and equipment |
626.5 |
1.5 |
136.3 |
29.8 |
794.1 |
|
Intangible exploration and evaluation |
512.2 |
582.6 |
246.1 |
- |
1,340.9 |
|
Depletion, depreciation and amortisation |
(360.2) |
(1.2) |
(178.4) |
(22.1) |
(561.9) |
|
Impairment losses recognised in income statement |
(31.3) |
- |
- |
- |
(31.3) |
|
Exploration costs written off |
(320.9) |
(176.1) |
(173.9) |
- |
(670.9) |
Unallocated expenditure and net liabilities include amounts of a corporate nature and not specifically attributable to a geographic area. The liabilities comprise the Group's external debt and other non attributable corporate liabilities.
7. Taxation on profit on ordinary activities
a. Analysis of charge in period
The tax charge comprises:
|
|
2013 |
2012 |
|
Current tax |
|
|
|
UK corporation tax |
4.3 |
10.1 |
|
Foreign tax |
(9.8) |
360.2 |
|
Total corporate tax |
(5.5) |
370.3 |
|
UK petroleum revenue tax |
11.1 |
10.8 |
|
Total current tax |
5.6 |
381.1 |
|
Deferred tax |
|
|
|
UK corporation tax |
(35.5) |
17.3 |
|
Foreign tax |
130.8 |
53.6 |
|
Total deferred corporate tax |
95.3 |
70.9 |
|
Deferred UK petroleum revenue tax |
(3.8) |
(2.3) |
|
Total deferred tax |
91.5 |
68.6 |
|
Total tax expense |
97.1 |
449.7 |
b. Factors affecting tax charge 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 current tax charge shown above and the amount calculated by applying the standard rate of UK corporation tax applicable to UK profits 23% (2012: 24%) to the profit before tax is as follows:
|
|
2013 |
2012 |
|
|
Group profit on ordinary activities before tax |
313.2 |
1,115.9 |
|
|
Tax on Group profit on ordinary activities at the standard UK corporation |
72.0 |
267.8 |
|
|
Effects of: |
|
|
|
|
Expenses not deductible for tax purposes |
123.7 |
86.7 |
|
|
Other income not subject to corporation tax |
(85.2) |
(15.5) |
|
|
PSC income not subject to corporation tax |
(51.9) |
(83.1) |
|
|
Net losses not recognised |
86.6 |
129.1 |
|
|
Petroleum revenue tax (PRT) |
6.8 |
8.5 |
|
|
UK corporation tax deductions for current PRT |
(4.2) |
(5.3) |
|
|
Utilisation of tax losses not previously recognised |
(7.5) |
- |
|
|
Adjustments relating to prior years |
(52.5) |
20.8 |
|
|
Adjustments to deferred tax relating to change in tax rates |
0.1 |
16.5 |
|
|
Income taxed at a different rate |
32.5 |
161.2 |
|
|
Uganda capital gains tax |
- |
(132.6) |
|
|
Tax incentives for investment |
(23.3) |
(4.4) |
|
|
Group total tax expense for the year |
97.1 |
449.7 |
|
Following previous reductions in the main rate of UK corporation tax, on 26 March 2012 additional reductions from 26% to 24% effective from 1 April 2012 and from 24% to 23% from 1 April 2013 were substantively enacted. The Finance Act 2013 substantively enacted on 2 July 2013 included legislation reducing the main rate of UK corporation tax from 23% to 21% with effect from 1 April 2014 and a further phased reduction in the mainstream rate to 20% at 1 April 2015.
The Group's profit before taxation will continue to arise in jurisdictions where the effective rate of taxation differs from that in the UK. 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 $1,783.0 million (2012: $1,724.7 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. The Group has recognised $52.0 million in deferred tax assets in relation to taxable losses (2012: $49.4 million); this is disclosed net of a deferred tax liability in respect of capitalised interest.
No deferred tax liability is recognised on temporary differences of $24.5 million (2012: $30 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.
Current tax assets
As at 31 December 2013 current tax assets were $226.2 million (2012: $28.6 million) of which $203.0 million relates to Norway where 78% of exploration expenditure is refunded as a tax refund in the following year.
8. Acquisitions
On 11 December 2012 Tullow announced that it had acquired 100% of the ordinary share capital of Spring Energy Norway AS ("Spring"). The acquisition of Spring added a portfolio of 28 offshore licences across Norway's continental shelf in the North, Norwegian and Barents Seas. The acquisition enables the Group to rapidly build a strong platform for future growth in Norway. The transaction had an effective date of 1 September 2012 but completed on 22 January 2013 and this is therefore the acquisition date.
|
|
Final fair value |
|
Goodwill |
350.5 |
|
Intangible exploration and appraisal assets |
593.3 |
|
Property, plant and equipment |
0.6 |
|
Other non-current assets |
26.2 |
|
Inventory |
0.8 |
|
Trade receivables |
4.1 |
|
Other current assets |
30.4 |
|
Current tax assets |
90.7 |
|
Cash and cash equivalents |
26.3 |
|
Trade and other payables |
(68.4) |
|
Other financial liabilities - current5 |
(87.7) |
|
Deferred tax liabilities |
(414.6) |
|
Provisions |
(28.6) |
|
Total purchase consideration |
523.6 |
|
Represented by: |
|
|
Consideration satisfied by cash |
419.1 |
|
Contingent consideration |
104.5 |
|
Total purchase consideration |
523.6 |
|
Consideration satisfied by cash |
(419.1) |
|
Cash and cash equivalents acquired |
26.3 |
|
Purchase of subsidiaries per the cash flow statement |
(392.8) |
Valuation methodology and assumptions
All fair values calculated for the purposes of IFRS 3 are classified as Level 3 in accordance with IFRS 13 Fair Value Measurement. The following table summarises the techniques used to arrive at fair value and certain key assumption.
|
Category |
Valuation technique |
Key inputs & assumptions |
|
Goodwill |
n/a1 |
n/a |
|
Intangible exploration and appraisal assets |
$/boe of risked resources |
$/boe of risked resources |
|
Property, plant and equipment |
Discounted cash flow |
2P reserves, forward oil curve, 10% discount rate |
|
Inventory |
Historical cost |
Historical cost of all inventory lower than NRV |
|
Provisions2 |
Present value |
4% discount rate, 2% inflation, operator cost estimate |
|
Contingent consideration |
Discounted cash flow |
$/bbl of risked resources3, 8% discount rate |
|
All other items4 |
Carrying value |
The carrying value is equal to fair value |
1. The total purchase consideration equals the aggregate of the pre-tax fair value of the identifiable assets and liabilities of Spring. Given the nature of the oil and gas regime in Norway, the fair value of the business acquired has been determined based on the purchase price which is net of tax attributes. As a consequence, the goodwill balance solely results from the requirement on an acquisition to recognise a deferred tax liability, calculated as the difference between the tax effect of the fair value of the acquired assets and liabilities and their tax bases.
2. Provisions represent the present value of decommissioning costs ($18.6 million) which are expected to be incurred up to 2025 and a $10.0 million liability on development of the PL407 licence.
3. The contingent consideration represents the fair value of a contingent amount payable to the previous owners of Spring. The payable is calculated as $0.5/bbl to $1.0/bbl of recoverable resources recognised by four operated wells expected to be drilled in 2013 and 2014 and is capped at $300 million.
4. All other items includes, other non-current assets, trade receivables, other current assets, current tax assets, cash and cash equivalents, trade and other payables, other financial liabilities and deferred tax liabilities.
5. Other current financial liabilities at 31 December and at the acquisition date relate to Spring's Exploration Finance Facility, which provides funding for 74% of Norwegian exploration costs secured against the exploration tax refund on exploration expenditure of 78%
Transaction costs of $0.9m in respect of the acquisition are recognised in the 2013 income statement. From the date of acquisition, Spring has contributed $11.2 million to Group revenues and a loss of $17.7 million to the profit of the Group. If the acquisition had been completed on the first day of the financial year, Group revenues for the period would have been $2,647.8 million and Group profit would have been $216.9 million.
There were no acquisitions involving business combinations in 2012.
9. Disposals
In 2013 the Group completed the disposal of Tullow Bangladesh Limited for $41.4 million which was previously classified as held for sale. During 2013 the Group also farmed down a portion of its interest in CI-103 in Côte d'Ivoire and received $8.6 million in cash for past costs.
In 2012 the Group completed the farm-down of one-third of its Uganda interests to both Total and CNOOC ("the partners") for consideration of $3.3 billion (including $341.3 million of discounted contingent consideration), generating a profit on disposal of $701.0 million.
In 2012 the Group provided for $30.0 million in respect to the $313.0 million recoverable security paid by Tullow to the Uganda Revenue Authority as agent to the transaction between Tullow and Heritage Oil and Gas Ltd. This balance was initially capitalised as a cost of the Uganda assets and subsequently disposed, therefore on receipt of the receivable in full the Group recorded a profit on disposal in the 2013 income statement of $30.0 million. The $30.0 million balance previously provided for has been treated as an investing activity in the cash flow statement whereas the remaining $283.0 million is treated as a decrease in trade and other receivables.
Further disposals of oil and gas assets and non-oil and gas assets generating a loss on disposal of $0.5 million were completed in 2013 (2012: $1.5 million, profit)
10. Intangible exploration and evaluation assets
|
|
2013 |
2012 |
|
At 1 January |
2,977.1 |
5,529.7 |
|
Acquisition of subsidiaries (note 8) |
593.3 |
- |
|
Additions |
1,502.7 |
1,340.9 |
|
Disposals (note 9) |
(8.6) |
(2,573.6) |
|
Amounts written off |
(865.5) |
(670.9) |
|
Write-off associated with Norway contingent consideration |
(41.2) |
- |
|
Transfer to assets held for sale |
- |
(28.4) |
|
Transfer to property, plant and equipment |
(2.7) |
(625.3) |
|
Currency translation adjustments |
(6.8) |
4.7 |
|
At 31 December |
4,148.3 |
2,977.1 |
Included within 2013 additions is $56.9 million of capitalised interest (2012: $67.2 million). The Group only capitalises interest in respect of intangible exploration and evaluation assets where it is considered that development is highly likely and advanced appraisal and development is ongoing.
In 2013 the income statement exploration costs written-off differ from the table above as a result of the write down of the held for sale Pakistan assets of $5.1 million.
|
|
2013 |
2012 |
|
Exploration costs written off |
(870.6) |
(670.9) |
|
Associated deferred tax credit |
173.9 |
69.5 |
|
Net exploration costs written off |
(696.7) |
(601.4) |
During 2013 the Group spent $1.1 billion, including Norway exploration costs on a post tax basis, on exploration and appraisal activities and has written off $417.2 million in relation to this expenditure. This included net write-offs in relation to current year expenditure in French Guiana ($100.5 million), Norway ($28.0 million), Gabon ($27.6 million), Ethiopia ($45.3 million) and Mozambique ($77.0 million) and new venture costs were $75.0 million. In addition the Group has written off $279.5 million in relation to prior years expenditure and fair value adjustments as a result of licence relinquishments and changes in expected near-term work programmes. This included write-offs in Kenya ($79.0 million), Uganda ($66.9 million) and UK ($29.9 million).
In 2012 the Group spent $1.1 billion on exploration and appraisal activities and has written off $236.1 million in relation to this expenditure. This included net write-offs in relation to 2012 expenditure in Ghana ($36.9 million), Guyana ($46.4 million) and Sierra Leone ($37.9 million) and new venture costs were $66.8 million. In addition the Group has written off $365.3 million net of tax in relation to prior years expenditure and fair value adjustments as a result of licence relinquishments and changes in expected near-term work programmes. This included write-offs in Mauritania ($80.8 million), Namibia ($114.6 million) and Ghana ($37.0 million).
11. Other assets
|
|
2013 |
2012 |
|
Non-current |
|
|
|
Contingent consideration receivable |
- |
348.3 |
|
Recoverable security due from Heritage Oil and Gas Limited |
- |
283.5 |
|
Uganda VAT recoverable |
50.6 |
55.5 |
|
Other non-current assets |
18.1 |
9.4 |
|
|
68.7 |
696.7 |
|
Current |
|
|
|
Contingent consideration receivable |
358.1 |
- |
|
Amounts due from joint venture partners |
367.2 |
234.4 |
|
Underlifts |
30.8 |
16.7 |
|
Prepayments |
99.3 |
33.4 |
|
VAT recoverable |
7.9 |
12.3 |
|
Other current assets |
81.1 |
119.8 |
|
|
944.4 |
416.6 |
As at 31 December 2013, $358.1 million has been recorded as a current receivable (2012: $348.3 million, non-current) in respect of contingent consideration due on the 2012 Ugandan farm down. The carrying value represents a receivable due of $370.2 million discounted to the estimated due date to reflect the credit risk of the counterparties and the time value of money. The unwind of the discount has been accounted for as finance revenue.
In 2013 Tullow was successful in an action against Heritage Oil and Gas Ltd and received payment for $345.8 million in August 2013, which included receipt of the $313.0 million due and $32.8 million of interest, which has been recorded as finance revenue. The Group had previously provided for $30.0 million in respect to the $313.0 million. On 20 September 2013, the Court of Appeal granted Heritage permission to appeal the judgment with the appeal hearing expected to take place in May 2014.
12. Provisions
|
|
DecommissIoning 2013 $m |
Other provisions 2013 $m |
Total 2013 |
DecommissIoning 2012 $m |
Other provisions 2012 $m |
Total 2012 |
|
At 1 January |
531.6 |
- |
531.6 |
440.8 |
- |
440.8 |
|
New provisions and changes in estimates |
274.0 |
136.3 |
410.3 |
60.4 |
- |
60.4 |
|
Acquisition of subsidiary |
18.6 |
10.0 |
28.6 |
- |
- |
- |
|
Decommissioning payments |
(6.7) |
- |
(6.7) |
1.1 |
- |
1.1 |
|
Unwinding of discount |
16.7 |
0.8 |
17.5 |
20.3 |
- |
20.3 |
|
Transfer to assets held for sale |
- |
- |
- |
(1.6) |
- |
(1.6) |
|
Unwinding of discount |
7.3 |
0.6 |
7.9 |
10.6 |
- |
10.6 |
|
At 31 December |
841.5 |
147.7 |
989.2 |
531.6 |
- |
531.6 |
The decommissioning provision represents the present value of decommissioning costs relating to the European and African oil and gas interests, which are expected to be incurred up to 2035. A review of all decommissioning estimates was undertaken by an independent specialist at the start of 2013 which has been assessed and updated internally for the purposes of the 2013 financial statements. Assumptions, based on the current economic environment, have been made which management believe are a reasonable basis upon which to estimate the future liability. These estimates are reviewed regularly to take into account any material changes to the assumptions. However, actual decommissioning costs will ultimately depend upon future market prices for the necessary decommissioning works required which will reflect market conditions at the relevant time. Furthermore, the timing of decommissioning is likely to depend on when the fields cease to produce at economically viable rates. This in turn will depend upon future oil and gas prices, which are inherently uncertain.
Other provisions include a liability acquired through the acquisition of Spring (note 8) which is contingent in terms of timing and amount on the development of the PL407 licence in Norway. Other provisions also include the contingent consideration in respect of the Spring acquisition (note 8). The amount recorded on acquisition was $104.5 million and subsequent information provided through drilling results during 2013 has resulted in a net uplift of the provision to $131.2 million, which includes a specific write-off of $41.2 million in relation to the Mantra well result in Norway (note 10).
13. Called up equity share capital
In the year ended 31 December 2013, the Group issued 2,208,614 (2012: 2,848,078) new shares which included issuing 2,208,614 (2012: 2,623,123) new shares in respect of employee share options.
As at 31 December 2013 the Group had in issue 909,971,941 allotted and fully paid ordinary shares of Stg10 pence each (2012: 907,763,327).
14. Commercial Reserves and Contingent Resources summary (unaudited) working interest basis
|
|
West and |
South and |
Europe, South America and Asia |
TOTAL |
|||||
|
|
Oil mmbbl |
Gas bcf |
Oil mmbbl |
Gas bcf |
Oil mmbbl |
Gas bcf |
Oil mmbbl |
Gas bcf |
Petroleum mmboe |
|
COMMERCIAL RESERVES |
|
|
|
|
|
|
|
||
|
31 December 2012 |
339.6 |
16.5 |
- |
- |
1.4 |
265.9 |
341.0 |
282.4 |
388.0 |
|
Revisions |
9.6 |
4.7 |
- |
- |
(0.1) |
8.2 |
9.5 |
12.9 |
11.7 |
|
Acquisitions |
- |
- |
- |
- |
0.5 |
0.7 |
0.5 |
0.7 |
0.6 |
|
Transfer from CR |
- |
157.7 |
- |
- |
- |
- |
- |
157.7 |
26.3 |
|
Disposals |
- |
- |
- |
- |
(0.2) |
(80.5) |
(0.2) |
(80.5) |
(13.6) |
|
Production |
(23.2) |
(3.0) |
- |
- |
(0.3) |
(39.7) |
(23.5) |
(42.7) |
(30.6) |
|
31 December 2013 |
326.0 |
175.9 |
- |
- |
1.3 |
154.6 |
327.3 |
330.5 |
382.4 |
|
CONTINGENT RESOURCES |
|
|
|
|
|
|
|
||
|
31 December 2012 |
77.2 |
1,363.8 |
381.5 |
360.7 |
36.6 |
192.2 |
495.3 |
1,916.7 |
814.8 |
|
Revisions |
28.3 |
22.3 |
103.7 |
2.3 |
- |
- |
132.0 |
24.6 |
136.1 |
|
Acquisitions |
- |
- |
- |
- |
19.8 |
- |
19.8 |
- |
19.8 |
|
Additions |
- |
- |
34.1 |
- |
51.8 |
- |
85.9 |
- |
85.9 |
|
Disposals |
- |
- |
- |
- |
- |
(23.5) |
- |
(23.5) |
(3.9) |
|
Transfers to commercial reserves |
- |
(157.7) |
- |
- |
- |
- |
- |
(157.7) |
(26.3) |
|
31st December 2013 |
105.5 |
1,228.4 |
519.3 |
363.0 |
108.2 |
168.7 |
733.0 |
1,760.1 |
1,026.4 |
|
TOTAL |
|
|
|
|
|
|
|
|
|
|
31 December 2013 |
431.5 |
1,404.3 |
519.3 |
363.0 |
109.5 |
323.3 |
1,060.3 |
2,090.6 |
1,408.8 |
1. Proven and Probable Commercial Reserves are based on a Group reserves report produced by an independent engineer. Reserves estimates for each field are reviewed by the independent engineer based on significant new data or a material change with a review of each field undertaken at least every two years.
2. Proven and Probable Contingent Resources are based on a Group reserves report produced 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 and North Africa transfer from contingent resources to commercial reserves is in relation to the completion of a Gas Sales Agreement in Ghana for the TEN development.
4. The South and East Africa additions and revisions to contingent resources relates to exploration and appraisal activity in Kenya and Uganda.
5. The Europe, South America and Asia acquisitions relate to the acquisition of Spring Energy in Norway, which completed in January 2013.
6. The Europe, South America and Asia additions to contingent resources relates to the Wisting discovery in Norway.
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 349.1 mmboe at 31 December 2013 (31 December 2012: 349.6 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 Oil plc is a leading independent oil and gas, exploration and production group and is quoted on the London and Irish Stock Exchanges (symbol: TLW.L). The Group has interests in some 150 production and exploration licences in 24 countries and focuses on four core areas: Africa, Europe, South Asia and South America. For further information please consult the Group's website: www.tullowoil.com
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 (and simultaneous video webcast)
To access the call please dial the appropriate number below shortly before the call and ask for the Tullow Oil plc conference call. A replay facility will be available from approximately noon on 12 February until 19 February. The telephone numbers and access codes are:
|
Live event |
Replay facility available from Noon |
||
|
UK Participants |
020 3427 1911 |
UK Participants |
020 3427 0598 |
|
Irish Participants |
01 486 0916 |
Irish Participants |
01 486 0902 |
|
|
|
Access Code |
9265229# |
To join the live video webcast, or play the on-demand version which will be available from noon on 12 February, you will need to have either Real Player or Windows Media Player installed on your computer.
11.00 GMT - Press Conference Call
To access the call please dial the appropriate number below shortly before the call and use the access code. The telephone numbers and access code are:
|
UK Toll Free |
0808 109 0700 |
International Participants |
+44 (0) 20 3003 2666 |
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|
UK Local Call |
020 3003 2666 |
USA Toll Free |
+1 866 966 5335 |
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|
Irish Toll Free |
1 800 930 488 |
Access code |
8465357 |
|
15:00 GMT - US 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.
|
Live Event |
|
||
|
Domestic Toll Free |
+1 877 280 1254 |
Access code |
3689299 |
|
Toll |
+1 646 254 3366 |
|
|
FOR FURTHER INFORMATION CONTACT:
|
Tullow Oil plc (London) (+44 20 3249 9000) Chris Perry (Investor Relations) James Arnold (Investor Relations) George Cazenove (Media Relations) |
Citigate Dewe Rogerson (London) (+44 207 638 9571) Martin Jackson Shabnam Bashir |
Murray Consultants (Dublin) (+353 1 498 0300) Ed Micheau Joe Heron |
Follow Tullow on:
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Facebook: www.facebook.com/TullowOilplc LinkedIn: www.linkedin.com/company/Tullow-Oil
IR App: bit.ly/TullowApp Website: www.tullowoil.com
This information is provided by RNS
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