2010 Full Year Results
Jubilee field First Oil delivered
Major oil discoveries in Ghana and Sierra Leone
Uganda transactions nearing final Government approval
9 March 2011 - Tullow Oil plc (Tullow), the independent oil and gas exploration and production group, announces its results for the year ended 31 December 2010.
Results summary
In 2010, Tullow demonstrated continued exploration and appraisal success and delivered first production from the Jubilee development in record time. The reported financial results for 2010 are materially ahead of 2009 and broadly in line with the market's expectations. The successful equity placing in 2010, coupled with the planned Uganda farm-down, and the increased cash flow from Ghana, will ensure that the Group remains well funded to execute its exploration-led strategy and continue to grow the business.
|
|
2010 |
2009 |
Change |
|
Sales revenue ($m) |
1,090 |
916 |
+19% |
|
Operating profit ($m) |
235 |
151 |
+56% |
|
Profit before tax ($m) |
152 |
33 |
+361% |
|
Profit after tax ($m) |
73 |
31 |
+137% |
|
Basic earnings per share (cents) |
6.1 |
3.2 |
+90% |
|
Final dividend per share (pence) |
4.0 |
4.0 |
0% |
|
Operating cash flow before working capital ($m) |
762 |
588 |
+30% |
|
Production (boepd, working interest basis) |
58,100 |
58,300 |
0% |
|
Realised oil price ($ per bbl) |
78.0 |
60.0 |
+30% |
|
Realised gas price (pence per therm) |
42.0 |
39.3 |
+7% |
Key highlights
· Jubilee production offshore Ghana achieved in November, some 40 months after discovery.
· Working interest production averaged 58,100 bopd; three year reserves replacement ratio of 250%.
· Exceptional E&A performance: 83% success ratio in 2010; seven successes year-to-date in 2011.
· Important Equatorial Atlantic discoveries: Enyenra & Teak offshore Ghana; Mercury offshore Sierra Leone.
· A 50% operated interest in six licences covering 100,000 sq km was secured in Kenya and Ethiopia.
· A 40-well E&A campaign including basin-opening wells is planned for 2011.
· Financial results up on 2009 and will be transformed in 2011 by Jubilee production.
· Balance sheet strengthened during the year through additional debt and equity totalling $2.35 billion.
Commenting today, Aidan Heavey, Chief Executive, said:
"With First Oil in Ghana and an excellent exploration and appraisal success rate, 2010 was undoubtedly a transformational year for Tullow. This contrasted with slower progress on our agreed farm-down in Uganda. However, good progress has recently been made towards gaining Government approval and establishing a strong fiscal and legal framework for the successful development of the basin. 2011 has started very well with production increasing from Jubilee and continued exploration and appraisal success. With a diverse 40-well E&A campaign planned for 2011, we look forward to another year of significant progress."
Presentation in London, Webcast and Conference Calls: Details are available on page 26 of this announcement and in the Results Centre on the Group's website at www.tullowoil.com.
2010 Full year results overview
Making history in Ghana
Tullow's highlight of 2010 was achieving First Oil from the Jubilee field in Ghana with formal celebrations held on 15 December 2010. We are now a deepwater development operator having delivered production on schedule, within 5% of the original budget. The facilities uptime has been exceptional at over 90% and we will continue to ramp-up production over the next few months.
Establishing a major new partnership in Uganda
In 2010, we took the opportunity to pre-empt a deal agreed by our partner in Uganda when it decided to sell its stake. In parallel we agreed a farm-down of two thirds of our interests to CNOOC and Total to create a like-minded, aligned partnership. However, a transaction of this size and importance takes time to negotiate and finalise particularly in an election year. Large scale oil development is new to Uganda and it is important to get the appropriate fiscal and legal framework in place for the long-term benefit of all parties. Tullow and the Government of Uganda are currently engaged in finalising a Memorandum of Understanding (MOU). The signing of this MOU will be the first step on an exciting journey to successfully develop Uganda as a significant oil-producing country.
Strong financial performance
2010 revenue benefited from higher oil prices offset by slightly lower sales volumes. First Oil in Ghana was a major milestone for the Group and will transform Tullow's financial profile in 2011. During the year we raised $1.45 billion from an equity placing and took the opportunity, based on good operational performance and a strengthening external environment, to increase our debt capacity. Finalisation of the Ugandan farm-down will secure significant funding for the medium-term and ensure we are well capitalised for an ambitious growth programme.
Exceptional exploration and appraisal success
2010 was another year of exceptional exploration and appraisal success. We achieved an 83% success ratio; finding hydrocarbons in 24 out of 29 E&A wells during the year. Highlights in Ghana included the discovery of Enyenra (formerly Owo), subsequently proved to be a major oil field, and the successful appraisal of the Tweneboa field; the Mercury-1 discovery well in Sierra Leone extended the Jubilee play more than 1,000 km west of Ghana; and a 10 out of 10 success ratio in Uganda. We are now seeking to replicate our Ugandan success elsewhere in the East African Rift Basins and have acquired six contiguous licences in Kenya and Ethiopia.
Strong development and production performance
The performance of our global assets in 2010 was very strong with production exceeding our guidance at 58,100 boepd, a three year reserves replacement ratio of 250% and 500mmboe of Contingent Resources added. The contribution from the Jubilee field will considerably increase group production in 2011, expected to average between 86,000 and 92,000 boepd. A pipeline of development projects which continues to be replenished from the exceptional results of our exploration programmes will build our production profile in the medium-term.
Environment, Health and Safety
The management of Environment, Health and Safety remains a core priority and, during 2010, the Tullow Team delivered excellent EHS performance across the organisation while progressing a number of key EHS initiatives. Of particular note was the strong EHS performance on the Jubilee Project which delivered excellent EHS results during the course of a diverse and challenging project with many complex and potentially hazardous operations.
Dividend policy aligned with growth opportunities
The Board feels it is appropriate to continue to observe a stable dividend policy for 2010. The final dividend proposed is 4.0p per share, which brings the total payout for 2010 to 6.0p per share. The dividend will be paid on 20 May 2011 to shareholders on the register on 15 April 2011. The Annual General Meeting will be held on 12 May 2011 in Haberdashers Hall in London and the Dublin Shareholders' Meeting will be held on 2 June 2011 in the Royal College of Physicians of Ireland in Dublin.
Another exciting year in prospect
2011 looks to be an equally exciting year with finalisation of the farm-down in Uganda and moving forward on basin development with our new partners, a major exploration campaign to open up several potential new basins in both Africa and South America and appraisal programmes designed to enable the sanctioning of major new oil and gas development projects.
Operations Review
AFRICA
2010 Results highlights
|
Total production 39,000 boepd |
Total reserves and resources 1,326 mmboe |
Sales revenue $850 million |
2010 investment $2,521 million |
· 2010 average working interest production in line with forecast at 39,000 boepd.
· 82% exploration and appraisal success rate.
· First Oil production from the Jubilee field commenced in November 2010.
· Successful exploration and appraisal of the Enyenra (formerly Owo) and Tweneboa fields.
· Mercury-1 exploration well confirms Jubilee play extends 1,000 km from Ghana to Sierra Leone.
· Extensive West Cape Three Points exploration programme in the first half of 2011.
· Uganda transaction nearing final government approval.
· Rig secured for Equatorial Atlantic drilling campaign including Montserrado-1 well in Liberia.
Ghana and West African Equatorial Atlantic
In the Equatorial Atlantic region offshore West Africa Tullow has interests in 10 blocks across four countries: Sierra Leone, Liberia, Côte d'Ivoire and Ghana. 2010 has been a period of strong delivery for Tullow's operations in Ghana, culminating in the delivery of First Oil from the Jubilee field in November. Exploration and appraisal success continued throughout the year in Ghana and Sierra Leone where significant new fields have been discovered. The Group's extensive 2011 drilling programme has the potential to transform this area into one of Africa's most substantial oil producing regions.
First Oil from Jubilee field Phase 1 development
Production from the Phase 1 development of the Jubilee field commenced on 28 November and was inaugurated by the President of Ghana on 15 December 2010. This milestone was achieved around 40 months after discovery of the field, with top quartile safety performance and the final cost is expected to be within 5% of the original $3.1 billion budget. The project has set a significant new global benchmark for the delivery of major deepwater developments.
Gross production of over 69,000 bopd has been achieved from five wells and full production capacity of 120,000 bopd is expected to be reached in the next five months as the remaining four production wells are completed and brought on line. On 5 January 2011, the first lifting of Jubilee crude oil, a 650,000 barrel Tullow cargo, was successfully completed and three liftings have now been completed to date. Once plateau production is reached an average of three offtakes are expected each month. Water injection to two wells is currently around 110,000 bwpd and a further four water injection wells will be completed during 2011 to maintain plateau oil production levels. Gas injection will commence in March to a single well, the second injection well is expected to be completed in the third quarter of 2011.
Further phases of Jubilee development
Planning work for Phase 1a of the Jubilee development, to comprise between five and eight further wells, commenced in the fourth quarter of 2010. This development will help maintain field production at plateau levels and develop further reserves. It is anticipated that the investment decision will be made in the third quarter of 2011 following analysis of reservoir performance and submission of plans to the Government of Ghana. Sub-surface planning work is well advanced and has already identified the additional well locations. A deepwater rig to execute the programme starting early in 2012 is currently being tendered.
The Operator of the West Cape Three Points (WCTP) licence submitted a Declaration of Commerciality for the Mahogany East (previously known as 'Southeast Jubilee') area in September 2010. The Plan of Development for Mahogany East is currently under discussion with the Government of Ghana. The development of the Mahogany East reservoirs, which are extensive but generally thinner than in the main Jubilee reservoirs, is currently planned to consist of a four to six well tie-back to the existing Jubilee subsea infrastructure when capacity is available. However, an accelerated development as part of an integrated project with other WCTP discoveries, may be considered depending upon exploration and appraisal success in the WCTP licence.
Enyenra (formerly Owo) and Tweneboa
In February 2010, the first appraisal well on the Tweneboa field, Tweneboa-2, in the Deepwater Tano licence offshore Ghana intersected a significant combined hydrocarbon column. Combined with the Tweneboa-1 discovery in 2009, Tweneboa was established as a major gas-condensate and oil field.
In July 2010, the Owo-1 and Owo-1 sidetrack wells continued the success of Tullow's West African Equatorial Atlantic drilling campaign. The wells intersected a total of 69 metres of net oil pay in a substantial gross oil column of 200 metres and established Enyenra (formerly Owo) as a major new oil field in its own right. The wells also intersected 13 metres of net condensate pay and 6 metres of net gas pay below the Enyenra oil field.
A campaign of appraisal wells and flow tests has now commenced across both the Enyenra and Tweneboa fields. The programme is designed to determine reservoir extent and connectivity and to provide rock and fluid data. The first well in this campaign was Tweneboa-3, drilled in December 2010, which confirmed producible gas-condensate at this location. In February 2011, Enyenra-2A was drilled and encountered oil in excellent quality reservoirs in communication with the original Owo-1 discovery well located 7km up-dip. The result confirms Enyenra as a major light oil discovery. The activity programme this year will lead to a Declaration of Commerciality for the Enyenra and Tweneboa areas being submitted to the Government of Ghana later in 2011. The expected schedule of wells includes Tweneboa-4, Tweneboa DST, Enyenra-3A, Enyenra-DST and Enyenra-4A.
Development studies for both fields are focused on optimising the recovery of the light oil discovered at Enyenra and maximising both liquid and gas recovery from the Tweneboa field. Conceptual developments include the use of a large FPSO with liquid rates in the range of 75,000 to 125,000 barrels oil per day. Water and gas is expected to be injected into the reservoirs to optimise both oil and condensate recovery levels. Gas export infrastructure to shore will also be put in place to satisfy the growing demand in Ghana. A Plan of Development will be prepared for submission in the first quarter of 2012 and, pending approvals and a timely sanction of the project, first production would be anticipated before the end of 2014.
Further West African Equatorial Atlantic exploration and appraisal activity
In 2010, Tullow has continued to progress the Jubilee play in the West African Equatorial Atlantic region including Côte d'Ivoire, Sierra Leone and Liberia. In addition to the successes with Tweneboa and Enyenra, Tullow has also made other important discoveries through a campaign of wells in Ghana and Sierra Leone.
Following the interpretation of 10,000 sq km of 3D data over Tullow's acreage in Sierra Leone and Liberia, several Jubilee-type prospects have been identified. The Mercury-1 well, offshore Sierra Leone was drilled in November and encountered 35 metres of excellent quality oil pay in the primary objective and a further six metres oil pay in a shallower secondary objective. These accumulations are currently being assessed with a view to drilling a potential appraisal well during 2011. In Liberia, the high potential Montserrado (formerly Cobalt) prospect is now scheduled for drilling in the third quarter of 2011 with the operator having recently secured the Transocean Discoverer Spirit drillship for a campaign in the region.
In Ghana, another important discovery was made in February 2011 when the Teak-1 well in the West Cape Three Points licence found hydrocarbons in all five prospective horizons. An extensive multi-well exploration campaign is continuing in the licence before the exploration period expires in mid-2011. The current well, Teak-2, is being drilled into an adjacent fault block to that intersected by Teak-1 and a result is expected later in March.
The Dahoma-1 exploration well in the West Cape Three Points licence and the Onyina-1 exploration well in the Deepwater Tano licence were drilled in April and October 2010 respectively and were unsuccessful. The results from these wells have helped us to calibrate the basin and the Onyina-1 result also supported the required 25% relinquishment of non-prospective acreage in January 2011.
In Côte d'Ivoire, advanced processing of the large 3D surveys acquired in blocks CI-103 and CI-105 in 2010 have been completed and the interpretation of these datasets has revealed a number of potential targets for the two wells scheduled for the second half of 2011. Interpretation of the reprocessed 3D seismic data over CI-102 revealed limited prospectivity so Tullow withdrew from this Joint Venture at the end of December 2010. Until the current political uncertainty in Côte d'Ivoire is resolved our exploration licences have been placed in Force Majeure however there has been no impact on production.
Production and Development in Côte d'Ivoire
Net production from the East and West Espoir fields was in line with expectations averaging 3,850 boepd (2009: 5,000 boepd). The decrease in production from 2009 was due to planned shutdowns to facilitate the upgrade to the FPSO and because of the natural decline of the fields. The upgrade to the processing facilities was completed successfully in the middle of the year. An investigation into the feasibility of adding extra well slots to both platforms is at an advanced stage and infill drilling from both the East and West wellhead towers is anticipated in 2012 or 2013.
Ghana Listing
In November 2010, Tullow announced that in order to create a more accessible opportunity for Ghanaian individuals and institutions to invest in the future of their oil industry through Tullow, the Group was planning a secondary listing on the Ghana Stock Exchange. Originally planned for December, the Listing has been postponed due to the requirement over that period to focus on First Oil from the Jubilee field and year-end corporate planning. The Listing is now planned to go ahead as soon as practicable after our year-end results and the issue of our Annual Report.
Uganda
Tullow has had interests in the Lake Albert Rift basin in Uganda since 2004 when it acquired Energy Africa. Since then, the Group has drilled approximately 40 wells with all but one encountering hydrocarbons. To date, one billion barrels of P50 resources have been discovered and 1.5 billion barrels of P50 prospective resources remain. Over this period, Tullow has acquired additional equity by purchasing Hardman Resources in 2007 and Heritage Oil's interests in 2010. Tullow is now finalising plans to farm-down a one third interest to both CNOOC and Total to align interests across the basin and accelerate basin-wide development. Ultimately, Tullow expects the basin to be producing in excess of 200,000 bopd.
Purchase of Heritage interests and farm-down to CNOOC and Total
On 17 January 2010, Tullow exercised its right to pre-empt Heritage Oil and Gas Limited's ("Heritage") sale of its interests in Uganda to a third party. This resulted in Tullow acquiring a 50% interest in Exploration Areas 1 and 3A (EA 1 and EA 3A) for $1.45 billion on 26 July 2010. $1.05 billion was paid directly to Heritage, $121 million was deposited with the Ugandan Revenue Authority and $283 million was put into Escrow pending resolution of a dispute between the Government of Uganda and Heritage over payment of capital gains tax. Conditional approval from the Government of Uganda has been received for the purchase and a subsequent farm-down to CNOOC and Total, however the Government of Uganda has stated that final approval for both transactions will not be received until a basis for resolution of the Heritage capital gains tax dispute has been achieved.
Tullow and the Government of Uganda have been engaged in negotiations aimed at resolving this issue. A legally binding Memorandum of Understanding has been drafted to pave the way for the farm-down and development of all assets within the Lake Albert Rift basin by Tullow, Total and CNOOC. Although good progress has been made recently, the elections in Uganda, on 18 February 2011, have impacted the timing of a final agreement.
Exploration and Appraisal
The successful exploration and appraisal campaign in Uganda continued in 2010 with ten wells drilled, all of which encountered hydrocarbons. This led to the estimated P50 resource base for Uganda being revised upwards from 800 million barrels at the beginning of the year to 1 billion barrels at year-end.
The 2010 Ugandan drilling campaign commenced in January with the Kasamene appraisal programme where the OGEC-750 rig drilled three wells: Kasamene-2, 3 and 3A. Positive results from these wells give strong support to the development of this field.
In May, the Nzizi-3 appraisal well was drilled, establishing reservoir connectivity with the Nzizi-2 well and proving the well's viability as a future gas producer for the integrated power project. In June, the OGEC-600 rig arrived in EA 1 and a comprehensive two-rig exploration and appraisal campaign commenced across EA 1 and EA 2. In total, a further six successful appraisal wells were drilled and the Mpyo-1 exploration well made a material discovery.
Good progress is being made in defining numerous new exploration and appraisal drilling targets for the drill-out campaign in 2011 which will accelerate once the transaction with CNOOC and Total is approved. Following a short drilling hiatus, one rig is now operational in EA 2, a second rig is on standby and further rigs are being contracted. In 2011, two successful appraisal wells have been drilled; Nsoga-2 and Kigogole-6. Ngege-2 is currently drilling.
During the year, three 2D seismic surveys have been completed in the Butiaba Area of the basin resulting in a total of 767 line kilometres of good quality data. These surveys have firmed up a series of large prospects and have assisted in the placement of wells to finalise the appraisal of a number of discoveries. In addition, a new 3D survey is ongoing and will run through to the fourth quarter of 2011.
Lake Albert Rift Basin Development
During the year, good progress has been made on the first phase of the EA 2 development. An Extended Well Testing programme is planned to start in the second quarter of 2011 with test crude to be sold to a domestic industrial user. Field Development Plans have also been submitted to the Government of Uganda for the Waraga, Mputa and Nzizi discoveries as required at the end of the appraisal period. It is anticipated that the Kasamene Field Development Plan will be submitted in the second quarter of 2011.
The Front-End Engineering and Design (FEED) phase for the Nzizi and Kasamene development projects has been completed and work is underway to progress these developments to sanction. The Nzizi gas field development will deliver gas to a new power plant in the Lake Albert area. First gas from Nzizi is subject to gas sales agreements and the readiness of the new Lake Albert Power Plant, which is expected in 2012. The timing of the Kasamene development, based on a production facility with an initial capacity of up to 10,000 bopd, is under review to determine how this development will be best integrated into the overall Lake Albert development plan.
Following completion of the farm-down to CNOOC and Total, the partners will work closely with the Government on a development plan aimed at delivering in excess of 200,000 bopd which will include refinery options to supply petroleum products for the region as well as pipeline export routes to international markets. The target for achieving significant oil production from this phase of the development is currently 2015.
Focus on Capacity Building in Uganda
Tullow has facilitated considerable growth in the petroleum sector in Uganda. Tullow's Kampala team has grown with the focus firmly on maximising recruitment of Ugandan nationals in order to ensure the long-term sustainability of the project and of the industry as a whole. Over 80% of the team working in Kampala, Cape Town and London are Ugandans and competencies continue to build through on-the-job experience and formal training.
Tullow has also stepped-up its programme this year to build capacity in the supply sector by encouraging local businesses to partner with international specialists. A Logistics Suppliers Open Day, held in January 2011, attracted over 500 service providers and provided a forum for debate on the way in which access to the industry by local entrepreneurs can be supported. Further events planned in 2011 will expand these efforts to every sector of the industry.
Kenya and Ethiopia
In the second half of 2010, Tullow farmed into blocks 10A, 10BA, 10BB, 12A & 13T in Kenya and the South Omo block in Ethiopia. The deal was completed in early 2011 and Tullow now operates all six blocks covering an area of around 100,000 sq km. The acreage covers the Turkana Rift Basin which is similar in character to the Lake Albert Rift Basin and also a south-east extension of the geologically older Sudan rift basins trend. A 600 km 2D seismic survey has already been completed in Block 10BB and an 800 km 2D seismic survey covering Block 10A is in progress. A Full Tensor Gravity Gradiometry (FTG) survey will commence in the first quarter of 2011 followed by multiple 2D seismic programmes across all the blocks. Two wildcat exploration wells are planned for late 2011. In March 2011, Tullow also farmed in to Block L8 offshore Kenya, subject to certain approvals. On completion, Tullow will gain a 10% interest and an option to increase by a further 5% in this highly prospective acreage.
Congo (DRC)
In 2006, Tullow was awarded two Congo (DRC) licences adjacent to its Ugandan acreage on Lake Albert through a transparent bidding process. In June 2010, the Government awarded the licences via Presidential decree to two British Virgin Islands-registered companies. Tullow commenced legal proceedings to challenge that award and obtained an interim injunction preventing those companies carrying out any work until Tullow's rights had been legally determined. In subsequent proceedings, it became clear that Tullow's rights were not likely to be upheld so long as the DRC Government maintained its position that it had the right to ignore or revoke the earlier award to Tullow. Given the expense of further proceedings and the difficulty in enforcing any award against the DRC even in the event of success, the Board has regretfully taken the decision to discontinue the legal proceedings and withdraw from the DRC.
Equatorial Guinea
Net production from the Ceiba field was ahead of expectations, averaging 3,950 bopd in 2010, due to the optimised use of the subsea pumps. Net production from the Okume Complex averaged 11,750 bopd in 2010 as new production wells kept the field on plateau whilst uptime and throughput was enhanced leading to slightly higher average production than 2009.
During the year, two drilling rigs completed separate development drilling campaigns on the deep water and shallow water sections of the Okume Complex, with eight new wells drilled ahead of schedule. In the third quarter of 2010, a time lapse 3-D (4-D) seismic survey was acquired over the Ceiba field and the deep water part of the Okume Complex which is expected to assist with selecting future infill well locations.
Gabon
Net production in Gabon averaged 12,850 bopd from 13 fields during 2010, an increase of 7% over the previous year. The Niungo, Echira and Tchatamba fields all performed well and work is ongoing to further enhance production. Tullow and its partners drilled 53 wells in Gabon during 2010, including a series of very successful exploratory appraisal wells and in 2011 the level of drilling activity will be sustained with over 50 wells planned. Further seismic evaluation is also planned to support the 2012 drilling campaign.
In February 2010 the Maroc-Nord-1 exploration well discovered 50 metres of net oil pay in an emerging under-explored stratigraphic trap play which is currently being appraised and will be brought into the Onal area development in 2011. The Noix de Coco-1 exploration well was drilled in April 2010 on the Tullow operated Azobe Exploration Block but the well encountered non-commercial levels of hydrocarbons and following a full review the licence was relinquished. Tullow entered an agreement with Perenco to farm-in to the offshore Arouwe Exploration block for a 35% interest. The Falcon North-1 exploration well was drilled in December 2010 and encountered non-commercial volumes of hydrocarbon, however material prospectivity remains in the licence for the new exploration campaign ahead.
Congo (Brazzaville)
Net production from the M'Boundi field averaged 4,000 bopd in 2010. A delay in the ramp up of water injection has resulted in a decline in average reservoir pressure and hence a decline in well productivity. Infill drilling however continued throughout the year, with the delivery of 30 new wells. Hydraulic fracturing has been successful in improving productivity of a number of wells and downhole pumps are being installed in producer wells to deal with the rising watercut.
Mauritania and Senegal
In Mauritania, the Chinguetti field production rate declined in line with expectations, averaging 1,500 boepd net to Tullow. Towards the end of 2010, a programme of well and flowline optimisation resulted in a reduction in the rate of decline and the potential for further optimisation in 2011 and beyond is being evaluated.
The Cormoran-1 exploration well, located in offshore Block 7, completed drilling in January 2011. The objective of the well was to appraise the Pelican gas discovery and to target two underlying exploration prospects; Cormoran and Petronia. The well successfully intersected gas in both Pelican and Cormoran. The Pelican interval was flow tested at a stabilised flow rate of approximately 23 mmscfd. In the deeper Petronia target, the well encountered rich gas in Turonian-age reservoirs. However, drilling had to be stopped for operational reasons soon after penetrating the trap.
The result from the Gharabi-1 well, in Mauritania Block 6, was announced in February 2011. The well, which was selected by the operator to meet licence commitments, intersected poorly developed water-bearing reservoirs. The result has no impact on Tullow's future plans for its Mauritanian or other West African acreage. In 2011, Tullow will continue defining prospects throughout the Mauritania-Senegal basin with further planned exploration activity in 2011 and 2012.
Tanzania
In April 2010, the Likonde-1 exploration well in the Lindi Block was drilled to a depth of 3,647 metres testing Tertiary and Cretaceous sequences. Significant amounts of residual oil and gas were found, however no commercial quantities would have been producible from the well. Tullow's strategy of exploring for oil in the Ruvuma Basin continued throughout 2010 with the entire seismic dataset being reprocessed to better image potential objectives in the Lindi and Mtwara blocks with a second commitment well planned later in 2011.
Madagascar
Due to the political instability in Madagascar during 2010, Tullow elected to delay the 2D seismic acquisition programme until 2011. However, Tullow completed an extensive geological field study programme to better define areas of high prospectivity targeting a light oil play in the Permo-Triassic Karoo interval. Oil sampled from natural seepages along the faults which bound the prospects, is being analysed. Tullow has also completed a reprocessing project of the historical seismic data which has resulted in a large improvement of the dataset. The assignment of Madagascar Oil's 50% equity in Block 3109 to Tullow completed by the end of 2010 and a well in Block 3111 is planned for 2012.
Namibia
Terms of a new Kudu Petroleum Agreement have been agreed with the Ministry of Mines and Energy and a revised 25 year Production Licence is expected to be issued in the first quarter of 2011. Tullow, on behalf of the Production Licence partners NAMCOR, Gazprom International and Itochu, has completed the concept selection study for the offshore development of the Kudu gas field and is now entering into technical integration discussions with NamPower to optimise design concepts of both the offshore development and the Kudu Power Station. In parallel, discussions are underway with NamPower on the gas supply agreements and for the 800MW power station and, subject to progress, Tullow expects to initiate detailed design of the offshore development in the second quarter of 2011.
Angola
On 30 November 2010, Tullow elected to withdraw from the Block 1/06 licence in Angola on commercial grounds. The first exploration period has terminated and in-country operations are due to complete by mid-year.
REST OF THE WORLD
2010 Results highlights
|
Total production 19,100 boepd |
Total reserves and resources 61 mmboe |
Sales revenue $239 million |
2009 investment $111 million |
· 2010 average working interest production ahead of forecast at 19,100 boepd.
· UK production ahead of expectation due to strong CMS Area performance.
· Successful Shekhan-1 exploration well in Pakistan commenced long-term production test in December.
· Rigs secured for South American basin-opening exploration campaigns which commence in March 2011.
The Group's Rest of the World assets form an important part of Tullow's business. Gas production in the UK and South Asia contribute important revenues while low risk exploration prospects and development opportunities in Europe combine with high-impact potential in South America and South Asia to provide an exciting exploration portfolio.
Europe
Tullow's well established producing assets lie in the Southern Gas Basin offshore UK and are centred around two gas producing hubs, associated fields and infrastructure. Tullow also has a portfolio of mostly operated exploration blocks offshore the Netherlands where it is looking to capitalise on the exploration success it has experienced in adjacent UK blocks in recent years.
UK
Production in 2010 from the UK assets exceeded expectations averaging 13,300 boepd (2009: 14,450 boepd). In the Thames Area, production was in line with expectations supported by a full year of combined flow from the Tullow-operated Horne, Wren and Wissey fields. In the CMS Area, higher rates were achieved as a result of the successful implementation of a detailed well performance improvement programme on the Ketch field, the earlier than forecast tie-in of the Ketch-8z well, the successful in-fill drilling on the Boulton field and various well interventions across the portfolio.
2010 marked a busy year of operational activity in the CMS Area. The Boulton B5 infill well was drilled and brought on stream; successful well interventions took place on the Kelvin field; and a development concept and export route was agreed for the Harrison development in block 44/19b with gas production anticipated to commence in the second half of 2012. In addition, the Ketch-8z well was brought on production ahead of schedule in August 2010 and the Ketch-10 well is now planned for 2011. Following a farm-in agreement with ConocoPhillips in January 2011, Tullow increased its equity in the Cameron prospect located south of the Harrison discovery in 44/19b. The exploration well will be operated by Tullow and is expected to commence drilling in April 2011.
In the Thames Area, in December 2010, Tullow acquired a 100% interest in Block 49/29d and in February 2011 agreed a deal for a further 65% in 49/30b and 49/29e. These blocks are considered to have material gas prospectivity. Tullow intends to drill a well in the first half of 2011 and in the event of a success, the well will be tied back to Thames, deferring field abandonment and generating additional revenues.
Netherlands
Building on the successful exploitation of the Carboniferous play in the UK CMS Area, Tullow has been building an extensive operated position in the adjacent underexplored Carboniferous province of the Dutch offshore sector and now has interests in 10 blocks. In early 2010, Tullow and its partners participated in two major 3D seismic reprocessing programmes and the results led to the acquisition of a significant 1,600 sq km high specification 3D seismic survey during the summer. The data will be used in 2011 to mature the prospect inventory for a potential drilling campaign in 2012 and 2013.
Tullow participated with 4.3% working interest in the drilling of the non-operated Muscovite prospect, which extends into Block E13b and sits immediately south of the Tullow operated acreage in the E blocks. The purpose of participating was to calibrate geological risk factors in the area at a low cost to Tullow. The well found only residual gas and was plugged and abandoned. Valuable insights from this well will now be applied to Tullow's Carboniferous exploration acreage in the Netherlands.
Portugal
Following the completion of work programme commitments in the frontier, deep-water Alentejo Basin and a detailed evaluation of the full subsurface dataset, Tullow took the decision not to pursue this opportunity any further and its operated interest in the acreage was transferred to other parties within the Joint Venture.
South Asia
The demand for energy in Asian economies remains strong. This region offers Tullow excellent growth potential through exploration, particularly in Pakistan, where the Group has a significant non-operated position.
Bangladesh
Production from the Bangora field in 2010 was marginally ahead of expectations averaging 5,650 boepd (2009: 5,050 boepd). In March, the installation of a Hydrocarbon Dew Point unit to improve the gas sales specification was completed, increasing condensate yield from 140 to 400 barrels per day whilst delivering on-spec gas at a maximum permissible rate of 120 mmscfd.
Tullow has also undertaken reprocessing and reinterpretation work on the southerly extension of the Bangora structure where there is significant potential for satellite traps which could be tied into the Bangora facilities. The viability of exploration drilling and life-of-field optimisation programmes will be considered during 2011.
The offshore exploration block SS-08-05 is due to be awarded to Tullow following competitive bidding. However, the award is being delayed until a maritime border dispute between India and Bangladesh is resolved.
Pakistan
In July 2010, the Shekhan-1 exploration well penetrated a total net gas pay of 45 metres in sandstone reservoirs over a gross interval of 93 metres. A pipeline and gas processing and production facilities were then installed so that an extended well test could be performed with gas sold into the Pakistan gas grid. This was achieved in record time allowing sales of around 15 mmscfd of gas plus 100 barrels per day of condensate to commence in December 2010. The test will continue into 2011 and will assist in deciding upon forward programmes for the Shekhan area.
In the first half of 2011, a second exploration well, Jabbi-1, will be drilled 20 km to the west, along the same geological structural trend as Shekhan. If successful, Jabbi-1 gas could be quickly tied-in to the Shekhan production facilities. Tullow has equity in several other high-impact exploration blocks in Pakistan and is working with the local authorities to enable activity in these blocks to recommence as soon as local security conditions permit.
The Sara-Suri field continued producing gas at very low levels until the fourth quarter of 2010 when it was shut-in pending approval from the Government for the sale of the asset.
South America
Tullow has deep water interests in the Guyane Martime, Block 47 and Georgetown licences in French Guiana, Suriname and Guyana respectively. The Guyana Basin of South America has long been recognised as the potential twin to the West Africa Basins where Tullow has had significant exploration success over the past three years.
French Guiana
Seismic acquisition on the Eastern Slope part of the Guyane Maritime permit in French Guiana, which started in September 2009, was completed in early 2010 with a total of 2,500 sqkm 3D and 180 km 2D seismic acquired. Interpretation of this data during 2010 confirmed the presence of the major Late Cretaceous turbidite system previously identified on the existing regional 2D seismic in 2008. A portfolio of high risk but high-impact deepwater prospects analogous to the Jubilee field in Ghana, have been interpreted and the first well on the Zaedyus prospect commenced drilling with the ENSCO 8503 in early March 2011. The well has the potential to open up a major new oil province in French Guiana with a significant number of further prospects and leads already identified. Tullow is operator with 27.5% equity in the licence.
Guyana
Tullow has a 30% interest in the Georgetown Block in Guyana where, following analysis of a 3D seismic survey acquired and processed during 2008-2009, a number of prospects were identified in 2010. Jaguar, a Late Cretaceous turbidite fan prospect, will be the first well to be drilled in the licence. The Atwood Beacon jack-up rig has been contracted and the well is expected to commence drilling in the third quarter of 2011.
Suriname
In September 2010, Tullow signed a Production Sharing Contract for the deepwater Block 47. While previous industry focus in this area had been on an Early Cretaceous tilted fault block play, Tullow's focus is on the Cretaceous turbidite fan play analogous to Tullow's West African discoveries. Planning for a large 3D seismic programme (2,000 sq km) is currently ongoing with an anticipated commencement date of late 2011/early 2012. Onshore activity in Suriname is focused on continued preparation for the five well Coronie and two well Uitkijk drilling programmes in 2011.
Finance review
Our financial strategy is to ensure we have a strong balance sheet and the flexibility to support the Group's significant exploration-led growth strategy. In 2011 we expect to spend some $1.5 billion on high-impact exploration, further significant appraisal and development programmes in Ghana and Uganda and the remainder will be allocated across the rest of the business.
In 2010, Tullow strengthened its balance sheet with $0.9 billion of additional debt facilities and $1.45 billion raised from an equity placing in January. This finance, the expected Uganda farm-down proceeds and the revenues from Jubilee production, will ensure we have a very secure funding base for the next phase of our growth.
Looking forward, our focus will remain on high-impact exploration campaigns funded increasingly by selective developments and portfolio activity. We may also seek to further diversify our sources of debt funding when appropriate.
|
2010 full year results |
2010 |
2009 |
Change |
|
Production (boepd, working interest basis) |
58,100 |
58,300 |
No change |
|
Sales volume (boepd) |
47,400 |
48,350 |
-2% |
|
Realised oil price per bbl (US$) |
78.0 |
60.0 |
+30% |
|
Realised gas price (pence per therm) |
42.0 |
39.3 |
+7% |
|
Cash operating costs per boe (US$)1 |
12.5 |
12.4 |
No change |
|
Operating cash flow before working capital per boe (US$) |
35.9 |
27.6 |
+30% |
|
Net debt ($ million) 2 |
1,943 |
1,144 |
+70% |
|
Interest cover (times)3 |
13.8 |
10.1 |
3.7 times |
|
Gearing (%)4 |
50 |
47 |
3% |
1. Cash operating costs are cost of sales excluding depletion, depreciation and amortisation and under/over lift movements
2. Net debt is cash and cash equivalents less financial liabilities
3. Interest cover is earnings before interest, tax, depreciation and amortisation charges and exploration written off divided by net
finance costs
4. Gearing is net debt divided by net assets
2010 financial results
2010 profit before tax was higher than 2009 primarily because of the following:
- Increased revenues of $174 million from higher oil and gas prices partially offset by lower sales volumes;
- A lower IAS 39 charge of $28 million in 2010 compared with a charge of $60 million in 2009; and
- Partly offset by increased exploration write-offs which were $72 million higher in 2010.
Production, commodity prices and revenue
Working interest production averaged 58,100 boepd, which is in line with 2009 and ahead of budget expectations. Additional production from Ghana, Gabon and successful infill drilling in the UK largely mitigated the impact of the decline in other mature fields. Sales volumes averaged 47,400 boepd, which is a reduction of 2% compared to 2009.
On average, oil prices in 2010 were significantly higher than 2009 levels. Realised oil price after hedging for 2010 was US$78.0/bbl (2009: US$60.0/bbl), an increase of 30%. Tullow's oil production sold at an average discount of 2% to Brent Crude during 2010 (2009: also 2% discount).
UK gas prices in 2010 were broadly in line with 2009 levels. The realised UK gas price after hedging for 2010 was 42.0 pence/therm (2009: 39.3 pence/therm), an increase of 7%.
Higher commodity prices more than offset the lower sales volumes. Overall revenue increased by 19% to $1,089.8 million (2009: $915.9 million).
Operating costs, depreciation and impairments
Underlying cash operating costs, which exclude depletion and amortisation and movements on under/overlift, amounted to $264.3million; $12.47/boe (2009: $264.7 million; $12.43/boe), in line with 2009 levels.
Depreciation, depletion and amortisation charges before impairment charges for the year amounted to $355.9 million; $16.78/boe (2009: $350.7 million; $16.46/boe). The Group has also recognised a further impairment charge of $4.3 million; $0.20/boe (2009: $12.5 million; $0.59/boe) in respect of the Chinguetti field in Mauritania.
At the year-end, the Group was in a net underlift position amounting to 10,100 barrels. The movements during 2010 in the underift and stock position have given rise to a credit of $8.3 million to cost of sales (2009: charge of $10.1 million).
Administrative expenses of $89.6 million (2009: $77.6 million) include an amount of $10.2 million (2009: $18.3 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 2010 with staff numbers increasing by 40% to 935 people.
Exploration cost written-off
Exploration costs written-off were $154.7 million (2009: $82.7 million), in accordance with the Group's 'successful efforts' accounting policy, which requires that all costs associated with unsuccessful exploration are written-off in the income statement. This write-off is principally associated with exploration activities in Gabon, Ghana and Tanzania, new ventures activity and licence relinquishments in Angola and Gabon.
Derivative instruments
Tullow continues to undertake hedging activities as part of the ongoing management of its business risk and to protect the availability of cash flow for reinvestment in capital programmes that are driving business growth.
At 31 December 2010, the Group's derivative instruments had a net negative fair value of $82.4 million (2009: negative $17.6 million), inclusive of deferred premium. The movement in the fair value position has mainly been caused by a strengthening of the underlying commodity prices during the year.
While all of the Group's commodity derivative instruments currently qualify for hedge accounting, a pre tax charge of $27.7 million (2009: charge of $59.8 million) has been recognised in the income statement for 2010. The charge is in relation to the reduction in time value of the Group's commodity derivative instruments, caused by a strengthening of the underlying commodity prices during the year.
Commodity hedging summary
At 1 March 2011 the Group's commodity hedge position to the end of 2013 was as follows:
|
Hedge position |
2011 |
2012 |
2013 |
|
Oil hedges |
|
|
|
|
Volume - bopd |
19,167 |
13,500 |
8,000 |
|
Current price hedge - US$/bbl |
104.1 |
107.9 |
106.6 |
|
Gas hedges |
|
|
|
|
Volume - mmscfd |
43.9 |
19.2 |
8.4 |
|
Current price hedge - p/therm |
55.9 |
61.5 |
64.7 |
Operating profit
Operating profit amounted to $234.6 million (2009: $151.0 million), an increase of 55%. The increase was principally due to higher commodity prices, partly offset by higher exploration costs written-off during 2010 together with higher staff related general and administrative costs.
Gearing, financing costs and interest cover
The net interest charge for the period was $55.0 million (2009: $58.7 million) and reflects the increase in net debt levels during 2010 offset by an increase in interest capitalised during the year on qualifying assets, principally associated with the Jubilee phase 1 development in Ghana.
At 31 December 2010, Tullow had net debt of $1,943 million (2009: $1,144.0 million), with unutilised debt capacity of approximately US$685 million. The Group's gearing was 50% (2009: 47%) and EBITDA interest cover has increased to 13.8 times (2009: 10.3 times).
Taxation
The tax charge of $79.4 million (2009: $1.9 million) relates to the Group's North Sea, Gabon, Equatorial Guinea and Ghanaian activities. After adjusting for exploration costs and profit on disposal of subsidiaries, the Group's underlying effective tax rate is 26% (2009: 3%). The increase in the effective tax rate is mainly due to the fact that losses were generated in fiscal regimes where uncertainty exists as to the recoverability of those losses.
Dividend
Due to the ongoing capital requirements of the Group, and in particular the opportunity to add significantly to shareholder value by continuing to invest in its exceptional portfolio of exploration assets, the Board believes that it remains appropriate to maintain the final dividend at the 2009 level. Consequently, the Board has proposed a final dividend of 4.0 pence per share (2009: 4.0 pence per share). This brings the total payout in respect of 2010 to 6.0 pence per share (2009: 6.0 pence per share). The dividend will be paid on 20 May 2011 to shareholders on the register on 15 April 2011.
Operating cash flow and capital expenditure
Increased commodity prices led to an operating cash flow before working capital movements of $762.0 million (2009: $587.8 million), 30% higher than 2009. This cash flow together with the equity placing proceeds helped facilitate significant 2010 capital investment in exploration and development activities, payment of dividends and the servicing of debt facilities.
Based on the current estimates and work programmes, capital expenditure for 2011 is forecast to be $1.5 billion. Approximately 40% of this investment will be for exploration and appraisal and the remainder will be on development and production activities. Tullow's activities in Ghana and Uganda will comprise approximately 50% of the anticipated 2011 capital outlay.
Balance sheet
Total net assets at 31 December 2010 amounted to $3,868.9 million (31 December 2009: $2,431.0 million), with the increase mainly as a result of the share placing in January 2010 increasing share capital by 9.9%; partly offset by dividends and hedge movements.
Portfolio management
In July 2010, Tullow acquired a 50% interest in Exploration Areas 1 and 3a in the Lake Albert Rift basin from Heritage Oil and Gas Limited. $1.05 billion was paid to Heritage with $121 million deposited with the Ugandan Revenue Authority and $283 million held in Escrow pending a resolution of a dispute between Heritage and the Government of Uganda over payment of capital gains tax.
Tullow and the Government of Uganda are engaged in negotiations aimed at resolving the Heritage capital gains tax issue. A legally binding Memorandum of Understanding is being finalised to pave the way for the farm-down and development of all assets within the Lake Albert rift basin by Tullow, Total and CNOOC.
Long-term funding
In January 2010, Tullow completed a share placing raising net proceeds of $1.45 billion, increasing its share capital by 9.9%. In addition, Tullow increased the commitments of its Reserve Based Lending facility by $500 million to $2.5 billion in May 2010. It also increased its Revolving Corporate facility by $350 million in October 2010 and by a further $50 million in December 2010 to $650 million. The Group now has total debt facilities of $3.15 billion which, when combined with the anticipated Uganda farm-down proceeds, further strengthens the balance sheet in support of Tullow's strategy to:
- Maintain a $500 - $700 million per annum exploration programme and develop longer-term exploration options;
- Accelerate development in Uganda with new partners Total and CNOOC; and
- Continue with Jubilee Phase 1a development following successful first production from the Jubilee field together with fully appraising and developing the Tweneboa and Enyenra discoveries.
Accounting policies
UK listed companies are required to comply with the European regulation to report consolidated statements that conform to International Financial Reporting Standards (IFRS). The Group's significant accounting policies and details of the significant accounting judgements and critical accounting estimates are disclosed within the notes to the financial statements. The Group has not made any material changes to its accounting policies in the year ended 31 December 2010.
Presentational currency
With effect from 1 January 2010 the Group presents its financial statements in US Dollars. The Group has decided it is now appropriate to change the presentational currency from Sterling as the majority of the Group's activities are in Africa where oil revenue and costs are Dollar denominated.
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. The Group seeks to ensure that it has a minimum ongoing capacity of $500 million for a period of at least 12 months to safeguard the Group's ability to continue as a going concern. In addition to the Group's operating cash flows, portfolio management opportunities are reviewed to potentially enhance the financial capacity and flexibility of the Group. The major assumption in current cash flow forecasts is that the receipt of disposal proceeds from the Uganda farm-down, which have been delayed longer than expected, will now be received in the second quarter of 2011. On this basis, 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 very significant financial headroom for the 12 months from the date of approval of the 2010 Annual Report and Accounts. However, in the unlikely event that the Ugandan farm-down process is delayed beyond the second quarter of 2011, the Directors are confident that the Group can manage its financial affairs, including the securing of additional funding, agreement with existing lenders, portfolio management and deferring of non-essential capital expenditure, so as to ensure that sufficient funding remains available for the next twelve months. Therefore, not withstanding the above uncertainties, the Directors consider that the Group has adequate resources to continue in operational existence for the foreseeable future.
Risks to 2011 performance
In common with other companies in the oil and gas sector, Tullow is exposed to commodity price risk, the delivery of major projects and ensuring safe operations in all locations. The Board determines the specific key risks for the company and required mitigation plans and reviews delivery on a regular basis. Risks for 2011 include successful ramp up of the Jubilee oil field, completion of the Uganda farm-down and maintaining an adequate hedging programme.
Financial strategy and outlook
Our financial strategy is to maintain flexibility to support the Group's high-impact exploration campaigns, significant appraisal and development programmes in Ghana and Uganda and effectively allocate capital across the remainder of our business. This financial flexibility has been materially enhanced during 2010 by a successful equity placing and the expansion of our debt facilities to $3.15 billion. The finalisation of the Uganda farm-down in the first half of 2011 will create a very strong platform for future investment.
The outlook for 2011 is very positive for Tullow. The Jubilee field commenced production in November 2010 and is expected to ramp-up to 120,000 bopd (gross) during 2011 and plans for further development with potential new field developments, Enyenra and Tweneboa, in Ghana are under review and we expect a successful completion of the Ugandan farm-down in the near future. Over the next 12 months we plan to drill exploration and appraisal wells in French Guiana, Ghana, Sierra Leone and Uganda which have the potential to add material resources to the Group. Overall, Tullow is well positioned to deliver further growth in shareholder value over the coming years.
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 2010 Annual Report.
Condensed consolidated income statement
Year ended 31 December 2010
|
|
|
Note |
2010 $m |
2009 $m |
|
Sales revenue |
|
|
1,089.8 |
915.9 |
|
Cost of sales |
|
|
(611.4) |
(625.5) |
|
Gross profit |
|
|
478.4 |
290.4 |
|
Administrative expenses |
|
|
(89.6) |
(77.6) |
|
Profit on disposal of subsidiaries |
|
|
- |
16.0 |
|
Profit on disposal of oil and gas assets |
|
|
0.5 |
4.9 |
|
Exploration costs written off |
|
|
(154.7) |
(82.7) |
|
Operating profit |
|
|
234.6 |
151.0 |
|
Loss on hedging instruments |
|
|
(27.7) |
(59.8) |
|
Finance revenue |
|
|
15.1 |
2.1 |
|
Finance costs |
|
|
(70.1) |
(60.8) |
|
Profit from continuing activities before tax |
|
|
151.9 |
32.5 |
|
Income tax expense |
|
7 |
(79.4) |
(1.9) |
|
Profit for the period from continuing activities |
|
|
72.5 |
30.6 |
|
Attributable to: |
|
|
|
|
|
Owners of the parent |
|
|
54.0 |
25.2 |
|
Non-controlling interest |
|
|
18.5 |
5.4 |
|
|
|
|
72.5 |
30.6 |
|
Earnings per ordinary share |
|
|
c |
c |
|
- Basic |
|
2 |
6.1 |
3.2 |
|
- Diluted |
|
2 |
6.1 |
3.1 |
Condensed consolidated statement of comprehensive income and expense
Year ended 31 December 2010
|
|
|
|
2010 $m |
2009 $m |
||
|
Profit for the year |
|
72.5 |
30.6 |
|||
|
Cash flow hedges |
|
|
|
|||
|
Losses arising from the year |
|
(26.8) |
(18.0) |
|||
|
Reclassification adjustments for losses included in profit on realisation |
|
(10.3) |
(13.3) |
|||
|
|
|
(37.1) |
(31.3) |
|||
|
Exchange differences on translation of foreign operations |
|
(11.4) |
42.0 |
|||
|
Other comprehensive income |
|
(48.5) |
10.7 |
|||
|
Tax relating to components of other comprehensive income |
|
8.2 |
(12.4) |
|||
|
Other comprehensive income for the year |
|
(40.3) |
(1.7) |
|||
|
Total comprehensive income for the year |
|
|
32.2 |
28.9 |
|
|
|
Attributable to: |
|
|
|
|
|
|
|
Owners of the parent |
|
|
13.7 |
23.5 |
|
|
|
Non-controlling interest |
|
|
18.5 |
5.4 |
|
|
|
|
|
32.2 |
28.9 |
|||
Condensed consolidated balance sheet
As at December 2010
|
|
|
|
2010 $m |
2009 $m |
|
ASSETS |
|
|
|
|
|
Non-current assets |
|
|
|
|
|
Intangible exploration and evaluation assets |
|
|
4,001.2 |
2,121.6 |
|
Property, plant and equipment |
|
|
2,974.4 |
2,199.8 |
|
Investments |
|
|
1.0 |
1.0 |
|
Deferred tax assets |
|
|
110.7 |
50.4 |
|
|
|
|
7,087.3 |
4,372.8 |
|
Current assets |
|
|
|
|
|
Inventories |
|
|
138.2 |
109.6 |
|
Trade receivables |
|
|
158.9 |
92.4 |
|
Other current assets |
|
|
655.3 |
296.0 |
|
Cash and cash equivalents |
|
|
338.3 |
252.2 |
|
Derivative financial instruments |
|
|
- |
2.3 |
|
|
|
|
1,290.7 |
752.5 |
|
Total assets |
|
|
8,378.0 |
5,125.3 |
|
LIABILITIES |
|
|
|
|
|
Current liabilities |
|
|
|
|
|
Trade and other payables |
|
|
(1,008.2) |
(557.1) |
|
Other financial liabilities |
|
|
(309.8) |
- |
|
Current tax liabilities |
|
|
(120.0) |
(73.8) |
|
Derivative financial instruments |
|
|
(47.1) |
- |
|
|
|
|
(1,485.1) |
(630.9) |
|
Non-current liabilities |
|
|
|
|
|
Trade and other payables |
|
|
(354.0) |
(31.8) |
|
Other financial liabilities |
|
|
(1,890.0) |
(1,314.6) |
|
Deferred tax liabilities |
|
|
(466.1) |
(473.5) |
|
Provisions |
|
|
(278.6) |
(223.5) |
|
Derivative financial instruments |
|
|
(35.3) |
(20.0) |
|
|
|
|
(3,024.0) |
(2,063.4) |
|
Total liabilities |
|
|
(4,509.1) |
(2,694.3) |
|
Net assets |
|
|
3,868.9 |
2,431.0 |
|
EQUITY |
|
|
|
|
|
Called up share capital |
|
|
143.5 |
130.1 |
|
Share premium |
|
|
251.5 |
242.3 |
|
Other reserves |
|
|
574.2 |
614.5 |
|
Retained earnings |
|
|
2,839.1 |
1,402.0 |
|
Equity attributable to equity holders of the parent |
|
|
3,808.3 |
2,388.9 |
|
Non-controlling interest |
|
|
60.6 |
42.1 |
|
Total equity |
|
|
3,868.9 |
2,431.0 |
Condensed statement of changes in equity
Year ended 31 December 2010
|
|
Share capital $m |
Share premium $m |
Other reserves $m |
Retained earnings $m |
Total $m |
Minority interest $m |
Total equity $m |
|
At 1 January 2009 |
119.7 |
231.1 |
607.8 |
898.6 |
1,857.2 |
36.7 |
1,893.9 |
|
Total recognised income and expense for the year |
- |
- |
(1.7) |
25.2 |
23.5 |
5.4 |
28.9 |
|
Purchase of treasury shares |
- |
- |
(5.7) |
- |
(5.7) |
- |
(5.7) |
|
Issue of equity shares |
9.7 |
- |
- |
549.3 |
559.0 |
- |
559.0 |
|
New shares issued in respect of employee share options |
0.7 |
11.2 |
- |
- |
11.9 |
- |
11.9 |
|
Vesting of PSP shares |
- |
- |
14.1 |
(14.1) |
- |
- |
- |
|
Share-based payment charges |
- |
- |
- |
18.3 |
18.3 |
- |
18.3 |
|
Dividends paid |
- |
- |
- |
(75.3) |
(75.3) |
- |
(75.3) |
|
At 1 January 2010 |
130.1 |
242.3 |
614.5 |
1,402.0 |
2,388.9 |
42.1 |
2,431.0 |
|
Total recognised income and expense for the year |
- |
- |
(40.3) |
54.0 |
13.7 |
18.5 |
32.2 |
|
Issue of equity shares |
13.1 |
2.1 |
- |
1,432.9 |
1,448.1 |
- |
1,448.1 |
|
New shares issued in respect of employee share options |
0.3 |
7.1 |
- |
- |
7.4 |
- |
7.4 |
|
Vesting of PSP shares |
- |
- |
- |
(0.2) |
(0.2) |
- |
(0.2) |
|
Share-based payment charges |
- |
- |
- |
29.6 |
29.6 |
- |
29.6 |
|
Dividends paid |
- |
- |
- |
(79.2) |
(79.2) |
- |
(79.2) |
|
At 31 December 2010 |
143.5 |
251.5 |
574.2 |
2,839.1 |
3,808.3 |
60.6 |
3,868.9 |
Condensed consolidated cash flow statement
Year ended 31 December 2010
|
|
|
Note |
2010 $m |
2009 $m |
|
|
Cash flows from operating activities |
|
|
|
|
|
|
Cash generated from operations |
|
8 |
818.0 |
463.6 |
|
|
Income taxes paid |
|
|
(85.6) |
(187.1) |
|
|
Net cash from operating activities |
|
|
732.4 |
276.5 |
|
|
Cash flows from investing activities |
|
|
|
|
|
|
Disposal of subsidiaries |
|
- |
- |
5.1 |
|
|
Disposal of oil and gas assets |
|
- |
6.7 |
12.3 |
|
|
Purchase of intangible exploration & evaluation assets |
|
|
(2,006.1) |
(668.4) |
|
|
Purchase of property, plant and equipment |
|
|
(625.6) |
(520.9) |
|
|
Advances to contractors |
|
|
(172.4) |
- |
|
|
Finance revenue |
|
|
5.4 |
1.2 |
|
|
Net cash used in investing activities |
|
|
(2,792.0) |
(1,170.7) |
|
|
Cash flows from financing activities |
|
|
|
|
|
|
Net proceeds from issue of share capital |
|
|
1,453.3 |
570.6 |
|
|
Debt arrangement fees |
|
|
(16.7) |
(100.5) |
|
|
Repayment of bank loans |
|
|
(20.9) |
(376.3) |
|
|
Drawdown of bank loan |
|
|
907.0 |
701.9 |
|
|
Finance costs |
|
|
(94.2) |
(49.2) |
|
|
Dividends paid |
|
|
(79.2) |
(75.3) |
|
|
Purchase of treasury shares |
|
|
- |
(5.5) |
|
|
Net cash generated by financing activities |
|
|
2,149.3 |
665.7 |
|
|
Net increase/(decrease) in cash and cash equivalents |
|
89.7 |
(228.5) |
||
|
Cash and cash equivalents at beginning of year |
|
252.2 |
450.3 |
||
|
Foreign exchange |
|
|
(3.6) |
30.4 |
|
|
Cash and cash equivalents at end of year |
|
|
338.3 |
252.2 |
|
Notes to the preliminary financial statements
Year ended 31 December 2010
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 April 2011.
The financial information for the year ended 31 December 2010 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 2009 have been delivered to the Registrar of Companies and those for 2010 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 auditors 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 2009. 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 2010, 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 $54.0 million (2009: $25.2 million) and a weighted average number of shares in issue of 879.8 million (2009: 796.4 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 7.9 million (2009: 9.0 million) in respect of employee share options, resulting in a diluted weighted average number of shares of 887.7 million (2009: 805.4 million).
3. Dividends
During the year the Company paid a final 2009 dividend of 4.0 pence per share and an interim 2010 dividend of 2.0p per share, a total dividend of 6.0 pence per share (2009: 6.0 pence per share). The Directors intend to recommend a final 2010 dividend of 4.0 pence per share, which, if approved at the AGM, will be paid on 20 May 2011 to shareholders on the register of the Company on 15 April 2011.
4. 2010 Annual Report and Accounts
The Annual Report and Accounts will be mailed on 7 April 2011 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 Thursday 12 May 2011 at 11.00 a.m.
6. Segmental Reporting
In the opinion of the Directors the operations of the Group comprise one class of business, oil and gas exploration, development and production and the sale of hydrocarbons and related activities. The Group also operates within four geographical markets, Africa, Europe, South Asia and South America.
The following tables present revenue, profit and certain asset and liability information regarding the Group's business segments for the years ended 31 December 2010 and 2009.
|
|
Africa $m |
Europe $m |
South Asia $m |
South America $m |
Unallocated $m |
Total $m |
|
2010 |
|
|
|
|
|
|
|
Sales revenue by origin |
850.4 |
218.3 |
21.1 |
- |
- |
1,089.8 |
|
Segment result |
328.9 |
(6.8) |
4.9 |
(3.3) |
- |
323.7 |
|
Profit on sale of oil and gas assets |
|
|
|
|
|
0.5 |
|
Unallocated corporate expenses |
|
|
|
|
|
(89.6) |
|
Operating profit |
|
|
|
|
|
234.6 |
|
Loss on hedging instruments |
|
|
|
|
|
(27.7) |
|
Finance revenue |
|
|
|
|
|
15.1 |
|
Finance costs |
|
|
|
|
|
(70.1) |
|
Profit before tax |
|
|
|
|
|
151.9 |
|
Income tax expense |
|
|
|
|
|
(79.4) |
|
Profit after tax |
|
|
|
|
|
72.5 |
|
Total assets |
7,438.1 |
584.5 |
88.8 |
166.3 |
100.3 |
8,378.0 |
|
Total liabilities |
(1,928.6) |
(291.4) |
(26.6) |
(39.2) |
(2,223.3) |
(4,509.1) |
|
Other segment information |
|
|
|
|
|
|
|
Capital expenditure: |
|
|
|
|
|
|
|
Property, plant and equipment |
1,041.7 |
104.7 |
2.9 |
- |
3.1 |
1,152.4 |
|
Intangible exploration and evaluation assets |
2,007.5 |
22.2 |
9.2 |
8.8 |
- |
2,047.7 |
|
Depletion, depreciation and amortisation |
(230.3) |
(125.5) |
(10.3) |
- |
(1.2) |
(367.3) |
|
Impairment losses recognised in income statement |
(4.3) |
- |
- |
- |
- |
(4.3) |
|
Exploration costs written off |
(128.7) |
(22.0) |
(0.7) |
(3.3) |
- |
(154.7) |
|
|
Africa $m |
Europe $m |
South Asia $m |
South America $m |
Unallocated $m |
Total $m |
|
2009 |
|
|
|
|
|
|
|
Sales revenue by origin |
645.4 |
248.6 |
21.9 |
- |
- |
915.9 |
|
Segment result |
212.4 |
(10.7) |
8.0 |
(2.0) |
- |
207.7 |
|
Profit on disposal of subsidiaries |
|
|
|
|
|
16.0 |
|
Profit on disposal of oil and gas assets |
|
|
|
|
|
4.9 |
|
Unallocated corporate expenses |
|
|
|
|
|
(77.6) |
|
Operating profit |
|
|
|
|
|
151.0 |
|
Loss on hedging instruments |
|
|
|
|
|
(59.8) |
|
Finance revenue |
|
|
|
|
|
2.1 |
|
Finance costs |
|
|
|
|
|
(60.8) |
|
Profit before tax |
|
|
|
|
|
32.5 |
|
Income tax expense |
|
|
|
|
|
(1.9) |
|
Profit after tax |
|
|
|
|
|
30.6 |
|
Total assets |
4,162.7 |
654.1 |
78.1 |
185.9 |
44.5 |
5,125.3 |
|
Total liabilities |
(992.4) |
(266.0) |
(18.1) |
(49.2) |
(1,368.6) |
(2,694.3) |
|
Other segment information |
|
|
|
|
|
|
|
Capital expenditure: |
|
|
|
|
|
|
|
Property, plant and equipment |
498.6 |
47.5 |
5.2 |
- |
9.4 |
560.7 |
|
Intangible exploration and evaluation assets |
640.8 |
27.3 |
4.0 |
10.1 |
2.5 |
684.7 |
|
Depletion, depreciation and amortisation |
(215.8) |
(126.8) |
(8.1) |
- |
(8.5) |
(359.2) |
|
Impairment losses recognised in income statement |
(12.5) |
- |
- |
- |
- |
(12.5) |
|
Exploration costs written off |
(20.7) |
(56.3) |
(1.6) |
(2.0) |
(2.1) |
(82.7) |
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:
|
|
|
|
2010 $m |
2009 $m |
|
Current tax |
|
|
|
|
|
UK corporation tax |
|
|
23.6 |
32.7 |
|
Foreign tax |
|
|
98.3 |
76.6 |
|
Total corporate tax |
|
|
121.9 |
109.3 |
|
UK petroleum revenue tax |
|
|
10.2 |
(4.4) |
|
Total current tax |
|
|
132.1 |
104.9 |
|
Deferred tax |
|
|
|
|
|
UK corporation tax |
|
|
1.0 |
(71.3) |
|
Foreign taxation |
|
|
(47.7) |
(31.9) |
|
Total corporate tax |
|
|
(46.7) |
(103.2) |
|
UK petroleum revenue tax |
|
|
(6.0) |
0.2 |
|
Total deferred tax |
|
|
(52.7) |
(103.0) |
|
Total tax expense |
|
|
79.4 |
1.9 |
b. Factors affecting tax charge for period
As the Group earns a significant portion of its profits in the UK the tax rates applied to profit on ordinary activities in preparing the reconciliation below is the standard rate of UK corporation tax applicable to the Group's oil and gas activities plus the rate of supplementary corporation tax (SCT).
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 upstream profits (30%) plus the rate of SCT in respect of UK upstream profits (20%) to the profit before tax is as follows:
|
|
|
2010 $m |
2009 $m |
|
Group profit on ordinary activities before tax |
|
151.9 |
32.5 |
|
Tax on group profit on ordinary activities at a combined standard UK corporation tax and SCT rate of 50% (2009: 50%) |
|
76.0 |
16.3 |
|
Effects of: |
|
|
|
|
Expenses not deductible for tax purposes |
|
64.5 |
12.0 |
|
Utilisation of tax losses not previously recognised |
|
(2.7) |
(16.7) |
|
Net losses not recognised |
|
39.2 |
60.3 |
|
Petroleum revenue tax (PRT) |
|
3.2 |
(4.2) |
|
UK corporation tax deductions for current PRT |
|
(1.6) |
2.1 |
|
Adjustments relating to prior years |
|
0.9 |
(8.2) |
|
Income taxed at a different rate |
|
(28.2) |
9.3 |
|
Income not subject to corporation tax |
|
(71.9) |
(69.0) |
|
Group total tax expense for the year |
|
79.4 |
1.9 |
The Group's profit before taxation will continue to be subject to 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 depend on the jurisdictions in which pre-tax profits and exploration costs written off arise.
The Group has tax losses of $840.1 million (2009: $412.3 million) that are available indefinitely 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 $184.0 million in deferred tax assets in relation to taxable losses (2009: $38.9 million).
No deferred tax liability is recognised on temporary differences of $485.6 million (2009: $433.8 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.
8. Cash Flows from Operating Activities
|
|
|
|
2010 $m |
2009 $m |
|
Profit before taxation |
|
|
151.9 |
32.5 |
|
Adjustments for: |
|
|
|
|
|
Depletion, depreciation and amortisation |
|
|
367.3 |
359.2 |
|
Impairment loss |
|
|
4.3 |
12.5 |
|
Exploration costs written off |
|
|
154.7 |
82.7 |
|
Profit on disposal of subsidiaries |
|
|
- |
(16.0) |
|
Profit on disposal of oil and gas assets |
|
|
(0.5) |
(4.9) |
|
Decommissioning expenditure |
|
|
(10.3) |
(2.0) |
|
Share-based payment charge |
|
|
11.9 |
5.4 |
|
Loss on hedging instruments |
|
|
27.7 |
59.8 |
|
Finance revenue |
|
|
(15.1) |
(2.1) |
|
Finance costs |
|
|
70.1 |
60.8 |
|
Operating cash flow before working capital movements |
|
|
762.0 |
587.9 |
|
Increase in trade and other receivables |
|
|
(66.7) |
(185.9) |
|
Increase in inventories |
|
|
(29.0) |
(52.7) |
|
Increase in trade payables |
|
|
151.7 |
114.3 |
|
Cash generated from operations |
|
|
818.0 |
463.6 |
9. Called up equity share capital
In the year ended 31 December 2010, the Group issued 83,922,894 (2009: 71,424,409) new shares which included issuing 1,918,305 (2009: 4,486,268) new shares in respect of employee share options and in January 2010 issuing 82,004,589 (2009: 66,938,141) new shares in respect of a share placing to institutional investors representing an increase of approximately 9.9% of the existing issued share capital.
As at 31 December 2010 the Group had in issue 888,236,870 allotted and fully paid ordinary shares of Stg10 pence each (2009: 804,313,976).
10. Commercial Reserves and Contingent Resources Summary (unaudited) working interest basis
|
|
AFRICA |
EUROPE |
SOUTH ASIA |
TOTAL |
|||||
|
|
Oil mmbbl |
Gas bcf |
Oil mmbbl |
Gas bcf |
Oil mmbbl |
Gas bcf |
Oil mmbbl |
Gas bcf |
Petroleum mmboe |
|
Commercial Reserves |
|
|
|
|
|
|
|
|
|
|
1 Jan 2010 |
255.6 |
23.4 |
1.2 |
139.0 |
- |
99.0 |
256.8 |
261.4 |
300.4 |
|
Revisions |
2.9 |
- |
0.4 |
38.9 |
0.3 |
16.8 |
3.6 |
55.7 |
12.9 |
|
Acquisitions |
0.3 |
- |
- |
- |
- |
- |
0.3 |
- |
0.3 |
|
Additions |
1.1 |
- |
- |
- |
- |
4.8 |
1.1 |
4.8 |
1.9 |
|
Production |
(14.0) |
(1.3) |
(0.2) |
(27.6) |
- |
(12.5) |
(14.2) |
(41.4) |
(21.1) |
|
31 December 2010 |
245.9 |
22.1 |
1.4 |
150.3 |
0.3 |
108.1 |
247.6 |
280.5 |
294.4 |
|
Contingent Resources |
|
|
|
|
|
|
|
|
|
|
1 Jan 2010 |
385.2 |
1,117.6 |
- |
114.9 |
- |
16.2 |
385.2 |
1,248.7 |
593.3 |
|
Revisions |
0.9 |
7.2 |
- |
(20.9) |
- |
(4.2) |
0.9 |
(17.9) |
(2.1) |
|
Acquisitions |
300.8 |
11.6 |
- |
- |
- |
- |
300.8 |
11.6 |
302.8 |
|
Additions |
219.5 |
301.9 |
- |
- |
- |
- |
219.5 |
301.9 |
269.9 |
|
Disposals |
(13.2) |
(338.5) |
- |
(7.1) |
- |
- |
(13.2) |
(345.6) |
(70.8) |
|
31 December 2010 |
893.2 |
1,099.8 |
- |
86.9 |
- |
12.0 |
893.2 |
1,198.7 |
1,093.1 |
|
Total |
|
|
|
|
|
|
|
|
|
|
31 December 2010 |
1,139.1 |
1,121.9 |
1.4 |
237.2 |
0.3 |
120.1 |
1,140.8 |
1,479.2 |
1,387.5 |
1. Proven and Probable Commercial Reserves are based on a Group reserves report produced by an independent engineer. Reserves estimates for each field are reviewed by the independent engineer based on significant new data or a material change with a review of each field undertaken at least every two years.
2. Proven and Probable Contingent Resources are based on both Tullow's estimates and the Group reserves report produced by an independent engineer.
3. The contingent resource acquisition in 2010 relates to the purchase of a 50% working interest in Blocks 1 and 3A in Uganda from Heritage Oil and Gas Ltd.
4. The total Commercial Reserves and Contingent Resources of 1,387.5 mmboe at 31 December 2010 include a 100% working interest in Blocks 1, 2 and 3A in Uganda. Post completion of the farm-down transaction with Total and CNOOC in Uganda, total Commercial Reserves and Contingent Resources are expected to reduce to 869 mmboe.
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 231.6 mmboe at 31 December 2010 (31 December 2009: 265.4 mmboe).
Contingent Resources relate to resources in respect of which development plans are in the course of preparation or further evaluation is under way with a view to development within the foreseeable future.
About Tullow Oil plc
Tullow 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 over 90 production and exploration licences in 22 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 results 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 9 March until 22 March. The telephone numbers and access codes are:
|
Live event |
Replay facility available from Noon |
||
|
UK Participants |
020 7806 1967 |
UK Participants |
020 7111 1244 |
|
Irish Participants |
01 486 0916 |
Irish Participants |
01 486 0902 |
|
|
|
Access Code |
5487925# |
To join the live Video webcast, or play the on-demand version which will be available from noon on 9 March, 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 Participants 0800 028 1243 |
UK Local Call 0845 634 0041 |
|
|
|
International Participants +44 20 8817 9301 |
Irish Free Call +1 800 943 094 |
|
|
|
USA Toll Free |
+1 866 629 2704 |
Access Code 4399861 |
|
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. A replay facility will be available from approximately 18.00 on 9 March until 22 March. The telephone numbers and access codes are:
|
Live Event |
Replay Facility available from 18:00 |
||
|
Domestic Toll Free |
+1 888 935 4575 |
Domestic Toll Free |
+1 866 932 5017 |
|
Toll |
+1 212 444 0412 |
Toll |
+1 347 366 9565 |
|
|
|
Access Code |
6412950# |
For further information contact:
|
Tullow Oil plc +44 20 3249 9000 |
Citigate Dewe Rogerson +44 20 7638 9571 |
Murray Consultants +353 1 498 0300 |
|
Ian Springett, Chief Financial Offcier |
Martin Jackson |
Joe Murray |
|
Chris Perry, Head of Investor Relations |
George Cazenove |
Ed Micheau |
This information is provided by RNS