2011 Full-Year Results
Record financial results; profit before tax over $1billion
Basin-opening discovery in South America; E&A success ratio 74%
Completed $2.9 billion farm down in Uganda in February 2012
14 March 2012 - Tullow Oil plc (Tullow), the independent oil and gas exploration and production Group, announces its results for the year ended 31 December 2011.
Results summary
2011 was a very good year for Tullow. Industry leading exploration success continued with the opening of a major new basin offshore French Guiana as well as further discoveries in Africa. The Group's financial performance has also been strong with record results for the year based on a 35% increase in production and significantly higher commodity prices helping to deliver a profit after tax increase of 670% to $689 million. Since year-end, Tullow has completed the $2.9 billion farm down in Uganda. Tullow now has a strong balance sheet providing financial flexibility and a solid foundation for future growth.
|
|
2011 |
2010 |
Change |
|
Working interest production (boepd) |
78,200 |
58,100 |
Up 35% |
|
Realised oil price per barrel ($) |
108 |
78 |
Up 38% |
|
Realised gas price per therm (pence) |
57 |
42 |
Up 36% |
|
Sales revenue ($m) |
2,304 |
1,090 |
Up 111% |
|
Operating profit ($m) |
1,132 |
262 |
Up 332% |
|
Profit before tax ($m) |
1,073 |
179 |
Up 499% |
|
Profit after tax ($m) |
689 |
90 |
Up 670% |
|
Basic earnings per share (cents) |
72.5 |
8.1 |
Up 795% |
|
Full year dividend per share (pence) |
12 |
6 |
Up 100% |
|
Operating cash flow before working capital ($m) |
1,832 |
789 |
Up 132% |
Key highlights
· Record revenues of $2.3 billion and operating cash flow of $1.8 billion; full year dividend up 100%.
· Average working interest production up 35% at 78,200 boepd.
· Another year of industry leading E&A performance; 74% success ratio in 2011.
· Major basin-opening discovery with the Zaedyus-1 well in French Guiana.
· Value-adding acquisitions of $737 million in the Netherlands and Ghana.
· Tweneboa-Enyenra-Ntomme (TEN) project appraisal & development planning progressing well; Owo-1 tested at combined rate of ~20,000 bopd.
· 38 well campaign planned for 2012; Frontier exploration partnership with Shell announced in January.
· $2.9 billion farm down to CNOOC and Total in Uganda completed on 21 February 2012.
Commenting today, Aidan Heavey, Chief Executive, said:
"Record results in 2011 and the $2.9 billion farm down to CNOOC and Total in Uganda are further landmarks in Tullow's evolution. In the coming year, we will continue to execute our industry-leading exploration programme, appraise major discoveries and invest in key development projects in Ghana and Uganda. Tullow now has a very strong balance sheet and increased cash flow, which gives us real financial flexibility and a firm foundation for further growth. With many opportunities for growth, 2012 promises to be another excellent year for Tullow."
Presentation in London, Webcast and Conference Calls: Details are available on page 28 of this announcement and in the Results Centre on the Group's website at www.tullowoil.com.
2011 overview and 2012 outlook
Record performance in 2011
Tullow delivered record results in 2011. Sales revenue grew 111% to $2.3 billion (2010: $1.1 billion) as a result of a 41% increase in sales volumes and significantly higher average price realisations. Profit before tax was up 499% to $1,073 million (2010: $179 million). Profit after tax for the year increased 670% to $689 million (2010: $90 million). Basic earnings per share grew 795% to 72.5 cents (2010: 8.1 cents).
In 2011, Tullow achieved the best safety performance in its history with the lowest Lost Time Injury Frequency Rate (LTIFR) of 0.38. The Group also continues to foster the creation of shared prosperity in the countries and communities in areas of operation through localisation, local content development and social enterprise investment, which increased 346% to $11.6 million in 2011.
Material production growth and world class development in Ghana
In 2011, Group working interest production increased 35% to 78,200 boepd. While there was a strong performance from the Jubilee production facilities overall, with average FPSO uptime of over 95%, productivity issues were experienced with some of the Jubilee wells related to problems with the original well completion design. The intention is to use 2012 to resolve these issues and a remedial work programme is already underway to rebuild the production rate towards facility capacity and ensure that plateau production is delivered in 2013. Recoverable resource estimates are unchanged and the Group remains focused on the field's long-term upside potential. Phase 1A development of the Jubilee field was sanctioned in January 2012 and drilling of the first production well commenced on schedule in February 2012. This development will be conducted over an 18 month period and the total cost is expected to be approximately $1.1 billion. In 2012, the Group expects to deliver total net production of 78,000 to 86,000 boepd.
During 2011, good progress was also made in appraising the TEN discoveries in Ghana with the highly successful Ntomme-2A discovery reinforcing the TEN resource base. In February 2012, this was supported by the flow testing of the Owo-1 well which produced at a combined rate of approximately 20,000 bopd giving confidence in the ultimate commerciality of the field. The engineering design of this development, which will consist of an FPSO and major subsea infrastructure, is progressing and a plan of development is expected to be submitted in the third quarter of 2012, with first oil forecast 30 months after approval.
Best in class exploration in 2011 and exciting prospects in 2012
The Group has developed a best-in-class reputation for exploration, opening up three major new oil basins since 2006 and delivering a five year average exploration and appraisal success ratio of 77%. Highlights for 2011 include the basin-opening Zaedyus discovery offshore French Guiana; significant discoveries at Teak in Ghana along with appraisal success at Tweneboa and Enyenra. In addition, the Jobi-East-1, Gunya-1 and Mypo-3 well results made an excellent start to the next phase of exploration and appraisal in the Lake Albert Basin in Uganda. In 2012, there is an exciting high-impact exploration and appraisal campaign on the West African and South American margins of the Equatorial Atlantic Basin including wells in French Guiana, Guyana, Sierra Leone, Côte d'Ivoire. Further work is also planned in Ghana, which is focused on extending the Jubilee play, building on the results which come with each well. In East Africa, the Group has a number of wells planned to spud in Uganda in the first half of 2012, building on the excellent well results of 2011.
Tullow has a number of potentially transformational up-and-coming exploration campaigns in other areas of its portfolio. In Mauritania and Senegal the Group's commanding acreage position and in-depth geological studies of new plays has positioned Tullow to 'move the needle' should there be any basin opening discoveries. A high-impact programme is planned to commence in Mauritania in the third quarter of 2012. In Kenya and Ethiopia, Tullow has embarked on a rift basin exploration campaign complementary to its programme in Uganda, covering approximately 100,000 square kilometres. The Group covered this unexplored acreage, which is ten times larger than its Uganda acreage, with the world's largest ever Full Tensor Gradiometry (FTG) gravity survey. Advanced fidelity 2D seismic surveying is ongoing and this data will be integrated with the FTG. Like all exploration campaigns, the work in Ethiopia and Kenya is high-risk but the Group is hopeful of a breakthrough with the first few wells planned for 2012.
Active portfolio management and new strategic partnerships
On 30 June 2011, Tullow completed the acquisition of Nuon E&P from the Vattenfall Group for a cash consideration of €300 million ($432 million). This added a portfolio of 25 licences and over 30 producing fields as well as various development and exploration opportunities, together with ownership of key infrastructure. On 25 July 2011, Tullow completed the acquisition of the Ghanaian interests of EO Group Limited (EO) for a combined cash and share consideration of $305 million. On 29 December 2011, Tullow, on behalf of itself and the other Jubilee Partners, acquired ownership of the Kwame Nkrumah FPSO from Modec which reflects the Partners' belief that ownership of the vessel will maximise commercial value and operational flexibility.
In January 2012, the Group signed a non-binding Memorandum of Understanding with Shell to explore in select frontier basins and geological plays within the Atlantic Basin. This partnership combines the knowledge base and specialist capabilities of both companies to allow more effective de-risking in areas with the potential to deliver exceptional results.
In February 2012, Tullow signed two new Production Sharing Agreements with the Government of Uganda. This was followed by the completion of the farm-down of two thirds of its Ugandan licences to CNOOC Limited and Total for a consideration of $2.9 billion. The Group is now ready with its partners to embark on the development of Uganda's oil industry. First oil could be as early as 2014, with material production volumes likely to be from 2016.
Strong balance sheet and flexible financing
Tullow increased its Reserves Based Lending facility by $1.0 billion to $3.5 billion during 2011. Tullow also extended the term of the $650 million Revolving Corporate Facility by three years to December 2014. The Group had total debt facilities of $4.15 billion at year end. At 31 December 2011, Tullow had net debt of $2.85 billion (2010: $1.9million). Unutilised debt capacity at year-end amounted to approximately $825 million.
Tullow's financial strategy continues to be to maintain flexibility to support the significant exploration, appraisal and development programmes in Ghana and Uganda and effectively allocate capital across the remainder of the business. This financial flexibility has been materially enhanced during 2011 by expansion of the Group's debt facilities to $4.15 billion and by the finalisation of the $2.9 billion Uganda farm-down in early 2012.
The medium-term outlook for the oil price is positive and supports continued strong investment in Tullow's successful exploration-led growth strategy. Based on current estimates and work programmes, 2012 capital expenditure is forecast to reach $2.0 billion. Approximately 45% of this investment will be in exploration and appraisal (E&A) and the remainder will be for development activities.
Board changes and dividend policy
At the end of 2011 Pat Plunkett retired after 11 years as Chairman. Simon Thompson became Chairman on January 1, 2012. David Williams, chairman of the Audit Committee, will retire after the Annual General Meeting in 2012 after six years on the Board. Steve Lucas has been appointed as Non-executive Director and as chairman designate of the Audit Committee from today. Steve McTiernan, the Senior Independent Director, will retire from the Board at the end of 2012 after 12 years on the Board.
The Board is proposing a final dividend of 8.0 pence per share (2010: 4.0 pence per share). This doubles the total payout in respect of 2011 to 12.0 pence per share, compared with 2010. Tullow's finances have fundamentally changed in 2011 with material growth in production and record cash flow from the business. The Board believes that it is appropriate to continue with its progressive dividend policy. The dividend will be paid on 24 May 2012 to shareholders on the register on 20 April 2012. Total shareholder return for 2011 was 12%, compared with a negative 2% return for the FTSE 100 over the same period.
Strategy and outlook
Tullow has established a distinctive competitive position and is evolving into a leading global independent oil company. The Group has a solid financial foundation but is differentiated from its peers by its high-impact, exploration-led growth strategy. The Group has a unique exploration inventory which is focused on frontier areas and concentrates on specific core regions and geological plays. Tullow seeks to realise value from exploration discoveries through a combination of major development projects and portfolio management activity.
The Group has consistently demonstrated the ability to create new opportunities for growth, develop major projects effectively and generate exceptional shareholder returns. Despite the current economic uncertainties, the outlook for oil price remains good and the Group's exploration programme and development pipeline have never been stronger. With these rich opportunities ahead, Tullow looks forward with confidence and excitement.
Operations review
WEST AND NORTH AFRICA
|
Total production 57,400 boepd |
Total reserves and resources 657.8 mmboe |
Sales revenue $1,944 million |
2011 investment $768 million |
Tullow's African production comes from Ghana, Equatorial Guinea, Gabon, Côte d'Ivoire, Congo (Brazzaville) and Mauritania. Whilst the main development and operating focus is on the Jubilee and TEN projects offshore Ghana, Tullow has significant ongoing development activities in the majority of its operational areas. The Group also has high-impact exploration acreage across this region in Mauritania, Senegal, Liberia, Sierra Leone, Côte d'Ivoire and Ghana.
Ghana
Tullow has interests in two licences offshore Ghana, Deepwater Tano and West Cape Three Points. 2011 activity included the ramp-up of production from the Jubilee field, further appraisal drilling which confirmed Enyenra as a major light oil field, and additional exploration success in the Ntomme-2A, Teak-1, 2 and 3A wells. Production operations on the FPSO Kwame Nkrumah continued to perform well with a low rate of unplanned shut-downs and no significant safety or environmental issues. Activity in 2012 will include the start of the Jubilee Phase 1A development and further appraisal and development activities on the TEN project.
Jubilee field Phase 1 & 1A developments
The start of 2011 saw the first lifting of Jubilee crude oil from the FPSO Kwame Nkrumah and since then, over 30 million barrels of oil have been produced and 30 cargoes have been safely exported. Following the strong operating performance of the Kwame Nkrumah FPSO, Tullow, on behalf of the Jubilee Partners, acquired the FPSO from Modec on 29 December 2011. This acquisition will enable the Jubilee Partners to maximise the FPSO's commercial value and operational efficiency whilst Modec will continue to provide operations and maintenance services.
The Jubilee Phase 1 development was completed in October 2011 when the last of the initial 17 wells were drilled, completed and brought on stream. Also at this time, the water injection design capacity for the FPSO was reached, with rates over 235,000 bwpd being injected into the reservoirs and pressure support being seen across the field. By the end of 2011, gas re-injection reached 80 mmscfd and gas flaring was reduced to minimal levels.
In 2011, gross production from the Jubilee field averaged 66,000 bopd (2010: 3,200 bopd), reaching 88,000 bopd before declining to approximately 70,000 bopd at the end of the year. However, production from the field was below expectations due to reduced productivity in a number of wells related to problems with the original well completion design. The issue is not expected to impact the level of field reserves or resources and a remedial work programme is underway to regain well productivity lost to date. This work involved the sidetracking of the J-07 production well using a new completion design which is now on-stream and being closely monitored. Further remedial work including acid stimulations and additional recompletions are planned for 2012.
The next phase of development for the Jubilee field is Phase 1A. Following approval gained from the Government of Ghana in early 2012, development started in February 2012, with the spudding of the first production well, and will continue over the next 18 months. The development is anticipated to cost approximately $1.1 billion and will consist of eight new wells; five producers, three additional water injectors and the expansion of the subsea network. The first of the Phase 1A wells is expected to come on stream from late in the second quarter of 2012.
The combination of the Phase 1 remedial work and the additional Phase 1A wells coming onstream, will enable production to resume its build up towards the FPSO design capacity of 120,000 bopd. Production is expected to average between 70,000 and 90,000 bopd in 2012, depending on the well performance achieved from the Phase 1 recovery programme and the execution schedule of the Phase 1A wells.
Tweneboa-Enyenra-Ntomme (TEN) Cluster Development
During 2011, significant progress was made in the programme of appraisal drilling and flow testing of the Tweneboa, Enyenra and Ntomme fields, collectively known as TEN. Tullow anticipates developing the three accumulations in an integrated subsea cluster development scheme using a single FPSO.
The appraisal programme commenced in January 2011 with the drilling of the Tweneboa-3 well comprising two deviated exploratory boreholes drilled into the Ntomme prospect which was proven to be a material and separate gas-condensate accumulation. Appraisal of the Ntomme accumulation commenced in early 2012 with the drilling of the Ntomme-2A well, located over four kilometres south of Tweneboa-3. This exploratory appraisal well successfully discovered high quality oil bearing reservoirs, below the Ntomme gas-condensate accumulation, reinforcing the overall TEN resource base potential.
Further appraisal drilling on the Enyenra field has continued during 2011 including the re-drill of the Owo-1 discovery well in December 2011, to allow testing and coring. To determine the level of reservoir connectivity and well deliverability, the well was flow tested. The lower channel was tested at a rate of approximately 10,000 bopd, and a commingled rate for the two upper channels was approximately 12,000 bopd. The pressure response will be monitored by pressure gauges deployed in the Enyenra-2A and Enyenra-3A wells, located to the south and north respectively. The Enyenra-4A well is currently drilling to determine the southern extent of the Enyenra field.
The TEN Development Project has made significant progress since the Front End Engineering & Design (FEED) commenced in August 2011. A design competition has commenced with three FPSO contractors and a local project office has been set up in Singapore to support this activity. Subsea FEED is nearing completion and tenders for this work are being prepared.
Tullow expects to submit the TEN Plan of Development (PoD) and a formal declaration of commerciality to the Government of Ghana in the third quarter of 2012. This will incorporate the information gained from the FEED work and the ongoing appraisal programme. First production from the TEN cluster development is anticipated to be approximately 30 months after government approval of the PoD.
Exploration and Appraisal Activity
In 2011, Tullow continued its exploratory drilling activity in Ghana, drilling the Teak-1, Teak-2, Teak-3, Banda, Akasa-1 and Makore-1 wells in the West Cape Three Points licence, operated by Kosmos. The Teak-1 well drilled in February 2011 encountered a thick tally of oil and gas pay, and the Teak-2 well drilled in March 2011 tested the fault block between the Teak-1 discovery and the Jubilee field, where it penetrated a gas reservoir that may represent a gas cap to the Jubilee field. The Teak-3 well was drilled in November 2011 and confirmed the northern extension of the Teak discovery, across a major fault. Plans are in place for the Teak-4 appraisal well and flow testing in 2012, the outcome of which will guide future development plans.
The Banda exploration well in the east of the West Cape Three Points block was drilled in June 2011 to explore the previously untargeted Cenomanian play. The well found very thick but low porosity Cenomanian sandstones with only three metres of oil pay. The Makore-1 exploration well was drilled in July 2011 targeting a discrete Jubilee-type reservoir. The well found excellent quality sandstones which were unfortunately water-bearing at this location. These results have been integrated into Tullow's regional geological model to enable better targeting of these plays elsewhere in Tullow's Equatorial Atlantic acreage.
In August 2011, the Akasa-1 well (previously known as Dahoma up-dip) was drilled and made a light oil discovery. The Turonian reservoirs encountered are similar in age to those discovered at the Jubilee field and the oil samples recovered from the Akasa-1 well indicate 38 degrees API gravity. The West Cape Three Points operator, Kosmos, remains in discussions with the Government of Ghana in relation to further appraisal and development plans for the Mahogany, Teak, Banda and Akasa discoveries.
In the Deepwater Tano licence operated by Tullow, a set of attractive remaining prospects have been identified and exploration activity will be completed before the end of the first quarter of 2013. Three exploration wells are expected to be drilled on the block and potential prospects include: Wawa-1 that will target hydrocarbons which may have moved to a trap up-dip from the TEN oil and gas-condensate fields; Sapele-1, immediately south of the Jubilee field, will test a prospective turbidite lobe and Tweneboa Deep-1, a material prospect below the TEN fields.
EO Group Ghanaian interests acquisition and equity redetermination
On 26 May 2011, Tullow entered into a conditional agreement to acquire the Ghanaian interests of EO Group Limited (EO) for a combined share and cash consideration of $305 million. This acquisition increased Tullow's interest in the West Cape Three Points licence offshore Ghana by 3.5% to 26.4% and increased the Group's interest in the Jubilee field by 1.75% to 36.5%. The acquisition was completed on 25 July 2011.
In October 2011 the partnership completed the first equity redetermination of the Jubilee Unit Area (JUA) and the net result is that Tullow's working interest in the JUA has reduced slightly from 36.5% to 35.5% which became effective from 1 December 2011.
Liberia & Sierra Leone
Tullow has four contiguous deepwater licences offshore Liberia and Sierra Leone where the Group is looking to capitalise on the success of the Jubilee play in Ghana. In May 2011, Tullow increased its equity from 10% to 20% in block SL-07B-10 (originally SL-06 and SL-07) in Sierra Leone by exercising pre-emptive rights. In November 2011, the Montserrado exploration well offshore Liberia was drilled and made a non-commercial oil discovery. Further analysis is being carried out following this result which will enable the partners to consider follow-up exploration targets in the play. Following the well in Liberia, the rig moved to Sierra Leone to drill the Jupiter-1 exploration well which finished in February 2012. The well encountered 30 metres of net pay in multiple zones, thus confirming a working hydrocarbon system in the Liberian Basin. The Mercury-2 exploratory well, a bold step out from the Mercury discovery, is currently drilling and is expected to complete in April 2012.
Côte d'Ivoire
Net production in 2011 from the East and West Espoir fields averaged 3,750 boepd (2010: 3,850 boepd). During the year, production was impacted by gas compressor issues; however all four gas compressors are now operational and gas exports have recovered to full capacity. A drilling campaign of at least eight infill wells across West and East Espoir is planned to start in the fourth quarter of 2012. This campaign will rejuvenate production and extend the life of the field.
Following the lifting of Force Majeure for both deepwater exploration blocks, CI-103 and CI-105, the plan to drill one well in each block was reactivated. The Eirik Raude rig was released from Ghana and commenced drilling the Kosrou prospect (CI-105) in February 2012, the well is expected to complete in April 2012. This will be followed by the drilling of the high-impact Paon prospect (CI-103).
Mauritania & Senegal
Production from the Chinguetti field in Mauritania continued to decline but at a reduced rate with full year net production averaging 1,400 boepd (2010: 1,500 boepd). Potential for further production optimisation in 2012 is being evaluated.
Two exploration wells were drilled in Mauritania in the first half of 2011. The Cormoran-1 well in Block 7 intersected four stacked hydrocarbon accumulations. In the deepest of these sections the well discovered highly pressured rich gas in the Petronia prospect, providing an encouraging test of our concept that Tullow's core play in Late Cretaceous turbidites extends into northern Mauritania. The Gharabi-1 well in Block 6, encountered poorly developed water-bearing reservoir and was plugged and abandoned in February 2011. The well was drilled by the operator to meet a commitment on the block and the result has no impact on Tullow's future plans for its Mauritanian acreage.
Tullow signed the new C-10 exploration Production Sharing Contract (PSC) in Mauritania on 27 October 2011 at an operated equity of 59%. This licence, the exploration area of the previous PSC A and PSC B, is over 10,000 sq km in area and carries a two well commitment in the first three years. Tullow is planning a number of exploration activities across its various exploration licenses in the Mauritania-Senegal basin during 2012 including 3D seismic acquisition and drilling.
In addition, Tullow has been granted extensions to the discovery areas of the previous PSC A and PSC B licences and increased its equity in these licences to 67.3% and 64.1% respectively. These licences, which Tullow now operates, contain the Banda, Tevet and Tiof oil and gas discoveries. The development of the Banda oil and gas discovery is progressing with project concepts under review.
Equatorial Guinea
The Ceiba field performed above expectation in the first half of 2011 but fell below 15,000 bopd gross in the second half of the year due to delays to the workover programme. Gross production averaged 19,915 bopd in 2011 (2010: 27,600 bopd). A major workover and infill drilling programme is now underway to restore production to higher levels. The Ocean Valiant rig moved to the field in January 2012 and began work on the first of the three well workovers before commencing the drilling of eight infill wells.
Production in the Okume Complex fell in the second half of 2011 due to a delay on the Akom North field tieback; gross production averaged 71,680 bopd in 2011 (2010: 82,360 bopd). The Akom North well was drilled and completed in late December 2011 and first oil was produced in January 2012. A major infill drilling campaign is planned with a rig secured to start operations in July 2013.
The results of the 4D seismic, shot in 2011, have been used to support the drilling campaigns in both fields.
Gabon
Net production in Gabon averaged 12,700 bopd for the year (2010: 12,850 bopd). Appraisal and infill drilling has been very successful throughout 2011 with over 120 wells being drilled and completed resulting in production being sustained and reserves replacement of 351%, an exceptional result in this mature area. This level of development and drilling activity is expected to be sustained in 2012.
In June 2011, Tullow completed a 20% farm-in to the Perenco-operated onshore exploration blocks DE-7 and Ogueyi. However, the Big Oba prospect in DE-7 and the Nkongono prospect in the Ogueyi block both proved unsuccessful and the Ogueyi block has since been relinquished. Acquisition of further 2D seismic data is planned to outline additional prospects in the DE-7 and Nziembou blocks; a multi-azimuth 3D survey is planned on the offshore Arouwe block in the first quarter of 2012. The seismic processing over Kiarsseny is now complete and interpretation is ongoing; the intention is to drill two exploration wells back-to-back, commencing in the fourth quarter of 2012.
Congo (Brazzaville)
Net production from the M'Boundi field was below expectations averaging 3,000 bopd in 2011 (2010: 4,000 bopd). Production volumes from the field fell in the second half of the year following issues with the water injection system which have now been resolved. Infill drilling and workover activity continued throughout the year with 19 wells drilled. Production volumes are expected to recover in the first quarter of 2012 as sustained water injection rates continue following the installation of a second high volume pump in the field.
SOUTH AND EAST AFRICA
|
Total production NIL |
Total reserves and resources 964 mmboe |
Sales revenue NIL |
2011 investment $418 million |
Following the sale of a two thirds interest in the Lake Albert Rift Basin to CNOOC and Total in February 2012, the Group now has an aligned partnership focused on completion of the Exploration and Appraisal programme and development of the basin. Following the success in Uganda, Tullow recently embarked upon the next stage of its exploration strategy in the region by securing significant acreage in Kenya and Ethiopia in 2011, with drilling commencing in Kenya in January 2012. In Namibia, following the signing of the Kudu field Petroleum Agreement in the third quarter of 2011, development activities are being advanced pending finalisation of the commercial agreements.
Uganda
Tullow has worked in Uganda since 2004 when the Group acquired Energy Africa. Tullow increased its interests in Uganda through the acquisitions of Hardman Resources in 2007 and Heritage Oil and Gas Ltd's Ugandan interests in 2010. Since entering the basin, Tullow has drilled 46 wells, completed a pioneering Full Tensor Gradiometry (FTG) Gravity Survey and has discovered 1.1 billion barrels of P50 resources in the Lake Albert Rift Basin with only two dry holes.
Following the completion of the acquisition of Heritage's interests in Uganda in July 2010, Tullow signed a legally binding Memorandum of Understanding (MoU) with the Government of Uganda on 15 March 2011. As a result, Tullow signed Share Purchase Agreements (SPAs) with CNOOC and Total for the farm-down of two thirds of Tullow's interests in Uganda on 30 March 2011.
On 3 February 2012, Tullow signed two Production Sharing Agreements (PSAs) relating to the Lake Albert Rift Basin with the Government of Uganda. This enabled Tullow and it new partners to complete the farm-down on 21 February 2012 for a consideration of $2.9 billion. Pursuant to the completion of the deal, operatorship responsibilities within the basin will be divided between the Partners. Total will operate Exploration Area-1 (EA-1) and Tullow will operate Exploration Area-2 (EA-2). In the former Exploration Area-3A, CNOOC Limited will operate the new Kanywataba licence and the Kingfisher production licence.
Alongside the March 2011 MoU with the Government of Uganda, Tullow was designated by the Ugandan Revenue Authority (URA) as agent to the deal between Tullow and Heritage. This designation required Tullow to pay a recoverable security of $313 million to the URA. This sum is equivalent to the outstanding Capital Gains Tax that the Ugandan Government believes it is owed by Heritage. Separately, and under the terms of Tullow and Heritage's SPA, Tullow has opened proceedings against Heritage in London to recover this sum. The case is expected to be heard in early 2013 after other cases involving Heritage in London and Kampala have been concluded.
The Partnership expects to submit options for the development of the Lake Albert Rift Basin later this year and these options will include a refinery and an export pipeline. Some small scale production is envisaged starting late 2012 but substantial production from the Basin is expected approximately 36 months after a basin-wide plan of development is approved by the Government of Uganda. Based on this timetable, ramp-up of major production should commence in 2016.
Lake Albert Rift Basin Development
Drilling operations in the Lake Albert Rift Basin continued in 2011. In EA-1, Tullow made an important discovery with the Jobi-East 1 well in June 2011 which encountered 20 metres of hydrocarbon bearing reservoir. Following this discovery, Tullow drilled the Jobi-2 appraisal well in the north of the Jobi-Rii field in July 2011 and confirmed the northward extension of this exciting discovery. Elsewhere in EA-1, Tullow drilled the Mpyo-3 well in June 2011 which confirmed the reservoir sands to be good quality with viscous oil, similar to that encountered in the shallower oil bearing zone of Mpyo-1.
Tullow then drilled the Gunya-A well in July 2011, which made a discovery in an undrilled fault block downdip of the Mpyo field. Appraisal drilling on the Jobi-East discovery commenced with Jobi-East-5 in August 2011 and Jobi-East-2 in September 2011. Jobi-East-5 provided valuable data for regional reservoir mapping but was drilled just outside the closure of the field. Jobi-East-2 successfully extended the field five kilometres north. A significant inventory of prospects has also been identified in EA-1 in a play that extends to the west of the river Nile. The Omuka well will test this new play and will spud in the fourth quarter of 2012. A large number of appraisal wells and well tests are also planned in the block in 2012.
In EA-2, three successful appraisal wells, Nsoga-2, Kigogole-6 and Ngege-2, were drilled and an extensive 3D seismic campaign covering the Kasamene, Ngiri, Nsoga and Kigogole discoveries was completed. The data recovered is of high quality and is currently being interpreted. In October 2011, Tullow received confirmation of the continuation of the appraisal periods for Kasamene, Wahrindi, Kigogole, Nsoga, Ngege and Ngara for an additional year and well testing will take place in the first half of 2012. Drilling activity in 2012 will focus on further appraisal of the Ngege, Nsoga and Waraga discoveries. The Kanywataba prospect at the southern end of the basin is expected to be drilled, in the third quarter of 2012.
Kenya and Ethiopia
Tullow farmed into blocks 10A, 10BA, 10BB, 12A & 13T in Kenya and the South Omo block in Ethiopia in 2010 and Block 12B in Kenya in February 2012. Tullow operates and has a 50% interest in all seven blocks. The acreage covers the Turkana Rift Basin, which has similar characteristics to the Lake Albert Rift Basin, and includes a south-east extension of the geologically older Sudan rift basins trend.
A Full Tensor Gradiometry (FTG) Gravity Survey acquired across most of the Kenya-Ethiopia licence blocks, covering an area of around 100,000 sq km, has been completed and processed. The data quality is excellent and there are strong similarities with the successful FTG survey acquired in Uganda in 2009. A 1,000 km 2D seismic programme in the South Omo Block in Ethiopia completed in early 2012. In Kenya, a 500 km 2D seismic programme was started in Block 13T in January 2012. This will be followed by a 1,350 km 2D survey in Block 10BA.
The Ngamia well in Block 10BB, which has an anticipated depth of 2,700 metres, spudded on 25 January 2012. Once this well is completed, the rig will drill the Paipai-1 well in Block 10A. It is also planned to drill a well in the South Omo Block in Ethiopia, in the third quarter of 2012.
In 2011, Tullow completed a farm-in to Block L8, offshore Kenya, and holds a 15% equity position with a 5% additional equity option. The high-impact Mbawa-1 well will be drilled in the third quarter of 2012 where Tullow has identified a potential oil prone area in this gas rich province.
Namibia
Tullow acquired the Kudu gas field through the acquisition of Energy Africa in 2004. Numerous initiatives have been pursued over the intervening years and the development of the field, as a gas-to-power project, is now making progress. A new Kudu Petroleum Agreement was signed in October 2011 and a 25 year Production Licence was issued by the Minister of Mines & Energy in November 2011. The Upstream Joint Operating Agreement, Project Development Agreement and Gas Sales Agreement Heads of Terms are being progressed and when concluded will allow the development to proceed to sanction. An investment decision is targeted for late 2012 which could mean the delivery of gas and power generation by the end of 2015.
Madagascar
Following the completion of a field programme in the first half of 2011, over 450 km of good quality 2D seismic data was then acquired in Blocks 3109 and 3111 which is still being processed. The rift basin trend covered by the seismic data has already proven successful for light oil in Block 3133 directly to the south. Based on encouraging data, Tullow's intention is to acquire further seismic and use these data to pick potential wildcat well locations. A farmout process is also under way, with the intention of reducing Tullow's equity to 50%.
Tanzania
Until November 2011, Tullow held a 50% interest in the Ruvuma Concession comprising the Lindi and Mtwara Blocks. In November 2011, Tullow farmed-down half its interest (25%) to its partners, Ndovu Resources Ltd (Aminex) and Solo Oil. Owing to a delay in securing the drilling rig, Caroil 6, an extension was granted by the Ministry of Energy and Minerals for completion. Ntorya-1 spudded on 22 December 2011 in the Mtwara Block. Tullow elected to withdraw from this well in March 2012.
EUROPE, SOUTH AMERICA & ASIA
|
Total production 20,800 boepd |
Total reserves and resources 120.8 mmboe |
Sales revenue $360 million |
2011 investment $246 million |
Tullow has gas production assets, ongoing developments and exploration acreage in the UK and the Netherlands which provide valuable cash flow to the Group. Tullow's experience in the North Sea provides a strong platform for expansion in this region. Tullow has qualified as an operator in Norway as a first step in the Group's strategy in the North Atlantic.
In South America, Tullow has significant exploration acreage in French Guiana, Guyana and Suriname where the Group is attempting to replicate the success of the West African Jubilee play across the Atlantic in South America. The first test of this was the Zaedyus-1 well in French Guiana which successfully discovered oil in September 2011. In 2012, follow-up drilling in French Guiana and Guyana aims to further establish this area as a new and exciting petroleum province.
The Group also produces from the Bangora field in Bangladesh and has an exploration portfolio in Pakistan. In March 2012, Tullow took the decision to commence a process to sell these Asian assets in order to focus on its core African and Atlantic Margin strategy.
UK
Net production from the UK assets in 2011 was in line with expectations averaging 12,500 boepd (2010: 13,300 boepd). These mature fields performed well, with high production efficiency despite their natural decline.
In the Thames Area, net production averaged 1,000 boepd supported by a combined flow from Wren, Wissey and Horne fields. In August 2011, Tullow drilled the 49/30b-10 well on the Foxtrot prospect, the sands were found to be water wet and the well has been suspended for later re-entry following evaluation of the deeper Rotliegendes play.
In the CMS Area, 2011 net production averaged 11,500 boepd. Tullow has well intervention programmes in place to ensure optimal well performance to maximise reserve recovery. In September 2011, the Katy development project was sanctioned, consisting of a single well tie-back to the CMS facilities. The KA-10 infill well commenced in mid-November 2011 and drilling progress is in line with expectations, with production due to commence in March 2012.
Further exploration activity took place in the CMS Area in 2011, with Tullow operating the Cameron-1 exploration well (44/19a-7a). The well commenced drilling in April 2011 and discovered gas within the Carboniferous play. Since the discovery, the commerciality of the Cameron field has been assessed and a decision on development options will be made with partners in the first half of 2012.
Looking forward, Tullow's strategy for the UK is to ensure rigorous technical assessment of all opportunities in an effort to offset natural decline and to prolong the life of the fields.
Netherlands
In May 2011, Tullow significantly enhanced its Dutch portfolio though the acquisition of Nuon Exploration & Production from the Vattenfall Group for a cash consideration of €300 million ($432 million). This is a non-operated portfolio of 25 licences, over 30 gas producing fields, a range of exploration opportunities and an equity interest in infrastructure. Net production in the second half of 2011 was between 6,000 and 7,000 boepd, an improvement on the rates at the time of the acquisition. Additional production came from the GdF Suez L15-FA 107 well which was brought on-stream in November 2011. The well tested around 30 mmscfd and is anticipated to recover around 25 bcf of gas.
In late 2011, a significant well and reservoir campaign commenced on the Joint Development Area (JDA) offshore the Netherlands. Four additional non-operated wells are expected to be drilled on the acreage in 2012 and 25 JDA wells will be worked over by mid-2013. This will extend the field life by 10 years and the combined net incremental production of these activities is expected to be over 1,500 boepd.
Tullow considers the area to have great potential and purchased 51,174 sq km of PGS MegaMerge 3D seismic data in the Dutch Southern North Sea to evaluate future regional exploration. In the Tullow operated E-Block, a risked and ranked prospect inventory was completed in 2011 and Tullow will drill the Vincent prospect in Block E11 in 2012. Tullow's high success ratio in this Carboniferous play in the UK bodes well for the adjacent Dutch portfolio.
French Guiana
In September 2011, the Zaedyus-1 exploration well made a significant oil discovery offshore French Guiana, encountering 72 metres of net oil pay in two turbidite fans. This is the first well in Tullow's extensive Guyanas Basin acreage and successfully opened a new basin, proving that the Jubilee play is mirrored across the Atlantic from West Africa to South America.
Drilling operations, which commenced in March 2011, continued after the discovery until mid-November 2011. An extensive data gathering programme was conducted including sidetracking of the well to cut a core through the reservoir and gather essential data. A liner was run over the main oil bearing reservoir and the well was suspended for future re-entry. The rig went off contract on 23 November 2011.
The Joint Venture partners are discussing a comprehensive follow-up exploration and appraisal programme which will include 3D seismic acquisition and a drilling programme, scheduled to commence in mid-2012. The drilling programme is expected to start with an appraisal well on the Zaedyus discovery and be followed by an exploration well on one of the neighbouring prospects. The Ministerial Order granting Tullow, Shell and Total approval for both the transfer and renewal of the Guyane Maritime permit was received on 22 December 2011. Shell then took over Operatorship of the block on 1 February 2012.
Suriname
In Suriname, Tullow finalised the farm-down of a 30% interest in Block 47 to Statoil in December 2011. Planning is now well advanced to acquire over 2,500 sq km of 3D seismic which will commence in the second quarter of 2012, subject to the necessary environmental approvals. The 3D programme is scheduled to take approximately four months to complete.
On the onshore Coronie licence, drilling operations began at the beginning of December 2011 on the first of five initial exploration wells. The first well has encountered oil shows which is encouraging for the following four wells in the programme. It is anticipated that drilling operations will continue until the second quarter of 2012. Having fulfilled all contractual obligations on the Uitkijk Block, Tullow returned its equity to Paradise Oil in June 2011 and no longer retains any equity in the block.
Guyana
The Atwood Beacon jack-up rig, contracted to drill the Late Cretaceous Jaguar prospect in the Georgetown block in Guyana, was expected to commence drilling in the fourth quarter of 2011. Operational and weather delays, on wells drilled by other parties in Suriname, meant that the rig did not arrive on location until early-December 2011. Inclement weather conditions meant that the well did not commence drilling until February 2012 and operations are expected to take 180 days to complete the well.
Bangladesh
Gross production from the Bangora field in 2011 was just over 100 mmscfd and 325 bpd of condensate. This was marginally lower than planned due to well maintenance issues. Tullow will be installing new compression facilities in 2012 to optimise the production profile for the longer-term and ultimately increase recoverable reserves. Installation and commissioning of these new facilities will lead to some production downtime, but gross production is still expected to average 100 mmscfd in 2012. Reprocessing of 3D geophysical data over the entire Bangora area is expected to lead to the identification of additional prospectivity within the Bangora development lease. Planning will then commence for development and near-field drilling in 2013. Negotiations with the government for the award of offshore exploration block SS-08-05 is pending resolution of an ongoing maritime boundary dispute with India.
Pakistan
In Pakistan, production from the extended well test at Shekhan in the Kohat licence was maintained for the full year at low levels and is providing reservoir data which will be used to plan additional appraisal or development drilling. Also in the Kohat licence, drilling of the Jabbi-1 well, a second exploration well located 20 km along the trend west of Shekhan, is ongoing. The well is due to complete in early 2012 and if successful, could quickly be tied into the processing plant already installed at Shekhan. Plans are in place for a comprehensive 2D and 3D seismic survey over the Shekhan, Jabbi and adjacent prospective structures which should provide a portfolio of development, appraisal and exploration targets for drilling in 2013-4.
Recent successful drilling at Zin, which is near to Tullow interests in Block 28 and the Kohlu and Kalchas licences, is a positive sign both for prospectivity and operational access to these areas.
Finance review
Tullow's successful growth strategy is underpinned by a clear financial strategy, which is to build a strong well funded balance sheet and significant operational cash flow. Jubilee production in Ghana and the completion of the Uganda farm down provide a powerful platform to fund future growth.
Financial results and KPI summary
|
|
2011 |
2010 |
Change |
|
Working interest production (boepd) |
78,200 |
58,100 |
+35% |
|
Sales volume (boepd) |
66,800 |
47,400 |
+41% |
|
Realised oil price per barrel ($) |
108.0 |
78.0 |
+38% |
|
Realised gas price per therm (pence) |
57.0 |
42.0 |
+36% |
|
Sales revenue ($m) |
2,304 |
1,090 |
+111% |
|
Cash operating costs per boe ($)1 |
13.5 |
12.5 |
+8% |
|
Operating profit ($m)2 |
1,132 |
262 |
+332% |
|
Profit from continuing activities before tax ($m)2 |
1,073 |
179 |
+499% |
|
Profit for the year from continuing activities ($m)2 |
689 |
90 |
+670% |
|
Basic earnings per share (cents)2 |
72.5 |
8.1 |
+795% |
|
Cash generated from operations ($m)3 |
1,832 |
789 |
+132% |
|
Operating cash flow per boe ($)3 |
64.2 |
37.2 |
+73% |
|
Dividend per share (pence) |
12.0 |
6.0 |
+100% |
|
Capital investment ($m) 4 |
1,432 |
1,235 |
+16% |
|
Year-end net debt ($m)5 |
2,854 |
1,943 |
+47% |
|
Interest cover (times)6 |
16.7 |
14.3 |
2.4 times |
|
Gearing (%)7 |
60 |
50 |
+10% |
1. Cash operating costs are cost of sales excluding depletion, depreciation and amortisation and under/over lift movements.
2. 2010 has been restated to reflect a change in accounting policy with regards to inventory valuation.
3. Before working capital movements.
4. 2011 capital investment exclude the Nuon and EO Group acquisitions.
5. Net debt is cash and cash equivalents less financial liabilities.
6. Interest cover is earnings before interest, tax, depreciation and amortisation charges and exploration written-off divided by net finance costs.
7. Gearing is net debt divided by net assets.
2011 results overview
Tullow delivered record results in 2011. Sales revenue grew 111% to $2.3 billion (2010: $1.1 billion) as a result of a 41% increase in sales volumes and significantly higher average price realisations. Profit from continuing activities before tax was up 499% to $1.1 billion (2010: $179 million) as a result of a combination of:
· $1.2 billion increase in sales revenue;
· $27 million IAS 39 gain;
· $34 million reduction in exploration costs written-off; and
· Partly offset by an increase in operating costs of $160 million and an increase in Depreciation, Depletion and Amortisation (DD&A) and impairment charges of $187 million; both largely due to first year of production from the Jubilee field in Ghana.
Profit for the year from continuing activities increased 670% to $689 million (2010: $90 million). Basic earnings per share grew 795% to 72.5 cents (2010: 8.1 cents).
Production, commodity prices and revenue
Working interest production averaged 78,200 boepd, an increase of 35% for the year (2010: 58,100 boepd). This reflects increasing production from the Jubilee field in Ghana, where first oil was achieved in November 2010. Sales volumes averaged 66,800 boepd, up 41% compared to 2010.
On average, oil prices in 2011 were significantly higher than 2010 levels. Realised oil price after hedging for 2011 was US$108.0/bbl (2010: US$78.0/bbl), an increase of 38%. Tullow's oil production sold at an average premium of 1% to Brent Crude during 2011 (2010: 2% discount). UK gas prices in 2011 were higher than 2010. The realised UK gas price after hedging for 2011 was 57.0 pence/therm (2010: 42.0 pence/therm), an increase of 36%. Higher commodity prices and sales volumes resulted in an overall revenue increase of 111% to $2.3 billion (2010: $1.1 billion).
Operating costs, depreciation and impairments
Underlying cash operating costs, which exclude depletion and amortisation and movements on the underlift/overlift, amounted to $386 million; $13.5/boe (2010: $264 million; $12.5/boe).
DD&A charges before impairment amounted to $514 million; $18.0/boe for the year (2010: $356 million; $16.8/boe). The Group recognised an impairment charge of $51 million; $1.8/boe (2010: $4.3 million; $0.20/boe) in respect of the M'Boundi field in the Congo due to field underperformance and an impairment reversal of $17 million; $0.6/boe in respect of the Chinguetti field in Mauritania due to improved field performance.
At the year-end, the Group was in a net overlift position of 220,000 barrels. The movements during 2011 in the underlift and stock position have given rise to a credit of $2.1 million to cost of sales (2010: credit of $35.6 million).
Administrative expenses of $122.8 million (2010: $89.6 million) include an amount of $23.6 million (2010: $10.2 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 2011 with Tullow's total workforce increasing by 26% to 1,548 people.
Exploration costs written-off
Exploration costs written-off were $121 million (2010: $155 million), in accordance with the Group's 'successful efforts' accounting policy. This requires that all costs associated with unsuccessful exploration are written-off in the income statement. This write-off is principally associated with unsuccessful exploration activities in Ghana, Liberia, Gabon and the UK, together with new ventures activity.
Operating profit
Operating profit grew 332% to $1.13 billion (2010: $262 million). The increase was principally due to increased sales volumes and higher commodity prices, partly offset by higher operating costs and DD&A charges following Ghana first oil production in November 2010.
Derivative instruments
Tullow continues to undertake hedging activities as part of the ongoing management of its business risk and 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 2011, the Group's derivative instruments had a net negative fair value of $47 million (2010: negative $82 million), inclusive of deferred premium. While all of the Group's commodity derivative instruments currently qualify for hedge accounting, a pre tax credit of $27 million (2010: charge of $28 million) has been recognised in the income statement for 2011. The credit is in relation to the increase in time value of the Group's commodity derivative instruments; mainly caused by the Group's oil hedging activity at relatively higher commodity prices throughout the year, compared with the forward curve on 31 December 2011.
At 9 March 2012 the Group's commodity hedge position to the end of 2014 was as follows:
|
Hedge position |
2012 |
2013 |
2014 |
|
Oil hedges |
|
|
|
|
Volume (bopd) |
34,500 |
25,500 |
12,000 |
|
Current price hedge ($/bbl) |
117.4 |
111.9 |
104.6 |
|
Gas hedges |
|
|
|
|
Volume (mmscfd) |
29.1 |
12.2 |
3.0 |
|
Current price hedge (p/therm) |
60.2 |
68.3 |
75.9 |
Net financing costs
The net interest charge for the year was $86 million (2010: $55 million) and reflects the increase in net debt levels during 2011, offset by an increase in interest capitalised during the year on qualifying assets and by a one-off gain of $22 million resulting from the purchase of the FPSO by the Jubilee partners in December 2011 and consequent settlement of the Ghana FPSO finance lease liability.
Taxation
The tax charge of $384 million (2010: $90 million) relates to the Group's North Sea, Gabon, Equatorial Guinea and new significant Ghanaian activities. After adjusting for exploration costs and profit on disposal of subsidiaries, the Group's underlying effective tax rate is 32% (2010: 27%). The increase in the effective tax rate is mainly due to the increase in profits before tax driven by the new Ghanaian activities which are subject to a 35% tax rate.
Operating cash flow
Higher production and increased commodity prices drove operating cash flow before working capital movements 132% higher to $1.8 billion (2010: $789 million). In 2011, this cash flow together with increased debt facilities helped fund $1.7 billion capital investment in exploration and development activities, $502 million on acquisitions, $114 payment of dividends and the servicing of debt facilities.
|
Summary cash flow ($million) |
2011 |
2010 |
|
Sales revenue |
2,304 |
1,090 |
|
Operating costs |
(386) |
(264) |
|
Operating expenses |
(86) |
(37) |
|
Cash flow from operations |
1,832 |
789 |
|
Working capital and tax |
(101) |
(57) |
|
Capital expenditure |
(1,653) |
(1,179) |
|
Investing activities |
(388) |
(1,612) |
|
Financing activities |
279 |
2,149 |
|
Net (decrease)/increase in cash during the year |
(31) |
90 |
Capital expenditure
2011 capital expenditure amounted to $1.4 billion (2010: $1.2 billion) with 28% invested on development activities, 23% on appraisal activities and 49% on exploration activities. More than 50% of the total was invested in Ghana and Uganda and over 80%, more than $1.2 billion, was invested in Africa. Based on current estimates and work programmes, 2012 capital expenditure is forecast to reach $2.0 billion.
Portfolio management
On 30 June 2011, Tullow completed the acquisition of Nuon E&P from the Vattenfall Group for a cash consideration of €300 million ($432 million), before working capital adjustments. This added a portfolio of 25 licences, over 30 producing fields as well as various development and exploration opportunities together with ownership of key infrastructure.
On 25 July 2011, Tullow completed the acquisition of the Ghanaian interests of EO Group Limited (EO) for a combined cash and share consideration of $305 million, before working capital adjustments. This increased Tullow's interest in the West Cape Three points licence by 3.5% to 26.4% and increased the Group's interest in the Jubilee fields by 1.75% to 36.5%.
Ghana share listing
In July 2011, Tullow allotted 3,531,546 ordinary shares of 10p each in the capital of Tullow, which rank pari passu with the existing Shares in issue, pursuant to the offer for subscription of up to 4,000,000 Shares in connection with Tullow's secondary listing on the Ghana Stock Exchange (GSE). This represented a total amount of 109,477,926 Ghana Cedis (approximately $72.3 million). It was the largest primary share offer ever completed on the GSE and has more than doubled the market capitalisation of the GSE. The first day of trading was on 27 July 2011.
Dividend
The Board is proposing a final dividend of 8.0 pence per share (2010: 4.0 pence per share). This doubles the total payout in respect of 2011 to 12.0 pence per share, compared with 2010. Tullow's finances have fundamentally changed with material growth in production and record cash flow from operations. As a result, the Board believes that it is appropriate to continue with its progressive dividend policy.
The dividend will be paid on 24 May 2012 to shareholders on the register on 20 April 2012. 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 Euros. 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 the record date for the dividend. 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 the record date.
Balance sheet
Tullow increased its Reserves Based Lending facility by $1.0 billion to $3.5 billion during 2011. Tullow also extended the term of the $650 million Revolving Corporate Facility by three years to December 2014. The Group had total debt facilities of $4.15 billion at year end. At 31 December 2011, Tullow had net debt of $2.85 billion (2010: $1.9million). Unutilised debt capacity at year-end amounted to approximately $825 million. Gearing was 60% (2010: 50%) and EBITDA interest cover increased in 2011 to 16.7 times (2010: 14.3 times). Total net assets at 31 December 2011 amounted to $4.8 billion (31 December 2010: $3.9 billion) with the increase in total net assets principally due to the profit for the year from continuing activities.
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. During the year the Group has revised its inventory product accounting policy to value inventory product at net realisable value. The Group has not made any other material changes to its accounting policies in the year ended 31 December 2011.
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 to potentially 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 2011 Annual Report and Accounts.
2012 principal risks and uncertainties
The Board determines the key risks for the Group and monitors mitigation plans and performance on a monthly basis. The principal risks and uncertainties facing the Group at the yearend are detailed in the risk management section of this Annual Report. The Group has identified its principal risks for the next 12 months as being:
· Remediation of Jubilee production and delivery of Group production targets;
· Exploration risk in the context of a very active programme;
· Delivery of the Lake Albert Basin Plan of Development and achieving approvals for this from the Ugandan authorities; and
· Oil price and overall market volatility.
Events since year-end
In February 2012, Tullow completed the farm down of one third of its Uganda interests to both Total and CNOOC for a total headline consideration of $2.9 billion paving the way for full development of the Lake Albert Rift Basin oil and gas resources. The Revolving Corporate Facility commitments reduced from $650 million to $500 million following the Uganda farm down completion.
Financial strategy
Our financial strategy continues to be to maintain flexibility to support the 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 2011 by expansion of our debt facilities to $4.15 billion and by the finalisation of the $2.9 billion Uganda farm-down in early 2012.
Outlook
The outlook is very positive for Tullow. In 2012, we expect significant progress in Ghana and Uganda and we have an exciting high-impact exploration and appraisal programme with wells planned in French Guiana, Cote D'Ivoire, Ghana, Kenya, Sierra Leone and Uganda. We are well positioned to continue to deliver significant 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 2011 Annual Report.
Condensed consolidated income statement
Year ended 31 December 2011
|
|
Notes |
2011 $m |
*Restated 2010 $m |
|
Continuing activities |
|
|
|
|
Sales revenue |
|
2,304.2 |
1,089.8 |
|
Cost of sales |
|
(930.8) |
(584.1) |
|
Gross profit |
|
1,373.4 |
505.7 |
|
Administrative expenses |
|
(122.8) |
(89.6) |
|
Profit on disposal of oil and gas assets |
|
- |
0.5 |
|
Profit on disposal of other assets |
|
2.0 |
- |
|
Exploration costs written off |
|
(120.6) |
(154.7) |
|
|
|
|
|
|
Operating profit |
|
1,132.0 |
261.9 |
|
Gain / (loss) on hedging instruments |
|
27.2 |
(27.7) |
|
Finance revenue |
|
36.6 |
15.1 |
|
Finance costs |
|
(122.9) |
(70.1) |
|
Profit from continuing activities before tax |
|
1,072.9 |
179.2 |
|
Income tax expense |
7 |
(383.9) |
(89.7) |
|
Profit for the year from continuing activities |
|
689.0 |
89.5 |
|
Attributable to: |
|
|
|
|
Owners of the parent |
|
649.0 |
71.0 |
|
Non-controlling interest |
|
40.0 |
18.5 |
|
|
|
689.0 |
89.5 |
|
Earnings per ordinary share from continuing activities |
|
|
|
|
Basic |
2 |
72.5 |
8.1 |
|
Diluted |
2 |
72.0 |
8.0 |
* Certain numbers shown above do not correspond to the 2010 financial statements as a result of a retrospective restatement as set out in note 11.
Condensed consolidated statement of comprehensive income and expense
Year ended 31 December 2011
|
|
|
2011 $m |
*Restated 2010 $m |
|
Profit for the year |
|
689.0 |
89.5 |
|
Cash flow hedges |
|
|
|
|
Losses arising in the year |
|
(6.7) |
(26.8) |
|
Reclassification adjustments for losses |
|
|
|
|
included in profit on realisation |
|
15.2 |
(10.3) |
|
|
|
8.5 |
(37.1) |
|
Exchange differences on translation of foreign operations |
|
(34.5) |
(11.4) |
|
Other comprehensive income |
|
(26.0) |
(48.5) |
|
Tax relating to components of other comprehensive income |
|
2.9 |
8.2 |
|
Other comprehensive income for the year |
|
(23.1) |
(40.3) |
|
Total comprehensive income for the year |
|
665.9 |
49.2 |
|
|
|
|
|
|
Owners of the parent |
|
625.9 |
30.7 |
|
Non-controlling interest |
|
40.0 |
18.5 |
|
|
|
665.9 |
49.2 |
* Certain numbers shown above do not correspond to the 2010 financial statements as a result of a retrospective restatement as set out in note 11.
Condensed consolidated balance sheet
As at December 2011
|
|
|
2011 $m |
*Restated 2010 $m |
|
ASSETS |
|
|
|
|
Non-current assets |
|
|
|
|
Intangible exploration and evaluation assets |
|
5,450.0 |
4,001.2 |
|
Property, plant and equipment |
|
3,658.2 |
2,974.4 |
|
Investments |
|
1.0 |
1.0 |
|
Other non-current assets |
|
313.5 |
- |
|
Deferred tax assets |
|
39.0 |
100.4 |
|
|
|
9,461.7 |
7,077.0 |
|
Current assets |
|
|
|
|
Inventories |
|
225.7 |
183.0 |
|
Trade receivables |
|
272.4 |
158.9 |
|
Other current assets |
|
360.2 |
655.3 |
|
Current tax assets |
|
7.0 |
- |
|
Cash and cash equivalents |
|
307.1 |
338.3 |
|
|
|
1,172.4 |
1,335.5 |
|
Total assets |
|
10,634.1 |
8,412.5 |
|
LIABILITIES |
|
|
|
|
Current liabilities |
|
|
|
|
Trade and other payables |
|
(1,118.6) |
(1,008.2) |
|
Other financial liabilities |
|
(217.8) |
(309.8) |
|
Current tax liabilities |
|
(153.8) |
(120.6) |
|
Derivative financial instruments |
|
(42.4) |
(47.1) |
|
|
|
(1,532.6) |
(1,485.7) |
|
Non-current liabilities |
|
|
|
|
Trade and other payables |
|
(2.4) |
(354.0) |
|
Other financial liabilities |
|
(2,858.1) |
(1,890.0) |
|
Deferred tax liabilities |
|
(1,030.0) |
(465.5) |
|
Provisions |
|
(440.8) |
(278.6) |
|
Derivative financial instruments |
|
(4.2) |
(35.3) |
|
|
|
(4,335.5) |
(3,023.4) |
|
Total liabilities |
|
(5,868.1) |
(4,509.1) |
|
Net assets |
|
4,766.0 |
3,903.4 |
|
EQUITY |
|
|
|
|
Called up share capital |
|
146.2 |
143.5 |
|
Share premium |
|
551.8 |
251.5 |
|
Other reserves |
|
551.1 |
574.2 |
|
Retained earnings |
|
3,441.3 |
2,873.6 |
|
Equity attributable to equity holders of the parent |
|
4,690.4 |
3,842.8 |
|
Non-controlling interest |
|
75.6 |
60.6 |
|
Total equity |
|
4,766.0 |
3,903.4 |
* Certain numbers shown above do not correspond to the 2010 financial statements as a result of a retrospective restatement as set out in note 11.
Condensed statement of changes in equity
Year ended 31 December 2011
|
|
Share |
Share |
Other reserves $m |
Retained earnings |
Total |
Non-controlling interest |
Total |
|
At 1 January 2010 (restated*) |
130.1 |
242.3 |
614.5 |
1,419.5 |
2,406.4 |
42.1 |
2,448.5 |
|
Total recognised income and expense for the year (restated*) |
- |
- |
(40.3) |
71.0 |
30.7 |
18.5 |
49.2 |
|
Issue of equity shares |
13.1 |
2.1 |
- |
1,432.9 |
1,448.1 |
- |
1,448.1 |
|
New shares issued in respect of employee |
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 1 January 2011 (restated*) |
143.5 |
251.5 |
574.2 |
2,873.6 |
3,842.8 |
60.6 |
3,903.4 |
|
Total recognised income and expense for the year |
- |
- |
(23.1) |
649.0 |
625.9 |
40.0 |
665.9 |
|
Issue of equity shares |
2.2 |
285.5 |
- |
- |
287.7 |
- |
287.7 |
|
New shares issued in respect of employee |
0.5 |
14.8 |
|
- |
15.3 |
- |
15.3 |
|
Vesting of PSP shares |
- |
- |
- |
(0.1) |
(0.1) |
- |
(0.1) |
|
Share-based payment charges |
- |
- |
- |
33.0 |
33.0 |
- |
33.0 |
|
Dividends paid |
- |
- |
- |
(114.2) |
(114.2) |
- |
(114.2) |
|
Distribution to minority shareholders |
- |
- |
- |
- |
- |
(25.0) |
(25.0) |
|
|
146.2 |
551.8 |
551.1 |
3,441.3 |
4,690.4 |
75.6 |
4,766.0 |
* Certain numbers shown above do not correspond to the 2010 financial statements as a result of a retrospective restatement as set out in note 11.
Condensed consolidated cash flow statement
Year ended 31 December 2011
|
|
Notes |
2011 |
*Restated 2010 |
|
Cash flows from operating activities |
|
|
|
|
Cash generated from operations |
8 |
1,903.1 |
818.0 |
|
Income taxes paid |
|
(171.8) |
(85.6) |
|
|
|
1,731.3 |
732.4 |
|
|
|
|
|
|
Disposal of oil and gas assets |
|
- |
6.7 |
|
Disposal of other assets |
|
2.4 |
- |
|
Purchase of subsidiaries |
|
(404.0) |
- |
|
Purchase of intangible exploration and evaluation assets |
|
(1,018.4) |
(2,006.1) |
|
Purchase of property, plant and equipment |
|
(635.1) |
(625.6) |
|
Advances to contractors |
|
- |
(172.4) |
|
Finance revenue |
|
13.6 |
5.4 |
|
|
|
(2,041.5) |
(2,792.0) |
|
|
|
|
|
|
Net proceeds from issue of share capital |
|
86.7 |
1,453.3 |
|
Debt arrangement fees |
|
(30.0) |
(16.7) |
|
Repayment of bank loans |
|
(320.0) |
(20.9) |
|
Drawdown of bank loan |
|
1,200.0 |
907.0 |
|
Repayment of obligations under finance leases |
|
(308.4) |
- |
|
Finance costs |
|
(210.2) |
(94.2) |
|
Dividends paid |
|
(114.2) |
(79.2) |
|
Distribution to minority shareholders |
|
(25.0) |
- |
|
|
|
278.9 |
2,149.3 |
|
|
|
(31.3) |
89.7 |
|
Cash and cash equivalents at beginning of year |
|
338.3 |
252.2 |
|
Foreign exchange |
|
0.1 |
(3.6) |
|
|
|
307.1 |
338.3 |
* Certain numbers shown above do not correspond to the 2010 financial statements as a result of a retrospective restatement as set out in note 11.
Notes to the preliminary financial statements
Year ended 31 December 2011
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 2012.
The financial information for the year ended 31 December 2011 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 2010 have been delivered to the Registrar of Companies and those for 2011 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.
During 2011 the group has revised its oil product inventory valuation policy to value oil product inventory at net realisable value in line with IAS 2 Inventories. In order to aid comparability the group has retrospectively applied the accounting policy. Other than oil product inventory the accounting policies applied are consistent with those adopted and disclosed in the Group's financial statements for the year ended 31 December 2010. 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 2011; 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 $649.0 million (2010: $71.0 million) and a weighted average number of shares in issue of 895.7 million (2010: 879.8 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 6.2 million (2010: 7.9 million) in respect of employee share options, resulting in a diluted weighted average number of shares of 901.9 million (2010: 887.7 million).
3. Dividends
During the year the Company paid a final 2010 dividend of 4.0 pence per share and an interim 2011 dividend of 4.0p per share, a total dividend of 8.0 pence per share (2010: 6.0 pence per share). The Directors intend to recommend a final 2011 dividend of 8.0 pence per share, which, if approved at the AGM, will be paid on 24 May 2012 to shareholders on the register of the Company on 20 April 2012.
4. 2011 Annual Report and Accounts
The Annual Report and Accounts will be mailed on 16 April 2012 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 16 May 2012 at 12 noon.
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. In 2011 the Group reorganised its operational structure into three regions so that the management and resources of the business are aligned with the delivery of business objectives. The reportable segments in accordance with IFRS 8 are therefore now the three geographical regions that the Group operates within, being Europe, South America and Asia; West and North Africa and South and East Africa. The following tables present revenue, profit and certain asset and liability information regarding the Group's business segments for the year ended 31 December 2011, 31 December 2010 and 31 December 2009. The tables for the years ended 31 December 2010 and 31 December 2009 have been restated to reflect the new reportable segments of the business.
|
|
Europe, South America and Asia |
West and North Africa |
South and East Africa |
Unallocated |
Total |
|
2011 |
360.2 |
1,944.0 |
- |
- |
2,304.2 |
|
|
31.9 |
1,216.7 |
4.2 |
- |
1,252.8 |
|
Profit on disposal of other assets |
|
|
|
|
2.0 |
|
Profit on disposal of oil and gas assets |
|
|
|
|
- |
|
Unallocated corporate expenses |
|
|
|
|
(122.8) |
|
|
|
|
|
|
1,132.0 |
|
Loss on hedging instruments |
|
|
|
|
27.2 |
|
Finance revenue |
|
|
|
|
36.6 |
|
Finance costs |
|
|
|
|
(122.9) |
|
|
|
|
|
|
1,072.9 |
|
Income tax expense |
|
|
|
|
(383.9) |
|
|
|
|
|
|
689.0 |
|
|
1,790.1 |
4,745.1 |
3,977.6 |
121.3 |
10,634.1 |
|
|
(920.7) |
(1,202.8) |
(565.5) |
(3,179.1) |
(5,868.1) |
|
|
|
|
|
|
|
|
Capital expenditure: |
|
|
|
|
|
|
Property, plant and equipment |
92.7 |
638.6 |
0.8 |
31.8 |
763.9 |
|
Intangible exploration and evaluation assets |
171.9 |
482.5 |
535.6 |
- |
1,190.0 |
|
Acquisition of subsidiaries (note 10) |
963.7 |
- |
- |
- |
963.7 |
|
Depletion, depreciation and amortisation |
(170.1) |
(344.3) |
(0.4) |
(19.0) |
(533.8) |
|
Impairment losses recognised in income statement |
- |
(51.0) |
- |
- |
(51.0) |
|
Exploration costs written off |
(39.7) |
(85.9) |
5.0 |
- |
(120.6) |
|
|
Europe, South America and Asia |
West and North Africa |
South and East Africa |
Unallocated |
Total |
|
2010 (restated) |
237.9 |
851.9 |
- |
- |
1,089.8 |
|
|
(9.1) |
424.9 |
(64.8) |
- |
351.0 |
|
Profit on disposal of oil and gas assets |
|
|
|
|
0.5 |
|
Unallocated corporate expenses |
|
|
|
|
(89.6) |
|
|
|
|
|
|
261.9 |
|
Loss on hedging instruments |
|
|
|
|
(27.7) |
|
Finance revenue |
|
|
|
|
15.1 |
|
Finance costs |
|
|
|
|
(70.1) |
|
|
|
|
|
|
179.2 |
|
Income tax expense |
|
|
|
|
(89.7) |
|
|
|
|
|
|
89.5 |
|
|
814.3 |
4,334.7 |
3,099.9 |
163.6 |
8,412.5 |
|
|
(341.8) |
(1,552.6) |
(336.9) |
(2,277.8) |
(4,509.1) |
|
|
|
|
|
|
|
|
Capital expenditure: |
|
|
|
|
|
|
Property, plant and equipment |
78.4 |
1,040.9 |
- |
33.1 |
1,152.4 |
|
Intangible exploration and evaluation assets |
39.8 |
249.0 |
1,758.9 |
- |
2,047.7 |
|
Depletion, depreciation and amortisation |
(128.4) |
(228.7) |
- |
(10.2) |
(367.3) |
|
Impairment losses recognised in income statement |
- |
(4.3) |
- |
- |
(4.3) |
|
Exploration costs written off |
(28.8) |
(61.1) |
(64.8) |
- |
(154.7) |
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:
|
|
2011 |
*Restated 2010 |
|
Current tax |
|
|
|
UK corporation tax |
37.4 |
23.6 |
|
Foreign tax |
137.4 |
99.7 |
|
|
174.8 |
123.3 |
|
UK petroleum revenue tax |
11.6 |
10.2 |
|
|
186.4 |
133.5 |
|
|
|
|
|
UK corporation tax |
15.2 |
1.0 |
|
Foreign tax |
185.7 |
(38.8) |
|
|
200.9 |
(37.8) |
|
Deferred UK petroleum revenue tax |
(3.4) |
(6.0) |
|
|
197.5 |
(43.8) |
|
|
383.9 |
89.7 |
* Certain numbers shown above do not correspond to the 2010 financial statements as a result of retrospective restatement as set out in note 11.
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 26% (2010: 28%) to the profit before tax is as follows:
|
|
2011 |
*Restated 2010 |
|
Group profit on ordinary activities before tax |
1,072.9 |
179.2 |
|
|
279.0 |
50.2 |
|
|
|
|
|
Expenses not deductible for tax purposes |
69.7 |
36.4 |
|
Utilisation of tax losses not previously recognised |
(20.9) |
(1.5) |
|
Net losses not recognised |
21.3 |
22.0 |
|
Petroleum revenue tax (PRT) |
9.1 |
1.8 |
|
UK corporation tax deductions for current PRT |
(3.0) |
(0.9) |
|
Adjustments relating to prior years |
(5.8) |
0.5 |
|
Adjustments to deferred tax relating to change in tax rates |
18.2 |
- |
|
Income taxed at a different rate |
82.3 |
21.5 |
|
Income not subject to corporation tax |
(66.0) |
(40.3) |
|
|
383.9 |
89.7 |
* Certain numbers shown above do not correspond to the 2010 financial statements as a result of retrospective restatement as set out in note 11.
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 $1,082.3 million (2010: $840.1 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 $117.5 million in deferred tax assets in relation to taxable losses (2010: $175.1 million).
No deferred tax liability is recognised on temporary differences of $253.0 million (2010: $485.6 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
|
|
2011 |
*Restated 2010 |
|
Profit before taxation |
1,072.9 |
179.2 |
|
Adjustments for: |
|
|
|
Depletion, depreciation and amortisation |
533.8 |
367.3 |
|
Impairment loss |
51.0 |
4.3 |
|
Impairment reversal |
(17.4) |
- |
|
Exploration costs written off |
120.6 |
154.7 |
|
Profit on disposal of oil and gas assets |
- |
(0.5) |
|
Profit on disposal of other assets |
(2.0) |
- |
|
Decommissioning expenditure |
(14.2) |
(10.3) |
|
Share-based payment charge |
28.5 |
11.9 |
|
Loss on hedging instruments |
(27.2) |
27.7 |
|
Finance revenue |
(36.6) |
(15.1) |
|
Finance costs |
122.9 |
70.1 |
|
Operating cash flow before working capital movements |
1,832.3 |
789.3 |
|
Increase in trade and other receivables |
(91.9) |
(66.7) |
|
Increase in inventories |
(43.8) |
(56.3) |
|
Increase in trade payables |
206.5 |
151.7 |
|
|
1,903.1 |
818.0 |
* Certain numbers shown above do not correspond to the 2010 financial statements as a result of retrospective restatement as set out in note 11.
9. Called up equity share capital
In the year ended 31 December 2011, the Group issued 16,678,379 (2010: 83,922,894) new shares which included issuing 3,009,637 (2010: 1,918,305) new shares in respect of employee share options, issuing 3,531,546 (2010: 82,004,589) new shares in respect of a share placing to institutional investors and issuing 10,137,196 ordinary shares in respect of the EO Group Limited transaction representing an increase of approximately 1.6% of the existing issued share capital.
As at 31 December 2011 the Group had in issue 904,915,249 allotted and fully paid ordinary shares of Stg10 pence each (2010: 888,236,870).
10. Business combinations
On 24 May 2011 Tullow announced that it had acquired 100% of Nuon Exploration & Production B.V. ("Nuon") from the Vattenfall Group. The acquisition of Nuon added a portfolio of 25 licences, over 30 producing fields, a number of development and exploration opportunities and ownership of key infrastructure. The Nuon transaction had an effective date of 1 January 2011 but completed on 30 June 2011 and this is therefore the acquisition date. Accordingly, the financial statements include the balance sheet of Nuon including fair value adjustments. Revenue and expenses were included within the Group income statement from 1 July 2011.
The fair value allocation to the Nuon assets is preliminary due to the finalisation of an independent review of acquired contingent resources and will be reviewed in accordance with the provisions of IFRS 3 - Business Combinations. The purchase consideration equals the aggregate of the fair value of the identifiable assets and liabilities of Nuon and therefore no goodwill has been recorded on the acquisition. Deferred tax has been recognised in respect of the fair value adjustments as applicable.
|
|
Provisional fair value |
|
Intangible exploration and appraisal assets |
424.1 |
|
Property, plant and equipment |
539.6 |
|
Trade and other receivables |
19.8 |
|
Trade and other payables |
(20.0) |
|
Deferred tax liabilities |
(472.9) |
|
Provisions |
(86.6) |
|
|
404.0 |
Transaction costs in respect of the Nuon acquisition of $1.1 million have been recognised in the income statement. From the date of the acquisition, Nuon has contributed $67.6 million to Group revenues and $3.2 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 year would have been $2,384.3 million and group profit would have been $695.4 million.
11. Retrospective restatement
During the year the group has revised its inventory oil product valuation accounting policy to value inventory oil product at net realisable value in line with IAS 2 Inventories. In order to aid comparability the group has retrospectively applied the revised accounting policy. The impact on the financial statements is summarised in the below table.
|
|
Previously stated |
Impact of revision in accounting policy |
Restated 2010 |
|
Effect on income statement: |
|
|
|
|
Cost of sales |
(611.4) |
27.3 |
(584.1) |
|
Profit from continuing activities before tax |
151.9 |
27.3 |
179.2 |
|
Income tax expense |
(79.4) |
(10.3) |
(89.7) |
|
|
72.5 |
17.0 |
89.5 |
|
|
|
|
|
|
Deferred tax assets |
110.7 |
(10.3) |
100.4 |
|
Non-current assets |
7,087.3 |
(10.3) |
7,077.0 |
|
Inventories |
138.2 |
44.8 |
183.0 |
|
Current assets |
1,290.7 |
44.8 |
1,335.5 |
|
Total assets |
8,378.0 |
34.5 |
8,412.5 |
|
Current tax liabilities |
(120.0) |
(0.6) |
(120.6) |
|
Current liabilities |
(1,485.1) |
(0.6) |
(1,485.7) |
|
Deferred tax liabilities |
(466.1) |
0.6 |
(465.5) |
|
Non-current liabilities |
(3,024.0) |
0.6 |
(3,023.4) |
|
Total liabilities |
(4,509.1) |
- |
(4,509.1) |
|
Net assets |
3,868.9 |
34.5 |
3,903.4 |
|
Retained earnings |
2,839.1 |
34.5 |
2,873.6 |
|
|
3,868.9 |
34.5 |
3,903.4 |
12. Commercial Reserves and Contingent Resources summary (unaudited) working interest basis
|
|
ESAA |
WNA |
SEA |
TOTAL |
|
|||||
|
|
Oil |
Gas |
Oil |
Gas |
Oil |
Gas |
Oil |
Gas |
Petroleum |
|
|
|
mmbbl |
bcf |
mmbbl |
bcf |
mmbbl |
bcf |
mmbbl |
bcf |
mmboe |
|
|
COMMERCIAL RESERVES |
|
|
|
|
|
|
|
|
|
|
|
31 December 2010 |
1.7 |
258.5 |
245.9 |
22.0 |
- |
- |
247.6 |
280.5 |
294.4 |
|
|
Revisions |
- |
8.7 |
8.1 |
(0.8) |
- |
- |
8.1 |
7.9 |
9.4 |
|
|
Acquisitions |
0.1 |
79.4 |
9.0 |
- |
- |
- |
9.1 |
79.4 |
22.3 |
|
|
Additions |
- |
- |
- |
- |
- |
- |
- |
- |
- |
|
|
Disposals |
- |
- |
- |
- |
- |
- |
- |
- |
- |
|
|
Production |
(0.2) |
(43.9) |
(20.6) |
(2.2) |
- |
- |
(20.8) |
(46.1) |
(28.5) |
|
|
31 December 2011 |
1.6 |
302.7 |
242.4 |
19.0 |
- |
- |
244.0 |
321.7 |
297.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONTINGENT RESOURCES |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
31 December 2010 |
- |
98.9 |
120.7 |
798.1 |
772.5 |
301.7 |
893.2 |
1,198.7 |
1,093.1 |
|
|
Revisions |
- |
- |
2.6 |
(7.0) |
14.3 |
79.3 |
16.9 |
72.3 |
29.0 |
|
|
Acquisitions |
- |
94.0 |
25.1 |
393.3 |
- |
- |
25.1 |
487.3 |
106.3 |
|
|
Additions |
36.6 |
- |
60.3 |
146.4 |
113.7 |
- |
210.6 |
146.4 |
235.0 |
|
|
Disposals |
- |
- |
(18.2) |
- |
- |
- |
(18.2) |
- |
(18.2) |
|
|
31st December 2011 |
36.6 |
192.9 |
190.5 |
1,330.8 |
900.5 |
381.0 |
1,127.6 |
1,904.7 |
1,445.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
31 December 2011 |
38.2 |
495.6 |
432.9 |
1,349.8 |
900.5 |
381.0 |
1,371.5 |
2,226.4 |
1,742.8 |
|
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 both Tullow's estimates and the Group reserves report produced by an independent engineer.
3. The ESAA commercial and contingent resources acquisition in 2011 relates to the purchase of the Nuon assets from the Vattenfall Group.
4. The West and North Africa commercial and contingent resources acquisition in 2011 relates to the purchase of EO Group Limited Ghanaian interests and increased equity levels in Mauritania.
5. The total Commercial Reserves and Contingent Resources of 1,742.8 mmboe at 31 December 2011 include Tullow's working interest in Blocks 1, 2 and 3A in Uganda pre completion of the farm-down transaction with Total and CNOOC in Uganda. Post completion of the farm-down, total Commercial Reserves and Contingent Resources are expected to reduce to 1,139.0 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 260.6 mmboe at 31 December 2010 (31 December 2010: 231.6 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 over 90 production and exploration licences in 22 countries which are managed as three regional business units: West & North Africa, South & East Africa and Europe, South America and Asia. 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 14 March until 28 March. The telephone numbers and access codes are:
|
Live event |
Replay facility available from Noon |
||
|
UK Participants |
020 7136 2054 |
UK Participants |
020 7111 1244 |
|
Irish Participants |
01 659 0423 |
Irish Participants |
01 486 0902 |
|
|
|
Access Code |
6115465 |
To join the live Video webcast, or play the on-demand version which will be available from noon on 14 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 |
020 3003 2666 |
UK Local Call |
0808 109 0700 |
|
International Participants |
44 20 3003 2666 |
Irish Free Call |
1 800 930 488 |
|
USA Toll Free |
1 866 966 5335 |
Access Code |
4843829 |
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 1900 on 14 March until 28 March. The telephone numbers and access codes are:
|
Live Event |
Replay Facility available from 19:00 |
||
|
Domestic Toll Free |
+1 877 280 2342 |
Toll |
+1 347 366 9565 |
|
Toll |
+1 646 254 3366 |
Access Code |
4620844 |
For further information contact:
|
Tullow Oil plc +44 20 3249 9000 |
Citigate Dewe Rogerson +44 20 7638 9571 |
Murray Consultants +353 1 498 0300 |
|
Chris Perry / James Arnold - Investor Relations |
Martin Jackson |
Joe Murray |
|
George Cazenove - Media Relations |
Kate Lehane |
Ed Micheau |
This information is provided by RNS
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