2012 Full Year Results

 

Good financial performance and significantly strengthened balance sheet

Basin-opening success in Kenya at Ngamia-1 and Twiga South-1

Over 40 E&A wells planned for 2013 in Africa and the Atlantic Margins

 

 

13 February 2013 - Tullow Oil plc (Tullow), the independent oil and gas exploration and production group, announces its results for the year ended 31 December 2012.

 

2012 Full Year Results Highlights

·    Financial results in line with market expectations and balance sheet substantially strengthened through debt re-financing and $2.9bn from Uganda farm-down.

·    Following successful and cost-effective well remediation, the Jubilee field is now producing around 110,000 bopd; A 2013 exit rate in excess of 120,000 bopd is expected.

·    Tweneboa-Enyenra-Ntomme (TEN) project Plan of Development submitted; approval expected shortly.

·    Major basin-opening discovery in Kenya with the Ngamia-1 and Twiga South-1 wells; Twiga South-1 well flow-tested at a combined rate of  2,351 barrels of 37 degree API oil from two zones with the final test ongoing.

·    Significant strategic portfolio management with a renewed focus on light oil including the acquisition of Norway's Spring Energy for $372m and the disposal of gas assets in Europe and Asia.

·    Additional new country entries in Africa and the Atlantic margins; Guinea, Greenland, Uruguay and Mozambique.

·    40+ E&A well campaign planned for 2013; High-impact wells expected in Kenya, Ethiopia, Mauritania, Mozambique, Norway, French Guiana and Côte d'Ivoire.

 

Financial overview

	2012	2011	Change
Sales revenue ($m)	2,344	2,304	+2%
Operating profit ($m)	1,185	1,132	+5%
Profit before tax ($m)	1,116	1,073	+4%
Profit after tax ($m)	666	689	-3%
Basic earnings per share (cents)	68.8	72.5	-5%
Full year dividend per share (pence)	12.0	12.0	0%
Operating cash flow before working capital ($m)	1,777	1,832	-3%
Working interest production (boepd)	79,200	78,200	+1%
Realised oil price per barrel ($)	108.0	108.0	0%
Realised gas price per therm (pence)	58.5	57.0	+3%

 

Commenting today, Aidan Heavey, Chief Executive, said:

"2012 was a year of major progress for Tullow. We materially enhanced the business with a basin-opening oil discovery in Kenya, by adding highly prospective new licences in Africa and the Atlantic Margins, refinancing our debt and partially monetising our Ugandan assets. The Jubilee Field in Ghana is now approaching its full potential and provides the base for our production profile and operational cash flow. Our financial position underpins our highly ambitious 2013 exploration programme which has high-impact wells planned in Kenya, Ethiopia, Norway, Mauritania, Mozambique, Côte d'Ivoire and French Guiana. This focus on exploration-led growth, together with active portfolio management and Tullow's strong balance sheet, provides an excellent platform for growth in 2013 and beyond."

 

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.

 

 

 

2012 overview and 2013 outlook 

 

Solid financial performance in 2012

Tullow delivered another solid financial performance in 2012. While the oil price was volatile throughout the year due to economic and political uncertainty, it averaged $108 per barrel, in line with 2011. Sales revenue grew by 2% to $2,344 million (2011: $2,304 million) due to higher sales volumes. Profit from continuing activities before tax increased by 4% to $1,116 million (2011: $1,073 million) as the $701 million pre-tax gain on the Uganda-farm down was largely offset by an increase in total exploration write-offs, which amounted to $300 million for 2012 activities coupled with a further asset write-down announced at the half year giving a total of $671 million (2011: $121 million), and higher operating costs associated with mature fields. Profit from continuing activities after tax declined 3% to $666 million (2011: $689 million) and basic earnings per ordinary share from continuing activities decreased 5% to 68.8 cents (2011: 72.5 cents).

Basin-opening exploration in 2012

In 2012, Tullow invested close to $1 billion in exploration and appraisal, drilling 46 Exploration & Appraisal wells with an overall success ratio of 74%. The discovery of a new oil basin in Kenya - the fourth major basin-opening discovery by Tullow in the past six years - was the highlight of the year and significant success was also achieved in Uganda and Ghana. There were also some disappointments, particularly the Zaedyus-2 well, which failed to intersect oil but nevertheless added significantly to our knowledge of this new oil basin, offshore French Guiana.

High-quality, oil-focused production

Jubilee field production issues, offshore Ghana, were successfully and cost-effectively remediated in 2012. The field is currently producing around 110,000 bopd and the total well production capacity is now over 120,000 bopd. There was a slight shortfall in overall Group production versus our target for 2012 due to the enforced shutdown of Tullow's non-operated production in the CMS area of the UK in early December 2012 following a third party safety incident. As a result, Group working interest production averaged 79,200 boepd, which was broadly similar to 2011. Production guidance for 2013 is in the range of 86,000 to 92,000 boepd. This guidance includes gas producing assets currently held for sale. Following the proposed sale of these assets, Tullow's production will be predominantly focused on higher-margin, low cost-per-barrel light oil.

Active Portfolio management

In early 2012 Tullow took a decision to exit Bangladesh and Pakistan and expects to complete this disposal by the end of 2013. In December 2012, Tullow announced its intention to sell its gas assets in the UK and Netherlands sectors of the Southern North Sea. These assets have served Tullow well, providing vital cash flow to fund an ambitious exploration programme, but they no longer fit with the Group's strategy of pursuing big oil exploration opportunities in Africa and the Atlantic Margins. As a consequence, they can no longer compete for capital effectively with other projects within the portfolio. During 2012, Tullow entered new licences in Mozambique, Guinea, Greenland and Uruguay. Tullow also made a significant acquisition in Norway with the purchase of Spring Energy where the group will be exploring for oil in highly prospective Atlantic Margin acreage.

Well-funded and strong balance sheet

The farm-down of Uganda transformed Tullow's balance sheet and high-value production growth in Ghana underpins strong operational cash flow for the Group, approaching $2 billion per annum. In November 2012 Tullow extended the final maturity of its $3.5 billion Reserved Base Lending credit facility to 2019 and took the opportunity to create a more flexible facility to better serve its funding needs.

Board changes and dividend

Non-executive Directors David Williams and Steve McTiernan retired after six and ten years respectively of exceptional service to Tullow. In 2012, Steve Lucas and Anne Drinkwater joined the board, bringing valuable financial and industry experience. David Bamford has taken over as Senior Independent Director. In view of Tullow's intensive exploration campaign in 2013, the Board intends to maintain the final dividend payment of 8.0 pence per share, bringing the total payout for the year to 12 pence per share.

Strategy and outlook

Tullow's exploration-led strategy is enabled by the Group's financial strength. Through cashflow from production and asset sales, and through appropriate leverage, Tullow funds both its E&A programmes and those developments to which the Group decides to commit. Tullow is an exploration-led business and views production as part of the cashflow required to fund major, high-growth exploration campaigns.

Tullow has the right team, the right approach, the right assets and the funding in place to maintain its track record of success. Tullow is consistent in its exploration-led growth strategy with a focus on light oil in frontier areas and continues to re-shape its assets to provide the Group with further access to material opportunities. At the beginning of 2013, Tullow has an exceptionally strong platform for future growth and is well placed to drive the strategy and the business forward.

 

Operations review

 

 

WEST AND NORTH AFRICA

 

2012 production 57,850 boepd

Total reserves and resources 647.0 mmboe

Sales revenue $1,964 million

2012 investment $1,087 million

 

 

Ghana

Tullow has interests in two licences offshore Ghana, Deepwater Tano and West Cape Three Points, with the Jubilee Field straddling both licence areas. In 2012, Tullow conducted a highly successful and cost-effective remediation programme on a number of wells in the Jubilee field. Towards the end of 2012, the first Jubilee Phase 1A well was brought on-stream with the second coming on-stream in early January 2013. The FPSO Kwame Nkrumah, which serves the Jubilee field, continues to perform well with a very low rate of unplanned shut-downs and an excellent safety and environmental record.

 

During the year, the Group also successfully appraised the Tweneboa-Enyenra-Ntomme (TEN) Cluster Development and submitted a Plan of Development (PoD) for the TEN project in November 2012. Approval of the PoD is expected in the near future. Exploration drilling activity in the Deepwater Tano licence continued throughout 2012.

 

Jubilee field Phase 1 and Phase 1A Developments

Since the start-up of production at the end of 2010 to the end of January 2013, the Jubilee field had produced 55 million barrels of oil. Gross field production during 2012 averaged 72,000 bopd. This was slightly lower than envisaged at the start of the year due to productivity issues with some of the wells. Acid stimulations proved to be the best and most cost-effective solution to these issues and well productivity has been restored at a cost of $160 million gross, significantly below the amount originally budgeted at the start of 2012.

 

The Jubilee Phase 1A development project, designed to increase production and recover additional reserves, was approved by the Government of Ghana in January 2012. Phase 1A consists of eight new wells of which five are producers and three are additional water injectors. The project has progressed well with two wells currently producing and three more expected on stream by the end of the third quarter of 2013.

 

As a result of the Phase 1 remediation programme and Phase 1A production coming on stream at the end of 2012, gross production increased during the year, exiting 2012 at around 110,000 bopd. 2013 average gross production is expected to be within the range of 100,000-110,000 bopd with a year end exit rate in excess of 120,000 bopd. The increase from current production levels will follow work scheduled to take place in the third quarter of the year to remove gas compression constraints on the FPSO. A full field development plan that sets out future investment opportunities has been prepared and is being discussed with the Government of Ghana. This work demonstrates the potential to significantly extend the Jubilee production plateau.

 

TEN Appraisal and Development

During 2012 the Group made good progress on the Development Plan for the TEN Project which culminated in the Declaration of Commerciality and the Plan of Development (PoD) being submitted to the Minister of Energy in November 2012. The current estimated capex cost for the base development plan, which includes around 23 injection and production wells, and excludes FPSO lease costs, is around $4.5 billion. As at 31 December 2012 Tullow has transferred 112 mmboe from contingent resources to commercial reserves in respect of the TEN development.

 

The TEN appraisal programme, which started in January 2011, continued in 2012 with the drilling of three wells. The Owo-1RA well was drilled and successfully tested in January 2012 at combined rates in excess of 20,000 bopd. Enyenra-4A was drilled in March 2012, intersecting 32 metres of oil pay. Water injection tests on this down-dip well were carried out in April 2012, with results proving that the Enyenra channel sands are suitable for water injection to support oil production.

 

The Ntomme-2A well was drilled in January 2012 and found oil (the Ntomme discovery well) down dip of the Tweneboa-3ST non-associated gas discovery. The well was production tested in May 2012 at combined flow rates in excess of 20,000 bopd, confirming excellent quality reservoir. The top-hole of the final appraisal well, Enyenra-6A, has been drilled and will be completed in Q1 2013 after the drilling of Sapele-1. Pressure gauges were installed in a number of the exploration and appraisal wells and readings have confirmed reservoir continuity within the core parts of the Enyenra and Ntomme fields.

 

The FPSO design competition was completed and bids have now been received from the two contractors and these are being evaluated. A contract award will take place in early 2013, subject to PoD approval. The subsea FEED is now complete and the tender evaluation process ongoing. The TEN FPSO production capacity has been optimised at around 80,000 bopd with a flexible design allowing for potential future expansion to allow near field resource potential to be tied in. As previously guided, first production from the TEN Project is anticipated to be between 32 and 36 months after Government of Ghana approval of the PoD.

 

Exploration and Appraisal activity

Exploration drilling activity in the Deepwater Tano licence continued in 2012. The first of three wells, Wawa-1, was completed drilling in July 2012. The results of drilling, wireline logging and sampling showed that Wawa-1 had intersected separate oil and gas condensate accumulations up dip of the Enyenra field which the Deepwater Tano partners have elected to appraise.

 

The Okure-1 exploration well reached its planned total depth of 4,511 metres in December 2012. The well was then plugged and abandoned after encountering light oil within a gross 17 metre interval of low net to gross Turonian age sandstone reservoirs. Integration of wireline logs and pressure data indicated that this oil accumulation was not connected to other hydrocarbon discoveries in the licence area. The Sapele-1 well is the last exploration well to be drilled on the Deepwater Tano block prior to the end of the Exploration Period in the first quarter of 2013. The well spudded in December 2012 and has been drilled to a depth of 3,900 metres. The primary target encountered a high-quality water-bearing reservoir and drilling operations are now continuing to a deeper target.

 

In the West Cape Three Points licence, the Teak-4 appraisal well encountered thin non-commercial reservoirs and the well was plugged and abandoned. Appraisal activities were also performed including installing downhole pressure gauges in Teak 2 and a DST at Akasa-1 with rates exceeding 7,500 bopd. Discussions are on-going in relation to further appraisal and development plans for the Mahogany, Teak and Akasa discoveries. In January 2013, the discovery area associated with the Banda discovery on the West Cape Three Points licence was relinquished.

 

Mauritania

During 2012, Tullow continued to build the in-country infrastructure needed to support a high-impact exploration programme of up to four wells. The drilling campaign, scheduled to commence in the second quarter of 2013, is designed to drill new deeper plays in the offshore Mauritanian basin which have not been tested by previous exploration wells. Three of the four wells are scheduled to be drilled in 2013 using the West Leo rig which has been operating in Ghana for Tullow. The Group believes that there is significant follow-on potential if any of these wells proves to be successful.

 

Tullow continued to build its equity position offshore Mauritania, following the award of the new C-10 licence in 2011 we have also completed farm-ins to the C-6 and C-7 Blocks. The C-10 licence was awarded to cover the exploration areas previously covered by the Production Sharing contracts PSC A and PSC B. Extensions were also granted to the discovery areas of the PSC A and B licences which contain the Banda, Tevet and Tiof oil and gas discoveries. Tullow has increased its equity in all of these areas to over 60% and is the operator.

 

In November 2012 the Banda field was declared commercial and it is planned that the field will supply gas to a new local power station, subject to completion of a suitable Gas Sales Agreement. Discussions are now under way to put in place the commercial agreements that will underpin the project.

 

Production from the Chinguetti field in Mauritania, which is a separate play type from the Group's new exploration acreage, averaged 1,300 boepd in 2012, a decline from 1,400 boepd in 2011 and in-line with expectations.

 

Liberia and Sierra Leone

Tullow has four contiguous deepwater licences offshore Liberia and Sierra Leone where the Group is looking to extend the Ghana Jubilee-play westwards. In February 2012, the Group announced that the Jupiter-1 exploration well in Sierra Leone had encountered 30 metres of net pay in multiple zones. This confirmed a working hydrocarbon system in the Liberian Basin. The Mercury-2 exploratory well, drilled in April 2012, intersected thick water bearing sandstone reservoirs with oil shows.

 

In Liberia, reprocessing of the extensive 3D seismic data from Blocks LB-16 and LB-17 began in the second half of 2012. Analysis of well results and extensive 3D seismic data acquired in this basin continues with a view to refining the remaining prospectivity and commercialising the discovered resources. The results from this further work on all four licences so far has proven encouraging for the overall exploration programme in the West African Equatorial Atlantic where Tullow continues to seek a hub-class discovery.

 

Côte d'Ivoire

Net production for 2012 from the East and West Espoir fields averaged 3,400 boepd as natural field declines continue to be managed. A new drilling campaign of eleven infill wells (seven producers and four injectors) across the field is to start by the end of the first quarter of 2013. This campaign will sustain production and extend the life of the field.

 

Two exploration wells were drilled in Côte d'Ivoire in the first half of 2012. The first well, Kosoru-1 on Block CI-105, encountered thick sandstone reservoirs but log analysis indicated that they were water bearing at this location and so the licence was relinquished in August 2012.

 

In Tullow-operated Block CI-103, the Group drilled the Paon-1X exploration prospect. This well successfully encountered 31 metres of net oil pay in a relatively high net-to-gross interval and evaluation of this oil discovery is ongoing. An appraisal plan for the Paon discovery was submitted in January 2013. A second exploration well is planned for the second quarter of 2013 on the adjacent Calao prospect and may be followed later by a further well on the Paon discovery.

 

Equatorial Guinea

The Ceiba field performed strongly in 2012 with net production averaging 2,850 bopd. A workover and infill drilling campaign that commenced in January 2012 continues to perform well with the first three workovers and two new wells contributing materially to production. New 4D seismic data interpretation has delivered good results to date enabling the well paths of the workovers and new wells to be optimally positioned. Four further production wells are planned to increase current production levels.

 

Net production from the Okume Complex exceeded expectations, averaging 8,350 bopd in 2012. A rig has been secured to carry out a major infill drilling campaign of at least ten wells on the Okume Complex fields commencing in the fourth quarter of 2013.

 

The processing and interpretation of another new 4D seismic survey continues and will help define an infill drilling programme over the Elon area on the shallower part of the licence.

 

Gabon
Net production in Gabon, particularly from Tchatamba, Limande, Niungo and Echira fields, was strong in 2012 averaging 14,000 bopd, in line with expectations.

 

Appraisal and infill drilling has been very successful on Tullow's Gabon assets during the year. The Tchatamba-South B9 well has been drilled and is now producing 1,000 bopd net and the more recent Limande-8 Hz development well is producing 1,400 bopd net.

 

Exploration drilling plans in Kiarsseny are well advanced, with a two well operated programme due to commence in the middle of 2013. Acquisition of 2D seismic surveys in the Nziembou and DE7 blocks have now been completed with exploration wells to be drilled on both licences in 2014. Interpretation of data acquired from a 3D survey in the complex Arouwe Block is ongoing and will be followed by a well in 2014.

 

Significant offshore and onshore drilling activity is expected to continue on all fields in 2013, with a programme exceeding 60 infill wells across the Gabon portfolio.

 

Congo (Brazzaville)

Net production from the M'boundi field remained stable during 2012, averaging 2,500 bopd. Sustained water injection and the continuing work-over and infill drilling campaign arrested the decline seen in 2011. Two recent wells successfully increased production and opened up a southeast extension of the field.

 

In the first quarter of 2013, a gas injection project, which was the last component of the M'boundi Field redevelopment, will be delivered and will target a series of specific fault blocks.

 

Guinea

At the end of December 2012, Tullow acquired a 40% operated interest in Hyperdynamics Corporation's oil and gas exploration concession, offshore Guinea. Approval from the government was granted in January 2013 and the parties intend to begin drilling a well to test a deepwater fan prospect before April 2014.

 

 

 

SOUTH AND EAST AFRICA

 

2012 production NIL

Total reserves and resources 441.6 mmboe

Sales revenue NIL

2012 investment $433 million

 

Uganda
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 its new partners, CNOOC Limited and Total, to complete a farm-down of two thirds of Tullow's interests in Uganda on 21 February 2012 for a headline consideration of approximately $2.9 billion. As a result, all Partners now have a one third interest in each of the Exploration Areas: Exploration Area-1 (EA-1), Exploration Area-2 (EA-2) and the Kingfisher production licence. Operating responsibilities within the basin are divided between the Partners: Total operates EA-1 and Tullow operates EA-2. In the former Exploration Area-3A, CNOOC Limited operates the Kingfisher production licence. Following completion of the farm-down, the Partners also each held a one third interest in the Kanywataba prospect area, also located in the former Exploration Area-3A but in August 2012 this exploration licence expired and the associated PSA terminated.

 

In March 2011, Tullow was designated by the Ugandan Revenue Authority (URA) as agent to the transaction between Tullow and Heritage. This designation required Tullow to pay, as agent on behalf of Heritage, $313 million to the URA. This sum is equivalent to the Capital Gains Tax that the Ugandan Government believes it is owed by Heritage. Separately, Tullow has commenced proceedings against Heritage in the High Court, London to recover this sum under the terms of the Sale and Purchase Agreement with Heritage. The case is due to be heard in March 2013.

 

Tullow has also been assessed by the URA for Capital Gains Tax on the farm-down to CNOOC and Total. The assessment of $473 million is disputed by Tullow. Following the payment of $142 million to the URA on account - being 30% of the assessed amount that Tullow was required to pay under Ugandan law in order to dispute the assessment - the case will be heard before the Tax Appeals Tribunal in Kampala. A decision is expected in the second half of the year. On the advice of leading counsel, the Group believes it has a strong case under both international and Ugandan law and currently views the most probable outcome to be that any liability will be at a similar level to the amount already paid on account.

 

Following a hiatus in which the PSAs and farm-down were agreed, a significant appraisal and testing campaign commenced in EA-1 in 2012. This campaign includes over 20 appraisal wells, extensive well-testing and 3D seismic acquisition on the Mpyo, Gunya, Ngiri, Jobi-Rii and Jobi-East discoveries over the course of 2012 and 2013.

 

In the Tullow-operated EA-2 block, successful appraisal drilling and testing activities in the Kasamene-Wahrindi and Kigogole/Nsoga/Ngege/Ngara areas continued throughout 2012.

 

In the Kanywataba prospect area, in the southern part of the Lake Albert Rift Basin, the Kanywataba-1 exploration well operated by CNOOC Limited spudded in May 2012. However, the reservoir proved to be water bearing. This was the last exploration well in the southern part of the basin and the Kanywataba prospect area exploration licence expired in August 2012.

 

Four wildcat exploration wells were drilled in EA-1 up to December 2012 to help delimit the ultimate basin potential ahead of potential relinquishments. Riwu-1 (tested far northwestern limits), Raa-1 (tested northern extent) and Til-1 (tested far northeastern limits) did not encounter commercial hydrocarbons. However, the Lyec-1 well encountered oil pay, which is currently under evaluation and re-mapping. A significant amount of outstanding exploration and appraisal drilling activity remains in 2013.

 

Tullow, CNOOC Limited and Total presented a joint development plan concept for the Lake Albert Rift Basin to His Excellency the President of Uganda and the Government of Uganda in July 2012. A Committee was then set up by the Government of Uganda comprising representatives of key ministries and the three Operators to discuss the remaining issues in order to progress the Lake Albert Rift Basin development plan with a view to harmonising plans for the development during the first half of 2013. Constructive discussions are ongoing. 

 

Kenya and Ethiopia

Tullow's acreage in Kenya and Ethiopia includes Blocks 10A, 10BA, 10BB, 12A, 12B & 13T in Kenya and the South Omo Block in Ethiopia which together cover around 100,000 sq km. Tullow operates all seven of these blocks and has a 50% interest in six of them. In July 2012, Tullow completed the acquisition of an additional 15% interest in Block 12A, taking its interest in that block to 65%. Tullow also has a 15% interest in Block L8, offshore Kenya, with an option to increase this equity by a further 5%.

 

The onshore acreage covers over 10 Rift Basins in Kenya and Ethiopia, which have similar characteristics to the Lake Albert Rift Basin, and include a southeast extension of the geologically older Sudan Rift Basins trend. Exploration drilling in the Kenya Rift Basins commenced in January 2012 with the drilling of the Ngamia-1 wildcat well in Block 10BB. The well was drilled to a total depth of 2,340 metres and made a significant oil discovery of over 100 metres of net oil pay, across multiple reservoir zones within a 1.1 km thick gross oil bearing interval.

 

Exploration activity continued with the Twiga South-1 well which spudded in August 2012 and is located, on-trend, 22 km from Ngamia-1 in Block 13T. In November 2012, the Group announced that the well had encountered 30 metres of net oil pay and an additional tight reservoir rock section with hydrocarbon shows over a total gross interval of 796 metres. Moveable oil, with an API greater than 30 degrees, was recovered to surface from all sections, during an MDT sampling programme.

 

The discoveries at Ngamia and Twiga South demonstrate that substantial oil generation has occurred in the South Lokichar Basin, one of more than 10 Tertiary Rift Basins in the Kenya-Ethiopia acreage, each of which is similar in size to the Lake Albert Rift Basin in Uganda. To build up our knowledge of the natural variance in reservoir performance, and to assess deliverability and reserves, a series of flow tests will be conducted on both wells.

 

Four flow tests have so far been carried out on the Twiga South-1 well in January and early February 2013 and a fifth test is ongoing. A cumulative rate of 2,351 bopd was recorded from two separate sands in the Auwerwer formation. One test flowed naturally without pumping at a maximum flow rate of 1,860 bopd of 37°API oil and the other flowed at a rate of 491 bopd using a Progressive Cavity Pump (PCP). The final flow test in the Auwerwer formation is ongoing using a PCP and we anticipate that the zone will flow over 500 bopd taking the total combined rate to over 2,850 bopd for the well. Two deeper tests were also completed on the tight reservoir rock at the bottom of the well and, as anticipated, both produced at sub-commercial flow rates and reconfirmed the presence of moveable oil.

 

These tests provide the first potentially commercial flow rates achieved in Kenya and provide real encouragement for the Ngamia test. With the conclusion of the Twiga South-1 testing programme, the Weatherford-804 rig will move to Ngamia-1A to re-enter the well and perform four flow tests. These tests are expected to deliver rates similar to Twiga South-1.

 

A Full Tensor Gradiometry (FTG) Gravity Survey has been completed across most of the Kenya-Ethiopia licence area and over 100 leads and prospects have currently been identified. Three drilling rigs are currently operational along with two seismic crews. Given the positive results to date, work is under way to secure further operational capacity to accelerate the exploration and appraisal campaign; this will include a further light rig for flow testing activities, and a 3D seismic capability to appraise the now proven hydrocarbon potential of the Lokichar basin.

 

In 2013, Tullow plans to drill up to 11 exploration and appraisal wells and carry out up to five well tests to de-risk further basins and to understand the potential scale of the South Lokichar discoveries. Whilst both the Ngamia and Twiga South discoveries have exceeded expectations and substantially de-risked further prospects in the South Lokichar Basin, it will require considerably more exploration and appraisal activity to be completed before the commercial threshold for the basin is achieved.

 

Paipai-1 has been drilled to a total depth of 4,255 metres. Light hydrocarbon shows have been encountered while drilling through Lower Cretaceous sands. We have been unable to obtain samples conventionally due to difficult hole conditions. The well is now being cased to enable sampling and the measurement of reservoir properties over a narrow zone of interest. We plan to evaluate and report on the conclusions drawn from this activity by the end of February 2013. On completion of operations at Paipai the Sakson PR-5 will mobilise to Kenya Block 10BB to spud the Etuko-1 well in the Lokichar basin. The well is expected to spud in 2Q 2013.

 

The Sabisa-1 prospect in the South Omo block in Ethiopia commenced drilling in January 2013. This well is a high risk wildcat, testing for an entirely new petroleum system in the undrilled South Omo Basin. The rig is expected to drill up to two further wells in Tullow's Ethiopian rift basin acreage during 2013.

 

In Block L8, offshore Kenya, the Mbawa-1 well encountered 52 metres of net gas pay in the shallower primary targets. This was the first hydrocarbon discovery, offshore Kenya and clearly demonstrates a working petroleum system. The well has been plugged and abandoned but the results will be instrumental in deciding the next steps on this highly prospective licence.

 

Namibia

Tullow acquired an interest in the Kudu gas field through the acquisition of Energy Africa in 2004. Numerous initiatives have been pursued over the intervening years. 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. However, in the first half of 2012, Tullow wrote down its interest in Kudu following the regular six-monthly review of assets.

 

In late 2012, a Namibian Cabinet resolution indicated its support for Kudu as a strategic energy generation project for Namibia. A Cabinet sub-committee is facilitating further discussions to solicit the assistance of the World Bank, in an effort to improve the project structure and minimise Government exposure. In the meantime, negotiations resumed with NamPower to finalise the Project Development Agreement and Gas Sales Agreement heads of terms. Signature of these agreements are awaiting NamPower board approval, at which point the FEED stage of the project will commence with a target of reaching a final investment decision in the first quarter of 2014. Although Kudu remains written down, this project's status will be reviewed as progress is made.

 

Mozambique

In August 2012, Tullow farmed into two blocks in the southern part of the Rovuma Basin, area 2 and 5 offshore Mozambique, operated by Statoil. Tullow's interest is 25%, Statoil retains 65% while Empresa Nacional de Hidrocarbonetos (ENH), the national oil and gas company of Mozambique, holds a 10% carried interest. The blocks are located in a frontier area with a water depth varying between 300 and 2,400 metres and cover 7,800 square kilometres. The partnership plans to drill two wells in the licence, starting with the Cachalote well which is scheduled to commence drilling in Q2 using the Discoverer Americas rig.

 

Madagascar

Following the completion of a field programme in the first half of 2011, 560 km of good quality 2D seismic data was then acquired in Blocks 3109 and 3111. The rift basin trend covered by the seismic data has already proven successful for light oil in Block 3113, directly to the south. Based on encouraging data, Tullow's intention is to acquire further seismic and use this data to pick potential wildcat well location to commence drilling in early 2014. A farm out process will commence in early 2013, with the intention of reducing Tullow's equity from 100% to 50%.

 

Tanzania

The Ntorya-1 well commenced drilling in December 2011. Tullow decided not to participate in the final section of the well in March 2012. Tullow, having completed its well obligations in the northern part of the onshore Rovuma Basin without commercial success, subsequently relinquished its equity in the concession and has now exited the country.

 

 

EUROPE, SOUTH AMERICA & ASIA

 

2012 production 21,350 boepd

Total reserves and resources 114.3 mmboe

Sales revenue $381 million

2012 investment $350 million

 

Norway

On 11 December 2012, Tullow announced the acquisition of Spring Energy for $372 million. Having completed the transaction on 21 January 2013, the Group now plans to drill 10 wells, offshore Norway, in 2013 targeting a variety of oil prospects. Tullow's assessment of Spring's exploration portfolio of 28 licences at the point of purchase is that it contains in excess of 230 mmboe of risked prospective resources and has existing reserves and resources of 24 mmboe. Norway's licence terms, where 78% of costs of both successful and unsuccessful exploration drilling are returned, are also highly attractive.

 

This exploration portfolio was materially added to in January 2013 when Spring was awarded 13 licences, of which 4 are operated, in Norway's very competitive 2012 Awards in Predefined Areas licensing round. In common with the existing acreage, the new licences are located in all three areas of the highly prospective Norwegian Continental Shelf - North Sea, Norwegian Sea and the Barents Sea. Both Tullow and Spring applied for licences in Norway's 22nd licensing round, the results of which will be known in the second quarter of 2013.

 

This acquisition, alongside Tullow's qualification as an operator on the Norwegian Continental Shelf earlier in 2012, has allowed the Group to build a strong platform for future growth in Norway.

 

UK

Tullow announced in December 2012 that it intended to sell its production, development and exploration assets in the UK and Dutch Southern North Sea gas basin. The Southern North Sea gas business has been highly successful for Tullow and a key contributor to the Group's growth over the past decade. However, following exploration and development success in Ghana, Kenya and Uganda, these assets are now non-core to the Group and no longer fit within Tullow's light oil focused portfolio.

Overall net production from the UK assets in 2012 was marginally below expectations, averaging 10,050 boepd. This was due to schedule delays and well performance issues with the Ketch-10 infill well in the Caister Murdoch Area (CMS). An enforced shutdown of Tullow's non-operated production in the CMS area in early December 2012 was resolved by the end of the year. This shut-down occurred following a safety incident involving an operator of a separate field on which the CMS area relies for blend gas. In November 2012, flow testing at the Katy development, in the CMS area, achieved a rate of almost 100 mmscfd. In January 2013, CMS area production was enhanced when the field came on stream at a constrained rate of 44 mmscfd.

Netherlands

Production from the Netherlands in 2012 was been slightly below expectations, averaging 6,350 boepd.

 

Tullow increased its equity in the Dutch 'E' blocks from 30% to 60% by successfully acquiring XTO and GTO interests during 2012. Preparations have continued throughout the year to drill the play opening Vincent prospect in the Tullow operated E Blocks later in 2013 using the Ensco-92 rig.

 

Greenland

On 15 October 2012, the Group announced that Greenland's Government, Naalakkersuisut, had approved an agreement with Maersk Oil for Tullow to take a 40 per cent non-operated equity position in the 11,802 square kilometres Block 9 (Tooq licence), Baffin Bay, North West Greenland. The licence will be operated by Maersk Oil, which holds a 47.5 per cent interest, with the remaining 12.5 per cent interest held by Nunaoil, Greenland's state oil company.

 

The multi-year work programme is under way and following the submission of a full Environmental Impact Assessment (EIA), the first commitment was completed during summer of 2012 with the acquisition of 1,800 sq km of 3D seismic. Tullow is now working with its partners to evaluate the seismic data and carry out further environmental studies and a social impact assessment. Following comprehensive evaluation, a decision will be made on whether Tullow enters the next phase which would involve drilling an exploration well on the Tooq licence in 2015.

 

French Guiana

A 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 with Shell taking over Operatorship of the block on 1 February 2012. Tullow retains a 27.5% non-operated interest.

 

Following the successful Zaedyus-1 discovery well in September 2011, an extensive follow-up appraisal and exploration programme commenced in 2012 with GM-ES-2, the Zaedeyus appraisal well. The well, located 7km from the discovery well, commenced drilling on 6 July 2012 and was aimed at appraising the up-dip potential of the Zaedyus discovery and testing a deeper turbidite fan. In December 2012 Tullow announced that while the GM-ES-2 well encountered a total of 85 metres of reservoir quality sands with oil shows in several objectives, no commercial hydrocarbons were encountered at this location. Zaedyus-2 was the first of a four well drilling programme and drilling operations on the second well, GM-ES-3, on the Priodontes prospect in the west of the Cingulata fan system, commenced in December 2012. Drilling activities are ongoing and the joint venture has obtained valuable geological insights from the first two wells and applied them to this well.

 

An extensive 3D seismic programme either side of the Cingulata fan system commenced in July 2012. Over 750 sq km of 3D seismic has been acquired over the Cebus lead to the southeast, and acquisition of over 4,000 sq km 3D seismic programme to the northwest was completed in December 2012.

 

Guyana

The Jaguar-1 well in Guyana commenced drilling in February 2012. The well had been identified in advance as high-pressure/high-temperature and was drilling to depths untested by the industry in this area. A decision was taken in July 2012, to plug and abandon the well at a depth of 4,876 metres, without reaching the primary objective. The decision to stop drilling was taken after reaching a point in the well where the pressure design limits for safe operations prevented further drilling to the main objective. Analysis of data gathered from drilling operations has highlighted the significant challenges of drilling in this licence and the associated costs. The Georgetown licence expired on 25 November 2012 and while Tullow continues to evaluate oil exploration opportunities in Guyana and the wider region, Tullow decided not to participate in the next phase of the Georgetown license.

 

Suriname

Following the farm-down of 30% equity in offshore Suriname Block 47 to Statoil in December 2011, Tullow commenced a 3,000 sq km 3D seismic programme across the licence in the second quarter of 2012. The survey was completed in September 2012 and early results from the data processing are encouraging with final processed volumes over the prospects likely to be available by the middle of 2013. In early 2012, shallow drilling commenced in the non-operated onshore Coronie Block, targeting a different geological play to the offshore Cretaceous turbidite fan play. The five commitment wells in the block have now been completed and based on the results of this shallow drilling programme Tullow has decided not to participate in the next Exploration Period of the Coronie licence.

Uruguay

As part of the Group's strategy to increase its exposure to potentially significant basin opening exploration, Tullow successfully bid for offshore Block 15 in the Uruguayan 2nd Bid Round. In October 2012, following Government approval, Tullow signed 100% equity in the 8,030 sq km licence. The block lies in the Pelotas Basin in water depths between 2,000 and 3,000 metres. The geological plays being targeted in Uruguay are similar to the mid-Cretaceous stratigraphic turbidite plays that Tullow have targeted in West Africa and Northeast Latin America. Currently there is sparse 2D seismic over the licence and the forward work programme will include a 2,000 sq km 3D seismic programme which aims to mature existing leads into prospects and to identify further opportunities within the licence.

 

Bangladesh

Early in 2012 Tullow announced the planned divestment of its Asian gas assets in Bangladesh and Pakistan in order to focus on its core African and Atlantic Margin strategy. Tullow is proceeding with the sale process and has received a number of offers for both the Pakistan and the Bangladesh businesses which are currently under review.

 

Gross production in the Bangora field has been in line with expectations in 2012, averaging close to 100 mmcfd for the year. Planning is under way to work-over a number of the wells by mid-2013 to restore production to close to the plant capacity of 120 mmscfd. To enhance the life of the field, as well as its safety and reliability, the installation of compression and improvement in condensate storage and handling is proceeding as planned and will be largely completed during 2013.

 

Pakistan

In Pakistan, the year started with testing of the Jabbi-1 well, located 20km along trend west of Shekhan. As expected, the tests encountered gas, but a commercial flow rate was not achieved from the flank of the structure. This well was suspended whilst technical options for achieving potential gas production from the crest of the structure are reviewed.

 

Drilling of the Kohat-1 well was completed in October 2012, flowing gas and water. The well is interpreted to have encountered a fault zone and has been suspended for possible re-entry following acquisition of 3D seismic over the area which is now planned for early 2013.

 

The transfer of the Sara-Suri lease to Spud Energy, which had been awaiting government approval for some time, was completed in August 2012.

 

 

Finance review

 

2012 results overview

Tullow delivered solid financial results in 2012 and also significantly strengthened the balance sheet through portfolio activity and refinancing. Sales revenue grew 2% to $2.3 billion (2011: $2.3 billion) principally as a result of a 2% increase in sales volumes. Profit from continuing activities before tax was up 4% to $1.1 billion (2011: $1.1 billion) as a result of a combination of:

 

·       $40 million increase in sales revenue;

·       $701 million pre-tax gain on Uganda farm-down; and

·       Partly offset by an increase in exploration write-downs of $550 million and higher costs.

 

Profit for the year from continuing activities decreased 3% to $666 million (2011: $689 million). Basic earnings per share decreased by 5% to 68.8 cents (2011: 72.5 cents).

 

Production and commodity prices

Working interest production averaged 79,200 boepd, an increase of 1% for the year (2011: 78,200 boepd). The increase is primarily due to production from the Jubilee field offset by decline in mature fields. Sales volumes averaged 68,000 boepd, up 2% compared to 2011.

 

On average, oil prices in 2012 were consistent with 2011 levels. Realised oil price after hedging for 2012 was US$108.0/bbl (2011: US$108.0/bbl). European gas prices in 2012 were higher than 2011. The realised European gas price after hedging for 2012 was 58.5 pence/therm (2011: 57.0 pence/therm), an increase of 3%.

 

Operating costs, depreciation, impairments and expenses

Underlying cash operating costs, which excludes depletion and amortisation and movements on the underlift/overlift, amounted to $437 million; $14.6/boe (2011: $386 million; $13.5/boe). The increase of 8% is principally due to a higher proportion of fixed operating costs on mature fields with declining production.

 

DD&A charges before impairment amounted to $537 million; $17.9/boe for the year (2011: $514 million; $18.0/boe). The Group recognised an impairment charge of $31 million; $1.0/boe (2011: $51 million; $1.8/boe) in respect of the M'Boundi field in the Congo due to higher anticipated future costs.

Administrative expenses of $191 million (2011: $122.8 million) include an amount of $30.5 million (2011: $23.6 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 2012 with Tullow's total workforce increasing by 17% to 1,415 people.

Total costs written-off

Write-offs associated with unsuccessful exploration activities during 2012 in Guyana, Ghana, Sierra Leone, Côte d'Ivoire, Suriname, Tanzania, Uganda and new ventures activity and licence relinquishments totalled $300 million, compared with $121 million in 2011.

 

As a result of the Group's review of the exploration asset values on its balance sheet compared with expected near-term work programmes and the relative attractiveness of further investment in these assets an additional write-down of $371 million was announced with the 2012 half-year results. The principal elements of the write-downs are: the Odum discovery in Ghana where acreage has been relinquished ($37 million); carried costs for Kudu in Namibia where progress towards commercialisation continues to be delayed ($160 million); undeveloped discoveries in Mauritania ($93 million) and exploration costs to date in Sierra Leone where interest remains, but a hub class commercial discovery has yet to be made ($50 million).

 

When the cost of unsuccessful 2012 exploration activities is added to the half-year write-off of $371 million, the total write-off for 2012 was $671 million.

 

Operating profit

Operating profit grew 5% to $1.2 billion (2011: $1.1 billion). The increase was principally due to increased sales volumes with the gain on the Uganda farm-down ($701 million), largely offset by a significant increase in exploration cost write-offs and increased cost of sales.

 

Derivative instruments

Tullow continues to undertake hedging activities as part of the ongoing management of its business risk to protect against volatility and to ensure the availability of cash flow for reinvestment in capital programmes that are driving business growth.

 

At 31 December 2012, the Group's derivative instruments had a net negative fair value of $59 million (2011: negative $47 million), inclusive of deferred premium. While all of the Group's commodity derivative instruments currently qualify for hedge accounting, a pre tax charge of $20 million (2011: credit of $27 million) in relation to the change in time value of the Group's commodity derivative instruments has been recognised in the income statement for 2012.

 

At 8 February 2013 the Group's commodity hedge position to the end of 2015 was as follows:

 

Hedge position	2013	2014	2015
Oil hedges
Volume (bopd)	35,000	26,500	13,000
Current price hedge ($/bbl)	113.7	107.0	101.1
Gas hedges
Volume (mmscfd)	23.7	10.4	4.9
Current price hedge (p/therm)	65.4	68.2	68.2

 

Net financing costs

The net interest charge for the year was $49 million (2011: $86 million) and reflects the reduction in net debt levels during 2012, as a result of a repayment of part of the Reserve Based Lending facility with the Ugandan proceeds and acquisition of the Jubilee FPSO in the second half of 2011. The 2012 net interest charge includes interest incurred on the Group's debt facilities and the decommissioning finance charge offset by interest earned on cash deposits and borrowing costs capitalised principally against the Ugandan assets.

 

Taxation

The tax charge of $450 million (2011: $384 million) relates to the Group's North Sea, Gabon, Equatorial Guinea and Ghanaian production activities and payment of a presumed amount for Ugandan capital gains tax. After adjusting for exploration write-offs, the related deferred tax benefit in relation to the exploration write-offs and the profit on disposal, the Group's underlying effective tax rate is 41% (2011: 32%). The increase in underlying effective tax rate is primarily a result of lower PSC income and also higher administrative costs and the derivative charge to the income statement.

 

Profit from continuing activities and basic earnings per share

Profit for the year from continuing activities decreased 3% to $666 million (2011: $689 million). Basic earnings per share decreased by 5% to 68.8 cents (2011: 72.5 cents).

 

Dividend per share

The Board is proposing a final dividend of 8.0 pence per share (2011: 8.0 pence per share). The dividend will be paid on 16 May 2013 to shareholders on the register on 19 April 2013. Shareholders with registered addresses in the UK will be paid their dividends in pounds Sterling. Those with registered addresses in European countries which have adopted the Euro will be paid their dividends in Euro. Such shareholders may, however, elect to be paid their dividends in either pounds Sterling or Euro, provided such election is received at the Company's registrars by 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.

 

Operating cash flow

Higher operating costs partially offset by increased sales volumes decreased operating cash flow before working capital movements by 3% to $1.8 billion (2011: $1.8 billion). In 2012, this cash flow together with increased debt facilities helped fund $1.9 billion capital investment in exploration and development activities, $173 million payment of dividends and the servicing of debt facilities.

 

Capital expenditure

2012 capital expenditure amounted to $1.9 billion (2011: $1.4 billion) with 42% invested on development activities, 18% on appraisal activities and 40% on exploration activities. More than 50% of the total was invested in Ghana and Uganda and over 80%, more than $1.6 billion, was invested in Africa. Based on current estimates and work programmes, 2013 capital expenditure is forecast to reach $2.0 billion.

Portfolio management

On 21 February 2012, the Group completed the farm-down of two thirds of its Uganda interests to Total and CNOOC for a headline consideration of $2.9 billion. A pre-tax profit on disposal of $701 million and a post tax profit on disposal of $572 million have been recognised in respect of this transaction.

In anticipation of the farm-down of the Ugandan assets to CNOOC and Total, the Uganda Revenue Authority (URA) issued an initial assessment for $473 million in respect of capital gains tax on the transaction. At completion, $142 million was paid by Tullow to the URA, being 30% of the tax assessed as legally required for an appeal. The assessment denies relief for costs incurred by the Group in the normal course of developing the assets, and also excludes certain contractual and statutory reliefs from capital gains tax the Group maintains are properly allowable. The appeal will be heard by the Tax Appeals Tribunal in Kampala later in the year. On the advice of leading counsel, the Group believes it has a strong case under both international and Ugandan law and currently views the most probable outcome to be that any liability will be at a similar level to the amount already paid on account.

Net debt and financing

On 31 October 2012 Tullow successfully finalised arrangements for the refinancing of its $3.5 billion Reserve Based Lending credit facilities, extending final maturity from 2015 to 2019. Commitments under the Reserve Based Lending Facility remain unchanged at $3.5 billion from 2011. In 2012, the Revolving Corporate Facility commitments were reduced by $0.15 billion to a revised aggregate of $0.5 billion, following the Uganda asset disposal. At 31 December 2012, Tullow had net debt of $1.0 billion (2011: $2.9 billion). Unutilised debt capacity at year-end amounted to approximately $2.2 billion. Gearing was 19% (2011: 60%) and EBITDA interest cover increased to 48.3 times (2011: 16.7 times). Total net assets at 31 December 2012 amounted to $5.3 billion (31 December 2011: $4.8 billion) with the increase in total net assets principally due to the profit for the year from continuing activities

 

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 2012 Annual Report and Accounts.

 

2013 principal risks and uncertainties

As part of our 2013 to 2015 business plan a number of risks and uncertainties to the Group's financial and operational performance for the period were identified and these are also incorporated. Overall, the Tullow Board has responsibility for risk management.

 

The principal financial risks to performance identified for 2013 are:

·    Delivery of financial strategy to  maintain appropriate liquidity;

·    Ensuring cost and capital discipline and effective supply chain management; and

·    Oil price and overall market volatility.

 

Events since year-end

In January 2013, Tullow has completed the farm-in announced in November 2012 to gain a 40% operated interest in the Hyperdynamics Corporation's oil and gas exploration licence offshore Guinea. The Group also completed the acquisition of Spring Energy Norway AS ("Spring") that was previously announced in December 2012.

 

Financial strategy and outlook

Our financial strategy remains to maintain the appropriate financial flexibility to fund high-impact exploration and selective developments. Our focus is to fund exploration activities from production cash flow and to fund selective developments primarily from a combination of debt capacity and swapping equity to pay for development costs (carries). Where surplus cash is generated from farm-downs, this will either be reinvested or returned to shareholders as appropriate. We will also look to broaden the sources of funding for Tullow, whilst ensuring an appropriate capital structure. Allied to this we will work to ensure that our cost base remains appropriate as we continue to build our organisational capacity and international footprint. These goals are aligned with the 2013-2015 business plan key objectives and enable us to support the Group's growth strategy with a robust, well funded business. We start 2013 with a strong balance sheet and clear plans to grow the value of the business.

 

 

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 2012 Annual Report.

 

 

Condensed consolidated income statement

Year ended 31 December 2012

	Notes	2012 $m	2011 $m
Continuing activities
Sales revenue	6	2,344.1	2,304.2
Cost of sales		(999.3)	(930.8)
Gross profit		1,344.8	1,373.4
Administrative expenses		(191.2)	(122.8)
Profit on disposal	8	702.5	2.0
Exploration costs written off	9	(670.9)	(120.6)
Operating profit		1,185.2	1,132.0
(Loss)/gain on hedging instruments		(19.9)	27.2
Finance revenue		9.6	36.6
Finance costs		(59.0)	(122.9)
Profit from continuing activities before tax		1,115.9	1,072.9
Income tax expense	7	(449.7)	(383.9)
Profit for the year from continuing activities		666.2	689.0
Attributable to:
Owners of the parent		624.3	649.0
Non-controlling interest		41.9	40.0
		666.2	689.0
Earnings per ordinary share from continuing activities		¢	¢
Basic	2	68.8	72.5
Diluted	2	68.4	72.0

 

 

 

Condensed consolidated statement of comprehensive income and expense

Year ended 31 December 2012

		2012 $m	2011 $m
Profit for the year		666.2	689.0
Cash flow hedges
Losses arising in the year		(3.3)	(6.7)
Reclassification adjustments for items included in profit on realisation		11.0	15.2
		7.7	8.5
Exchange differences on translation of foreign operations		7.7	(34.5)
Other comprehensive income		15.4	(26.0)
Tax relating to components of other comprehensive income		0.1	2.9
Other comprehensive income for the year		15.5	(23.1)
Total comprehensive income for the year		681.7	665.9
Attributable to:
Owners of the parent		639.8	625.9
Non-controlling interest		41.9	40.0
		681.7	665.9

 

 

Condensed consolidated balance sheet

As at December 2012

	Notes	2012 $m	*Restated 2011 $m
ASSETS
Non-current assets
Intangible exploration and evaluation assets	9	2,977.1	5,529.7
Property, plant and equipment		4,407.9	3,580.3
Investments		1.0	1.0
Other non-current assets	10	696.7	313.5
Deferred tax assets		4.9	39.0
		8,087.6	9,463.5
Current assets
Inventories		163.7	225.7
Trade receivables		238.7	272.4
Other current assets		416.6	360.2
Current tax assets		28.6	7.0
Cash and cash equivalents		330.2	307.1
Assets classified as held for sale		116.4	-
		1,294.2	1,172.4
Total assets		9,381.8	10,635.9
LIABILITIES
Current liabilities
Trade and other payables		(848.1)	(1,119.6)
Other financial liabilities		-	(217.8)
Current tax liabilities		(292.4)	(153.8)
Derivative financial instruments		(39.4)	(42.4)
Liabilities directly associated with assets classified as held for sale		(48.9)	-
		(1,228.8)	(1,533.6)
Non-current liabilities
Trade and other payables		(30.6)	(2.4)
Other financial liabilities		(1,173.6)	(2,858.1)
Deferred tax liabilities		(1,076.3)	(1,030.8)
Provisions		(531.6)	(440.8)
Derivative financial instruments		(19.3)	(4.2)
		(2,831.4)	(4,336.3)
Total liabilities		(4,060.2)	(5,869.9)
Net assets		5,321.6	4,766.0
EQUITY
Called up share capital	11	146.6	146.2
Share premium		584.8	551.8
Other reserves		566.6	551.1
Retained earnings		3,931.2	3,441.3
Equity attributable to equity holders of the parent		5,229.2	4,690.4
Non-controlling interest		92.4	75.6
Total equity		5,321.6	4,766.0

*   Certain numbers shown above do not correspond to the 2011 financial statements as a result of a retrospective restatement as set out in note 12.

 

 

 

Condensed statement of changes in equity

Year ended 31 December 2012

 

	Share capital $m	Share premium $m	Other reserves $m	Retained earnings $m	Total $m	Non-controlling interest $m	Total Equity $m
At 1 January 2011	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 share options	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)
At 1 January 2012	146.2	551.8	551.1	3,441.3	4,690.4	75.6	4,766.0
Total recognised income and expense for the year	-	-	15.5	624.3	639.8	41.9	681.7
Issue of equity shares	-	4.9	-	-	4.9	-	4.9
New shares issued in respect of employee share options	0.4	28.1	-	-	28.5	-	28.5
Vesting of PSP shares	-	-	-	(9.1)	(9.1)	-	(9.1)
Share-based payment charges	-	-	-	47.9	47.9	-	47.9
Dividends paid	-	-	-	(173.2)	(173.2)	-	(173.2)
Distribution to minority shareholders	-	-	-	-	-	(25.1)	(25.1)
At 31 December 2012	146.6	584.8	566.6	3,931.2	5,229.2	92.4	5,321.6

 

 

 

Condensed consolidated cash flow statement

Year ended 31 December 2012

	Notes	2012 $m	2011 $m
Cash flows from operating activities
Profit before taxation		1,115.9	1,072.9
Adjustments for:
Depletion, depreciation and amortisation		561.9	533.8
Impairment loss		31.3	51.0
Impairment reversal		-	(17.4)
Exploration costs written off		670.9	120.6
Profit on disposal	8	(702.5)	(2.0)
Decommissioning expenditure		(2.4)	(14.2)
Share-based payment charge		32.6	28.5
Loss/(gain) on hedging instruments		19.9	(27.2)
Finance revenue		(9.6)	(36.6)
Finance costs		59.0	122.9
Operating cash flow before working capital movements		1,777.0	1,832.3
Increase in trade and other receivables		(11.3)	(91.9)
Decrease/(increase) in inventories		11.3	(43.8)
Increase in trade payables		7.5	206.5
Cash flows from operating activities		1,784.5	1,903.1
Income taxes paid		(264.1)	(171.8)
Net cash from operating activities		1,520.4	1,731.3
Cash flows from investing activities
Disposal of exploration and evaluation assets	8	2,568.2	-
Disposal of oil and gas assets		0.3	-
Disposal of other assets		1.3	2.4
Purchase of subsidiaries		-	(404.0)
Purchase of intangible exploration and evaluation assets		(1,196.6)	(1,018.4)
Purchase of property, plant and equipment		(652.8)	(635.1)
Finance revenue		1.3	13.6
Net cash generated/(used in) investing activities		721.7	(2,041.5)
Cash flows from financing activities
Net proceeds from issue of share capital		24.5	86.7
Debt arrangement fees		(77.2)	(30.0)
Repayment of bank loans		(2,407.5)	(320.0)
Drawdown of bank loan		565.0	1,200.0
Repayment of obligations under finance leases		(1.8)	(308.4)
Finance costs		(103.2)	(210.2)
Dividends paid		(173.2)	(114.2)
Distribution to minority shareholders		(25.1)	(25.0)
Net cash (used in)/generated by financing activities		(2,198.5)	278.9
Net increase/(decrease) in cash and cash equivalents		43.6	(31.3)
Cash and cash equivalents at beginning of year		307.1	338.3
Cash transferred to held for sale		(18.0)	-
Foreign exchange (loss)/gain		(2.5)	0.1
Cash and cash equivalents at end of year		330.2	307.1

 

 

Notes to the preliminary financial statements

Year ended 31 December 2012

 

1.     Basis of Accounting and Presentation of Financial Information

 

Whilst the financial information in this preliminary announcement has been prepared in accordance with International Financial Reporting Standards (IFRS) and International Financial Reporting Interpretation Committee (IFRIC) interpretations adopted for use by the European Union, with those parts of the Companies Act 2006 applicable to companies reporting under IFRS and with the requirements of the United Kingdom Listing Authority (UKLA) Listing Rules, this announcement does not contain sufficient information to comply with IFRS. The Group will publish full financial statements that comply with IFRS in March 2013.

 

The financial information for the year ended 31 December 2012 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 2011 have been delivered to the Registrar of Companies and those for 2012 will be delivered following the Company's annual general meeting. The auditor has reported on these accounts; their reports were unqualified, did not include a reference to any matters to which the auditor drew attention by way of emphasis of matter and did not contain a statement under section 498 (2) or (3) of the Companies Act 2006.

 

The accounting policies applied are consistent with those adopted and disclosed in the Group's financial statements for the year ended 31 December 2011. 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 2012; 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 $624.3 million (2011: $649.0 million) and a weighted average number of shares in issue of 906.8 million (2011: 895.7 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 5.6 million (2011: 6.2 million) in respect of employee share options, resulting in a diluted weighted average number of shares of 912.4 million (2011: 901.9 million).

 

3.     Dividends

 

During the year the Company paid a final 2011 dividend of 8.0 pence per share and an interim 2012 dividend of 4.0 pence per share, a total dividend of 12.0 pence per share (2011: 12.0 pence per share). The Directors intend to recommend a final 2012 dividend of 8.0 pence per share, which, if approved at the AGM, will be paid on 16 May 2013 to shareholders on the register of the Company on 19 April 2013.

 

4.     2012 Annual Report and Accounts

 

The Annual Report and Accounts will be mailed on 25 March 2013 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 8 May 2013 at 12 noon.

 

6.     Segmental Reporting

 

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 reportable segments in accordance with IFRS 8 are 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 2012 and 31 December 2011.

 

	Europe, South America and Asia $m	West and North Africa $m	South and East Africa $m	Unallocated $m	Total $m
2012 Sales revenue by origin	380.6	1,963.5	-	-	2,344.1
Segment result	(124.0)	974.1	(176.2)	-	673.9
Profit on disposal of other assets					702.5
Unallocated corporate expenses					(191.2)
Operating profit					1,185.2
Loss on hedging instruments					(19.9)
Finance revenue					9.6
Finance costs					(59.0)
Profit before tax					1,115.9
Income tax expense					(449.7)
Profit after tax					666.2
Total assets	1,868.0	5,148.3	2,185.6	179.9	9,381.8
Total liabilities	(999.4)	(1,531.9)	(285.1)	(1,243.8)	(4,060.2)
Other segment information
Capital expenditure:
Property, plant and equipment	136.3	626.5	1.5	29.8	794.1
Intangible exploration and evaluation assets	246.1	512.2	582.6	-	1,340.9
Depletion, depreciation and amortisation	(178.4)	(360.2)	(1.2)	(22.1)	(561.9)
Impairment losses recognised in income statement	-	(31.3)	-	-	(31.3)
Exploration costs written off	(173.9)	(320.9)	(176.1)	-	(670.9)

 

 

 

	Europe, South America and Asia $m	West and North Africa $m	South and East Africa $m	Unallocated $m	Total $m
2011 (restated*) Sales revenue by origin	360.2	1,944.0	-	-	2,304.2
Segment result	31.9	1,216.7	4.2	-	1,252.8
Profit on disposal of oil and gas assets					2.0
Unallocated corporate expenses					(122.8)
Operating profit					1,132.0
Gain on hedging instruments					27.2
Finance revenue					36.6
Finance costs					(122.9)
Profit before tax					1,072.9
Income tax expense					(383.9)
Profit after tax					689.0
Total assets	1,791.9	4,745.1	3,977.6	121.3	10,635.9
Total liabilities	(922.5)	(1,202.8)	(565.5)	(3,179.1)	(5,869.9)
Other segment information
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	965.5	-	-	-	965.5
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)

*   Certain numbers shown above do not correspond to the 2011 financial statements as a result of a retrospective restatement as set out in note 12.

 

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:

	2012 $m	2011 $m
Current tax
UK corporation tax	10.1	37.4
Foreign tax	360.2	137.4
Total corporate tax	370.3	174.8
UK petroleum revenue tax	10.8	11.6
Total current tax	381.1	186.4
Deferred tax
UK corporation tax	17.3	15.2
Foreign tax	53.6	185.7
Total deferred corporate tax	70.9	200.9
Deferred UK petroleum revenue tax	(2.3)	(3.4)
Total deferred tax	68.6	197.5
Total tax expense	449.7	383.9

 

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 24% (2011: 26%) to the profit before tax is as follows:

	2012 $m	2011 $m
Group profit on ordinary activities before tax	1,115.9	1,072.9
Tax on Group profit on ordinary activities at the standard UK corporation tax rate of 24% (2011: 26%)	267.8	279.0
Effects of:
Expenses not deductible for tax purposes	86.6	69.7
Utilisation of tax losses not previously recognised	-	(20.9)
Net losses not recognised	129.1	21.3
Petroleum revenue tax (PRT)	8.5	9.1
UK corporation tax deductions for current PRT	(5.3)	(3.0)
Adjustments relating to prior years	20.8	(5.8)
Adjustments to deferred tax relating to change in tax rates	16.5	18.2
Income taxed at a different rate	161.2	82.3
Income not subject to corporation tax	(235.5)	(66.0)
Group total tax expense for the year	449.7	383.9

 

 

Following previous reductions in the main rate of UK corporation tax, on 26 March 2012 additional reductions from 26% to 24% effective from 1 April 2012 and from 24% to 23% from 1 April 2013 were substantively enacted. Draft legislation has also been published for inclusion in Finance Bill 2013 which further reduces the main tax rate to 21% effective from 1 April 2014. As this change was not substantively enacted at the balance sheet date, the rate reduction to 21% is not yet reflected in these financial statements.

 

The Group's profit before taxation will continue to arise in jurisdictions where the effective rate of taxation differs from that in the UK. Furthermore, unsuccessful exploration expenditure is often incurred in jurisdictions where the Group has no taxable profits, such that no related tax benefit arises. Accordingly, the Group's tax charge will continue to vary according to the jurisdictions in which pre-tax profits and exploration costs written off arise.

 

The Group has tax losses of $1,724.7 million (2011: $1,082.3 million) that are available for offset against future taxable profits in the companies in which the losses arose. Deferred tax assets have not been recognised in respect of these losses as they may not be used to offset taxable profits elsewhere in the Group. The Group has recognised $49.4 million in deferred tax assets in relation to taxable losses (2011: $117.5 million), this is disclosed net of a deferred tax liability in respect of capitalised interest.

 

No deferred tax liability is recognised on temporary differences of $30 million (2011: $253 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.     Acquisitions and disposals

a.          Acquisitions of subsidiaries

On 24 May 2011 Tullow announced that it had acquired 100% of Nuon Exploration & Production B.V. ("Nuon") from the Vattenfall Group with an acquisition date of 30 June 2011. The fair values of the identifiable assets and liabilities were reassessed in the first few months of 2012 to reflect additional information which has become available concerning conditions that existed at the date of acquisition in accordance with the provisions of IFRS 3 - Business Combinations. The final acquisition fair values of the identifiable assets and liabilities are set out in the below table and the retrospective adjustments to the fair values previously reported are set out in note 12.

	Provisional fair value $m	Adjust-ments to fair values $m	Final fair value $m
Intangible exploration and appraisal assets	424.1	79.7	503.8
Property, plant and equipment	539.6	(77.9)	461.7
Trade and other receivables	19.8	-	19.8
Trade and other payables	(20.0)	(1.0)	(21.0)
Deferred tax liabilities	(472.9)	(0.8)	(473.7)
Provisions	(86.6)	-	(86.6)
Total consideration satisfied by cash	404.0	-	404.0

 

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. Transaction costs in respect of the Nuon acquisition of $1.1 million were recognised in the 2011 income statement. In 2012 Nuon has contributed $142.3 million to Group revenues (2011: $67.6 million) and $15.2 million to the profit of the Group (2011: $3.2 million). Provisions represent the present value of decommissioning costs, which are expected to be incurred up to 2033.

There were no acquisitions involving business combinations in 2012.

b.      Disposal on exploration and evaluation assets

On 21 February 2012 the Group completed the farm-down of one-third of its Uganda interests to both Total and CNOOC ("the partners") for a headline consideration of $2.9 billion. The Ugandan assets are classified as intangible exploration and evaluation assets and the Group has formed an accounting policy under IAS 8 to account for the farm-down, whereby a profit has been recognised on disposal as the difference between total consideration and the net book value of the disposal assets. The following is a reconciliation of the consideration and the value of assets disposed:

 

	$m
Headline considerations	2,933.3
Contingent consideration	341.3
Net book value of disposed assets	(2,573.6)
Profit on disposal	701.0

 

The contingent consideration represents the fair value of completion statement amounts due from the partners on issue of Final Investment Decision ("FID") in Uganda.

The total cash consideration received in 2012 was $2.6 billion, with capital gains tax of $142 million being paid directly out of this amount. The $2.6 billion cash consideration received represents headline consideration of $2.9 billion less deposits received in 2011.

In anticipation of the farm-down of the Ugandan assets to CNOOC and Total, the Uganda Revenue Authority (URA) issued an assessment for $473 million in respect of capital gains tax on the transaction. At completion, $142 million was paid to the URA, being 30% of the tax assessed as legally required for an appeal. The assessment denies relief for costs incurred by the Group in the normal course of developing the assets, and excludes certain contractual and statutory reliefs from capital gains tax that the Group maintains are properly allowable. The appeal is scheduled to be heard by the Tax Appeals Tribunal in Kampala later in 2013. On the advice of leading counsel, the Group believes that it has a strong case under both international and Ugandan law and currently views the most probable outcome to be that any liability will be at a similar level to the amount already paid on account. The amount of $142 million is included in the Group's tax charge for the year ended 31 December 2012.

Further disposals of oil and gas assets and non-oil and gas assets generating a profit on disposal of $1.5 million were also completed in 2012 (2011: $2.0 million).

9.     Intangible exploration and evaluation assets

	2012 $m	*Restated 2011 $m
At 1 January	5,529.7	4,001.2
Acquisition of subsidiaries (note 8)	-	503.8
Additions	1,340.9	1,190.0
Disposals (note 8)	(2,573.6)	-
Amounts written off	(670.9)	(120.6)
Transfer to assets held for sale	(28.4)	-
Transfer to property, plant and equipment	(625.3)	-
Currency translation adjustments	4.7	(44.7)
At 31 December	2,977.1	5,529.7

 

Included within 2012 additions is $67.2 million of capitalised interest (2011: $128.8 million). The Group only capitalises interest in respect of intangible exploration and evaluation assets where it is considered that development is highly likely and advanced appraisal and development is ongoing.

Exploration costs written-off were $670.9 million (2011: $120.6 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. Write-offs associated with unsuccessful exploration activities during 2012 in Guyana, Ghana, Sierra Leone, Côte d'Ivoire, Suriname, Tanzania, Uganda and new ventures activity and licence relinquishments totalled $300 million. As a result of the Group's review of the exploration asset values on its balance sheet compared with expected near-term work programmes and the relative attractiveness of further investment in these assets an additional write-down of $371 million has been made. The principal elements of the write-downs are: the Odum discovery in Ghana where acreage has been relinquished ($37 million); carried costs for Kudu in Namibia where progress towards commercialisation continues to be delayed ($160 million); undeveloped discoveries in Mauritania ($93 million) and exploration costs to date in Sierra Leone where interest remains, but a hub-class commercial discovery has yet to be made ($50 million).

During the year the TEN project in Ghana was transferred from contingent resources to commercial reserves following submission of the Plan of Development to the Government of Ghana. As a result $599.9 million of costs associated with the project were transferred from intangible exploration and evaluation assets to oil and gas assets. The remainder of the transfers from intangible exploration and evaluation assets relate to the sanction of the Katy project and drilling of the Ketch SW flank in the UK.

10.  Other non-current other assets

At 31 December 2012 other non-current assets consist of amounts receivable of $341 million of contingent consideration receivable from the Uganda farm-down (note 8) and the recoverable security paid by Tullow to the Ugandan Revenue Authority (URA) as agent to the transaction between Tullow and Heritage Oil & Gas Limited (Heritage) in respect of the sale of their interest in Uganda. Separately, and under the terms of Tullow and Heritage's PSA, Tullow has opened proceedings against Heritage in London to recover this sum. Recoverable VAT in Uganda has also been classified as non-current as at 31 December 2012.

11.  Called up equity share capital

In the year ended 31 December 2012, the Group issued 2,848,078 (2011: 16,678,379) new shares which included issuing 2,623,123 (2011: 3,009,637) new shares in respect of employee share options and 224,955 shares in settlement of a $4.9 million obligation of a Group company.

As at 31 December 2012 the Group had in issue 907,763,327 allotted and fully paid ordinary shares of Stg10 pence each (2011: 904,915,249).

12.  Retrospective restatement

The fair values of the identifiable assets and liabilities of the Nuon acquisition were reassessed in 2012, to reflect additional information which has become available concerning conditions that existed at the date of acquisition, in accordance with the provisions of IFRS 3 - Business Combinations. Adjustments made to previously reported fair values have been retrospectively restated. The principal fair value adjustments are in respect of intangible exploration and appraisal assets and property plant and equipment as a result of the finalisation of an independent review of acquired commercial reserves and contingent resources.

The impact on the 2011 financial statements is summarised in the below table.

	Previously stated 2011 $m	Impact of revision in accounting policy $m	Restated 2011 $m
Effect on balance sheet:
Intangible exploration and evaluation assets	5,450.0	79.7	5,529.7
Property, plant and equipment	3,658.2	(77.9)	3,580.3
Non-current assets	9,461.7	1.8	9,463.5
Total assets	10,634.1	1.8	10,635.9
Trade and other payable	(1,118.6)	(1.0)	(1,119.6)
Current liabilities	(1,532.6)	(1.0)	(1,533.6)
Deferred tax liabilities	(1,030.0)	(0.8)	(1,030.8)
Non-current liabilities	(4,335.5)	(0.8)	(4,336.3)
Total liabilities	(5,868.1)	(1.8)	(5,869.9)
Net assets/total equity	4,766.0	-	4,766.0

 

13.  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 2011	1.6	302.7	242.4	19.0	-	-	244.0	321.7	297.6
Revisions	-	8.6	5.4	-	-	-	5.4	8.6	6.8
Acquisitions	-	-	0.2	-	-	-	0.2	-	0.2
Additions	-	-	112.4	-	-	-	112.4	-	112.4
Disposals	-	-	-	-	-	-	-	-	-
Production	(0.2)	(45.4)	(20.8)	(2.5)	-	-	(21.0)	(47.9)	(29.0)
31 December 2012	1.4	265.9	339.6	16.5	-	-	341.0	282.4	388.0
CONTINGENT RESOURCES
31 December 2011	36.6	192.9	190.5	1,330.8	900.5	381.0	1,127.6	1,904.7	1,445.1
Revisions	-	(0.7)	9.2	(225.4)	53.5	0.4	62.7	(225.7)	25.1
Acquisitions	-	-	0.3	122.8	-	-	0.3	122.8	20.8
Additions	-	-	21.0	135.6	27.8	-	48.8	135.6	71.4
Disposals	-	-	(31.4)	-	(600.3)	(20.7)	(631.7)	(20.7)	(635.2)
Transfers to commercial reserves	-	-	(112.4)	-	-	-	(112.4)	-	(112.4)
31st December 2012	36.6	192.2	77.2	1,363.8	381.5	360.7	495.3	1,916.7	814.8
TOTAL
31 December 2012	38.0	458.1	416.8	1,380.3	381.5	360.7	836.3	2,199.1	1,202.8

 

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 West and North Africa commercial and contingent resources acquisition in 2012 relates to the purchase of Roc Oils interests in Mauritania.

4.   The West and North Africa transfer from contingent resources to commercial reserves is in respect of the TEN development following submission of the Plan of Development to the Government of Ghana.

5.   The South and East Africa contingent resource disposal was as a result of completion of the farm-down of 66.6% interest in Uganda to CNOOC and Total.

 

The Group provides for depletion and amortisation of tangible fixed assets on a net entitlements basis, which reflects the terms of the Production Sharing Contracts related to each field. Total net entitlement reserves were 349.6 mmboe at 31 December 2012 (31 December 2011: 260.6 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 100 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 BST - 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 13 February until 20 February. The telephone numbers and access codes are:

 

Live event		Replay facility available from Noon
UK Participants	020 7136 2056	UK Participants	020 3427 0598
Irish Participants	01 486 0920	Irish Participants	01 486 0902
		Access Code	8138415#

 

To join the live Video webcast, or play the on-demand version which will be available from noon on 13 February, you will need to have either Real Player or Windows Media Player installed on your computer.

 

11.00 BST - 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	0808 109 0700	International Participants	+44 (0) 20 3003 2666
UK Local Call	020 3003 2666	USA Toll Free	+1 866 966 5335
Irish Free Call	1 800 930 488	Access code	6695470

 

15:00 BST - US Conference Call

To access the call please dial the appropriate number below shortly before the call and ask for the Tullow Oil plc conference call.

 

Live Event
Domestic Toll Free	+1 877 249 9037
Toll	+1 212 444 0412
Access code	8451106

 

 

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	Jack Rich	Ed Micheau