2011 Half-yearly Results

RNS Number : 9168M

Tullow Oil PLC

24 August 2011

 



Record first half revenue and profit

Interim dividend doubled

Exploration success continues and developments being progressed

24 August 2011 - Tullow Oil plc (Tullow), the independent oil and gas exploration and production Group, announces its half-yearly results for the six months ended 30 June 2011.

2011 Half-yearly results summary

Tullow had a very strong first half. Record results were driven by increased production from the Jubilee field in Ghana and higher commodity prices. Exploration and appraisal success continued and the Group strengthened its portfolio with farm-ins in East Africa and two strategic acquisitions. Further progress was made in Uganda and Tullow now expects completion of its farm-down to CNOOC and Total in September. In July the Group listed Tullow Oil plc shares on the Ghana Stock Exchange.

	1H 2011	1H 2010	Change
Sales revenue ($m)	1,062	486	+119%
Operating profit ($m)	588	124	+374%
Profit before tax ($m)	540	131	+312%
Profit after tax ($m)	330	89	+271%
Basic earnings per share (cents)	35.0	9.4	+272%
Interim dividend per share (pence)	4	2	+100%
Operating cash flow before working capital ($m)	855	367	+133%
Production (boepd, working interest basis)	75,100	55,800	+35%
Realised oil price (US$ per bbl)	112	77	+45%
Realised gas price (pence per therm)	56	34	+65%

Key highlights

·      Record sales revenue of over $1 billion driven by Jubilee Production; interim dividend doubled.

·      71% exploration and appraisal success year-to-date (17/24); Akasa-1 discovery announced today.

·      Completion of farm-in to six blocks in Kenya and Ethiopia; first well to spud in Kenya in Q4 2011.

·      Group production expected to average 82-84,000 bopd for 2011 and exceed 100,000 bopd by year-end.

·      Jubilee production in Ghana is expected to increase to 105,000 bopd in October; plateau production of 120,000 bopd is now expected before year-end.

·      MoU signed with the Government of Uganda; $2.9 billion Sale and Purchase Agreements signed for the farm-down to CNOOC and Total; completion now expected in September.

·      Nuon E&P and EO Group acquisitions completed in June and July respectively.

·      Secondary listing on the Ghana Stock Exchange completed in July following successful $72.3 million offer.

Commenting today, Aidan Heavey, Chief Executive, said:

"We have delivered a strong performance and achieved record results in the first half allowing us to double the dividend. We continue to make good progress with production plans in both Ghana and Uganda and while delays to the farm-down to CNOOC and Total have been frustrating, we now expect completion in September. With a strong balance sheet, growing production and a potentially transformational drilling campaign to come, we move into the second half of the year with real confidence."

Presentation in London, Webcast and Conference Calls: Details are available on page 27 of this announcement and in the Results Centre on the Group's website at www.tullowoil.com.

Interim management report

Six months ended 30 June 2011

Operations Review

AFRICA

2011 Half-yearly results highlights

Total production 55,600 boepd

Total reserves and resources 1,421 mmboe

Sales revenue US$900.5 million

1H 2011 investment US$632.0 million

·      Exploration and appraisal success rate 76% year-to-date (16/21).

·      MoU and SPA's signed in Uganda; deal now expected to complete in September.

·      Jubilee production ramp up continues; production now expected to reach 120,000 bopd by year end.

·      High-impact exploration continues; results from the Montserrado well, offshore Liberia, due in September.

·      Enyenra and Tweneboa appraisal programmes continue; development scenarios being evaluated with sanction expected 1H 2012.

·      Listing on the Ghana Stock Exchange completed on 27 July following successful $72.3m offer.

Ghana and West African Equatorial Atlantic

In the Equatorial Atlantic region, offshore West Africa, Tullow has interests in 10 blocks across four countries, Sierra Leone, Liberia, Côte d'Ivoire and Ghana. In Ghana, the first half of 2011 has been marked by the ongoing ramp-up of production from the Jubilee field where production operations on the FPSO Kwame Nkrumah have been highly successful, with a low rate of unplanned shut-downs and no significant safety or environmental issues. Meanwhile, exploration and appraisal activities continued apace with the highlights being the confirmation that Enyenra is a major light oil field, further discoveries by the Teak-1 and Teak-2 exploration wells and the commencement of a high-impact exploration drilling programme in the region.

Jubilee field phase 1 & 1A developments

Since the start-up of production on the Jubilee field at the end of 2010, over 15 million barrels of oil have been produced and 15 oil cargoes have been safely exported. The field is now producing around 85,000 bopd with over 75 mmscfd of gas being re-injected. A total of 17 wells have been drilled to date of which 14 have been completed and brought on line. This total consists of eight oil production wells, five water injection wells and one gas injector well. The final production well is expected to be brought on stream in October, taking Jubilee production to 105,000 bopd. Plateau production of 120,000 bopd gross is now expected to be reached by the end of the year following the sidetrack of an existing production well. This well was not optimally located in the reservoir and has lower productivity than expected. The final water and gas injection wells are also expected to be completed by year-end. In addition, production will be enhanced with the recent startup of the third water injection pump which has increased water injection rates from 150,000 bwpd to 225,000 bwpd. The reservoir performance to date continues to support the Reserves and Resources for the Jubilee Unit Area.

During the first half of the year, plans for Jubilee Phase 1A development have been progressed. It is envisaged that this will consist of eight additional wells and associated infrastructure and will maintain Jubilee plateau production until around 2015. Long-lead items have been ordered and Government approval is expected over the coming months. This development plan will be initiated in early 2012 with incremental wells phased as necessary.

The development plan for Mahogany East has been discussed with the Government of Ghana and includes additional delineation activities that are expected to occur in 2012.  In addition, further appraisal activity at Teak is planned to begin before the end of 2011.

Enyenra-Tweneboa appraisal and development

The appraisal of the Enyenra and Tweneboa fields in the Deep Water Tano block is under way and involves a comprehensive programme of appraisal drilling and flow testing.  These fields have been proven to be major oil and gas-condensate discoveries and the initial development planning work is already under way and is expected to move to the Front End Engineering and Design (FEED) stage in September.

The 2011 Enyenra-Tweneboa appraisal programme commenced in January with the drilling of the Tweneboa-3 appraisal well. Two deviated boreholes were drilled, testing a separate area of the Tweneboa field known as Ntomme. This was proven to be a separate gas-condensate accumulation as it is not in pressure communication with the Tweneboa-1 or Tweneboa-2 wells. An appraisal programme for this region of the field was approved by the Government in July and the first appraisal well is planned for early-2012.

In March, the Enyenra-2A well was drilled and proved Enyenra to be a major light oil field. The well also discovered a deeper gas condensate pool, provisionally called Enyenra-Deep, which is currently being studied to determine if it warrants further appraisal. This was followed by the Tweneboa-4 appraisal well in April which proved up the western flank of the Tweneboa gas-condensate field.

In June, the programme of flow tests was initiated in the oil zone of the Tweneboa-2 well which was tested at a restricted rate of 6,500 bopd. Pressure gauges were then set in the gas condensate zone of Tweneboa-2 to assist in understanding reservoir connectivity. A further flow test has just been completed in the Tweneboa-4 gas condensate zone producing at sustained rates of 30 mmscfd of gas and 3,500 bopd of condensate. The results have demonstrated good reservoir productivity and further analysis of the data is under way.

The Deepwater Millennium rig has now moved to drill the Enyenra-3A appraisal well to test the up-dip extent of the Enyenra field. The rig will be released from contract in October, being replaced by the Sedco Energy rig which has been contracted for two years from September 2011. The rig programme will include the re-drilling, coring and flow testing of the Owo-1 well and the drilling of the Enyenra-4A well before commencing the Jubilee Phase 1A programme in the first half of 2012.

Development planning for Enyenra-Tweneboa has been progressing well with the completion of conceptual engineering. The Front End Engineering & Design (FEED) FPSO and subsea contracts for the combined Enyenra-Tweneboa development will be initiated in September. Subject to the ongoing appraisal programme, submission of a Plan of Development and Sanction of the project is targeted for the first half of 2012. It is anticipated that first production will be within two and a half years of development sanction. The initial FEED work will examine an FPSO scheme with 75,000 to 125,000 barrels of oil per day production capacity and gas handling capacity to enable both gas injection and cycling to maximise both liquid recovery and future gas export.

Ghana Exploration activity

On the West Cape Three Points Block, the Teak-1 exploration well was drilled in February encountering a thick tally of oil and gas pay. An appraisal programme to discover the extent of the field and reservoir distribution was submitted to the Government in July 2011 and it is anticipated that appraisal drilling and testing will commence in the fourth quarter of 2011.

The Teak-2 exploration well was drilled in March, testing a fault block between the Teak-1 discovery and the Jubilee field. The well penetrated a gas reservoir which may represent the gas cap to the Jubilee field. Studies to test this interpretation, which will guide future phases of Jubilee development, are ongoing and gauges may be deployed in the well to monitor pressure changes induced by production from the Jubilee field.

The Banda exploration well was drilled in June, in the eastern extent of the West Cape Three Points block to explore the previously untargeted Cenomanian play. The well found three metres of oil pay in very thick but low porosity Cenomanian sandstones. The results from this new oil play are now being integrated into the regional geological model to enable better prediction of potential reservoir development at the Cenomanian level elsewhere in Tullow's Equatorial Atlantic acreage. The Makore-1 exploration well, targeting a discrete fan of Jubilee age, was drilled in July, and found excellent quality sandstones which were water bearing at this location.

The Akasa-1 well (previously Dahoma Up-dip) was drilled in August and has made a light oil discovery. The well was drilled to a total depth of 3,918 metres and full analysis of well results, including wireline logs, reservoir pressures and fluid samples, confirms that the well penetrated 33 metres of oil-bearing pay in four good-quality Turonian-aged sand packages. The Turonian reservoirs encountered are similar in age to those discovered at the Jubilee field. Oil samples recovered from the Akasa-1 well indicate 38 degrees API gravity.

The final exploration period of the West Cape Three Points block came to an end in July. However, the partnership retains a right of first refusal over the relinquished area and is in discussions with the Government of Ghana regarding the future of this acreage.

Tullow has an excellent set of attractive prospects in the Deepwater Tano licence. These include the Wawa prospect which lies immediately up-dip from the Enyenra oil discovery and the large turbidite fans clearly evident in 3D seismic data below Tweneboa. These large turbidite fans, Turonian Deep and the deeper Cenomanian Deep fans, have been de-risked by recent wells offshore Ghana which encountered thick sands in this stratigraphic interval. The Sapele prospect, adjacent to the Jubilee field, and other new leads emerging from detailed seismic interpretations in this area are also strong candidates for Tullow's 2012 exploration programme, offshore Ghana.

Ghana Stock Exchange listing and share offer

On 13 June 2011, Tullow launched an offer for Tullow shares at a price of 31 Ghana Cedi per share. The offer, which was open to all investors in Ghana, closed on Monday, 4 July 2011 and valid applications were received for 3,531,546 shares. The share offer raised 109.5 million Ghana Cedis (US$72.3 million) and on 27 July, Tullow shares commenced trading on the Ghana Stock Exchange. The secondary listing and offer of Tullow shares in Ghana demonstrates Tullow's long-term commitment to Ghana and will give Ghanaian shareholders the opportunity to share in the future performance of Tullow's global operations.

EO Group acquisition

On 26 May 2011, Tullow announced that it had entered into a conditional agreement to acquire the interests of EO Group Limited (EO) for a combined share and cash consideration of $305 million. This acquisition increases Tullow's interest in the West Cape Three Points licence offshore Ghana by 3.5% to 26.4% and increases the Group's interest in the Jubilee field by 1.75% to 36.5%. The acquisition completed on 25 July 2011.

Liberia and Sierra Leone

In late May, Tullow exercised its pre-emptive right over a proposed deal between Anadarko and Mitsubishi to acquire an additional 10% equity in block SL-07B-10 (originally SL-06 and SL-07) in Sierra Leone. Once approved by the Government, Tullow will have increased its equity in the block containing the Venus and Mercury discoveries to 20%.

In July, the Discoverer Spirit drillship commenced drilling the high-impact Montserrado exploration well (Cobalt prospect) offshore Liberia and results are expected in early September. The rig will then go on to Sierra Leone to drill the Jupiter exploration well and the Mercury-2 exploratory appraisal well. The drilling campaign is expected to be completed by the end of the year.

Uganda 

Tullow has made further progress in Uganda in the first half of 2011. Having signed a Memorandum of Understanding (MoU) with the Government of Uganda in March, Tullow reactivated its drilling programme and is working with its partners and the Government of Uganda towards developing an agreed development plan for the Lake Albert Basin that involves creating both local refining capacity and crude oil exports.

Tullow has also had further exploration and appraisal success in Uganda, confirming the size and extent of the Lake Albert Basin, as well as two new discoveries at Jobi-East-1 and Gunya-1. Tullow has three rigs currently active in Uganda with a fourth in country being prepared for operational startup in EA3.

Farm-down to CNOOC and Total

On 15 March, Tullow signed a MoU with the Government of Uganda which provided a clear process to resolve key outstanding issues surrounding tax, licence extensions and consents for Tullow to finalise the purchase of the Heritage interests and subsequently farm-down to CNOOC and Total. The Sale and Purchase Agreements (SPAs) for the farm-down were signed with Tullow's partners on 29 March.

As disclosed at the time of the signing of the SPAs, Tullow made a payment of $313 million to the Government of Uganda having been designated as agent for the sale of Heritage's assets to Tullow in 2010. Consequently, on 14 April, Tullow made a claim against Heritage for this payment under the terms of the SPA through which Tullow acquired the stakes in Blocks 1 and 3A. Heritage are contesting Tullow's claim and have issued a counter-claim. A case management hearing will take place in November before the case is heard in the High Court in London in 2012.

As also disclosed, the Ugandan Revenue Authority have levied Capital Gains Tax of $472 million on the farm-down proceeds of which 30% is payable immediately after completion. Tullow is disputing this assessment and has requested a review by a Tax Tribunal in Kampala and is awaiting dates for the hearing which is expected to take place later this year.

Tullow initially forecast that completion would take place a few weeks after the SPAs were signed but the process has proved to be more time consuming than envisaged. In particular, Tullow, CNOOC and Total are waiting for the Government first, to complete its formal approval process for new Production Sharing Agreements which have now been agreed and secondly, to align the terms of the Kingfisher Production Licence with the Government's plans for the development of the Lake Albert Basin at which point the licence will be issued.

However, good progress has been made in recent weeks and almost all outstanding issues have now been dealt with. Completion is expected to take place during September after which Tullow will receive $2.9 billion. Operatorship of EA-2 will be retained by Tullow while operatorship of EA-1 and EA-3A/Kingfisher will be transferred to Total and CNOOC respectively. This overall process will create an aligned partnership with each partner having a one third interest in each of the EA-1, EA-2, Kingfisher and EA-3A licences and operatorship responsibility.

Exploration and Appraisal

Tullow's drilling activity in Uganda increased significantly in the first half and particularly after the signing of the SPAs. In EA-2, the Nsoga-2, Kigogole-6 and Ngege-2 wells were drilled, all of which were successful and provided valuable information for the Lake Albert Basin development plan. Following the restart of drilling activity in block EA-1 in May, Jobi-East and Gunya have been discovered, the successful Mpyo-3 exploratory-appraisal well has been drilled and an appraisal well on the Jobi-Rii field has confirmed the extension of this world class discovery.

Operations are currently being completed on the Jobi-East-5 well which was drilled some 5km to the south of Jobi-East-1. The well was water bearing but found over 65 metres of some of the best reservoir sands encountered in the basin to date. Further appraisal on the Jobi-East discovery will continue with the IRR-600 rig now moving to Jobi-East-2. 

In mid-August, Tullow completed 3D seismic activity across the Ngiri, Kasamene, Wahrindi, Kigogole, Nsoga, Ngege, and Ngara discoveries. The quality of information is excellent and the data has already undergone fast track processing and will assist materially in developing these fields.  Tullow is about to start a new programme of well testing this month on the Kasamene and Kigogole fields which will provide further data for the field development plans.

In the second half of the year, Tullow will spud the Kanywataba-1 well in the south of the basin, an important new prospect with significant follow on potential. Plans for further exploration drilling in EA-1 are currently being assessed including the Omuka well scheduled to spud in January 2012. The Omuka prospect has the potential to open up a new play on the west bank of the River Nile. Tullow will also drill a number of appraisal wells as well as undertaking various well tests to assist with completing development plans on EA-2.

Recoverable oil resources totalling 1.1 billion barrels (P50) have been discovered to date, with some 1.4 billion barrels (P50) in undrilled prospective resources potentially yet to find.

Lake Albert Rift Basin Development

Tullow and its Partners have continued to plan for development of the Lake Albert Basin throughout this year. The final development plan will detail the delivery of production volumes in excess of 200,000 bopd. This will include refinery options to supply petroleum products in the East Africa region as well as pipeline export routes to international markets. The target for achieving oil production from the primary phase of the development is 2015. In the meantime, alongside its E&A drilling, Tullow is working over wells in preparation for production tests on various fields in EA-2 to assess long term reservoir performance and gather additional data. The government has given its support for the sale of crude oil, produced by testing, to local industry and commercial agreements are being finalised.

Plans for the Nzizi gas field to be used as fuel for a new Integrated Power Project continue to be discussed and engineering work on this project is being progressed. The FEED work on the development of the Kasamene field has been completed. It is intended that this field will be the leading supply option for the first phase of a refinery. Therefore, the Field Development plan will be revised to be consistent with plans for the refinery.

Equatorial Guinea

Tullow's net production from Equatorial Guinea for the first half of the year averaged 14,500 bopd. During the first half of the year, the Ceiba field performed above expectations and the Okume Complex was in line with expectations. Second half production is expected to be lower from both fields following natural field decline and some water breakthrough on the Okume field. However, a significant future work programme is planned to maintain production from both fields close to current levels. This will include the tie-back of the Akom North field to the Okume Complex in Q4 2011 and a work-over campaign on the Ceiba field planned for the end of 2011. Infill drilling programmes are also being considered for both fields as a result of the recent time-lapse 3-D seismic survey.

Côte d'Ivoire

Tullow's share of production in the first half of 2011 from the Espoir fields averaged 3,800 boepd net. Sand control issues experienced on some West Espoir wells are being addressed by a remedial work-over campaign and an infill drilling programme to replace production capacity is planned for 2012.

In February, civil unrest in Côte d'Ivoire led to Tullow's exploration blocks, CI-103 and CI-105, being put into Force Majeure, freezing all exploration commitments required on the blocks. Following improvement in the security situation, Force Majeure was lifted from both blocks in July and drilling plans are now well advanced. A rig has been secured to drill the Kosrou-1 well in CI-105 in late Q4 2011 and the Paon-1 well in CI-103 in Q1 2012. During this period, offshore production operations were not impacted.

Gabon 

Production in Gabon in the first half of the year was in line with expectations at 12,500 bopd net supported by the successful Limande-7 appraisal well and sustained production from the Tchatamba and Niungo fields. Production in the second half will be supported by the drilling of the Madiela well on Tchatamba South and two Turnix wells. Over the coming years production is expected to continue to be sustained at current levels or higher, despite natural decline in this mature area, due to the significant activity levels planned.

The final results from the new 3D survey in Kiarsseny are expected in mid-September with two exploration wells expected by mid-2012. In June, Tullow completed a 20% farm-in to the Perenco-operated onshore exploration blocks DE-7 and Ogueyi. The first exploratory well on the B'Oba prospect in the DE-7 block was a dry hole and has been plugged and abandoned. The rig is en-route to the Nkongono prospect in the Ogueyi block and is expected to commence in the coming weeks.

Congo (Brazzaville)

In the first half of 2011, net production from the M'Boundi field averaged 3,200 bopd. Over 15 infill wells are planned to be drilled in the second half of this year and gross water injection rates are expected to stabilise at over 120,000 bwpd with an upgrade to achieve a stretch target of 200,000 bwipd also being considered. Improving water injection performance is critical as the recent poor performance of the water injection systems has resulted in worse than expected production performance.

Mauritania

During the first half of 2011, Chinguetti field net production averaged 1,450 boepd. Following flowline optimisation at the end of 2010 the rate of production decline has been reduced.

Two exploration wells were drilled in the first half of 2011. The Cormoran-1 well in Block 7 intersected four stacked hydrocarbon accumulations. The deepest of these sections encountered highly pressured rich gas in the Petronia prospect, successfully extending Tullow's core play in Late Cretaceous turbidities into northern Mauritania. The Gharabi-1 well in Block 6, encountered poorly developed water-bearing reservoir and was plugged and abandoned in February with no impact on Tullow's plans for its Mauritanian acreage. Tullow's longer-term plans for the area include a series of exploration wells planned across the margin during 2012.

Namibia

Agreement has been reached with NamPower on the design of the Kudu gas production facilities and the Kudu power station. As a result, Gas Sales Agreement and Project Development Agreement negotiations have resumed with significant progress made. FEED studies for both the upstream and the downstream components are expected to commence in the fourth quarter of 2011, subject to final commercial agreement. An investment decision is targeted for the middle of next year which could deliver first gas and power generation in the second half of 2015.

Kenya and Ethiopia

In February 2011, Tullow completed the farm-in to blocks 10A, 10BA, 10BB, 12A and 13T in Kenya and the South Omo block in Ethiopia. Tullow now operates all six blocks covering an area of around 100,000 sq km in the Turkana Rift Basin where similar geological characteristics to the Lake Albert Rift Basin in Uganda have been identified. Significant 2D seismic acquisition activity will commence across the acreage in September. In March, Tullow farmed into the L8 block offshore Kenya for a 15% equity position with an option to increase to 20% (subject to legal and regulatory consent).

In Block 10BB, all existing 2D seismic data has been interpreted and the Ngamia prospect (formerly known as Fise) has been selected for drilling. The Weatherford 804 rig has been contracted and is currently mobilising from Tunisia to Kenya and will spud the well in early Q4 2011. In addition to drilling operations, a full tensor gradiometry (FTG) gravity survey has been substantially acquired to identify and refine basin-wide prospectivity along with a bathymetry survey in Lake Turkana.

In Block 10A, an 800km 2D seismic survey was completed in the second quarter of 2011 and has now been processed. Prospects have been identified and the Paipai prospect is a candidate to be drilled first. Site preparation will commence in September 2011 to meet a Q1 2012 spud date using the Weatherford 804 rig.

Madagascar and Tanzania

In Madagascar, a field programme was completed in blocks 3109 and 3111. This highlighted oil seeps and provided further information on the reservoir and seals in this frontier region. A 462 km 2D seismic programme is about to commence and, based on these results, a well is planned for 2012. In Tanzania, the Ntorya-1 well is planned for late-2011.

REST OF THE WORLD

2011 Half-yearly results highlights

Total production 19,500 boepd

Total reserves and resources 87.7 mmboe

Sales revenue US$161.9 million

1H 2011 investment US$91.3 million

·       1H 2011 average working interest production in-line with expectations at 19,500 boepd.

·       UK production averaged 14,050 boepd in 1H 2011 in line with expectations. Full year 2011 production of around 16,300 boepd is expected.

·       Acquired Nuon Exploration and Production (Nuon E&P) for €300 million ($404 million).

·       Result from the high-impact Zaedyus well in French Guiana expected in September.

Europe

UK

Thames Area production averaged 1,500 boepd net in the first half of 2011. Fields are facing natural decline but have performed well with high production efficiency throughout the period. Tullow drilled the 49/30b-10 well on the Foxtrot prospect in August. The well targeted the Upper Bunter sandstone formation. However, the sands were found to be water wet. The well has been suspended for later re-entry pending the evaluation of a deeper Rotliegendes play.

Production from the CMS Area averaged 12,550 boepd net in the first half of 2011. Production on the Schooner and Ketch fields has been within expectations and the Ketch-10 infill well is planned to commence before the end of the year.

The operator is on track to submit a Field Development Plan, for the Katy field (formerly Harrison), to the authorities in early September with drilling of a well scheduled for 2012. The Tullow operated Cameron-1 exploration well (44/19a-7a) commenced drilling in April with the Ensco 80 and discovered gas within the Carboniferous play. The well has since been suspended for potential future re-entry with a development sidetrack. The Cameron well result will now be integrated into a reservoir model to assess its commerciality.

Netherlands

Complementing its Dutch-operated exploration portfolio, Tullow completed the acquisition in June of Nuon E&P for a cash consideration of €300 million ($404 million) from the Vattenfall Group. The non-operated portfolio includes 25 licences with over 30 producing fields, numerous development and exploration opportunities and equity in key infrastructure. Production from the assets in the first half of the year averaged approximately 8,000 boepd. Whilst delays in drilling activity are expected to result in a production decline in the second half, the future programme of five infill and exploration wells is expected to enhance production in 2012.

Interpretation of the 2010 Tullow acquired E-Block 3D seismic has resulted in an improved prospect inventory being matured for a potential Carboniferous drilling campaign in 2012. The Cameron discovery continues the Group's historic 100% success record with this Carboniferous truncation play in the UK and bodes well for its neighbouring Dutch portfolio.

In February, Tullow participated in the non-operated Muscovite exploration well (E16-5) with a 4.3% working interest. The well targeted a structural play and was plugged and abandoned as a dry hole with residual gas indications from logging. Valuable insights from this well are being applied and integrated into the E-block portfolio and prospect inventory.

South Asia

Bangladesh

Gross production from the Bangora field has averaged 105 mmscfd for the first half of the year and is expected to be maintained at that level through to year-end. A number of the wells will be worked over in 2012 to revert to previous maximum capacity of 120 mmscfd. Planning is under way at Bangora for the installation of compression facilities in 2012/13 which will optimise the production profile going forward and increase ultimate recoverable reserves.

Reprocessing of the 3D geophysical data over Bangora is progressing well and will be interpreted in the second half of 2011 with a view to identifying additional prospectivity within the Bangora development lease for potential future drilling. Negotiations with the Bangladesh Government, to finalise the award of offshore exploration Block SS-08-05, remain on hold pending the outcome of a maritime boundary dispute with India.

Pakistan

The results from the extended well test on the Shekhan-1 discovery well have been encouraging and plans are now under way to acquire 3D seismic over the area and adjacent leads and prospects with a view to defining locations for appraisal and exploration drilling in 2012/13. Additional seismic is also being planned over other leads and prospects in the Kohat licence. The Jabbi-1 exploration well, which was spudded in May 2011, is progressing on schedule and should reach reservoir objectives in September. This prospect is located approximately 20 km along trend to the west of Shekhan and if successful could easily be tied-in to the processing and production facilities at Shekhan.

South America

French Guiana

The ENSCO 8503 rig commenced drilling the Jubilee-type Late Cretaceous Zaedyus prospect in March. The objective of this wildcat well is to test the Jubilee play across the Atlantic in a new potential hydrocarbon province where Tullow has secured a commanding acreage position. Delays have occurred during the drilling of this deepwater wildcat well for a number of reasons; in particular, issues have arisen from drilling in a new basin with little or no comparative data. The rig also had to handle periods of increased ocean currents and some hole instability. The final section of the well is now being drilled and results are expected in September.

Guyana

The Atwood Beacon jack-up, contracted to drill the Late Cretaceous Jaguar prospect in Guyana, has been delayed due to operational and weather delays on previous wells. The rig is now anticipated to commence the Jaguar well in the fourth quarter of 2011. The well is expected to take 180 days to drill.

Suriname

In Block 47 offshore Suriname, an Environmental Impact Assessment study has been initiated with a view to having the appropriate approvals in place for the commencement of an extensive 3D seismic programme of approximately 2,000 sq km early next year. The optimum weather window for seismic acquisition in this region is Q2 2012 and preparations are ongoing with a view to commencing the 3D seismic programme in April.

Onshore activity mainly focused on continued preparation for the Coronie drilling programme which is now due to commence in mid September. 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.

Finance review

Tullow's record half-yearly results are in line with expectations with both higher sales volumes and average price realisations resulting in profit after tax increasing 272% to $330.3 million (1H 2010: $89.0 million) and earnings per share increasing by the same percentage to 35.0 cents (1H 2010: 9.4 cents).

Key financial metrics	1H 2011	1H 2010	Change
Production (boepd, working interest basis)	75,100	55,800	35%
Sales volume (boepd)	64,000	44,200	45%
Realised oil price per bbl (US$)	112.0	77.0	45%
Realised gas price (pence per therm)	56.0	34.0	65%
Cash operating costs per boe ($)1	12.6	11.9	6%
Operating cash flow before working capital per boe ($)	62.9	36.3	73%
Net debt2  ($million)	2,609.2	203.3	1,183%
Interest cover3	18.9	57.4	-38.5 times
Gearing (%)4	63	5	58%

^1.       Cash operating costs are cost of sales excluding depletion, depreciation and amortisation, impairment loss and under/over lift movements.

^2.       Net debt is financial liabilities gross of unamortised arrangement fees less cash and cash equivalents.

^3.       Interest cover is earnings before interest, impairment losses and depreciation charges divided by net finance costs.

^4.       Gearing is net debt net of unamortised arrangement fees divided by net assets.

Operating performance

Working interest production averaged 75,100 boepd, in line with expectations and 35% higher than the corresponding period in 2010 following first oil from the Jubilee field in Ghana where production commenced in December 2010. Sales volumes averaged 64,000 boepd, representing an increase of 45%.

Realised oil price was US$112.0/bbl (1H 2010: US$77.0/bbl), an increase of 45% and realised gas price was 56.0p/therm (1H 2010: 34.0p/therm), an increase of 62%. Tullow's oil production was sold on average at a discount of 2% to Brent during the period (1H 2010: 2% discount).

Increased commodity prices combined with higher sales volumes resulting in an overall revenue increase of 119% to $1,062.4 million (1H 2010: $485.9 million).

Underlying cash operating costs, which exclude depletion and amortisation and movements on under/overlift, amounted to $172.6 million ($12.6/boe) (1H 2010: $11.9/boe) and depreciation, depletion and amortisation charges for the period amounted to $204.1 million ($14.9/boe) (1H 2010: $16.8/boe). There has been no impairment charge recognised in cost of sales in the first half of 2011 (1H 2010: $6.4 million). At the period end Tullow was in a net underlift position of 129,300 barrels and this combined with stock movements has given rise to a credit of $14.0 million to cost of sales.

Operating profit before exploration activities amounted to $642.7 million (1H 2010: $176.9 million), an increase of 263%, principally due to the higher realised oil prices and additional Ghana production during the period.

Administrative expenses of $56.9 million (1H 2010: $32.3 million) include an amount of $7.2 million (1H 2010: $7.0 million) associated with share-based payments under IFRS 2. The increase is primarily due to continued growth in employee numbers.

Exploration write-off

Exploration costs written-off were $54.6 million (1H 2010: $52.5 million), in accordance with the Group's 'successful efforts' accounting policy. This write-off is principally due to unsuccessful activities in Ghana, Mauritania, and Gabon and ongoing new ventures activity.

Derivative instruments

Tullow continues to undertake hedging activities as part of the ongoing management of its business risk and to protect the availability of cash flow for reinvestment in capital programmes.

At 30 June 2011, the Group's commodity derivative instruments had a net negative fair value of $110.2 million (30 June 2010: net positive $11.3 million). The movement in the fair value position during the first half of 2011 is a result of both oil and gas prices strengthening during the period.

The Group's interest rate derivative instruments had a net negative fair value of $10.7 million (30 June 2010: net negative $14.7 million) due to low dollar swap rates.

While all of the Group's commodity derivative instruments currently qualify for hedge accounting, a charge of $2.7 million (1H 2010: credit of $11.6 million) has been recognised in the income statement for the first half of 2011. The charge has been principally caused by Brent oil prices strengthening during the period, with a consequent decrease in the time value of the Group's derivative instruments.

The Group's hedge position as at 19 August 2011 can be summarised as follows:

Hedge position	2H 2011	2012	2013	2014
Oil
Volume - bopd	33,000	31,000	15,500	3,500
Current Price Hedge - US$/bbl	108.1	105.7	103.6	100.5
Gas Hedges
Volume - mmscfd	42.9	21.7	10.8	1.8
Current Price Hedge - p/therm	57.9	65.2	68.2	76.1

Gearing, financing costs and interest cover

The net interest charge for the period was $45.3 million (1H 2010: $5.5 million) and reflects the increase in average net debt levels experienced during the first half of 2011. Tullow had net debt of $2,609.2 million (1H 2010: $203.3 million), while unutilised debt capacity was in excess of US$740 million. Net debt at 31 December 2010 was $1,943 million and the increase in the first half of the year was principally due to continuing capital investment and the acquisition of Nuon E&P on 30 June 2011 offset by significantly increased cash flow from operations. The Group's gearing is 63% (1H 2010: 5%) and interest cover has decreased to 18.9 times (1H 2010: 57.4 times).

Taxation

The tax charge of $209.8 million (1H 2010: $41.5 million) relates to the Group's North Sea, Ghana, Gabon, Equatorial Guinea and Mauritanian activities and represents 39% of the Group's profit before tax (1H 2010: 32%). After adjusting for exploration costs and profit on disposal of subsidiaries, the Group's underlying effective tax rate is 35% (1H 2010: 23%).

Dividend

Tullow's finances are being fundamentally changed in 2011 by increased production and cash flow from the Jubilee field. As a result, the Board feels that it is appropriate to review Tullow's dividend policy and has doubled the dividend for the half year to 4.0 pence per share (1H or 1H2010: 2.0 pence per share). The dividend will be paid on 3 November 2011 to shareholders on the register on 30 September 2011.

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.

Operating cash flow and capital expenditure

Increased commodity prices and higher sales volumes led to operating cash flows before working capital movements of $854.5 million (1H 2010: $366.6 million). This cash flow facilitated investment in exploration and development activities, payment of a final dividend and servicing of the Group's debt facilities.

Total 2011 capital expenditure is expected to be approximately $1.5 billion. This investment will be split 45% on production and development and the remainder on exploration and appraisal. Tullow's activities in Ghana and Uganda will comprise 50% of the anticipated capital outlay.

Portfolio management and long-term funding

On 30 June 2011 Tullow completed the acquisition of Nuon E&P from the Vattenfall Group. This added a portfolio of 25 licences, over 30 producing fields as well as various development and exploration opportunities together with the ownership of key infrastructure.

In April 2011, Tullow increased the commitments of its Reserve Based Lending facility by $0.5 billion to US$3.0 billion and completed a further corporate facility of $300 million in June 2011. The Group now has total debt facilities of US$3.95 billion.

Risk factors

Effective risk management is critical to achieving the Group's strategic objectives and protecting its people and reputation. The Board determines the specific key risks for the company and required mitigation plans and reviews delivery on a monthly basis. The principal risks and uncertainties facing the Group at the year end, their potential impact and the mitigation strategies developed were detailed in the Annual Report and Accounts 2010 (available on our website www.tullowoil.com). All the risk and uncertainties which were identified at the year end have not changed and still remain appropriate. The Group has identified its principal risks for the next 6 months as being:

·       Completion of the Uganda farm-down;

·       Execution risk in major development projects in Ghana and Uganda;

·       Exploration risk in the context of a very active programme; and

·       Oil price and overall market volatility.

Liquidity risk management and going concern

The Group closely monitors and manages its liquidity risk. Cash forecasts are regularly produced and sensitivities run for different scenarios including, but not limited to, changes in commodity prices, different production rates from the Group's producing assets and delays to development projects. The Group generally seeks to ensure that it has a minimum ongoing capacity of $500 million for a period of at least 12 months to safeguard its ability to continue as a going concern. In addition to operating cash flows, portfolio management opportunities are reviewed to potentially enhance the financial capacity and flexibility of the Group. The major assumption in current cash flow forecasts is that the receipt of disposal proceeds from the Uganda farm-down, which have been delayed longer than expected, will now be received in Q4 2011. On this basis, the Group's forecasts, taking into account reasonably possible changes as described above, show that the Group will be able to operate within its current debt facilities and have very significant financial headroom for the 12 months from the date of the 2011 Half-yearly results. However, in the event that the Ugandan farm-down process is delayed further, the Directors are confident that the Group can manage its financial affairs, including the securing of additional funding, agreement with existing lenders, portfolio management and deferring of non-essential capital expenditure, so as to ensure that sufficient funding remains available for the next twelve months. Therefore, notwithstanding the above uncertainties, the Directors consider that the Group has adequate resources to continue in operational existence for the foreseeable future.

Financial strategy and outlook

Our financial strategy continues to be to maintain flexibility to support the Group's significant appraisal and development programmes in Ghana and Uganda and effectively allocate capital across the remainder of our business.

The outlook for the remainder of 2011 and the coming years is positive for Tullow. Production ramp up from the Ghana Jubilee field will continue in the second half of 2011, together with further appraisal and development activities. The completion of the Ugandan farm-down is expected to be completed in the near future which will pave the way for the basin-wide appraisal and development with CNOOC and Total.  Over the next 12 months we plan to drill exploration and appraisal wells in French Guiana, Côte d'Ivoire, Ghana, Kenya, Sierra Leone and Uganda which have the potential to add material resources to the Group. Overall, we are well placed to deliver significant growth in shareholder value over the coming years.

Responsibility statement

The Directors confirm that to the best of their knowledge:

a)   the condensed set of financial statements has been prepared in accordance with lAS 34 'Interim Financial Reporting';

b)   the interim management report includes a fair review of the information required by DTR 4.2.7R (indication of important events during the first six months and description of principal risks and uncertainties for the remaining six months of the year); and

c)   the interim management report includes a fair review of the information required by DTR 4.2.8R (disclosure of related parties' transactions and changes therein).

The Directors of Tullow Oil plc are as listed in the Group's 2010 Annual Report and Accounts. A list of the current Directors is maintained on the Tullow Oil plc website: www.tullowoil.com.

By order of the Board,

Aidan Heavey	Ian Springett
Chief Executive Officer	Chief Financial Officer
23 August 2011	23 August 2011

Disclaimer

This statement contains certain forward-looking statements that are subject to the usual 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 factors beyond the Group's control or within the Group's control where, for example, the Group decides on a change of plan or strategy. Accordingly no reliance may be placed on the figures contained in such forward-looking statements.

Independent review report to Tullow Oil plc

We have been engaged by the company to review the condensed set of financial statements in the half-yearly financial report for the six months ended 30 June 2011 which comprises the consolidated income statement, the consolidated statement of comprehensive income and expense, the consolidated balance sheet, the consolidated statement of changes in equity, the consolidated cash flow statement and related notes 1 to 13. We have read the other information contained in the half-yearly financial report and considered whether it contains any apparent misstatements or material inconsistencies with the information in the condensed set of financial statements.

This report is made solely to the Company in accordance with International Standard on Review Engagements (UK and Ireland) 2410 "Review of Interim Financial Information Performed by the Independent Auditor of the Entity" issued by the Auditing Practices Board.  Our work has been undertaken so that we might state to the company those matters we are required to state to it in an independent review report and for no other purpose. To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the company, for our review work, for this report, or for the conclusions we have formed.

Directors' responsibilities

The half-yearly financial report is the responsibility of, and has been approved by, the directors. The directors are responsible for preparing the half-yearly financial report in accordance with the Disclosure and Transparency Rules of the United Kingdom's Financial Services Authority.

As disclosed in note 2, the annual financial statements of the group are prepared in accordance with IFRSs as adopted by the European Union. The condensed set of financial statements included in this half-yearly financial report has been prepared in accordance with International Accounting Standard 34, "Interim Financial Reporting," as adopted by the European Union.

Our responsibility

Our responsibility is to express to the Company a conclusion on the condensed set of financial statements in the half-yearly financial report based on our review.

Scope of Review

We conducted our review in accordance with International Standard on Review Engagements (UK and Ireland) 2410 "Review of Interim Financial Information Performed by the Independent Auditor of the Entity" issued by the Auditing Practices Board for use in the United Kingdom. A review of interim financial information consists of making inquiries, primarily of persons responsible for financial and accounting matters, and applying analytical and other review procedures. A review is substantially less in scope than an audit conducted in accordance with International Standards on Auditing (UK and Ireland) and consequently does not enable us to obtain assurance that we would become aware of all significant matters that might be identified in an audit. Accordingly, we do not express an audit opinion.

Conclusion

Based on our review, nothing has come to our attention that causes us to believe that the condensed set of financial statements in the half-yearly financial report for the six months ended 30 June 2011 is not prepared, in all material respects, in accordance with International Accounting Standard 34 as adopted by the European Union and the Disclosure and Transparency Rules of the United Kingdom's Financial Services Authority.

Deloitte LLP

Chartered Accountants and Statutory Auditor

London, UK

23 August 2011

Condensed consolidated income statement

Six months ended 30 June 2011

	Note	6 months ended  30.06.11 Unaudited $'m	6 months ended  30.06.10 Unaudited $'m	Year ended 31.12.10 Audited $'m
Sales revenue	6	1,062.4	485.9	1,089.8
Cost of sales		(362.8)	(277.2)	(611.4)
Gross profit		699.6	208.7	478.4
Administrative expenses		(56.9)	(32.3)	(89.6)
Profit on disposal of assets		-	0.5	0.5
Exploration costs written off		(54.6)	(52.5)	(154.7)
Operating profit		588.1	124.4	234.6
(Loss)/gain on hedging instruments		(2.7)	11.6	(27.7)
Finance revenue		8.7	12.5	15.1
Finance costs		(54.0)	(18.0)	(70.1)
Profit from continuing activities before tax		540.1	130.5	151.9
Income tax expense	11	(209.8)	(41.5)	(79.4)
Profit for the period from continuing activities		330.3	89.0	72.5
Attributable to:
Equity holders of the parent		311.3	81.7	54.0
Non-controlling interest		19.0	7.3	18.5
		330.3	89.0	72.5
Earnings per ordinary share		c	c	c
- Basic	3	35.0	9.4	6.1
- Diluted	3	34.7	9.2	6.1

Condensed consolidated statement of comprehensive income and expense 

Six months ended 30 June 2011

		6 months ended  30.06.11 Unaudited $'m	6 months ended  30.06.10 Unaudited $'m	Year  ended 31.12.10 Audited $'m
Profit for the period		330.3	89.0	72.5
Cash flow hedges
Losses arising in the period		(27.5)	(7.7)	(26.8)
Reclassification adjustments for losses          included in profit  on realisation		(8.1)	(12.3)	(10.3)
		(35.6)	(20.0)	(37.1)
Exchange differences on translation of foreign operations		10.6	(18.7)	(11.4)
Other comprehensive income before tax		(25.0)	(38.7)	(48.5)
Tax relating to components of other comprehensive income		5.9	6.4	8.2
Other comprehensive income for the period		(19.1)	(32.3)	(40.3)
Total comprehensive income for the period		311.2	56.7	32.2
Attributable to:
Equity holders of the parent		292.2	49.4	13.7
Non-controlling interest		19.0	7.3	18.5
		311.2	56.7	32.2

Condensed consolidated balance sheet

As at 30 June 2011

		Note	30.06.11 Unaudited $'m	30.06.10 Unaudited $'m	31.12.10 Audited $'m
ASSETS
Non-current assets
Intangible exploration and evaluation assets			4,704.3	2,288.6	4,001.2
Property, plant and equipment			3,616.4	2,424.5	2,974.4
Investments			1.0	1.0	1.0
Other receivables		9	485.1	-	-
Deferred tax assets			65.6	54.6	110.7
			8,872.4	4,768.7	7,087.3
Current assets
Inventories			144.3	127.8	138.2
Trade receivables			318.0	110.4	158.9
Other current assets			578.2	474.8	655.3
Cash and cash equivalents			403.2	1,592.5	338.3
			1,443.7	2,305.5	1,290.7
Total assets			10,316.1	7,074.2	8,378.0
LIABILITIES
Current liabilities
Trade and other payables			(1,297.4)	(663.6)	(1,008.2)
Other financial liabilities			(395.4)	-	(309.8)
Current tax liabilities			(92.9)	(65.8)	(120.0)
Derivative financial instruments			(68.6)	(12.5)	(47.1)
			(1,854.3)	(741.9)	(1,485.1)
Non-current liabilities
Trade and other payables			(416.9)	(29.9)	(354.0)
Other financial liabilities			(2,537.7)	(1,669.2)	(1,890.0)
Deferred tax liabilities			(949.1)	(445.6)	(466.1)
Provisions			(356.8)	(274.5)	(278.6)
Derivative financial instruments			(52.3)	(13.5)	(35.3)
			(4,312.8)	(2,432.7)	(3,024.0)
Total liabilities			(6,167.1)	(3,174.6)	(4,509.1)
Net assets			4,149.0	3,899.6	3,868.9
EQUITY
Called up share capital			143.8	143.3	143.5
Share premium			259.7	247.6	251.5
Other reserves		10	555.1	582.2	574.2
Retained earnings			3,110.8	2,877.1	2,839.1
Equity attributable to equity holders of the parent			4,069.4	3,850.2	3,808.3
Non-controlling interest			79.6	49.4	60.6
Total equity			4,149.0	3,899.6	3,868.9

Condensed consolidated statement of changes in equity

As at 30 June 2011

	Share  Capital $'m	Share Premium $'m	Other Reserves (note 10) $'m	Retained Earnings $'m	Total $'m	Non-controlling Interest  $'m	Total Equity $'m
At 1 January 2010	130.1	242.3	614.5	1,402.0	2,388.9	42.1	2,431.0
Total comprehensive income and expense	-	-	(32.3)	81.7	49.4	7.3	56.7
Issue of equity shares	13.1	2.1	-	1,433.0	1,448.2	-	1,448.2
New shares issued in respect of employee share options	0.1	3.2	-	-	3.3	-	3.3
Vesting of PSP shares	-	-	-	(0.3)	(0.3)	-	(0.3)
Share-based payment charge	-	-	-	11.8	11.8	-	11.8
Dividends paid	-	-	-	(51.1)	(51.1)	-	(51.1)
At 30 June 2010	143.3	247.6	582.2	2,877.1	3,850.2	49.4	3,899.6
Total comprehensive income and   expense	-	-	(8.0)	(27.7)	(35.7)	11.2	(24.5)
New shares issued in respect of employee share options	0.2	3.9	-	-	4.1	-	4.1
Issue of equity shares	-	-	-	(0.1)	(0.1)	-	(0.1)
Vesting of PSP shares	-	-	-	0.1	0.1	-	0.1
Share-based payment charge	-	-	-	17.8	17.8	-	17.8
Dividends paid	-	-	-	(28.1)	(28.1)	-	(28.1)
At 31 December 2010	143.5	251.5	574.2	2,839.1	3,808.3	60.6	3,868.9
Total comprehensive income and expense	-	-	(19.1)	311.3	292.2	19.0	311.2
New shares issued in respect of employee share options	0.3	8.2	-	-	8.5	-	8.5
Share-based payment charge	-	-	-	18.0	18.0	-	18.0
Dividends paid	-	-	-	(57.6)	(57.6)	-	(57.6)
At 30 June 2011	143.8	259.7	555.1	3,110.8	4,069.4	79.6	4,149.0

Condensed consolidated cash flow statement

Six months ended 30 June 2011

			Note	6 months ended  30.06.11 Unaudited $'m	6 months ended  30.06.10 Unaudited $'m	Year  ended 31.12.10 Audited $'m
Cash flows from operating activities
Cash generated from operations			7	776.2	317.0	818.0
Income taxes paid				(111.5)	(69.0)	(85.6)
Net cash flow from operating activities				664.7	248.0	732.4
Cash flows from investing activities
Disposal of assets				0.3	0.5	6.7
Purchase of intangible exploration & evaluation assets				(518.6)	(195.1)	(2,006.1)
Purchase of property, plant and equipment				(236.4)	(299.4)	(625.6)
Purchase of subsidiaries			8	(404.0)	-	-
Advances to contractors				-	(129.9)	(172.4)
Finance revenue				8.7	10.2	5.4
Net cash used in investing activities				(1,150.0)	(613.7)	(2,792.0)
Cash flows from financing activities
Net proceeds from issue of share capital				8.4	1,449.3	1,453.3
Debt arrangement fees				(13.8)	(11.8)	(16.7)
Asset purchase arrangement fees				-	(37.3)	-
Repayment of bank loans				-	(47.3)	(20.9)
Drawdown of bank loan				730.0	450.3	907.0
Repayment of obligations under finance leases				(5.4)	-	-
Finance costs				(107.6)	(39.4)	(94.2)
Dividends paid				(57.6)	(51.1)	(79.2)
Net cash generated by financing activities				554.0	1,712.7	2,149.3
Net increase in cash and cash equivalents				68.7	1,347.0	89.7
Cash and cash equivalents at beginning of period				338.3	252.2	252.2
Translation difference				(3.8)	(6.7)	(3.6)
Cash and cash equivalents at end of period				403.2	1,592.5	338.3

Notes to the half-yearly financial statements

Six Months ended 30 June 2011

1.     General information

The financial information for the year ended 31 December 2010 does not constitute statutory accounts as defined in section 434 of the Companies Act 2006. This information was derived from the statutory accounts for the year ended 31 December 2010, a copy of which has been delivered to the Registrar of Companies. The auditor reported on those accounts; their report was unqualified, did not draw attention to any matters by way of emphasis and did not contain a statement under section 498(2) or (3) of the Companies Act 2006.

2.     Accounting policies

The annual financial statements of Tullow Oil plc are prepared in accordance with IFRSs as adopted by the European Union. The condensed set of financial statements included in this half-yearly report have been prepared in accordance with International Accounting Standard 34 'Interim Financial Reporting', as adopted by the European Union and the Disclosure and Transparency Rules of the Financial Services Authority.

Change in reportable segments

During 2011 information reported to the directors for the purposes of resource allocation and assessment of segment performance has changed from 4 to 3 geographical segments. In accordance with the requirements of IFRS 8 the disclosure of the Group's segments in these half-yearly financial statements has been amended to reflect this change (see note 6).

Basis of preparation

The condensed set of financial statements included in this half-yearly financial report have been prepared on a going concern basis as the Directors consider that the Group has adequate resources to continue in operational existence for the foreseeable future as explained in the Finance Review.

The same accounting policies, presentation and methods of computation are followed in the condensed set of financial statements as applied in the group's latest audited annual statements.

3.     Earnings per share

The calculation of basic earnings per share is based on the profit attributable to equity shareholders of $311.3 million (1H 2010: $81.7 million) and a weighted average number of shares in issue of 889.2 million (1H 2010: 872.6 million).

The calculation of diluted earnings per share is based on the profit for the period after taxation as for basic earnings per share. The number of shares outstanding, however, is adjusted to show the potential dilution if employee share options are converted into ordinary shares. The weighted average number of ordinary shares is increased by 7.1 million (1H 2010: 11.8 million) in respect of employee share options, resulting in a diluted weighted average number of shares of 896.3 million (1H 2010: 881.9 million).

4.     Dividends

The Company's shareholders approved a final dividend for the year ended 31 December 2010 of 4p per share at the Annual General Meeting on 12 May 2011. This amount was paid on 20 May 2011 to shareholders on the register of members of the Company on 15 April 2011.

The Board has declared an interim 2011 dividend of 4p per share in the half year to 30 June 2011 to be paid on 3 November 2011 to shareholders on the register on 30 September 2011 (1H 2010: 2p per share).

5.     Approval of Accounts

These half-yearly financial statements (Unaudited) were approved by the Board of Directors on 23 August 2011.

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, North Africa and Asia, Equatorial Atlantic 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 six months ended 30 June 2011 and 2010 and for the year ended 31 December 2010. The tables for the six months ended 30 June 2011 and for the year ended 31 December 2010 have been restated to reflect the new reportable segments of the business.

Six months ended 30 June 2011	Europe, North Africa and Asia $'m	Equatorial Atlantic $'m	South and East Africa $'m	Unallocated $'m	Total $'m
Sales revenue by origin	179.2	883.2	-	-	1,062.4
Segment result	43.0	603.8	(1.8)	-	645.0
Profit on disposal of assets					-
Corporate expenses					(56.9)
Operating profit					588.1
Loss on hedging instruments					(2.7)
Finance revenue					8.7
Finance costs					(54.0)
Profit before tax					540.1
Income tax expense					(209.8)
Profit after tax					330.3
Total assets	1,919.1	4,473.2	3,729.5	194.3	10,316.1
Total liabilities	(910.3)	(1,562.5)	(621.6)	(3,072.7)	(6,167.1)
Other segment information
Capital expenditure:
Property, plant and equipment	8.7	152.3	0.1	11.6	172.7
Intangible fixed assets	51.5	205.0	294.0	-	550.5
Depletion, depreciation and amortisation	(63.4)	(140.8)	-	(8.7)	(212.9)
Exploration costs written off	(15.6)	(37.2)	(1.8)	-	(54.6)

Unallocated expenditure and net liabilities include amounts of a corporate nature and not specifically attributable to a geographic area and the Group debt.

Six months ended 30 June 2010 (Restated)	Europe, North Africa and Asia $'m	Equatorial Atlantic $'m	South and East Africa $'m	Unallocated $'m	Total $'m
Sales revenue by origin	121.2	364.7	-	-	485.9
Segment result	(23.9)	192.7	(12.6)	-	156.2
Profit on disposal of assets					0.5
Corporate expenses					(32.3)
Operating profit					124.4
Gain on hedging instruments					11.6
Finance revenue					12.5
Finance costs					(18.0)
Profit before tax					130.5
Income tax expense					(41.5)
Profit after tax					89.0
Total assets	954.5	3,153.5	2,819.5	146.7	7,074.2
Total liabilities	(347.9)	(852.3)	(263.1)	(1,711.3)	(3,174.6)
Other segment information
Capital expenditure:
Property, plant and equipment	33.6	382.9	-	9.7	426.2
Intangible fixed assets	16.4	90.5	118.2	-	225.1
Depletion, depreciation and amortisation	(73.2)	(99.1)	-	(4.5)	(176.8)
Impairment losses recognised in income statement	(6.4)	-	-	-	(6.4)
Exploration costs written off	(15.5)	(24.4)	(12.6)	-	(52.5)

Unallocated expenditure and net liabilities include amounts of a corporate nature and not specifically attributable to a geographic area and the Group debt.

Year ended 31 December 2010 (Restated)	Europe, North Africa and Asia $'m	Equatorial Atlantic $'m	South and East Africa $'m	Unallocated $'m	Total $'m
Sales revenue by origin	285.2	804.6	-	-	1,089.8
Segment result	(3.0)	391.5	(64.8)	-	323.7
Profit on disposal of assets					0.5
Corporate expenses					(89.6)
Operating profit					234.6
Loss on hedging instruments					(27.7)
Finance revenue					15.1
Finance costs					(70.1)
Profit before tax					151.9
Income tax expense					(79.4)
Profit after tax					72.5
Total assets	1,033.9	4,080.6	3,099.9	163.6	8,378.0
Total liabilities	(403.5)	(1,490.6)	(336.9)	(2,278.1)	(4,509.1)
Other segment information
Capital expenditure:
Property, plant and equipment	90.0	1,029.3	-	33.1	1,152.4
Intangible fixed assets	63.0	225.8	1,758.9	-	2,047.7
Depletion, depreciation and amortisation	(137.3)	(219.8)	-	(10.2)	(367.3)
Impairment losses recognised income statement	(4.3)	-	-	-	(4.3)
Exploration costs written off	(30.2)	(59.7)	(64.8)	-	(154.7)

Unallocated expenditure and net liabilities include amounts of a corporate nature and not specifically attributable to a geographic area and the Group debt.

Sales revenue by origin			6 months ended  30.06.11 Unaudited $'m	6 months ended  30.06.10 Unaudited $'m	Year  ended 31.12.10 Audited $'m
Ghana1			386.6	-	-
Equatorial Guinea1			201.3	154.5	341.9
Côte d'Ivoire1			36.8	28.1	75.4
Gabon1			212.8	139.0	306.5
Congo1			45.2	40.6	79.4
Mauritania2			17.8	21.8	47.2
Total Africa			900.5	384.0	850.4
UK2			151.0	92.2	218.3
Total Europe			151.0	92.2	218.3
Pakistan2			0.8	0.1	0.6
Bangladesh2			10.1	9.6	20.5
Total South Asia			10.9	9.7	21.1
Total revenue			1,062.4	485.9	1,089.8

^1.       Included within the Equatorial Atlantic region

^2.       Included within the Europe, North Africa and Asia region

Non-current assets by origin			6 months ended  30.06.11 Unaudited $'m	6 months ended  30.06.10 Unaudited $'m	Year  ended 31.12.10 Audited $'m
Ghana1			2,649.5	2,047.3	1,313.8
Uganda3			3,081.0	2,829.0	1,217.3
Equatorial Guinea1			263.4	301.0	352.6
Côte d'Ivoire1			110.8	115.1	123.6
Gabon1			268.6	267.5	277.8
Congo1			165.1	155.3	165.8
Mauritania2			377.1	371.3	341.6
Other			257.2	217.0	239.3
Total Africa			7,172.7	6,305.5	4,031.8
UK2			417.8	429.3	424.2
Netherlands2			895.9	22.2	14.4
Total Europe			1,313.7	451.5	438.6
Pakistan2			18.8	17.5	14.2
Bangladesh2			34.9	36.4	42.3
Total South Asia			53.7	53.9	56.5
Total South America1			195.1	161.4	153.4
Unallocated			137.2	117.0	88.4
Total Non-current assets			8,872.4	7,087.3	4,768.7

^1.       Included within the Equatorial Atlantic region

^2.       Included within the Europe, North Africa and Asia region

^3.       Included within the South & East Africa region

7.      Cash Flows from Operating Activities

			6 months ended  30.06.11 Unaudited $'m	6 months ended  30.06.10 Unaudited $'m	Year  ended 31.12.10 Audited $'m
Profit before taxation			540.1	130.5	151.9
Adjustments for:
Depletion, depreciation and amortisation			212.9	176.8	367.3
Impairment loss			-	6.4	4.3
Exploration costs written off			54.6	52.5	154.7
Profit on disposal of assets			-	(0.5)	(0.5)
Decommissioning expenditure			(9.5)	-	(10.3)
Share based payment charge			8.4	7.0	11.9
(Loss)/gain on hedging instruments			2.7	(11.6)	27.7
Finance revenue			(8.7)	(12.5)	(15.1)
Finance costs			54.0	18.0	70.1
Operating cash flow before working capital movements			854.5	366.6	762.0
Increase in trade and other receivables			(62.5)	(44.0)	(66.7)
Increase in inventories			(5.6)	(19.0)	(29.0)
(Decrease)/increase in trade payables			(10.2)	13.4	151.7
Cash generated from operations			776.2	317.0	818.0

8.     Acquisition of subsidiaries

On 24 May 2011 Tullow announced that it had acquired 100% of Nuon E&P from the Vattenfall Group. The acquisition of Nuon E&P added a portfolio of 25 licences over 30 producing fields, a number of development and exploration opportunities and ownership of key infrastructure. This portfolio is expected to increase the Group's North Sea gas production by 9,000 boepd and add reserves and resources of 28 mmboe. The Nuon E&P transaction was completed on 30 June 2011 and this is therefore the acquisition date. Accordingly, the half-yearly financial statements include the balance sheet of Nuon E&P including fair value adjustments. However revenue and expenses from the acquired assets will be consolidated with effect from 1 July 2011.

The fair value allocation to the Nuon E&P assets is preliminary in nature given the timing of the acquisition and will be reviewed in accordance with the provisions of IFRS 3 - Business Combinations. Due to the inherently uncertain nature of the oil and gas industry and intangible exploration and evaluation assets in particular, the assumptions underlying the preliminary assigned values are highly judgemental in nature. The purchase consideration equals the aggregate of the fair value of the identifiable assets and liabilities of Nuon E&P, and therefore no goodwill has been recorded on the acquisition. Deferred tax has been recognised in respect of the fair value adjustments as applicable.

			Fair Value $'m
Intangible exploration and appraisal assets			204.0
Property, plant and equipment			666.4
Trade and other receivables			14.5
Trade and other payables			(12.5)
Deferred tax liabilities			(403.9)
Provisions			(64.5)
			404.0
Total consideration satisfied by cash			404.0

9.     Non-current assets - other receivables

Non-current assets - other receivables comprises amounts due from joint venture partners in relation to the long-term lease of the Jubilee FPSO.

10.   Other reserves

	Merger reserve $'m	Foreign currency translation reserve $'m	Hedge reserve $'m	Treasury shares $'m	Total $'m
At 1 January 2010	755.1	(129.6)	3.2	(14.2)	614.5
Hedge movement	-	-	(13.6)	-	(13.6)
Currency translation adjustment	-	(18.7)	-	-	(18.7)
At 30 June 2010	755.1	(148.3)	(10.4)	(14.2)	582.2
Hedge movement	-	-	(15.3)	-	(15.3)
Currency translation adjustment	-	7.3	-	-	7.3
At 31 December 2010	755.1	(141.0)	(25.7)	(14.2)	574.2
Hedge movement	-	-	(29.7)	-	(29.7)
Currency translation adjustment	-	10.6	-	-	10.6
At 30 June 2011	755.1	(130.4)	(55.4)	(14.2)	555.1

11.    Taxation

Income tax for the six month period is accrued based on the estimated annual effective rate of 39% (1H2010: 32%).

12.   Capital structure

In the six months ended 30 June 2011, the Group issued 1.9 million (1H 2010: 2.3 million) new shares in respect of employee share options.

As at 30 June 2011 the Group had in issue 890.2 million allotted and fully paid ordinary shares of Stg 10 pence each (1H 2010: 887.2 million).

In April 2011, Tullow increased its reserves based lending facility by $500 million to $3.0 billion and in June 2011 completed a further corporate facility of $300 million. The Group now has total debt facilities of $3.95 billion.

13.    Subsequent events

On 26 May 2011, Tullow announced that it had entered into a conditional agreement to acquire the interests of EO Group Limited (EO) for a combined share and cash consideration of $305 million. This acquisition increases Tullow's interest in the West Cape Three Points licence offshore Ghana by 3.5% to 26.4% and increases the Group's interest in the Jubilee field by 1.75% to 36.5%. The acquisition completed on 25 July 2011.

14.    Commercial Reserves and Contingent Resources Summary (Not reviewed by Auditors) working interest basis

	AFRICA			EUROPE			SOUTH ASIA			TOTAL
	Oil mmbbl	Gas bcf		Oil mmbbl	Gas bcf		Oil mmbbl	Gas bcf		Oil mmbbl	Gas bcf	Petroleum mmboe
Commercial Reserves
1 Jan 2011	245.9	22.1		1.4	150.3		0.3	108.1		247.6	280.5	294.4
Revisions	9.7	-		-	8.4		-	-		9.7	8.4	11.2
Acquisitions	0.8	-		-	76.0		-	-		0.8	76.0	13.4
Production	(9.9)	(1.0)		(0.1)	(14.4)		-	(5.9)		(10.0)	(21.3)	(13.6)
30 June 2011	246.5	21.1		1.3	220.3		0.3	102.2		248.1	343.6	305.4
Contingent Resources
1 Jan 2011	893.2	1,099.8		-	86.9		-	12.0		893.2	1,198.7	1,093.1
Additions	57.8	221.9		-	-		-	-		57.8	221.9	94.8
Acquisitions	-	-		-	94.0		-	-		-	94.0	15.7
30 June 2011	951.0	1,321.7		-	180.9		-	12.0		951.0	1,514.6	1,203.6
Total
30 June 2011	1,197.5	1,342.8		1.3	401.2		0.3	114.2		1,199.1	1,858.2	1,509.0

1.     Proven and Probable Commercial Reserves are based on a Group reserves report (with the exception of the Nuon E&P commercial reserves - see note 3 below) 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 commercial reserves and contingent resources acquisition relates to the purchase of Nuon E&P from the Vattenfall Group in June 2011 and are based on operator estimates.

4.     The total Commercial Reserves and Contingent Resources of 1,509 mmboe at 30 June 2011 include a 100% working interest in Blocks 1, 2 and 3A in Uganda. Post completion of the farm-down transaction with Total and CNOOC in Uganda, total Commercial Reserves and Contingent Resources are expected to reduce to 990 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 225.5 mmboe at 30 June 2011 (30 June 2010: 232.1 mmboe).

Contingent Resources relate to resources in respect of which development plans are in the course of preparation or further evaluation is under way with a view to development within the foreseeable future.

About Tullow Oil plc

Tullow Oil plc is a leading independent oil and gas, exploration and production group and is quoted on the London and Irish Stock Exchanges (symbol: TLW.L). The Group has interests in over 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 24 August until 30 August. The telephone numbers and access codes are:

Live event		Replay facility available from Noon
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Irish Participants	01 486 0922	Irish Participants	01 486 0902
		Access Code	6264631#

To join the live Video webcast, or play the on-demand version which will be available from noon on 25 August, you will need to have either Real Player or Windows Media Player installed on your computer.

11.00 BST - Press Conference Call

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UK Participants	0800 634 5205	International Participants	[phone]
UK Local Call	0208 817 9301	USA Toll Free	[phone]
Irish Free Call	1 800 943 094	Access code	5456947

15:00 BST - US Conference Call

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Live Event
Domestic Toll Free	[phone]
Toll	[phone]
Access code	5896764

For further information contact:

Tullow Oil plc [phone]	Citigate Dewe Rogerson [phone]	Murray Consultants [phone]
Chris Perry / James Arnold - Investor Relations	Martin Jackson	Joe Murray
George Cazenove - Media Relations	Kate Lehane	Ed Micheau

 

END

 

 

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