Tullow Oil announces good financial performance and significantly strengthened balance sheet

Wednesday, February 13, 2013
  • 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.
  • 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.

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."

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.

This article is for information and discussion purposes only and does not form a recommendation to invest or otherwise. The value of an investment may fall. The investments referred to in this article may not be suitable for all investors, and if in doubt, an investor should seek advice from a qualified investment adviser. More

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