27th Aug 2009 07:00
Press Release
Premier Oil plc
Half-Yearly Results for the six months to 30 June 2009
Highlights
Production of 39,700 boepd up 4 per cent on first half 2008 (38,000 boepd)
Completed acquisitions of Oilexco North Sea (UK) in May and Delek (Vietnam) in July for aggregate consideration of US$572.7 million
Pro forma reserves and resources increased 17 per cent to 265 mmboe and 181 mmboe at half year
Exploration successes in Vietnam and Norway with follow-up planned in the second half of 2009 and 2010
Operating cash flow of US$113.4 million (2008: US$191.1 million) and post-tax profits of US$26.9 million (2008: US$71.2 million) reflecting lower first half commodity prices
Outlook
Full year production for 2009 expected to be around 46,000 boepd including contribution from the Shelley field, on-stream 6 August. On track to reach our enhanced medium-term target of 75,000 boepd from existing projects
Asian development projects progressing well on revised lower cost estimates
Material second half exploration programme planned in Vietnam and Norway
Portfolio management continues with announced disposal of our Egyptian asset for US$12.5 million
Cash resources and undrawn bank facilities of around US$500 million available at 30 June which, together with cash flows, fully fund forward development spend with flexibility for other opportunities
Simon Lockett, Chief Executive, commented:
"Premier moved quickly this year to take advantage of good quality acquisition opportunities which arose earlier in the year at a time of weakness in oil prices and shortages of available funding. As a result, the company has entered an exciting stage of its strategic development with increased production, reserves and operatorship capability across a more geographically balanced portfolio. Over the next twelve months, we expect to deliver optimal outcomes for our Asian development projects and look forward to further exploration successes in Vietnam and Norway."
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ENQUIRIES |
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Premier Oil plc |
Tel: 020 7730 1111 |
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Simon Lockett |
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Tony Durrant |
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Pelham PR |
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James Henderson |
Tel: 020 7337 1501 / 07774 444 163 |
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Gavin Davis |
Tel: 020 7337 1515 / 07910 104 660 |
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Evgeniy Chuikov |
Tel: 020 7337 1513 / 07894 608 606 |
There will be an analyst presentation at the company's offices at 10:30am today which will be webcast live on the company's website at www.premier-oil.com
Following changes in the UK company disclosure regulations last year, it is not a requirement for half-yearly financial statements to be sent to shareholders. Accordingly, Premier will not be printing and distributing a 2009 Half-Yearly Report. A copy of this announcement is available for download from our website at www.premier-oil.com and hard copies can be requested by contacting the company (email: [email protected] or telephone: +44 (0)20 7730 1111).
INTERIM MANAGEMENT REPORT
CHAIRMAN'S STATEMENT
In an environment of unprecedented volatility in both commodity and capital markets, Premier's strong financial position allowed us to meet and expand our growth targets. We expect our newly enlarged asset base to produce 75,000 barrels of oil equivalent per day (boepd) in the medium-term. With the more recent recovery in oil and gas prices and the support of our capital providers we are well placed to exploit this expanded asset portfolio.
First half production increased to 39,700 boepd, up 4 per cent on the same period last year. Increased production in the North Sea as a result of the Oilexco North Sea Ltd (ONSL) acquisition was included from the completion date of 21 May. The ONSL acquisition, announced in March, was a major milestone for the company adding some 60 million barrels (bbls) of reserves and resources to our asset base at a favourable price. We were also delighted to add the majority of ONSL's employees to our team. The ONSL assets have now been combined with Premier's existing North Sea portfolio. The North Sea business unit, operating from offices in Aberdeen and Stavanger, now has full capability across production, development and exploration activities. First oil from the UK Shelley field, a former ONSL asset, was achieved on 6 August and will contribute significantly to production in the second half of the year.
Our Asian development projects continue to progress at lower capital costs than previously estimated and we were delighted to add an additional 25 per cent interest in our Chim Sáo development in Vietnam through the acquisition of Delek Energy (Vietnam) LLC, completed in July. The jacket for the Chim Sáo project is over one third complete and negotiations for the provision of a Floating Production, Storage and Offtake vessel (FPSO) are reaching a conclusion. In Indonesia, the contract for the Engineering, Procurement, Construction and Installation (EPCI) work for our Gajah Baru development was signed in May and delivered a significant cost reduction on previous estimates. Further savings are also expected in development drilling costs. Engineering optimisation studies continue on North Sumatra Block A. Funding for our development programme is fully covered by existing cash flows and available liquidity and is protected by our hedging programme.
We are pleased with the outcome of our exploration drilling in the first half. The discovery on Block 07/03 in Vietnam proves the existence of a working petroleum system for this new play, offering encouragement for further drilling on the same block and also on the adjacent Tuna Block in Indonesia. Seismic work is now under way on both blocks. The successful Grosbeak well was Premier's first ever participation in a well in Norway. The results of the well are still being evaluated but are supportive for future plans to drill prospects nearby. The Geyad discovery in Egypt, made in May, has quickly been moved into production. With only a small interest in the block however, we have negotiated a profitable sale of our interest.
Brent oil prices averaged US$52 per barrel (bbl) in the first half, compared to US$110/bbl in the corresponding period. Post-tax profits and operating cash flows were therefore lower at US$26.9 million (2008: US$71.2 million) and US$113.4 million (2008: US$191.1 million) respectively. Rising production for the second half, with the addition of the Oilexco assets and the recent recovery in oil prices, bode well for the remainder of the year.
We continue to prioritise health, safety and environmental concerns. In the International Association of Oil and Gas Producers' recent safety performance indicators report, Premier's drilling function was ranked number one across the industry for the lowest total recordable injury frequency. We have also retained our inclusion in the FTSE4Good Index.
We were pleased to announce the appointment of Mike Welton as a non-executive director with effect from 1 June 2009. Mike is Chairman of Southern Water, was formerly Chairman of Hanson plc and also formerly Chief Executive of Balfour Beatty plc. He will provide invaluable input to the Board.
Outlook
We are committed to our strategy of production and development growth underpinned by a strong financial position, together with a material exploration programme.
We remain focused on optimising our Asian development projects as we move forward in the execution phase. Work is under way in parallel to identify which development opportunities in the North Sea will be progressed in the medium-term.
We are also in the midst of an extensive exploration campaign. With our success earlier in the year we will drill a follow-on well on Block 07/03 in Vietnam, the location of which will be decided after a 3D seismic survey, currently being acquired. Two wells are planned on the neighbouring Tuna Block in Indonesia in 2010. In Norway, the Bream appraisal well has also been successful and will be followed, towards the end of the year, by the Greater Luno and Blåbaer wells.
The first half of the year has been a busy and exciting time for the company. With an enhanced asset base and an improving economic environment we look forward to the second half of the year.
Sir David John KCMG
Chairman
OPERATIONAL REVIEW
ASIA
During the first half of 2009, Premier's Asian business unit moved forward with its three development projects in Indonesia and Vietnam, and initiated the exploration programme on Block 07/03 in Vietnam.
Production and development
Indonesia
In the first half of 2009, the Premier-operated Natuna Sea Block A sold an overall average of 142 billion British thermal units per day (BBtud) (gross) from its gas export facility, whilst the non-operated Kakap Block contributed a further 46 BBtud (gross). Liquids production from the Block A Anoa field averaged 1,893 barrels of oil per day (bopd) (gross) and the Kakap field 4,621 bopd (gross). As a result of the strong production performance from the Anoa field being able to satisfy demand, plans to drill three further development wells in the second half of the year to maintain gas sales rates have been deferred to 2010. Overall, net production from Indonesia in the first half amounted to 10,900 boepd (2008: 11,850 boepd).
Significant progress has been made on the Gajah Baru project, the first of three fields to be developed to supply additional gas to Singapore and Batam under three new Gas Sales Agreements (GSAs) signed in 2008 and reported previously. A second tender for the EPCI contract was completed on 16 March 2009 with resultant gross cost reductions of approximately US$100 million. With further reductions expected in development drilling costs, total capital expenditure for the Gajah Baru project is now forecast to be US$196 million (net). Maximum routine gas sales will be in the order of 140 million standard cubic feet per day (mmscfd) and recoverable reserves from the three fields are expected to exceed 500 billion cubic feet (bcf). Construction initiation meetings were held with PT Saipem and PT SMOE in June and long lead equipment orders are progressing as planned. First gas is expected by October 2011 in advance of the contractual obligation under the GSA with Sembgas.
On the non-operated North Sumatra Block A, following approval of the Plan of Development for the Alur Siwah, Alur Rambong and Julu Rayeu gas fields in 2008, optimisation studies continued together with negotiation of fully termed agreements for use of the nearby facilities for transportation of gas and liquids. Finalisation of the basis of design is expected in the third quarter and due to the delay in signature of the Production Sharing Contract (PSC) extension, the EPCI contract award is now targeted for early 2010. Workover activity on the Tualang and Iee Tabeue oil fields on the block continued during the year to establish whether additional reserves are commercially recoverable. Work has been completed on four wells, including a well to be used for produced water disposal. Wireline logging, testing and workover of additional wells will continue through the third quarter.
Vietnam
On Chim Sáo, the Development Plan was revised at the beginning of the year. The new configuration of 14 wells from a single wellhead platform is expected to reduce project capital expenditure by more than US$100 million. Work continues on construction of the jacket and was 37 per cent complete at mid-year. Negotiations with two contractors are ongoing for the provision of an FPSO for Chim Sáo. Execution of both the FPSO lease agreement and the EPCI contract await conclusion of this process. First oil is expected mid-2011.
In July, it was announced that Premier had completed the acquisition of Delek Energy (Vietnam) LLC, holding a 25 per cent equity interest in Block 12W, which includes the Chim Sáo field. This was acquired from Delek Energy Systems Ltd at a cost of US$72 million, with contingent payments of up to US$10 million if fields other than Chim Sáo are developed on the block.
Separately, PetroVietnam Exploration and Production has confirmed that it will exercise its back-in right to acquire a 15 per cent interest in the PSC. Following completion of these two transactions, Premier will have a 53.125 per cent interest in the block.
Exploration and appraisal
The first commitment well drilled by Premier in Block 07/03 in Vietnam, was drilled to a total depth of 3,810m and intersected oil and gas pay within multiple stacked reservoir layers, two of which were tested and flowed oil at a combined rate of 3,265 bopd plus 8.1 mmscfd, through a 48/64" choke with no water production. Premier has taken advantage of current low seismic acquisition costs and commenced 3D seismic acquisition to define the resource potential of the discovery and adjacent structures, and to determine future exploration and appraisal activity. Premier currently plans to drill a second exploration well in the fourth quarter of 2009. Pan Pacific Petroleum (Vietnam) Pty Ltd acquired 15 per cent of Premier's equity in Block 07/03 in consideration of their funding part of Premier's residual 30 per cent interest of the well; the farm-in is subject to Vietnamese Government approval.
On the operated Tuna Block in Indonesia, plans have been updated following the success in Premier's Vietnam Block 07/03, immediately to the north. Interpretation of the 2,400km 2D survey has been encouraging and a contract has been signed for 850km2 3D seismic to be shot in the fourth quarter of 2009 before drilling wells in the third quarter of 2010.
On Natuna Sea Block A, a five-year exploration plan has been developed for the block and due to re-phasing of the development drilling programme, the Anoa Deep well will now be drilled in 2010.
On the non-operated Buton Block, the 250km 2D seismic survey begun in 2008 was completed mid-year; interpretation is under way and an exploration well is planned for the fourth quarter of 2010. On North Sumatra Block A, further work to define prospects for drilling in 2010 and 2011 and appraisal of the Kuala Langsa discovery is ongoing. Joint study activity under three agreements with the Indonesian licensing authority, MIGAS, in the North Merak, East Asahan and East Bangkanai areas, is nearing completion. In 2008 Premier and its partners acquired new seismic data over the Paneon Limestone trend in the Philippines SC43 licence. In the first half of 2009 the exploration of this trend continued with the acquisition of new gravity and magnetic data, geological field mapping and seismic reprocessing.
MIDDLE EAST-PAKISTAN
Our Pakistan assets again delivered record production for the period. Our team continues to seek business development opportunities elsewhere in the region with Premier's joint venture partner Emirates International Investment Company LLC (EIIC).
Production and development
Pakistan
Average production in Pakistan during the first half of the year was at a record 15,500 boepd, more than 5 per cent higher than the corresponding period's production in 2008 (14,750 boepd).
Average production from Qadirpur was 4,300 boepd (2008: 4,100 boepd). After completion of the plant capacity enhancement project at the end of 2008, production increased from 500 mmscfd to 600 mmscfd as of January 2009. Work is in progress to prepare for the planned supply of 75 mmscfd permeate gas (equivalent to 40 mmscfd processed gas) to Engro Ltd's nearby power plant - with first gas scheduled in the first quarter of 2010. In order to maintain optimal field production, five new production wells were drilled and successfully brought on-stream during the first half of 2009. A sixth new well was successfully injected into the system in August 2009. Work is progressing to put in place wellhead compression in order to mitigate the decreasing gas pressure in the field, and first gas from this project is expected next year.
Production from Kadanwari averaged 1,300 boepd during the first half of 2009 (2008: 1,350 boepd). In order to maintain the field production level, the development well K-14B was successfully drilled and brought on line in April 2009. The Government of Pakistan has recently approved an extension of the Kadanwari lease until 2022 whilst capping the gas price at an equivalent price of US$8.50 per million British thermal units (mmBtu).
Average production from Zamzama was 6,500 boepd during the first half of 2009 (2008: 6,150 boepd). 120 mmscfd of High Calorific Value (HCV) gas production was achieved in the first quarter of 2009, and following subsequent modifications the plant was producing around 127 mmscfd HCV gas by the end of the second quarter. Two successful infill wells, Zamzama 6 and 7, provided an additional 200 mmscfd (gross) gas sales. The Zamzama North-1 well was also successfully commissioned in March 2009, after completion of a 20km flowline. The compression project is on schedule and, subsequent to the completion of Front End Engineering Design (FEED), a letter of intent has been issued to General Electric Company for the supply of compressors.
Production from the Bhit/Badhra fields during the first half of 2009 averaged 3,400 boepd (2008: 3,150 boepd). Bhit-10 was drilled and completed in April 2009. The 8 per cent increased production in the first half of 2009 (compared to 2008) has been achieved through improved field deliverability from Bhit-10 and the additional capacity available from the Phase-II plant. This increased production is meeting sustained high gas demand. Wellhead compression work has commenced in the Bhit field in the first half of 2009, with compression on Bhit-11 already completed and installation at Bhit-3 in progress.
On the Zarghun South field, FEED has been completed and prequalification of contractors for facilities installation is in progress. First gas is expected around the end of 2011, with a GSA for the supply of 22 mmscfd. All Premier's costs pertaining to its 3.75 per cent interest in Zarghun South are carried by the operator during the development and production phases of the field (except for minor commitments due to the Government under Licence/Lease Agreements).
Exploration and appraisal
Pakistan
The Bado Jabal-1 well is currently being drilled in Area A of the Badhra Block. This 4,400m deep well is primarily targeting the Lower Goru sandstone beneath the producing reservoir zones of the field and has the potential to add significant gas reserves.
The K-19 exploration well will be drilled under the Kadanwari development and production lease in the fourth quarter of 2009, targeting a separate structural compartment defined by 3D seismic data in the E-Sands reservoir.
A comprehensive regional geological study was completed to evaluate exploration potential in Pakistan. New exploration and farm-in opportunities within Pakistan are being reviewed in preparation for the exploration blocks 'Bid Round', scheduled for the end of September 2009.
Egypt
With the completion of installation of early production facilities, first oil was achieved at the end of February from two Al Amir SE wells in Egypt. Since then Al Amir SE has produced a gross average of 2,100 bopd. To maintain the production profile, the Al Amir SE-3 appraisal well has been successfully drilled and will be followed by Al Amir SE-4.
Exploration well Geyad-1XST tested 40° API oil from two Kareem sandstone pay zones at 2,809 bopd and 3.04 mmscfd and the well has been completed as a future producer. Work on the tie-in of this well to the central facilities is complete and production will start after the grant of the Geyad Lease (separate from Al Amir SE).
In August, Premier announced the disposal of its 10 per cent interest in the NW Gemsa licence, which includes these discoveries, for the sum of US$12.5 million, subject to partner and government approval. Premier will record a profit of around US$9 million on completion of the sale.
NORTH SEA AND WEST AFRICA
The shape of Premier's North Sea business has been dramatically enhanced by the acquisition of Oilexco North Sea Ltd, which brought production, development and exploration assets into the Premier portfolio. The North Sea team is also now responsible for the company's assets in West Africa.
Production and development
UK
Premier successfully completed the acquisition of Oilexco North Sea Ltd on 21 May 2009 for an adjusted consideration of US$500.7 million.
Total UK production for the period averaged 12,100 boepd (2008: 10,600 boepd) to which the former Oilexco portfolio contributed an average rate of 13,300 boepd in the period from 21 May. This includes 8,000 boepd from the Brenda field.
The Wytch Farm oil field contributed 2,800 boepd net production to Premier, down 10 per cent on last year. A strong underlying production performance was maintained with minimal production interruptions. The main investment activity for the period included the F24 (F08 sidetrack) well that was completed and put on production. The pipeline replacement project was progressed with all gathering station works completed. The operator has temporarily suspended further drilling on Wytch Farm while the inventory of future drilling targets is upgraded. It is anticipated that the investment in drilling will resume in early 2011.
Production from Kyle of 2,700 boepd was in line with expectations.
The Scott and Telford fields produced 3,500 boepd, underperforming as a result of both facilities issues and the failure of the first well of the three-well infill programme. The facilities problems are believed to be largely resolved and should result in improved performance in the second half of 2009. Positive results from the latter two infill wells have encouraged the partnership to add a fourth infill well to this year's drilling programme.
Since Premier took control of Oilexco's Balmoral Floating Production Vessel (FPV), further analysis has been performed and a decision has been made to accelerate the renewal of some risers from 2010 into 2009. This will incur additional shutdown days this year with a reduced shutdown requirement in 2010. Work on the Balmoral FPV, to increase the capacity of both the gas lift system and the water handling system, is progressing and should be completed during the current annual shutdown. Work to optimise the use of the Brenda-Nicol sub-sea multiphase pump and to increase its capacity is also progressing with expected completion in the fourth quarter of 2009. Production from the Nicol field, where a second well was brought on-stream in June 2009, is currently somewhat constrained by offtake system bottlenecks, and it has been decided to defer further infill drilling on Brenda until 2010.
Following the acquisition of the Oilexco portfolio, Premier successfully negotiated a new contract with Sevan and other suppliers to enable the use of the Voyageur FPSO to develop the Shelley field (Premier - 100 per cent). Work on the field development project progressed rapidly. First oil was achieved on 6 August with initial rates of 11,000 boepd. Since start-up the field has averaged 8,000 boepd, including the impact of well downtime.
On the Huntington field, unitisation negotiations and development concept selection are expected to be completed by the end of 2009. It is anticipated that Premier will hold the dominant equity position at the completion of the unitisation process.
In the area surrounding the Scott field, Premier is co-operating with other interest owners to progress the development of a series of discoveries utilising the Scott facility.
Norway
The plan for development and operation of the Frøy field was submitted to the Norwegian authorities in September 2008. Work continues to identify opportunities for project cost reductions and the addition of third party volumes to the project. A number of exploration wells in the surrounding acreage are expected to be drilled during the course of 2009.
Mauritania
Chinguetti production averaged 12,600 bopd (gross) for the first half of 2009, in line with expectations. The operator continues to review opportunities for production enhancement and potential infill drilling, whilst development studies continue on commercialising the Banda gas field and other discoveries on the blocks. Discussions on these matters and terms for the extension of the exploration area of the PSCs are ongoing and are expected to conclude in the second half of 2009.
Exploration and appraisal
Most recently, UK exploration efforts have focused on managing the Oilexco portfolio and looking at the exploration potential adjacent to the producing assets. Premier has been awarded two exploration licences in the UKCS 25th Round. These both have interesting prospectivity and offer opportunities close to acreage already held by Premier: Block 15/23e is adjacent to the Bugle area, near the Scott field; Block 29/7b includes a pre-existing discovery near the Kyle field. The Bugle North well is expected to be drilled in early 2010 and will test the possible northward extension of the Bugle field. This field, discovered in 1997 and appraised in 2007, has been interpreted as stopping against a fault in the north. However, new reprocessing of the 3D seismic indicates that some of the reservoir sands are not faulted and continue northwards. Confirmation of this northern extension is likely to hasten the development of the Bugle field.
In Norway, the non-operated Grosbeak well on the PL378 licence, 10km north east of the Fram field, was a discovery with potential reserves of between 35 and 190 million barrels of oil equivalent (mmboe). The well discovered oil and gas in the Sognefjord and Brent Jurassic reservoirs. Extensive logging and coring was carried out. The well results are currently being evaluated and will be integrated with work on the remaining prospectivity identified on the licence.
In August, we announced the successful appraisal of the Bream discovery. A vertical hole and two horizontal sidetracks were drilled. One of the sidetracks was tested from a limited interval with a maximum flow rate of 2,516 boepd. Initial recoverable volumes of between 39 and 63 million barrels of oil (mmbbls) are estimated. The first half of the year has seen successful acquisition of the site survey and leg cores for the nearby Gardrofa well which will be spudded in mid-2010 and will be Premier's first operated well in Norway. A rig has already been contracted. Gardrofa could provide additional resources to the Bream discovery.
Forthcoming exploration activity includes the Greater Luno well in Norway in the fourth quarter on licence PL359 (Premier 30 per cent equity, non-operated) which lies close to the recent Luno and 16/2-5 oil and condensate discoveries in Norway. Following these successes, the operator has evaluated PL359 and mapped the Greater Luno prospect with similar Jurassic reservoirs. The Greater Luno exploration well, targeting 150 mmboe is scheduled to spud in the fourth quarter of 2009.
The Blåbaer prospect on licence PL374S (Premier 15 per cent equity, non-operated) will be drilled towards the end of the year or early in 2010 and is a structural high cut by several faults. The exploration well will test an individual fault compartment with potential P50 reserves of 21 mmbbls in the primary Cook reservoir. The various fault compartments, together, contain a potential 76 mmbbls of reserves in this reservoir, with upside in deeper Statfjord sandstones.
In Congo, the Frida Marine-1 exploration well was spudded on 23 July. Logging has indicated that the well did not encounter hydrocarbons and has been abandoned as a dry hole. Well result analysis is ongoing to determine implications of this result for the follow-up prospect, Ida, on the same block.
Working interest production by region
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Six months to 30 June 2009 |
Full year 2008 |
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Liquids kbopd |
Gas mmscfd |
Total kboepd |
Total kboepd |
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UK: |
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Balmoral area 1 |
0.5 |
0.2 |
0.5 |
- |
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Brenda |
1.8 |
1.1 |
2.0 |
- |
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Fife area |
- |
- |
- |
0.3 |
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Janice/James |
0.1 |
- |
0.1 |
- |
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Kyle |
1.8 |
4.0 |
2.7 |
2.5 |
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Nelson |
0.1 |
0.1 |
0.1 |
- |
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Nicol |
0.4 |
0.1 |
0.4 |
- |
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Scott/Telford |
3.2 |
1.9 |
3.5 |
3.5 |
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Wytch Farm |
2.7 |
0.3 |
2.8 |
3.0 |
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10.6 |
7.7 |
12.1 |
9.3 |
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Indonesia: |
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Anoa |
0.5 |
40.4 |
8.4 |
8.4 |
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Kakap |
0.9 |
8.0 |
2.5 |
3.3 |
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1.4 |
48.4 |
10.9 |
11.7 |
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Pakistan: |
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Bhit/Badhra |
- |
20.3 |
3.4 |
3.2 |
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Kadanwari |
- |
7.6 |
1.3 |
1.2 |
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Qadirpur |
- |
27.2 |
4.3 |
4.0 |
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Zamzama |
0.3 |
41.5 |
6.5 |
6.1 |
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0.3 |
96.6 |
15.5 |
14.5 |
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Others: |
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Al Amir |
0.2 |
- |
0.2 |
- |
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Chinguetti |
1.0 |
- |
1.0 |
1.0 |
|
1.2 |
- |
1.2 |
1.0 |
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Total |
13.5 |
152.7 |
39.7 |
36.5 |
1 Includes Glamis and Stirling fields.
Production from the ONSL assets is included from 21 May 2009, the completion date of the acquisition and averaged over the full six month period.
Actual daily average rates for the period for the former Oilexco assets were as follows:
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Period from 21 May to 30 June 2009 |
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Liquids kbopd |
Gas mmscfd |
Total kboepd |
|
|
Balmoral area 1 |
1.6 |
0.7 |
1.8 |
|
Brenda |
8.0 |
5.0 |
8.9 |
|
Janice/James |
0.4 |
- |
0.4 |
|
Nelson |
0.3 |
0.1 |
0.3 |
|
Nicol |
1.8 |
0.6 |
1.9 |
|
12.1 |
6.4 |
13.3 |
|
1 Includes Glamis and Stirling fields.
FINANCIAL REVIEW
Group production, on a working interest basis, averaged 39,700 boepd in the first half compared to 38,000 boepd in the first half of 2008, and 36,500 boepd for the full year 2008. This reflects underlying good performance from the Anoa field in Indonesia and from our Pakistan producing fields. The UK producing fields acquired with the ONSL acquisition averaged 13,300 boepd for the period from completion of the acquisition on 21 May.
As at 30 June 2009 proven and probable reserves on a working interest basis, based on Premier and operator estimates, were 265 mmboe, a 16 per cent increase since 31 December 2008. Total reserves and contingent resources have risen to 446 mmboe from 382 mmboe over the same period. These figures include the effect of the acquisition of ONSL, and the additional equity in Block 12W in Vietnam and the divestiture of Premier's Egyptian block, which were announced after the end of the period.
|
Proven and probable reserves mmboe |
2P Reserves and 2C contingent resources mmboe |
|
|
Start of 2009 |
228 |
382 |
|
Production |
(7) |
(7) |
|
Acquisitions/disposals |
46 |
72 |
|
Revisions/transfers |
(2) |
(1) |
|
265 |
446 |
Following the significant fall in oil prices in the second half of 2008, Premier's average realised oil price for the period was US$53/bbl (2008: US$110/bbl), in line with average Brent crude prices for the period. Average realised gas prices was US$4.98 per thousand cubic feet (mcf) (2008: US$6.61/mcf). The net effect of sales volume and price changes was to reduce turnover to US$213.9 million (2008: US$385.8 million). An underlift position of US$42.4 million was largely unwound by our first cargo from the Balmoral area which was lifted in the first week of July.
Cost of sales in the period was US$117.5 million (2008: US$138.8 million). Underlying operating costs, after adjusting for inventory movements, were US$8.2/boe (2008: US$9.6/boe) reflecting industry-wide downward cost pressures and the favourable effect of weaker sterling offset by the higher operating costs of the UK fields acquired with ONSL. Amortisation includes the effect of an impairment charge, as a result of a reserve downgrade, of US$22.7 million in respect of the Chinguetti field in Mauritania. Underlying unit amortisation (excluding impairment) rose to US$9.6/boe (2008: US$8.1/boe).
In accordance with IFRS 3 - 'Business Combinations', we have included in the income statement for the half year an amount of US$60.3 million, representing the excess of fair values recorded in respect of the Oilexco acquisition over and above cost. For this purpose, fair values of producing and development assets were calculated using a long-term oil price of US$60 per barrel. No value was allocated to exploration and evaluation assets. A deferred tax asset of US$146.5 million is also recorded on the balance sheet, reflecting the future value of UK corporation tax losses acquired with Oilexco North Sea Ltd.
Exploration expense and pre-licence exploration costs amounted to US$18.5 million (2008: US$25.4 million) and US$6.7 million (2008: US$6.7 million) respectively, after taking into account the write-off of US$17.9 million of previously capitalised costs relating to PSC B in Mauritania. This follows the completion of development studies in relation to Tiof and other oil discoveries on the block which indicate that these are unlikely to be commercial except at significantly higher oil prices.
Interest revenue, finance and other gains for the period were US$9.0 million (2008: US$7.5 million), offset by finance charges of US$17.0 million (2008: US$13.4 million). Net interest movements reflect generally lower interest rates on cash deposits and the increased charges associated with debt taken on to finance the Oilexco acquisition. Net finance charges also reflect non-cash accruals in relation to the outstanding convertible bonds and future abandonment obligations.
A net charge of US$44.2 million (2008: US$7.2 million) is recorded in the first half reflecting movement in the valuation of existing hedges. This charge takes account of cash payments of US$12.5 million made to establish the programme of oil and gas hedges currently in place with the balance representing non-cash movements.
The tax charge of US$45.7 million (2008: US$119.3 million) reflects an underlying tax rate similar to the prior period, on lower operating profits.
Profit after tax in the period to 30 June 2009 was US$26.9 million compared with US$71.2 million for the corresponding period last year.
Cash flow
Cash flow from operating activities amounted to US$113.4 million (2008: US$191.1 million). Capital expenditure in the period was US$111.2 million (2008: US$73.4 million) excluding acquisitions.
|
Capital expenditure (US$ million)
|
|
|
|
|
2009
Half year
|
2008
Half year
|
|
Fields/developments
|
68.5
|
21.7
|
|
Exploration
|
41.4
|
50.5
|
|
Other
|
1.3
|
1.2
|
|
Total
|
111.2
|
73.4
|
Exploration spend in the first half was US$41.4 million including the successful programmes in Vietnam and Norway. It is anticipated that there will be an increasing level of development spend in the second half of 2009 as the pace of activity on our development project portfolio accelerates.
Balance sheet
The acquisition of ONSL was completed on 21 May for an adjusted purchase consideration of US$500.7 million. The group funded the acquisition and associated costs by way of a rights issue, new credit facilities and from the group's existing cash resources. A 4 for 9 rights issue of new Ordinary Shares at a price of 485 pence per share was completed on 7 May to raise gross proceeds of approximately £171 million (US$252.1 million). 95 per cent of existing shareholders took up their rights with the balance being successfully placed by the underwriters. In parallel, new credit facilities were arranged consisting initially of a US$175.0 million 18-month bridge facility, a US$225.0 million three-year revolving credit facility and US$63.0 million and £60.0 million (US$99.0 million) three-year letter of credit facilities. During subsequent syndication the three-year revolving credit facility was extended to US$325.0 million.
Net debt at 30 June 2009 was US$254.1 million (2008: net cash of US$176.9 million) which included cash resources of US$193.5 million. Undrawn bank facilities at 30 June 2009 were US$325.0 million.
|
Net (debt)/cash (US$ million) |
||
|
2009 Half year |
2008 Half year |
|
|
Cash and cash equivalents |
193.5 |
433.0 |
|
Convertible bonds* |
(209.6) |
(203.1) |
|
Other long-term debt** |
(238.0) |
(53.0) |
|
Net (debt)/cash |
(254.1)*** |
176.9 |
|
* |
excluding unamortised issue costs and allocation to equity |
|
** |
excluding unamortised issue costs |
|
*** |
excluding US$71.3 million of cash held in an abandonment trust which has been classified in the balance sheet under trade and other receivables |
Financial risk management
The Board's policy continues to be to lock in oil and gas price floors for a portion of expected future production at a level which protects the cash flow of the group and the business plan. Such floors are purchased for cash or funded by selling caps at a ceiling price when market conditions are considered favourable. During the period 0.9 million hedged barrels matured at a cost of US$nil (2008: US$8.1 million). At 30 June 2009 the group had 9.9 million barrels of Dated Brent oil hedged with collars at an average floor price of US$48.06/bbl and a cap of US$85.45/bbl, of which 6.3 million barrels were embedded through an offtake agreement to the end of 2012. New collars, covering 3.6 million barrels of oil to the period to the end of December 2011 were put in place to cover approximately 50 per cent of the expected production acquired with the ONSL assets. 1.3 million barrels of oil were also sold forward at an average price of US$55.11/bbl in connection with the same acquisition. Upfront premia of US$12.5 million were paid for the additional hedges and to enhance existing hedges. No changes were made to the group's existing gas hedges which cover the period to 30 June 2013.
Premier operates and reports in US dollars. Foreign exchange exposure therefore relates only to certain sterling and other local currency expenditures. This net exposure is covered by the sale of US dollars on a spot or short-term forward basis. The average rate achieved for transactions maturing in the first half of 2009 was US$1.4950 : £1. Forward foreign exchange contracts outstanding at the end of June showed a positive mark to market valuation of US$1.66 million (2008: US$0.9 million). 80 per cent of the gross proceeds of the rights issue of £171 million (US$252.1 million) was sold forward into US dollars at US$1.4597 : £1.
There have been no material changes to, or material transactions with, the related parties as described in note 25 of the Annual Report and Financial Statements for the year ended 31 December 2008.
Fair presentation of rights issue
The condensed set of financial statements of the group have been prepared in accordance with IAS 34 - 'Interim Financial Reporting' (IAS 34) as issued by the International Accounting Standards Board (IASB) and as endorsed by the European Union. In order to present fairly the financial position, financial performance and cash flows of the group, as required by IAS 1 - 'Presentation of Financial Statements', and give a true and fair view of the assets, liabilities, financial position and profit or loss of the group as required by section 393 of the Companies Act 2006, Premier has departed from the requirements of IAS 32 - 'Financial Instruments: Presentation' (IAS 32) in so far as this standard requires the offer of rights by Premier to its shareholders in March 2009 to be classified as a derivative financial liability. Further details of this departure including its financial effect are provided in note 10 of the condensed set of financial statements. The directors have concluded that the condensed set of financial statements, prepared on the basis outlined in note 10, presents fairly and gives a true and fair view of the group's financial position, financial performance and cash flows.
Further to representations from a number of corporate entities, the IASB has issued Exposure Draft ED/2009/09 - 'Classification of Rights Issues' on 6 August 2009. If the Exposure Draft is approved substantively in its current form it will remove the need to treat issuance of the rights issue as a derivative financial liability.
Going concern
After making enquiries and in light of the group's available loan facilities, the group budget for 2009 and the medium-term plans, the directors have reasonable expectation that the group has adequate resources to continue operations for the foreseeable future. The going concern basis for the half yearly condensed set of financial statements has therefore continued to be adopted.
Business risks
Premier is an international business which has to face a variety of political, technical, financial and commercial risks. The company has identified certain risks pertinent to its business including: exploration and reserve risks, drilling and operating risks, costs and availability of materials and services, loss of or changes to production sharing or concession agreements, joint venture or related agreements, economic and sovereign risks, legal systems, market risk, security risk in areas of operation, loss of key human resources, volatility of future oil and gas prices and foreign currency risk.
Effective risk management is critical to achieving our strategic objectives and protecting our assets, personnel and reputation. Premier manages its risks by maintaining a balanced portfolio, through compliance with the terms of its agreements, application of appropriate policies and procedures and through the recruitment and retention of skilled individuals throughout the organisation. Further, the company has focused its activities mainly in known hydrocarbon basins in jurisdictions that have previously established long-term oil and gas ventures with foreign oil and gas companies, existing infrastructure of services and oil and gas transportation facilities, and reasonable proximity to markets.
The acquisition of ONSL materially increases the presence of Premier in the UK North Sea and reinforces certain of the operating risks mentioned above.
A summary of the principal risks facing the company and the way in which these risks are mitigated is provided on pages 29 and 30 of the 2008 Annual Report.
STATEMENT OF DIRECTORS' RESPONSIBILITIES
The directors confirm that, to the best of their knowledge the attached condensed set of financial statements has been prepared in accordance with IAS 34 - 'Interim Financial Reporting', and that the interim management report includes a fair review of the information required by DTR 4.2.7R (an indication of events during the first six months and a description of the principal risks and uncertainties for the remaining six months of the year) and DTR 4.2.8R (disclosure of related parties' transactions and changes therein) of the Disclosure and Transparency Rules.
By order of the Board
S C Lockett A R C Durrant
Director Director
26 August 2009
CONDENSED CONSOLIDATED INCOME STATEMENT
|
|
|
Six months
to 30 June
2009
Unaudited
|
Six months
to 30 June
2008 Unaudited
|
Year to 31 December 2008
|
|
|
Notes
|
$ million
|
$ million
|
$ million
|
|
Sales revenues
|
2
|
213.9
|
385.8
|
655.2
|
|
Cost of sales
|
3
|
(117.5)
|
(138.8)
|
(317.6)
|
|
Exploration expense
|
|
(18.5)
|
(25.4)
|
(42.9)
|
|
Pre-licence exploration costs
|
|
(6.7)
|
(6.7)
|
(15.8)
|
|
Acquisition of subsidiaries
|
|
60.3
|
-
|
-
|
|
General and administration costs
|
|
(6.7)
|
(11.3)
|
(17.2)
|
|
Operating profit
|
|
124.8
|
203.6
|
261.7
|
|
Interest revenue, finance and other gains
|
4
|
9.0
|
7.5
|
14.6
|
|
Finance costs and other finance expenses
|
4
|
(17.0)
|
(13.4)
|
(27.0)
|
|
Mark to market revaluation of commodity hedges
|
|
(44.2)
|
(7.2)
|
28.3
|
|
Profit before tax
|
|
72.6
|
190.5
|
277.6
|
|
Tax
|
|
(45.7)
|
(119.3)
|
(179.3)
|
|
Profit for the period/year
|
|
26.9
|
71.2
|
98.3
|
|
Earnings per share (cents):
|
|
|
|
|
|
Basic
|
5
|
26.3
|
71.1
|
99.0
|
|
Diluted
|
5
|
26.2
|
70.4
|
98.2
|
CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
|
|
|
Six months
to 30 June
2009
Unaudited
|
Six months
to 30 June
2008
Unaudited
|
Year to 31 December 2008
|
|
|
|
$ million
|
$ million
|
$ million
|
|
Profit for the period/year
|
|
26.9
|
71.2
|
98.3
|
|
Cash flow hedges: losses arising during the period
|
|
(19.6)
|
(116.9)
|
-
|
|
Unrealised currency translation differences
|
|
3.7
|
2.2
|
(5.6)
|
|
Actuarial losses on defined benefit pension schemes
|
|
-
|
-
|
(2.1)
|
|
Total comprehensive income/(loss) for the period/year
|
|
11.0
|
(43.5)
|
90.6
|
CONDENSED CONSOLIDATED BALANCE SHEET
|
|
|
At
30 June
2009
Unaudited
|
At
30 June
2008
Unaudited
|
At 31 December 2008
|
|
|
Notes
|
$ million
|
$ million
|
$ million
|
|
Non-current assets:
|
|
|
|
|
|
Intangible exploration and evaluation assets
|
6
|
195.7
|
185.2
|
157.9
|
|
Property, plant and equipment
|
7
|
1,320.7
|
710.8
|
767.4
|
|
Investments in associates
|
|
-
|
0.2
|
-
|
|
Deferred tax asset
|
|
137.0
|
-
|
5.8
|
|
|
|
1,653.4
|
896.2
|
931.1
|
|
Current assets:
|
|
|
|
|
|
Inventories
|
|
26.7
|
34.0
|
14.6
|
|
Trade and other receivables
|
|
443.0
|
626.3
|
181.2
|
|
Cash and cash equivalents
|
|
193.5
|
433.0
|
323.7
|
|
|
|
663.2
|
1,093.3
|
519.5
|
|
Total assets
|
|
2,316.6
|
1,989.5
|
1,450.6
|
|
Current liabilities:
|
|
|
|
|
|
Trade and other payables
|
|
(427.9)
|
(712.4)
|
(202.8)
|
|
Current tax payable
|
|
(80.1)
|
(129.4)
|
(73.8)
|
|
|
|
(508.0)
|
(841.8)
|
(276.6)
|
|
Net current assets
|
|
155.2
|
251.5
|
242.9
|
|
Non-current liabilities:
|
|
|
|
|
|
Convertible bonds
|
|
(206.3)
|
(199.0)
|
(202.7)
|
|
Other long-term debt
|
|
(219.9)
|
(52.1)
|
-
|
|
Deferred tax liabilities
|
|
(186.9)
|
(191.8)
|
(188.8)
|
|
Long-term provisions
|
|
(302.6)
|
(143.8)
|
(143.2)
|
|
Long-term employee benefit plan deficit
|
|
(7.8)
|
(8.8)
|
(6.8)
|
|
Deferred revenue
|
|
(29.5)
|
(37.9)
|
(33.6)
|
|
|
|
(953.0)
|
(633.4)
|
(575.1)
|
|
Total liabilities
|
|
(1,461.0)
|
(1,475.2)
|
(851.7)
|
|
Net assets
|
|
855.6
|
514.3
|
598.9
|
|
Equity and reserves:
|
|
|
|
|
|
Share capital
|
|
97.0
|
73.6
|
73.6
|
|
Share premium account
|
|
223.6
|
9.6
|
9.7
|
|
Retained earnings
|
|
489.2
|
377.4
|
472.9
|
|
Capital redemption reserve
|
|
4.3
|
1.7
|
1.7
|
|
Translation reserves
|
|
2.1
|
6.2
|
(1.6)
|
|
Equity reserve
|
|
39.4
|
45.8
|
42.6
|
|
|
|
855.6
|
514.3
|
598.9
|
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
|
Share capital |
Share premium account |
Retained earnings |
Capital redemption reserve |
Translation reserves |
Equity reserve |
Total |
|
|
$ million |
$ million |
$ million |
$ million |
$ million |
$ million |
$ million |
|
|
At 1 January 2008 |
73.5 |
9.4 |
415.5 |
1.7 |
4.0 |
48.8 |
552.9 |
|
Issue of Ordinary Shares |
0.1 |
0.3 |
- |
- |
- |
- |
0.4 |
|
Purchase of shares for ESOP Trust |
- |
- |
(17.9) |
- |
- |
- |
(17.9) |
|
Purchase of own shares |
- |
- |
(47.2) |
- |
- |
- |
(47.2) |
|
Provision for share-based payments |
- |
- |
20.1 |
- |
- |
- |
20.1 |
|
Transfer between reserves* |
- |
- |
6.2 |
- |
- |
(6.2) |
- |
|
Total comprehensive income |
- |
- |
96.2 |
- |
(5.6) |
- |
90.6 |
|
At 31 December 2008 |
73.6 |
9.7 |
472.9 |
1.7 |
(1.6) |
42.6 |
598.9 |
|
Issue of Ordinary Shares |
26.0 |
226.1 |
- |
- |
- |
- |
252.1 |
|
Expenses of issue of Ordinary Shares |
- |
(12.2) |
- |
- |
- |
- |
(12.2) |
|
Cancellation of Ordinary Shares |
(2.6) |
- |
- |
2.6 |
- |
- |
- |
|
Purchase of shares for ESOP Trust |
- |
- |
(2.5) |
- |
- |
- |
(2.5) |
|
Provision for share-based payments |
- |
- |
8.3 |
- |
- |
- |
8.3 |
|
Transfer between reserves* |
- |
- |
3.2 |
- |
- |
(3.2) |
- |
|
Total comprehensive income |
- |
- |
7.3 |
- |
3.7 |
- |
11.0 |
|
At 30 June 2009 |
97.0 |
223.6 |
489.2 |
4.3 |
2.1 |
39.4 |
855.6 |
|
At 1 January 2008 |
73.5 |
9.4 |
415.5 |
1.7 |
4.0 |
48.8 |
552.9 |
|
Issue of Ordinary Shares |
0.1 |
0.2 |
- |
- |
- |
- |
0.3 |
|
Purchase of shares for ESOP Trust |
- |
- |
(3.5) |
- |
- |
- |
(3.5) |
|
Provision for share-based payments |
- |
- |
8.1 |
- |
- |
- |
8.1 |
|
Transfer between reserves* |
- |
- |
3.0 |
- |
- |
(3.0) |
- |
|
Total comprehensive loss |
- |
- |
(45.7) |
- |
2.2 |
- |
(43.5) |
|
At 30 June 2008 |
73.6 |
9.6 |
377.4 |
1.7 |
6.2 |
45.8 |
514.3 |
|
* |
The transfer between reserves relates to the non-cash interest on the convertible bonds, less the amortisation of the issue costs that were charged directly against equity. |
CONDENSED CONSOLIDATED CASH FLOW STATEMENT
|
|
|
Six months to 30 June
2009
Unaudited
|
Six months
to 30 June
2008
Unaudited
|
Year to 31 December 2008
|
|
|
Notes
|
$ million
|
$ million
|
$ million
|
|
Net cash from operating activities
|
9
|
113.4
|
191.1
|
352.3
|
|
Investing activities:
|
|
|
|
|
|
Capital expenditure
|
|
(111.2)
|
(73.4)
|
(217.3)
|
|
Pre-licence exploration costs
|
|
(6.7)
|
(6.7)
|
(15.8)
|
|
Investment of funds in joint venture
|
|
-
|
(0.1)
|
-
|
|
Acquisition of subsidiaries
|
|
(574.1)
|
-
|
-
|
|
Proceeds from disposal of intangible exploration and evaluation assets
|
|
-
|
-
|
3.1
|
|
Net cash used in investing activities
|
|
(692.0)
|
(80.2)
|
(230.0)
|
|
Financing activities:
|
|
|
|
|
|
Issue of Ordinary Shares
|
|
252.1
|
0.3
|
0.4
|
|
Expenses of issue of Ordinary Shares
|
|
(12.2)
|
-
|
-
|
|
Purchase of shares for ESOP Trust
|
|
(2.5)
|
(3.5)
|
(17.9)
|
|
Purchase of own shares
|
|
-
|
-
|
(47.2)
|
|
Loan drawdowns
|
|
238.0
|
-
|
-
|
|
Debt arrangement fees
|
|
(19.9)
|
-
|
-
|
|
Repayment of long-term financing
|
|
-
|
-
|
(53.0)
|
|
Interest paid
|
|
(6.1)
|
(5.9)
|
(10.9)
|
|
Net cash from/(used in) financing activities
|
|
449.4
|
(9.1)
|
(128.6)
|
|
Currency translation differences relating to cash and cash equivalents
|
|
(1.0)
|
(0.8)
|
(2.0)
|
|
Net (decrease)/increase in cash and cash equivalents
|
|
(130.2)
|
101.0
|
(8.3)
|
|
Cash and cash equivalents at the beginning of the period/year
|
|
323.7
|
332.0
|
332.0
|
|
Cash and cash equivalents at the end of the period/year
|
9
|
193.5
|
433.0
|
323.7
|
NOTES TO THE CONDENSED SET OF FINANCIAL STATEMENTS
1. BASIS OF PREPARATION
General information
Premier Oil plc is a limited liability company incorporated in Scotland and listed on the London Stock Exchange. The address of the registered office is 4th Floor, Saltire Court, 20 Castle Terrace, Edinburgh, EH1 2EN, United Kingdom.
The condensed set of financial statements for the six months ended 30 June 2009 were authorised for issue in accordance with a resolution of the Board of Directors on 25 August 2009.
The information for the year ended 31 December 2008 contained within the condensed set of financial statements does not constitute statutory accounts within the meaning of section 240 of the Companies Act 1985. Statutory accounts for the year ended 31 December 2008 were approved by the Board of Directors on 25 March 2009 and delivered to the Registrar of Companies. The report of the auditors on those accounts was unqualified, did not contain an emphasis of matter paragraph and did not contain any statement under section 237(2) or (3) of the Companies Act 1985.
The financial information contained in this report is unaudited. The condensed consolidated income statement, condensed consolidated statement of comprehensive income, condensed consolidated statement of changes in equity and the condensed consolidated cash flow statement for the six months to 30 June 2009, and the condensed consolidated balance sheet as at 30 June 2009 and related notes, have been reviewed by the auditors and their report to the company is attached.
Basis of preparation
These condensed set of financial statements for the six months ended 30 June 2009 have been prepared in accordance with the Disclosure and Transparency Rules of the Financial Services Authority and with IAS 34 - 'Interim Financial Reporting', as endorsed by the European Union. The condensed set of financial statements are prepared in accordance with the recognition and measurement principles of International Financial Reporting Standards (IFRS) except for the accounting for rights issues as explained in note 10. These condensed set of financial statements should be read in conjunction with the annual financial statements for the year ended 31 December 2008, which have been prepared in accordance with IFRS as endorsed by the European Union.
These condensed set of financial statements have been prepared on a going concern basis. Further information relating to the going concern assumption is provided in the Financial Review.
Accounting policies
The accounting policies applied in these condensed set of financial statements are consistent with those of the annual financial statements for the year ended 31 December 2008, as described in the annual financial statements, with the exception of standards, amendments and interpretations effective in 2009.
Standards, amendments and interpretations effective in 2009
The following standards, amendments and interpretations to published standards were mandatory for the financial year beginning 1 January 2009:
IAS 1 (revised) - 'Presentation of Financial Statements'. The revised standard prohibits the presentation of items of income and expenses (that is 'non-owner changes in equity') in the statement of changes in equity, requiring 'non-owner changes in equity' to be presented separately from 'owner changes in equity'. All 'non-owner changes in equity' are required to be shown in a performance statement. The group has elected to present two statements: an income statement and a statement of comprehensive income. The condensed set of financial statements have been prepared under the revised disclosure requirements. IAS 1 (revised) requires the presentation of a statement of changes in equity as a primary statement, separate from the income statement and statement of comprehensive income. As a result, a condensed consolidated statement of changes in equity has been included in the primary statements, showing changes in each component of equity for each period presented.
IFRS 8 - 'Operating Segments'. IFRS 8 replaces IAS 14 - 'Segment Reporting'. It requires a 'management approach' under which segment information is presented on the same basis as that used for internal reporting purposes. This has not resulted in a change in the number of reportable segments presented. Operating segments are reported in a manner consistent with the internal reporting provided to the chief operating decision-maker.
IAS 23 (amendment) - 'Borrowing Costs'. The amended standard requires borrowing costs related to the acquisition, construction or production of a qualifying asset to be capitalised as part of the cost of the asset. All other borrowing costs should be expensed as incurred. The adoption of this standard has not had any impact on the accounting policies applied by the group.
The following new standards, amendments to standards and interpretations are mandatory for the first time for the financial year beginning 1 January 2009, but are not currently relevant for the group:
·; IFRIC 16 - ‘Hedges of a Net Investment in a Foreign Operation’.
·; IAS 39 (amendment) - ‘Financial Instruments: Recognition and Measurement’.
The following new standards, amendments to standards and interpretations have been issued, but are not effective for the financial year beginning 1 January 2009 and have not been early adopted:
IFRS 3 (revised) - 'Business Combinations' and consequential amendments to IAS 27 - 'Consolidated and Separate Financial Statements', IAS 28 - 'Investments in Associates' and IAS 31 - 'Interests in Joint Ventures'.
IFRIC 17 - 'Distributions of Non-cash Assets to Owners'.
IFRIC 18 - 'Transfers of Assets from Customers'.
2. GEOGRAPHICAL SEGMENTS
The group's operations are located and managed in three regional business units - North Sea and West Africa, Asia and Middle East-Pakistan. These geographical segments are the basis on which the group reports its primary segmental information. Sales revenue represents amounts invoiced, exclusive of sales-related taxes, for the group's share of oil and gas sales.
|
|
Six months
to 30 June 2009
Unaudited
|
Six months
to 30 June 2008
Unaudited
|
Year to 31 December 2008
|
|
|
$ million
|
$ million
|
$ million
|
|
Revenue:
|
|
|
|
|
North Sea and West Africa*
|
89.5
|
213.1
|
324.5
|
|
Asia
|
57.0
|
112.7
|
203.6
|
|
Middle East-Pakistan
|
67.4
|
60.0
|
127.1
|
|
Total group sales revenue
|
213.9
|
385.8
|
655.2
|
|
Interest and other finance revenue
|
1.1
|
6.1
|
12.5
|
|
Total group revenue
|
215.0
|
391.9
|
667.7
|
|
Group operating profit/(loss):
|
|
|
|
|
North Sea and West Africa*
|
49.3
|
96.0
|
89.4
|
|
Asia
|
36.2
|
73.1
|
102.0
|
|
Middle East-Pakistan
|
44.8
|
40.6
|
86.0
|
|
Unallocated**
|
(5.5)
|
(6.1)
|
(15.7)
|
|
Group operating profit
|
124.8
|
203.6
|
261.7
|
|
Interest revenue, finance and other gains
|
9.0
|
7.5
|
14.6
|
|
Finance costs and other finance expenses
|
(17.0)
|
(13.4)
|
(27.0)
|
|
Mark to market revaluation of commodity hedges
|
(44.2)
|
(7.2)
|
28.3
|
|
Profit before tax
|
72.6
|
190.5
|
277.6
|
|
Tax
|
(45.7)
|
(119.3)
|
(179.3)
|
|
Profit after tax
|
26.9
|
71.2
|
98.3
|
|
Balance sheet
|
|
|
|
|
Segment assets:
|
|
|
|
|
North Sea and West Africa*
|
1,274.2
|
538.8
|
442.1
|
|
Asia
|
655.2
|
540.8
|
527.8
|
|
Middle East-Pakistan
|
160.1
|
134.0
|
146.3
|
|
Unallocated**
|
227.1
|
775.9
|
334.4
|
|
Total assets
|
2,316.6
|
1,989.5
|
1,450.6
|
|
* |
The group's West Africa operations were combined with the North Sea business unit at the beginning of 2009. Accordingly, the 2008 segmental information has been re-presented to reflect this. |
|
** |
Unallocated expenditure and assets include amounts of a corporate nature and not specifically attributable to a geographical segment. These items include investments in associates, cash and mark to market valuations of commodity hedges. |
3. COST OF SALES
|
|
Six months
to 30 June 2009
Unaudited
|
Six months
to 30 June 2008
Unaudited
|
Year to 31 December 2008
|
|
|
$ million
|
$ million
|
$ million
|
|
Operating costs
|
58.9
|
66.1
|
127.1
|
|
Stock overlift/underlift movement
|
(42.4)
|
7.9
|
33.1
|
|
Royalties
|
8.4
|
8.2
|
16.8
|
|
Amortisation and depreciation of property, plant and equipment:
|
|
|
|
|
Oil and gas properties
|
69.3
|
56.0
|
107.2
|
|
Other fixed assets
|
0.6
|
0.6
|
1.5
|
|
Impairment of property, plant and equipment
|
22.7
|
-
|
31.9
|
|
|
117.5
|
138.8
|
317.6
|
4. INTEREST REVENUE AND FINANCE COSTS
|
|
Six months
to 30 June
2009
Unaudited
|
Six months
to 30 June
2008
Unaudited
|
Year to 31 December
2008
|
|
|
$ million
|
$ million
|
$ million
|
|
Interest revenue, finance and other gains:
|
|
|
|
|
Short-term deposits
|
1.1
|
6.2
|
10.9
|
|
Mark to market valuation of foreign exchange contracts
|
4.5
|
1.3
|
-
|
|
Others
|
-
|
-
|
1.6
|
|
Exchange differences
|
3.4
|
-
|
2.1
|
|
|
9.0
|
7.5
|
14.6
|
|
Finance costs and other finance expenses:
|
|
|
|
|
Bank loans and overdrafts
|
(4.7)
|
(2.0)
|
(3.0)
|
|
Payable in respect of convertible bonds
|
(7.2)
|
(7.0)
|
(14.2)
|
|
Unwinding of discount on decommissioning provision
|
(2.8)
|
(3.6)
|
(5.8)
|
|
Long-term debt arrangement fees
|
(2.3)
|
(0.4)
|
(0.8)
|
|
Mark to market valuation of foreign exchange contracts
|
-
|
-
|
(2.5)
|
|
Others
|
-
|
(0.3)
|
(0.7)
|
|
Exchange differences
|
-
|
(0.1)
|
-
|
|
|
(17.0)
|
(13.4)
|
(27.0)
|
5. EARNINGS PER SHARE
The calculation of basic earnings per share is based on the profit after tax and on the weighted average number of Ordinary Shares in issue during the period. The denominators for the purposes of calculating both basic and diluted earnings per share for all periods presented have been adjusted to reflect the bonus element related to the rights issue in 2009.
Basic and diluted earnings per share are calculated as follows:
|
Profit after tax
Unaudited
|
Weighted average
number of shares
|
Earnings per share
|
||||
|
|
Six months to 30 June
2009
|
Six months
to 30 June 2008
|
Six months to 30 June 2009
|
Six months to 30 June
2008
(restated)
|
Six months to 30 June
2009
|
Six months to 30 June 2008
(restated)
|
|
|
$ million
|
$ million
|
million
|
million
|
cents
|
cents
|
|
Basic
|
26.9
|
71.2
|
102.4
|
100.2
|
26.3
|
71.1
|
|
Outstanding share options
|
-
|
-
|
0.2
|
1.1
|
*
|
*
|
|
Convertible bonds
|
-
|
6.7
|
-
|
9.3
|
*
|
*
|
|
Diluted
|
26.9
|
77.9
|
102.6
|
110.6
|
26.2
|
70.4
|
|
*
|
The inclusion of the outstanding share options in the 2009 and 2008 calculations produces a diluted earnings per share. The outstanding share options number includes any expected additional share issues due to future share-based payments. At 30 June 2009 9,337,340 (2008 restated: 9,337,340) potential Ordinary Shares in the company that are underlying the company’s convertible bonds and that may dilute earnings per share in the future have not been included in the calculation of diluted earnings per share because they are anti-dilutive for the period to 30 June 2009. A similar number for the comparable period has been included. |
|
|
In accordance with IAS 33 - 'Earnings per Share', the comparatives have been restated to take into account the rights issue by the company.
6. INTANGIBLE EXPLORATION AND EVALUATION (E&E) ASSETS
|
Oil and gas properties |
||||
|
North Sea and West Africa |
Asia |
Middle East-Pakistan |
Total |
|
|
$ million |
$ million |
$ million |
$ million |
|
|
Cost: |
||||
|
At 1 January 2009 |
94.1 |
63.8 |
- |
157.9 |
|
Exchange movements |
4.6 |
- |
- |
4.6 |
|
Additions during the period |
14.3 |
37.4 |
0.8 |
52.5 |
|
Transfer to tangible fixed assets |
- |
- |
(0.8) |
(0.8) |
|
Exploration expenditure written off |
(18.5) |
- |
- |
(18.5) |
|
At 30 June 2009 |
94.5 |
101.2 |
- |
195.7 |
|
At 30 June 2008 |
72.2 |
111.4 |
1.6 |
185.2 |
The amounts for intangible E&E assets represent costs incurred on active exploration projects. These amounts are written off to the income statement as exploration expense unless commercial reserves are established or the determination process is not completed and there are no indications of impairment. The outcome of ongoing exploration, and therefore whether the carrying value of E&E assets will ultimately be recovered, is inherently uncertain.
7. PROPERTY, PLANT AND EQUIPMENT
|
Oil and gas properties |
|||||
|
North Sea and West Africa |
Asia |
Middle East-Pakistan |
Other fixed assets |
Total |
|
|
$ million |
$ million |
$ million |
$ million |
$ million |
|
|
Cost: |
|||||
|
At 1 January 2009 |
586.6 |
527.5 |
175.7 |
9.7 |
1,299.5 |
|
Exchange movements |
- |
- |
- |
0.6 |
0.6 |
|
Additions during the period |
601.4 |
36.2 |
13.8 |
1.3 |
652.7 |
|
Disposals |
- |
(7.8) |
- |
- |
(7.8) |
|
Transfer from intangible fixed assets |
- |
- |
0.8 |
- |
0.8 |
|
At 30 June 2009 |
1,188.0 |
555.9 |
190.3 |
11.6 |
1,945.8 |
|
Amortisation and depreciation: |
|||||
|
At 1 January 2009 |
300.0 |
129.5 |
96.8 |
5.8 |
532.1 |
|
Exchange movements |
- |
- |
- |
0.4 |
0.4 |
|
Charge for the period |
42.5 |
16.7 |
10.1 |
0.6 |
69.9 |
|
Impairment loss |
22.7 |
- |
- |
- |
22.7 |
|
At 30 June 2009 |
365.2 |
146.2 |
106.9 |
6.8 |
625.1 |
|
Net book value: |
|||||
|
At 31 December 2008 |
286.6 |
398.0 |
78.9 |
3.9 |
767.4 |
|
At 30 June 2009 |
822.8 |
409.7 |
83.4 |
4.8 |
1,320.7 |
|
At 30 June 2008 |
327.5 |
312.3 |
67.5 |
3.5 |
710.8 |
The impairment loss relates to the Chinguetti field in Mauritania. The impairment charge was calculated by reference to an assessment of the future discounted cash flows expected to be derived from production of commercial reserves measured against the carrying value of the asset. The future cash flows are discounted using a pre-tax discount rate. Estimates involved in impairment measurement include estimates of commercial reserves, future oil and gas prices, costs and timing which are inherently uncertain.
Amortisation and depreciation for oil and gas properties is calculated on a unit-of-production basis, using the ratio of oil and gas production in the period to the estimated quantities of proved and probable reserves at the end of the period plus production in the period, on a field-by-field basis. Proved and probable reserve estimates are based on a number of underlying assumptions including oil and gas prices, future costs, oil and gas in place and reservoir performance, which are inherently uncertain. Management uses established industry techniques to generate its estimates and regularly references its estimates against those of joint venture partners or external consultants. However, the amount of reserves that will ultimately be recovered from any field cannot be known with certainty until the end of the field's life.
8. HEDGING INSTRUMENTS
The group's activities expose it to financial risks of changes primarily in oil and gas prices but also in foreign currency exchange and interest rates. The group uses derivative financial instruments to hedge certain of these risk exposures. The use of financial derivatives is governed by the group's policies and approved by the Board of Directors, which provides written principles on the use of such financial derivatives.
Oil and gas hedging is undertaken with collar options and swaps. Oil volumes are hedged using Dated Brent oil price options. Indonesian gas volumes are hedged using HSFO Singapore 180cst which is the variable component of the gas price.
Oil production
During the period 0.9 million hedged barrels matured at a cost of US$nil (2008: US$8.1 million). At 30 June 2009 the group had 9.9 million barrels of Dated Brent oil hedged with collars at an average floor price of US$48.06/bbl and a cap of US$85.45/bbl, of which 6.3 million barrels were embedded through an offtake agreement to the end of 2012. In addition, a further 1.3 million barrels were sold forward at an average price of US$55.11/bbl to the end of 2010. Upfront premia of US$12.5 million were paid for additional hedges and to enhance existing hedges. For the period ended 30 June 2009, all movements of unexpired forward sales amounting to US$19.6 million relate to the intrinsic value of such instruments and have been recognised directly in reserves.
Indonesian gas production
During the current period gas hedges matured at a cost of US$nil (2008: US$3.1 million). Approximately 34 per cent of future production from the existing contract is hedged with a floor of US$250/metric tonne and a cap of US$500/metric tonne.
Fair values
The fair values, which have been determined from counterparties with whom the trades have been concluded, have been recognised in the balance sheet in trade and other receivables - oil hedges: US$34.8 million and trade and other payables - oil hedges: US$74.2 million, gas hedges: US$18.2 million.
The key variable which affects the fair value of the group's hedge instruments is market expectations about future commodity prices.
9. NOTES TO THE CONDENSED CONSOLIDATED CASH FLOW STATEMENT
|
|
Six months to 30 June 2009
Unaudited
|
Six months to 30 June 2008
Unaudited
|
Year to 31 December 2008
|
|
|
$ million
|
$ million
|
$ million
|
|
Profit before tax for the period/year
|
72.6
|
190.5
|
277.6
|
|
Adjustments for:
|
|
|
|
|
Depreciation, depletion, amortisation and impairment
|
92.6
|
56.6
|
140.6
|
|
Exploration expense
|
18.5
|
25.4
|
42.9
|
|
Pre-licence exploration costs
|
6.7
|
6.7
|
15.8
|
|
Acquisition of subsidiaries
|
(66.3)
|
-
|
-
|
|
Net operating charge for long-term employee benefit plans less contributions
|
-
|
-
|
(3.0)
|
|
Provision for share-based payments
|
8.3
|
8.1
|
20.1
|
|
Interest revenue, finance and other gains
|
(9.0)
|
(7.5)
|
(14.6)
|
|
Finance costs and other finance expenses
|
17.0
|
13.4
|
27.0
|
|
Mark to market revaluation of commodity hedges
|
44.2
|
7.2
|
(28.3)
|
|
Operating cash flows before movements in working capital
|
184.6
|
300.4
|
478.1
|
|
(Increase)/decrease in inventories
|
(12.1)
|
(11.5)
|
7.9
|
|
(Increase)/decrease in receivables
|
(36.1)
|
(54.2)
|
34.5
|
|
Increase in payables
|
4.4
|
18.5
|
21.7
|
|
Cash generated by operations
|
140.8
|
253.2
|
542.2
|
|
Income taxes paid
|
(29.1)
|
(68.7)
|
(203.1)
|
|
Interest income received
|
1.7
|
6.6
|
13.2
|
|
Net cash from operating activities
|
113.4
|
191.1
|
352.3
|
Analysis of changes in net (debt)/cash
|
|
Six months to 30 June 2009
Unaudited
|
Six months to 30 June 2008
Unaudited
|
Year to 31 December 2008
|
|
|
$ million
|
$ million
|
$ million
|
|
a) Reconciliation of net cash flow to movement in net (debt)/cash:
|
|
|
|
|
Movement in cash and cash equivalents
|
(130.2)
|
101.0
|
(8.3)
|
|
Proceeds from long-term loans
|
(238.0)
|
-
|
-
|
|
Repayment of long-term loans
|
-
|
-
|
53.0
|
|
Non-cash movements on debt and cash balances
|
(3.2)
|
(3.1)
|
(6.4)
|
|
(Decrease)/increase in net cash in the period/year
|
(371.4)
|
97.9
|
38.3
|
|
Opening net cash
|
117.3
|
79.0
|
79.0
|
|
Closing net (debt)/cash
|
(254.1)
|
176.9
|
117.3
|
|
b) Analysis of net (debt)/cash:
|
|
|
|
|
Cash and cash equivalents
|
193.5
|
433.0
|
323.7
|
|
Long-term debt*
|
(447.6)
|
(256.1)
|
(206.4)
|
|
Total net (debt)/cash*
|
(254.1)
|
176.9
|
117.3
|
|
* |
The carrying values of the convertible bonds and the other long-term debt on the balance sheet are stated net of the unamortised portion of the issue costs of US$3.3 million (2008: US$4.1 million) and debt arrangement fees of US$18.1 million (2008: US$0.9 million) respectively. |
10. RIGHTS ISSUE
On 25 March 2009, Premier announced its proposal to raise approximately £171 million (US$252.1 million) by way of a fully underwritten rights issue. Under the proposal, Premier offered its shareholders the opportunity to acquire 4 new Ordinary Shares for every 9 Ordinary Shares held at a price of 485 pence per new Ordinary Share. The proposal was subject to authorisation by shareholders which was obtained at a General Meeting held on 20 April 2009. The offer period commenced on 21 April 2009 and closed for acceptance on 6 May 2009. Dealing in the new shares began on 7 May 2009.
Accounting treatment under IFRS
Although Premier's functional currency is US dollars, the rights issue was denominated in sterling. Accordingly, under the requirements of IAS 32 - 'Financial Instrument: Presentation', paragraph 16(b)(ii), Premier was not able to demonstrate that it was issuing a fixed number of shares for a fixed amount of cash, and would therefore be prohibited under IAS 32 from accounting for the offer of rights in shareholders' equity. Under IAS 32, the offer of rights would be treated as a derivative financial liability.
As a derivative financial liability, under IAS 39 - 'Financial Instruments: Recognition and Measurement', the liability would have been measured at its fair value at inception of the offer on 21 April 2009, which is substantially the difference between the share price at that date and the issue price of 485 pence per new Ordinary Share. The corresponding entry on inception would have been made to shareholders' equity. Subsequently, the liability would have been re-measured at fair value with movements in fair value recognised in the income statement until the exercise of the rights, which were exercised by 6 May 2009. On the exercise of rights, the liability would have been credited to shareholders' equity. If this accounting treatment was to be adopted by Premier, a loss of US$75.4 million would have been recognised in the income statement, which was primarily due to an increase in Premier's share price between 21 April 2009 and 6 May 2009. There would have been no impact on the group's or Premier Oil plc's shareholders' equity or the distributable reserves.
The table below demonstrates the accounting entries for the rights issue under the accounting treatment required by IAS 32:
|
|
Retained earnings
|
Derivative liability
|
Income statement
|
|
|
$ million
|
$ million
|
$ million
|
|
Initial recognition of liability for offer of rights
|
(241.7)
|
241.7
|
-
|
|
Movement in fair value of rights
|
-
|
75.4
|
(75.4)
|
|
Exercise of rights
|
317.1
|
(317.1)
|
-
|
|
Transfer to retained earnings
|
(75.4)
|
-
|
75.4
|
|
Effect of rights issue on retained earnings
|
-
|
|
|
The following table shows the group's profit before tax, profit/(loss) for the period and profit/(loss) attributable to shareholders of the parent company if the offer of rights was classified as either a liability, as required by IAS 32, or an equity instrument, as reported.
Half year to 30 June 2009:
|
|
Equity instrument
(as reported)
|
Liability
instrument
|
|
|
$ million
|
$ million
|
|
Profit/(loss) before tax
|
72.6
|
(2.8)
|
|
Profit/(loss) for the period
|
26.9
|
(48.5)
|
|
Basic earnings/(loss) per share
|
26.3
|
(47.4)
|
|
Diluted earnings/(loss) per share
|
26.2
|
(47.4)
|
Future accounting developments
On 21 July 2009, following a recommendation from IFRIC that IAS 32 be urgently amended, the IASB discussed the classification of rights issues. As a result of that meeting, an Exposure Draft was issued on 6 August 2009 to amend IAS 32, such that, if adopted, IAS 32 would require rights issues such as Premier's rights issue to be accounted for as equity instruments rather than derivative financial liabilities. If the Exposure Draft is approved substantively in its current form it will retrospectively remove the need to treat issuance of the rights issue as a derivative financial liability.
Fair presentation
In the opinion of the directors, accounting for the rights issue in accordance with the current requirements of IAS 32 as set out above would be so misleading that it would conflict with the objective of financial statements set out in the IASB's framework. The directors concluded that the application of IAS 32 to the rights issue would not result in a fair representation of the transaction it purports to represent, and consequently would be likely to influence economic decisions made by users of the financial statements. The directors have therefore concluded that compliance with this specific requirement would be so misleading that the condensed set of financial statements would not present fairly the group's financial position, financial performance and cash flows.
In making this determination, the directors noted that the offer of rights had been made on equal terms, so far as legal requirements permit, to all ordinary shareholders in the currency in which their shares are denominated, and that in essence the transaction is one with existing ordinary shareholders, such that it would reasonably be expected to have no effect on the profit or loss attributable to ordinary shareholders for the accounting period. The principal factor which, under the requirements of IFRS, determined the movement in the liability over the offer period was the movement in the Premier share price; therefore the accounting treatment under IAS 32 would have resulted in amounts being recognised in the income statement in respect of a transaction with existing ordinary shareholders, and which are primarily caused by movements in the Premier share price. Furthermore, the directors noted that the financial effect of this accounting treatment is material in terms of its amount, and would cause a profit attributable to shareholders to become a loss attributable to shareholders. They therefore concluded that this was a fundamental consideration in understanding the financial performance of the group, such that the condensed set of financial statements prepared in accordance with the specific requirements of IAS 32, as set out above, would not be fairly presented and would not give a true and fair view of the group's financial position, financial performance and cash flows.
Accordingly, Premier has accounted for the offer of rights as an equity instrument, and has therefore not re-measured this instrument during the offer period. Premier has therefore accounted for the offer of rights in the same way that IAS 32 would require for an offer of rights in new shares denominated in the functional currency of the issuer.
Following the exercise of the rights and the allotment of new shares, the cash proceeds of the rights issue were recognised in shareholders' equity.
Share capital
Movement in share capital:
|
|
Number
|
$ million
|
|
At 1 January 2009
|
82,170,460
|
73.6
|
|
Shares issued in respect of rights issue (nominal value)
|
35,276,566
|
26.0
|
|
Shares issued under employee share plans
|
19,119
|
-
|
|
Treasury shares cancelled
|
(2,798,186)
|
(2.6)
|
|
At 30 June 2009
|
114,667,959
|
97.0
|
11. ACQUISITION OF SUBSIDIARIES
On 21 May 2009 the Premier Oil plc group, through its subsidiary Premier Oil Group Ltd, completed the acquisition of the entire issued share capital of Oilexco North Sea Ltd (ONSL) and its wholly-owned subsidiary Oilexco North Sea Exploration Ltd (ONSEL).
The group funded the acquisition and associated costs by way of:
A 4 for 9 rights issue of new Ordinary Shares at a price of 485 pence per share to raise gross proceeds of approximately £171 million (US$252.1 million);
New credit facilities consisting initially of a US$175.0 million 18-month bridge facility, a US$225.0 million three-year revolving credit facility and US$63.0 million and £60.0 million (US$99.0 million) three-year letter of credit facilities; and
The group's existing cash resources.
ONSL is an oil and gas exploration and production company active in the UK, with its producing properties located in the UK Central North Sea. The acquisition has provided the group with a greater presence in the North Sea, strengthening the group's existing operations in that area by adding a material package of assets comprising existing producing fields, development projects of existing discovered reserves and a portfolio of exploration prospects, together with high-quality UK operatorship capabilities.
The transaction has been accounted for by the purchase method of accounting with an effective date of 21 May 2009 being the date that the group gained control of ONSL. Information in respect of assets acquired is still being assessed and the fair value allocation to the ONSL and ONSEL assets is provisional in nature and will be reviewed in accordance with the provisions of IFRS 3 - 'Business Combinations'.
|
|
Fair value
|
|
|
$ million
|
|
Net assets acquired:
|
|
|
Property, plant and equipment
|
569.0
|
|
Deferred tax asset
|
146.5
|
|
Current assets
|
92.3
|
|
Current liabilities
|
(39.6)
|
|
Deferred tax liabilities
|
(2.1)
|
|
Long-term provisions
|
(125.7)
|
|
Total acquired net assets
|
640.4
|
|
Total consideration*
|
(574.1)
|
|
Excess of fair value over cost**
|
66.3
|
|
* |
Total consideration also includes US$63.0 million of cash paid by the group which is held in trust for future abandonment obligations, and direct acquisition costs of US$10.4 million. |
|
** |
The aggregate fair value of the identifiable assets and liabilities of ONSL and ONSEL were less than the purchase consideration by US$66.3 million. This excess of fair value over cost has been recognised immediately in the condensed consolidated income statement for the period under review, and has been offset by related acquisition expenses of US$6.0 million. |
The final payments made by Premier at completion amounted to US$500.7 million, after adjusting for certain payables, receivables and other items which have occurred between the effective date and completion.
ONSL and ONSEL contributed US$1.0 million to revenue and US$24.0 million to profit before tax for the period between the date of acquisition and the balance sheet date.
If the acquisition of ONSL had been completed on the first day of the financial year, group revenues for the period would have been US$279.2 million. As the acquired subsidiary was in administration prior to the acquisition, it is impracticable to calculate a fair estimate of cost of sales, and hence it is not possible to provide a pro forma profit before tax amount for the combined group since 1 January 2009. Similarly appropriate amounts are not available for carrying values of assets, liabilities and contingent liabilities immediately prior to the acquisition.
Due to the inherently uncertain nature of the oil and gas industry the assumptions underlying the provisionally-assigned values are judgemental in nature.
12. DIVIDENDS
No interim dividend is proposed (2008: US$nil).
13. EVENTS AFTER THE BALANCE SHEET DATE
On 20 July 2009, the group announced that it had signed a Sale and Purchase Agreement (SPA) and completed the acquisition from Delek Energy Systems Ltd of Delek Energy (Vietnam) LLC, the holding company for its 25 per cent interest in Block 12W in the Nam Con Son Basin, offshore Vietnam. The purchase price for the interest is US$72 million in cash, before adjustments, with an effective date of 31 March 2009. The SPA also provides for future payments of up to a total of US$10 million contingent on the development of fields in Block 12W other than Chim Sáo. Separately PetroVietnam Exploration and Production (PVEP) has confirmed that it will exercise its back-in right to acquire a 15 per cent interest in the PSC. Following completion of both the group's acquisition from Delek and the PVEP back-in, the interests in Block 12W will be; Premier 53.125 per cent (Operator), Santos 31.875 per cent, PVEP 15.000 per cent.
On 19 August 2009, the group announced the sale of its 10 per cent non-operated interest in the NW Gemsa licence, onshore Egypt, for the sum of US$12.5 million. The sale is subject to the approval of the Egyptian authorities.
On 26 August 2009, the group announced well results for the Frida Marine-1 well (Congo), as described in the Operational Review. At 30 June 2009, the related cost capitalised in the balance sheet, in intangible exploration and evaluation assets, was US$13.3 million.
INDEPENDENT REVIEW REPORT TO PREMIER 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 2009 which comprises the condensed consolidated income statement, the condensed consolidated statement of comprehensive income, the condensed consolidated balance sheet, the condensed consolidated statement of changes in equity, the condensed 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 them 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 1, 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 2009 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 Auditors
London
26 August 2009
Related Shares:
PMO.L