Half Yearly Results

RNS Number : 6598R

Premier Oil PLC

26 August 2010

 

26th August 2010

Premier Oil plc

("Premier" or the "Group")

Half Yearly Results for the six months to 30 June 2010

 

Highlights

·; Production of 46,600 boepd, up 17 per cent on first half 2009 (39,700 boepd)

·; Main development projects progressing on schedule to meet target of 75,000 boepd in 2012:

- Chim Sáo wellhead platform fully installed, development drilling under way

- Gajah Baru wellhead jacket installed; development drilling scheduled to commence shortly

- Huntington commercial agreements progressing; Field Development Plan submitted to UK Government (DECC)

·; Material exploration success on Catcher and Catcher East in the UK; Blåbær discovery in Norway

·; Operating cash flow of US$222.1 million (2009: US$113.4 million), an increase of 96 per cent

·; Profit before tax of US$111.6 million (2009: US$19.0 million), compared to full year 2009 profit before tax of US$79.9 million

·; Cash resources of US$449.1 million (2009: US$193.5 million) and available undrawn bank facilities of US$404 million (2009: US$500 million)

 

Outlook

·; Full year production for 2010 expected to be around 44,000 boepd, as previously indicated

·; Growing portfolio of potential developments representing next phase of growth (Bream, Catcher, Dua, Frøy, Naga, Pelikan, Solan)

·; Material wells planned for the second half of the year including follow-up on Catcher discoveries of up to four wells

·; Around 20 wells planned over the next 12 months targeting 300 mmboe

 

Simon Lockett, Chief Executive, commented:

"During the first half of this year, Premier has continued to make good progress towards our 2012 production target of 75,000 boepd. We were delighted to be part of the Catcher discoveries, which have been added to our growing portfolio of future developments. These developments have the potential to take production levels to 100,000 boepd in the medium-term. We also look forward to a significant exploration programme for the rest of the year containing material wells in the UK, Norway and Indonesia."

 

ENQUIRIES
Premier Oil plc	Tel: 020 7730 1111
Simon Lockett
Tony Durrant
Pelham Bell Pottinger	Tel: 020 7861 3159
Gavin Davis
Evgeniy Chuikov

 

 

There will be a presentation to analysts 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 in 2008, it is not a requirement for half yearly financial statements to be sent to shareholders. Accordingly, Premier will not be printing and distributing a 2010 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

 

Higher production levels and a stronger commodity price environment have delivered solid first half financial results. The exploration discoveries at Catcher have further improved the outlook for production growth.

 

Average production during the first half of the year was 46,600 barrels of oil equivalent per day (boepd), 17 per cent higher than the corresponding period in 2009 (39,700 boepd) driven by the acquisition in May 2009 of the Oilexco North Sea Limited (Oilexco) producing assets. Also in the UK, the Kyle, Scott and Wytch Farm fields produced in aggregate above 2009 levels. Production outside the UK remained steady, as rising gas demand and strong well performance were experienced in both Pakistan and Indonesia.

 

Significant progress on the development portfolio was achieved with both the Chim Sáo project in Vietnam and the Gajah Baru project in Indonesia continuing on schedule to achieve first oil and gas in 2011. For the Huntington field in the UK a Field Development Plan (FDP) has been submitted to DECC. A Letter of Intent was signed with Sevan Marine ASA (Sevan) for a Floating Production Storage and Offtake vessel (FPSO), facilitating exclusive negotiations and allowing long lead expenditures. First oil is scheduled for January 2012. Work is also progressing satisfactorily on the Frøy and Bream fields in Norway and the Dua field in Vietnam to achieve development approval in the first half of 2011.

 

In order to take advantage of future opportunities for increased gas deliveries from West Natuna, development work on the Pelikan and Naga fields in Indonesia has been accelerated by two years to achieve first gas in 2013 and 2014. On the non‑operated North Sumatra Block A, a Memorandum of Understanding was signed with the Governor of Aceh confirming provincial support for field development and the Production Sharing Contract (PSC) extension, although the Ministerial approval of the PSC extension remains unsigned.

 

We remain focused on our exploration target of achieving 200 million barrels of oil equivalent (mmboe) of reserve additions by 2015. The first half of 2010 has seen success with significant discoveries at Catcher in the UK, as well as a discovery at Blåbær in Norway. The Catcher area discoveries are of particular note, being one of the largest discoveries made in the UK Central North Sea over the last five years, on acreage which was acquired by Premier as part of the Oilexco acquisition.

 

We continue to build the exploration portfolio for future drilling, including the acquisition of new 3D seismic data in Indonesia and Vietnam. We have increased our interest in the UK West Rochelle prospect due to be drilled shortly. We also acquired a new licence, P1577, covering 1,700km2 of the frontier shallow water West Orkney Basin and 11 applications were made for UK Central North Sea acreage in the 26th Licence Round. A licence was also awarded in Egypt.

 

Some stability returned to oil and gas prices in the period with Brent crude oil prices trading in a range of US$69 per barrel (bbl) to US$88/bbl. The average for the period was US$77/bbl against US$52/bbl in the corresponding period last year. On the back of this stronger commodity price environment and with our significant increase in production, post-tax profits and operating cash flows increased significantly to US$62.0 million (2009: loss of US$27.3 million) and US$222.1 million (2009: US$113.4 million) respectively.

 

We continue to place a high priority on health, safety and environmental matters. In the International Association of Oil and Gas Producers' recent safety performance indicators report, Premier again demonstrated top quartile performance measured by the total recordable injury frequency across all functions. We have also retained our inclusion in the FTSE4Good Index.

 

Board change

As separately reported today, we are pleased to announce the appointment of Jane Hinkley as a Non-Executive Director with effect from 1 September 2010. Jane was formerly CEO of Gotaas‑Larsen Shipping Corporation, Managing Director of Navion Shipping AS and a Non‑Executive Director of Revus Energy ASA. She will provide invaluable input to the Board.

 

Outlook

We remain committed to our stated growth strategy and the prudent financing principles which support it. We will continue to give priority to the execution of our current development projects whilst progressing our growing portfolio of contingent resources towards development sanction. We continue to seek value-adding acquisitions in our core areas of activity.

 

In the second half of 2010, Premier plans to drill six to eight exploration wells, targeting an un‑risked net prospective resource base of between 85 mmboe and 350 mmboe. In the UK, although the recent Oates well was a disappointment, further exploration and appraisal drilling in the greater Catcher area is planned along with a well on the West Rochelle prospect. In Norway, the Gnatcatcher prospect will be drilled in the fourth quarter of 2010 as a follow-on to the Grosbeak discovery made in 2009 and, in Indonesia, the Gajah Laut Utara well is planned to spud in the fourth quarter. This is a material prospect within the same area as the Chim Sáo and Cá Rồng Đo discoveries made by Premier in Vietnam in the last few years.

 

For 2011 we expect to drill around 12 exploration and appraisal wells, including the appraisal of the Grosbeak and Cá Rồng Đo discoveries. The 2011 programme will target a mean net prospective resource base of approximately 200 mmboe.

 

The first half of this year has seen us deliver development progress and exploration success and we look forward to a very active second half of the year.

 

Mike Welton

Chairman

 

 

OPERATIONAL REVIEW

 

ASIA

Premier's key Asian developments have progressed well during the first half of the year. With less than a year until first oil at the Chim Sáo field, the project remains within budget and on schedule. Good progress has also been made on various projects to supply future gas from Indonesia to Singapore. Extensive preparations were also carried out for the exciting exploration campaign on the Tuna Block in Indonesia, which is due to start in the fourth quarter.

 

Production and development

Indonesia

During the first six months of 2010, the Premier-operated Natuna Sea Block A in Indonesia sold an overall average of 150 billion British thermal units per day (BBtud) (gross) from its gas export facility (up 6 per cent from first half 2009), whilst the non-operated Kakap Block contributed a further 54 BBtud (gross). Liquids production from the Block A Anoa field averaged 1,700 barrels of oil per day (bopd) (gross) and the Kakap fields 2,900 bopd (gross). Overall, net production from Indonesia amounted to 11,300 boepd (2009: 10,900 boepd) on a working interest basis.

 

Significant progress continues to be made on the Gajah Baru project, the first of a number of 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. Fabrication of both the wellhead platform and the central processing platform continue in Batam at two separate fabrication yards. The overall Engineering, Procurement, Construction and Installation (EPCI) contract was over 63 per cent complete at the end of July. The wellhead platform is in the process of being installed, allowing the start of development well drilling in September 2010. The project remains on track to deliver first gas on schedule in October 2011.

 

Development work on the Pelikan and Naga fields has been accelerated in order to be able to take on additional GSA market share from 2014. First gas is scheduled for 2013 and 2014 respectively instead of the previously planned 2015 and 2016. The project has passed through the concept selection gate and final project sanction is expected in 2011. The Pelikan and Naga fields will be tied-in to the existing West Natuna Transportation System.

 

On the non-operated North Sumatra Block A work continues on optimising the project and on the transportation studies prior to the issuing of EPCI tender documents. Negotiation of fully-termed agreements for use of third party facilities for transportation of gas and liquids continued, with strong support from the relevant authorities. The provincial government in Aceh has indicated its support and approval for the process of extending the North Sumatra Block A PSC and has signed a Memorandum of Agreement to this effect with the operator. The Indonesian Ministry responsible for such matters, MIGAS, is planning to finalise the PSC extension approval during the third quarter of this year. The delayed approval has impacted the project timetable with first gas now scheduled for early 2013.

 

Vietnam

The Chim Sáo field development remains on schedule. Key milestones in the first half of the year were the installation of the production jacket and laying of the 100km export pipeline through which produced gas will be transported from Chim Sáo to the Nam Con Son pipeline. Development drilling commenced in mid-June and will deliver eight wells for first oil. Fabrication of the topsides for the wellhead platform was completed by mid-year and these have now been installed offshore. The conversion of the Lewek Emas FPSO in Singapore was 60 per cent complete at the end of July and will be moved out to the field during the first half of 2011.

 

During the first half, detailed subsurface and facilities work was undertaken to define the development plan for the Dua field, which will potentially tie-in to Chim Sáo at a later date. Selection of the preferred development option is under way and a final field development project decision is targeted for the first half of 2011.

 

Exploration and appraisal

Indonesia

On the Premier-operated Tuna Block, significant progress has been made in preparation for the drilling programme later this year. Processing and interpretation of the 850km2 3D seismic survey was completed. Seismic attribute analysis has also highlighted several prospects with a seismic response consistent with that observed in the hydrocarbon-bearing reservoirs of the Cá Rồng Đo well drilled by Premier in the Vietnamese Block 07/03, immediately to the north of the Tuna Block. Site survey acquisition and processing was carried out safely and successfully over three prospects on the Tuna Block. Final plans are complete for drilling the Gajah Laut Utara and Belut Laut prospects in the fourth quarter of 2010.

 

On Natuna Sea Block A, given expectations of increasing demand for gas in the area, a five‑year exploration plan has been developed for the block, with a block-wide prospect inventory review in progress to refine the remaining risked resource potential. Planning is in progress for two exploration wells on the block in the second quarter of 2011: Anoa Deep and Biawak Besar.

 

Elsewhere, on the Buton Block, technical studies were completed with the identification of Benteng-1 as the drilling candidate for the fourth quarter of 2010. Onshore site preparation is in progress.

 

Vietnam

Work continued on the Cá Rồng Đo oil discovery (Block 07/03) in the Nam Con Son Basin ahead of drilling the appraisal well planned for early 2011. In July, 3D seismic data acquisition started over the central area of Block 07/03 and also on Block 104-109/05 offshore northern Vietnam, ahead of exploration drilling planned there for mid-2011.

 

MIDDLE EAST-PAKISTAN

Our producing assets in Pakistan delivered a satisfactory performance in the first half and field compression projects are progressing well. We were pleased to be awarded the South Darag Block in the Gulf of Suez, Egypt, and continue to seek opportunities across the region along with our joint venture partner Emirates International Investment Company LLC (EIIC).

 

Production and development

Pakistan

Average production in Pakistan during the first half of the year of 15,200 boepd (net to Premier), was marginally lower than the corresponding period in 2009 (15,500 boepd) due to planned shutdowns related to compression projects. Production was maintained at this level by fully utilising the existing gas fields' potential to meet the country's growing gas demand. Production facilities have been unaffected by the recent severe flooding in the country, although there was a short interruption to supply at one of our fields caused by a customer shutdown.

 

Average production from the Qadirpur gas field during the period (net to Premier) was 3,600 boepd (2009: 4,300 boepd). Work is ongoing on the compression project, initiated in 2009, which will counter the natural decline in field deliverability and which is scheduled to be completed before the winter season's increased demand. The QP-40 well has been drilled and will shortly be tied into production. Work commenced on the raised platform on the Indus River, which was being built to facilitate the drilling of three long reach wells to target areas north of the river, though this work was halted by the recent flooding. Supply of permeate gas at a rate of 60 million standard cubic feet per day (mmscfd) from the field to Sui Northern Gas Pipelines Ltd for Engro's nearby power plant commenced in February 2010, which also greatly reduced gas flaring/venting from the plant. Two additional permeate compressors have been delivered to the site and are in the process of being made operational.

 

During the period, the Kadanwari gas field produced 1,300 boepd (2009: 1,300 boepd), net to Premier. Two development wells K21 and K23 were drilled during the period. K19 and K21 are now on production and have contributed significantly to maintenance of current field production levels. The K23 tie-in is in progress and first gas is planned imminently. Drilling of the K24 development well is also now complete and tie-in is expected in October.

 

Average production from the Zamzama gas field during the period was 6,700 boepd, net to Premier, 3 per cent higher than last year (2009: 6,500 boepd). The front end compression project, at a gross cost of US$140 million, is on schedule for completion in June 2011, in order to compensate for the natural decline in reservoir pressure and to maintain production levels for next year.

 

The Bhit and Badhra gas fields produced an average of 3,600 boepd, net to Premier, during the first half of 2010, which was 6 per cent higher than the first half of last year (2009: 3,400 boepd). The wellhead compression project to maintain production levels has progressed well, with more than half the wells now under compression, and the remaining wells scheduled to be completed by the end of 2010.

 

Exploration and appraisal

Pakistan

Under the Qadirpur lease, the QP-Pirkoh-1 exploration well was drilled to test the potential of the shallow Pirkoh Limestone formation. Logging results showed high water saturations and the well was plugged and abandoned.

 

Drilling of the K18-ST exploration well and a step out appraisal well, K25, under the Kadanwari lease are planned for the third quarter of 2010.

 

Egypt

In the first quarter of 2010, the Egyptian General Petroleum Corporation (EGPC) awarded Premier the South Darag Block, in the Gulf of Suez, in the 2009 EGPC Bid Round. The award of this block is subject to formal government approvals which are now expected in the fourth quarter of 2010.

 

NORTH SEA AND WEST AFRICA

Integration of the Oilexco business acquired in 2009 has brought solid production performance, increasing development activity and an expanded UK exploration programme. In Norway, we continue to move forward with our exploration, appraisal and pre-development projects.

 

UK

Total UK production was 19,400 boepd in the first half of 2010 (2009: 12,100 boepd). The increase is mainly due to the assets acquired with Oilexco in 2009, although solid performance was also achieved at the Wytch Farm and Kyle fields. The Balmoral area (8,600 boepd) comprising Premier's equity in Balmoral, Brenda, Nicol and Stirling, was slightly below expectations as gas compression trips on the Floating Production Vessel (FPV) and the unsuccessful outcome of the Brenda pump speed initiative were only partly offset by the improved Nicol performance achieved by the on/off cycling of the two Nicol wells. Production from the Scott field was constrained by associated production of hydrogen sulphide gas although this was resolved towards the end of the period. The Shelley field (1,300 boepd) continued to decline, as expected, leading to permanent cessation of production in July. The Sevan Voyageur FPSO has sailed away from the field and is scheduled for employment on the Huntington field.

 

A new production riser for the Balmoral field will be installed in September and will allow production to re-commence from three oil wells in the Balmoral Paleocene sands. A further infill well is planned to spud in September. Premier operates the Balmoral FPV, which is a processing and export hub for five producing oil fields. We successfully concluded the management, design and fabrication of topside alterations in readiness for the Burghley field third-party tie-back which is expected to commence production in September and will reduce the shared facility costs for each user.

 

The Huntington project achieved concept selection and the joint venture partnership entered into a letter of intent with Sevan to progress negotiations on a charter party for the potential use of the Sevan Voyageur as the production unit for the Huntington field. The proposed charter party would be for a firm fixed term of five years with options for the Huntington owners to extend. The tender process for a drilling rig for development drilling is under way, with bids already received. Project sanction is scheduled for later in 2010, following the recent submission of the FDP to the DECC for approval. First oil is forecast for January 2012.

 

In July 2010, Premier entered into an agreement whereby the company will be granted an option to acquire a 40 per cent interest in the Solan field on final sanction of an FDP by the operator. If Premier exercises the option, it will pay a bonus on FDP approval by DECC, a carry of 20 per cent of the development project costs, and a contingent bonus on completion of the project. The block is situated west of the Shetland Islands and the operator estimates the Solan field resources to be 45 mmboe. The development solution currently under consideration is a standalone unmanned oil processing and storage facility with project sanction expected before the end of 2010.

 

Norway

On the Frøy project, an invitation to tender for the facilities was issued early in the year with responses received in April. A wellhead platform Invitation to Tender (ITT) was issued in July. The PL364 joint venture has also been assessing the discoveries near Frøy and the near-term exploration wells with a view to establishing Frøy as a potential oil hub in the area. Any additional reserves found nearby could provide valuable tie-back potential that could help accelerate the sanction decision for the Frøy project.

 

On PL407, containing the Bream field, an ITT for a production unit was issued in early June with responses received in early August. Selection of a development concept is expected in September.

 

Mauritania

Chinguetti gross production averaged approximately 8,200 boepd for the first half of the year in line with expectations, with some improvement in the decline rate due to higher facilities availability and better reservoir management.

 

The joint venture is negotiating the extension of both PSC A and PSC B with the Mauritanian Government and discussing potential development options and gas markets for the Banda gas field.

 

Exploration and appraisal

During the first half of 2010, Premier drilled seven exploration and appraisal wells in the North Sea including sidetracks at the successful Catcher and Blåbærlocations. Four wells were successful, notably the discoveries on the Catcher Block in the UK. We submitted 11 applications in the UK 26th Licensing Round and await the results, expected around year-end.

 

UK

The initial Catcher well on Block 28/9 (Premier equity 35 per cent) drilled in May, encountered good quality Cromarty reservoir with an estimated net oil pay of 27 metres. The subsequent drill stem test confirmed 30°API gravity oil with natural flow to the surface. Sand control issues hampered the measurement of a meaningful flow rate but it is estimated that the well would have flowed at a rate in excess of 7,500 bopd. A follow-up sidetrack (Catcher East) also encountered excellent quality oil bearing sandstones and a common pressure regime. Catcher East located 82ft of net hydrocarbon pay over a gross interval of over 236ft, with an average porosity of approximately 34 per cent.

 

An additional sidetrack (Catcher South West) appraised the Catcher Main discovery and also encountered excellent quality oil-bearing Cromarty sandstones. This well was drilled to 6,255ft measured depth and initial analysis indicated 68ft net hydrocarbon pay over a gross vertical reservoir interval of 261ft. The oil water contact was coincident with that seen in the Catcher Main discovery well. Estimated recoverable reserves for wells drilled to date on the Catcher Block are between 60 -100 million barrels of oil recoverable. Premier and its co-venturers have moved rapidly to acquire additional site surveys over potential drilling locations on Block 28/9 and further exploration wells are planned for later this year. This programme will define future development options.

 

The Bugle North well, drilled in April, targeted a northern extension of the Bugle oil discovery acquired with the Oilexco acquisition. The well was drilled close to the boundary between Blocks 15/23c and 15/23d (Premier share 50 per cent) with the cost split equally between the block partnerships. The well encountered only minor quantities of hydrocarbons. Work continues on evaluating the original Bugle discovery as a possible tie-in to the nearby Scott field infrastructure (Premier share 21.83 per cent).

 

After the period end, it was announced that the well on the Oates prospect (Premier share 50 per cent) had reached target depth but that no hydrocarbons were encountered.

 

Norway

The Greater Luno well in PL359 was plugged and abandoned as a dry hole with oil shows. The partners agreed to request a two-year licence extension in order to carry out further work on additional on-block prospectivity, including the Hinault prospect.

 

On PL374S, the Blåbær well encountered hydrocarbons in the Upper and Lower Cook Jurassic reservoirs. The Upper Cook reservoir was poor quality but 14 metres gross of high quality hydrocarbon-bearing sand was encountered in the Lower Cook reservoir. A sidetrack to test the fault seal model in the adjacent fault panel was dry. Future work will focus on confirming the discovered volume and appraising the potential of tie-back options including to the nearby Jordbaer development project.

 

On PL378, the joint venture partners have approved the southern location on Grosbeak as the optimum drilling location to appraise the discovery made last year. The Gnatcatcher prospect on the same block will be drilled in the second half of the year, followed by the Grosbeak appraisal well most likely in early 2011.

 

The application for consent to drill the Gardrofa well in licence PL406 in June was rejected by the Petroleum Safety Authority (PSA). The joint venture partnership is reviewing alternative approaches to the well, including the use of a semi-submersible rig. The well is now most likely to be drilled during 2011.

 

 

FINANCIAL REVIEW

Income statement

Group production, on a working interest basis, averaged 46,600 boepd in the first half of 2010 compared to 39,700 boepd in the corresponding period of 2009, and 44,200 boepd for the full year 2009. This reflects a full six-month contribution from the Oilexco UK assets acquired in May 2009 and good underlying performance from the Anoa field in Indonesia, on the back of strong gas demand in Singapore. Entitlement production for the period was 42,600 boepd (2009: 37,000 boepd).

 

Following the significant volatility of oil and gas prices during 2009, the first half of 2010 saw an average Brent oil price of US$77.3/bbl with a trading range of US$69/bbl to US$88/bbl. Premier's average realised oil price for the period was US$78.1/bbl (2009: US$53.0/bbl). Average realised gas prices for Indonesian production were US$13.8 per thousand cubic feet (mcf) (2009: US$8.9/mcf) in line with crude price increases and in Pakistan were US$3.3/mcf (2009: US$3.7/mcf). The effect of both production and price increases was to increase turnover to US$366.8 million (2009: US$213.9 million).

 

Cost of sales in the period was US$188.7 million (2009: US$116.4 million). Underlying operating costs, after adjusting for inventory movements, were US$12.9 per barrel of oil equivalent (boe) (2009: US$8.2/boe) reflecting the higher operating costs of UK North Sea fields acquired with Oilexco.

 

Amortisation of oil and gas properties rose from US$68.2 million to US$94.5 million and on a unit basis from US$9.5/boe to US$11.2/boe. This is due to the inclusion of a full six months of Oilexco assets' amortisation and higher abandonment cost provisions. There were no impairment charges in 2010 (2009: US$22.7 million).

 

Exploration expense and pre-licence exploration costs amounted to US$34.6 million (2009: US$18.5 million) and US$11.0 million (2009: US$6.7 million) respectively. The exploration write-off costs relate principally to the Greater Luno and Bugle North wells drilled in the first half. The cost of the Oates well, estimated at US$15.0 million, will be written off in the second half of the year.

 

Interest revenue, finance and other gains for the period were US$1.3 million (2009: US$9.0 million) offset by finance charges of US$33.9 million (2009: US$17.0 million). Net interest movements reflect lower interest rates on cash deposits and increased debt taken on in conjunction with our investment programme. Net finance charges also reflect the non-cash unwinding of discounting in relation to the outstanding convertible bonds and future abandonment obligations.

 

In total, a net credit of US$20.5 million (2009: US$44.2 million charge) is recorded in the first half, reflecting movement in the valuation of existing hedges and the release of deferred revenue. The majority of the group's oil collars are now embedded in long-term crude offtake arrangements. Being sales of production in the ordinary course of business, such embedded collars are not required to be marked to market. However, deferred revenue booked in prior years in respect of oil hedging arrangements is being credited to the income statement over the remaining life of the relevant hedges. A total of US$7.2 million was credited in this period. In addition, mark to market movements in respect of High Sulphur Fuel Oil (HSFO) hedges, which underlie the pricing mechanism for gas sold into the Singapore market, amounted to a credit of US$12.4 million in the period. No cash payments or receipts in respect of the group's collar arrangements were made in the first half.

 

Crude oil swaps, covering 700,000 barrels matured in the first half, generating a loss of US$1.2 million, which has been deducted from sales revenues.

 

The tax charge for the period was US$49.6 million (2009: US$46.3 million). Corporation tax payments were made in Indonesia and Pakistan but not in the UK where the group continues to benefit from capital allowances and losses acquired with the Oilexco acquisition. These stand at approximately US$1.05 billion at 30 June 2010. The average rate of tax for 2010 was lower than the corresponding period mainly due to the release of prior period provisions in the UK.

 

Profit after tax in the period to 30 June 2010 was US$62.0 million compared to a loss of US$27.3 million for the first half of 2009. Prior year comparatives have been restated, in accordance with the provisions of IFRS 3 - 'Business Combinations' for the re-assessment of acquisition fair values, which were presented in the group's full year 2009 results. Further details are provided in note 10 to the condensed financial statements.

 

Cash flow

Cash flow from operating activities amounted to US$222.1 million (2009: US$113.4 million), more than covering capital expenditure in the period of US$212.4 million (2009: US$111.2 million).

 

Capital expenditure (US$ million)

	2010 Half year	2009 Half year
Fields/developments	142.4	68.5
Exploration	69.4	41.4
Other	0.6	1.3
Total	212.4	111.2

 

Development spend in the first half was focused primarily on the Chim Sáo and Gajah Baru projects in Vietnam and Indonesia respectively and is likely to accelerate in the second half as these two projects continue to make good progress towards first oil and gas in 2011.

 

Exploration spend in the first half was US$69.4 million and is expected to accelerate in the second half as we return to drilling in South East Asia and follow-up on the Catcher successes in the UK.

 

Balance sheet

Net debt at 30 June 2010 was US$335.7 million (2009: US$254.1 million) including cash resources of US$449.1 million (2009: US$193.5 million).

 

Net debt (US$ million)

	2010 Half year	2009 Half year
Cash and cash equivalents	449.1	193.5
Convertible bonds*	(216.7)	(209.6)
Other long-term debt**	(568.1)	(238.0)
Net debt***	(335.7)	(254.1)

 

*	Excluding unamortised issue costs and allocation to equity.
**	Excluding unamortised issue costs.
***	Excluding US$64.6 million of cash held in an abandonment trust which has been classified in the balance sheet under trade and other receivables.

 

Long-term borrowings are made up of convertible bonds and bank debt. The bonds have a par value of US$250 million and a final maturity date of 27 June 2014. They carry a conversion price of £13.56 per share. Additional credit facilities of US$300 million were put in place on 30 April 2010. This additional borrowing has a five-year maturity and carries a fixed interest rate of 5.19 per cent. At 30 June, undrawn credit facilities with banks were US$404 million.

 

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. At 30 June 2010 the group had 6.7 million barrels of Dated Brent oil hedged with collars at an average floor price of US$48.29/bbl and an average cap of US$84.89/bbl covering the period to the end of 2012. An additional 700,000 barrels of oil are covered under swap arrangements at an average forward price of US$75.63/bbl for the second half of 2010. No changes have been made to the group's hedging position in Singapore 180 HSFO, which underlies the pricing mechanism for gas sold into the Singapore market. A total of 342,000 metric tonnes have been hedged to the period ending mid-year 2013 with a floor of US$250 per metric tonne (mt) and a cap of US$500/mt.

 

Premier operates and reports in US dollars. Foreign exchange exposure therefore relates only to certain sterling and other local currency expenditures. These exposures are covered by the purchase of local currency on a spot or short-term forward basis. The average sterling/dollar rate achieved for transactions maturing in the first half of 2010 was US$1.553: £1. Forward foreign exchange contracts outstanding at 30 June had a mark to market valuation loss in the period of US$0.2 million.

 

Premier seeks to maintain a balance of fixed and floating rate exposure to interest rate fluctuations within its debt portfolio. At 30 June, 85 per cent of the group total debt of US$784.8 million was denominated in fixed rate instruments, or locked into fixed rate costs using the interest rate swap market. Mark to market valuations of such interest rate swaps showed a movement of US$11.8 million for the period which, under hedge accounting rules, is recorded as an adjustment to equity reserves.

 

There have been no material changes to, or material transactions with, related parties as described in note 24 of the Annual Report and Financial Statements for the year ended 31 December 2009.

 

Going concern

The group monitors its capital position and its liquidity risk regularly throughout the year to ensure that it has sufficient funds to meet forecast cash requirements. Sensitivities are run to reflect latest expectations of expenditures, forecast oil and gas prices and other negative economic scenarios to manage the risk of funds shortfalls or covenant breaches and to ensure the group's ability to continue as a going concern.

 

After making enquiries and in light of the group's available loan facilities, the group budget for 2010 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 financial statements has therefore been 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.

 

A summary of the principal risks facing the company and the way in which these risks are mitigated is provided on pages 32 and 33 of the 2009 Annual Report and Financial Statements.

 

 

STATEMENT OF DIRECTORS' RESPONSIBILITIES

 

The directors confirm that, to the best of their knowledge the attached condensed financial statements have 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

Chief Executive Finance Director

 

25 August 2010

 

 

Disclaimer

This statement contains certain forward-looking statements that are subject to the usual risk factors and uncertainties associated with the oil and gas exploration and production business. Whilst the group believes the expectations reflected herein to be reasonable in light of the information available to it at this time, the actual outcome may be materially different owing to factors beyond the group's control or otherwise within the group's control but where, for example, the group decides on a change of plan or strategy. Accordingly, no reliance may be placed on the figures contained in such forward-looking statements.

 

 

CONDENSED CONSOLIDATED INCOME STATEMENT

 

		Six months to 30 June 2010  Unaudited	Six months  to 30 June 2009 (restated*)  Unaudited	Year to 31 December 2009
	Note	$ million	$ million	$ million
Sales revenues	2	366.8	213.9	621.1
Cost of sales	3	(188.7)	(116.4)	(361.4)
Exploration expense		(34.6)	(18.5)	(57.0)
Pre-licence exploration costs		(11.0)	(6.7)	(20.3)
Acquisition of subsidiaries		-	5.6	5.6
General and administration costs		(8.8)	(6.7)	(18.3)
Operating profit		123.7	71.2	169.7
Interest revenue, finance and other gains	4	1.3	9.0	15.7
Finance costs and other finance expenses	4	(33.9)	(17.0)	(44.4)
Mark to market revaluation of commodity hedges		20.5	(44.2)	(61.1)
Profit before tax		111.6	19.0	79.9
Tax		(49.6)	(46.3)	33.1
Profit/(loss) for the period/year		62.0	(27.3)	113.0
Earnings/(loss) per share (cents):
Basic	5	53.6	(26.7)	104.1
Diluted	5	51.4	(26.7)	103.9

 

 

 

CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME AND EXPENSE

 

	Six months to 30 June 2010  Unaudited	Six months to 30 June 2009 (restated*) Unaudited	Year to 31 December 2009
	$ million	$ million	$ million
Profit/(loss) for the period/year	62.0	(27.3)	113.0
Cash flow hedges - gains/(losses) arising during the period/year:
On commodity swaps	9.8	(19.6)	(9.8)
On interest rate swaps	(11.8)	-	(0.8)
Exchange differences on translation of foreign operations	(10.3)	3.7	8.7
Actuarial losses on long-term employee benefit plans	-	-	(3.5)
Total comprehensive income/(expense) for the period/year	49.7	(43.2)	107.6

 

* Details of the restatement are given in note 10.

 

 

 

CONDENSED CONSOLIDATED BALANCE SHEET

 

		At 30 June 2010  Unaudited	At 30 June 2009 (restated*) Unaudited	At 31 December 2009
	Note	$ million	$ million	$ million
Non-current assets:
Intangible exploration and evaluation assets	6	249.2	195.7	231.6
Property, plant and equipment	7	1,547.3	1,239.3	1,386.0
Deferred tax asset		166.5	130.7	190.6
		1,963.0	1,565.7	1,808.2
Current assets:
Inventories		24.2	37.1	35.3
Trade and other receivables		414.1	454.8	445.7
Cash and cash equivalents		449.1	193.5	250.6
		887.4	685.4	731.6
Total assets		2,850.4	2,251.1	2,539.8
Current liabilities:
Trade and other payables		(406.2)	(428.0)	(419.7)
Current tax payable		(57.5)	(80.1)	(46.5)
		(463.7)	(508.1)	(466.2)
Net current assets		423.7	177.3	265.4
Non-current liabilities:
Convertible bonds		(214.0)	(206.3)	(210.1)
Other long-term debt		(553.8)	(219.9)	(337.2)
Deferred tax liabilities		(174.5)	(186.9)	(179.8)
Long-term provisions		(345.4)	(291.2)	(307.6)
Long-term employee benefit plan deficit		(14.6)	(7.8)	(13.5)
Deferred revenue	8	(46.9)	(29.5)	(54.1)
		(1,349.2)	(941.6)	(1,102.3)
Total liabilities		(1,812.9)	(1,449.7)	(1,568.5)
Net assets		1,037.5	801.4	971.3
Equity and reserves:
Share capital		98.3	97.0	97.0
Share premium account		254.7	223.6	223.7
Retained earnings		650.8	435.0	603.2
Capital redemption reserve		4.3	4.3	4.3
Translation reserves		(3.2)	2.1	7.1
Equity reserve		32.6	39.4	36.0
		1,037.5	801.4	971.3

 

* Details of the restatement are given in note 10.

 

 

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 2009	73.6	9.7	472.9	1.7	(1.6)	42.6	598.9
Issue of Ordinary Shares	26.0	226.2	-	-	-	-	252.2
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	-	-	27.3	-	-	-	27.3
Transfer between reserves*	-	-	6.6	-	-	(6.6)	-
Total comprehensive income	-	-	98.9	-	8.7	-	107.6
At 31 December 2009	97.0	223.7	603.2	4.3	7.1	36.0	971.3
Issue of Ordinary Shares	1.3	31.0	(32.1)	-	-	-	0.2
Purchase of shares for ESOP Trust	-	-	(11.8)	-	-	-	(11.8)
Provision for share-based payments	-	-	28.1	-	-	-	28.1
Transfer between reserves*	-	-	3.4	-	-	(3.4)	-
Total comprehensive income	-	-	60.0	-	(10.3)	-	49.7
At 30 June 2010	98.3	254.7	650.8	4.3	(3.2)	32.6	1,037.5
At 1 January 2009	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 expense (restated)	-	-	(46.9)	-	3.7	-	(43.2)
At 30 June 2009 (restated)	97.0	223.6	435.0	4.3	2.1	39.4	801.4

 

*	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 2010 Unaudited	Six months to 30 June 2009 Unaudited	Year to 31 December 2009
	Note	$ million	$ million	$ million
Net cash from operating activities	9	222.1	113.4	347.7
Investing activities:
Capital expenditure		(212.4)	(111.2)	(303.1)
Pre-licence exploration costs		(11.0)	(6.7)	(20.3)
Acquisition of subsidiaries		-	(574.1)	(574.2)
Acquisition of oil and gas properties		-	-	(83.9)
Proceeds from disposal of oil and gas properties		20.4	-	14.8
Net cash used in investing activities		(203.0)	(692.0)	(966.7)
Financing activities:
Issue of Ordinary Shares		0.2	252.1	252.2
Expenses of issue of Ordinary Shares		-	(12.2)	(12.2)
Purchase of shares for ESOP Trust		(11.8)	(2.5)	(2.5)
Loan drawdowns		305.1	238.0	353.0
Debt arrangement fees		(3.9)	(19.9)	(25.6)
Repayment of long-term financing		(90.0)	-	-
Interest paid		(18.8)	(6.1)	(21.2)
Net cash from financing activities		180.8	449.4	543.7
Currency translation differences relating to cash and cash equivalents		(1.4)	(1.0)	2.2
Net increase/(decrease) in cash and cash equivalents		198.5	(130.2)	(73.1)
Cash and cash equivalents at the beginning of the period/year		250.6	323.7	323.7
Cash and cash equivalents at the end of the period/year	9	449.1	193.5	250.6

 

 

 

 

NOTES TO THE CONDENSED 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 financial statements for the six months ended 30 June 2010 were authorised for issue in accordance with a resolution of the Board of Directors on 25 August 2010.

 

The information for the year ended 31 December 2009 contained within the condensed financial statements does not constitute statutory accounts within the meaning of section 434 of the Companies Act 2006. Statutory accounts for the year ended 31 December 2009 were approved by the Board of Directors on 24 March 2010 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 498(2) or 498(3) of the Companies Act 2006.

 

The financial information contained in this report is unaudited. The condensed consolidated income statement, condensed consolidated statement of comprehensive income and expense, condensed consolidated statement of changes in equity and the condensed consolidated cash flow statement for the six months to 30 June 2010, and the condensed consolidated balance sheet as at 30 June 2010 and related notes, have been reviewed by the auditors and their report to the company is attached.

 

Basis of preparation

The condensed financial statements for the six months ended 30 June 2010 have been prepared in accordance with IAS 34 - 'Interim Financial Reporting', as endorsed by the European Union and with the requirements of the Disclosure and Transparency Rules issued by the Financial Services Authority. These condensed financial statements should be read in conjunction with the annual financial statements for the year ended 31 December 2009, which have been prepared in accordance with International Financial Reporting Standards as endorsed by the European Union.

 

The condensed financial statements have been prepared on a going concern basis. Further information relating to the going concern assumption is provided in the Financial Review.

 

In the prior year the company completed the acquisition of the entire issued share capital of Oilexco North Sea Limited (ONSL) and its wholly-owned subsidiary Oilexco North Sea Exploration Limited (ONSEL) for a consideration of US$574.2 million. The provisional fair values of the identifiable assets and liabilities presented in the group's 2009 half yearly results were reassessed in the second half of 2009 in order to reflect additional information that became available concerning conditions which existed at the date of acquisition, in accordance with the provisions of IFRS 3 - 'Business Combinations'. The corresponding amounts for the June 2009 comparative period have been restated accordingly.

 

Further details of the restatement are provided in note 10.

 

Accounting policies

The accounting policies applied in these condensed financial statements are consistent with those of the annual financial statements for the year ended 31 December 2009, as described in those annual financial statements, with the exception of standards, amendments and interpretations effective in 2010, as detailed below.

 

Standards, amendments and interpretations effective in 2010

The following standards and amendments to existing standards were mandatory for the financial year beginning 1 January 2010.

 

IFRS 3 (revised) - 'Business Combinations' introduces significant changes in the accounting for business combinations occurring on or after 1 January 2010 and IAS 27 (revised) - 'Consolidated and Separate Financial Statements' introduces requirements with regard to accounting for transactions with minority interests. There was no requirement to restate previous business combinations, and there have been no transactions with minority interests, so therefore there has been no material impact on the group's half yearly results on the adoption of these revised standards.

 

A number of other amendments to existing standards and interpretations were also effective for the current period, the adoption of which did not have a material impact on the group's half yearly results.

 

 

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 2010 Unaudited	Six months to 30 June 2009 (restated) Unaudited	Year to 31 December 2009
	$ million	$ million	$ million
Revenue:
North Sea and West Africa	217.5	89.5	351.7
Asia (destination Singapore)	90.0	57.0	146.4
Middle East-Pakistan	59.3	67.4	123.0
Total group sales revenue	366.8	213.9	621.1
Interest and other finance revenue	1.3	1.1	2.2
Total group revenue	368.1	215.0	623.3

 

Group operating profit/(loss):
North Sea and West Africa	48.6	(4.3)	31.4
Asia	41.8	36.2	75.9
Middle East-Pakistan	39.7	44.8	76.5
Unallocated*	(6.4)	(5.5)	(14.1)
Group operating profit	123.7	71.2	169.7
Interest revenue, finance and other gains	1.3	9.0	15.7
Finance costs and other finance expenses	(33.9)	(17.0)	(44.4)
Mark to market revaluation of commodity hedges	20.5	(44.2)	(61.1)
Profit before tax	111.6	19.0	79.9
Tax	(49.6)	(46.3)	33.1
Profit/(loss) after tax	62.0	(27.3)	113.0

 

Balance sheet
Segment assets:
North Sea and West Africa	1,257.0	1,208.7	1,249.8
Asia	970.2	655.2	822.6
Middle East-Pakistan	136.6	160.1	135.9
Unallocated*	486.6	227.1	331.5
Total assets	2,850.4	2,251.1	2,539.8

 

 

*	Unallocated expenditure and assets include amounts of a corporate nature and not specifically attributable to a geographical segment. These items include cash and mark to market valuations of commodity hedges.

 

 

 

3. COST OF SALES

 

	Six months to 30 June 2010 Unaudited	Six months to 30 June 2009 (restated) Unaudited	Year to 31 December 2009
	$ million	$ million	$ million
Operating costs	108.7	58.9	196.7
Stock overlift/underlift movement	(21.8)	(42.4)	(31.1)
Royalties	6.3	8.4	15.0
Amortisation and depreciation of property, plant and equipment:
Oil and gas properties	94.5	68.2	155.2
Other fixed assets	1.0	0.6	1.6
Impairment of oil and gas properties	-	22.7	24.0
	188.7	116.4	361.4

 

 

4. INTEREST REVENUE AND FINANCE COSTS

 

	Six months to 30 June 2010 Unaudited	Six months to 30 June 2009 Unaudited	Year to 31 December 2009
	$ million	$ million	$ million
Interest revenue, finance and other gains:
Short-term deposits	0.5	1.1	1.6
Mark to market valuation of foreign exchange contracts	-	4.5	2.8
Profit on disposal of oil and gas properties	-	-	9.3
Others	0.8	-	0.6
Exchange differences	-	3.4	1.4
	1.3	9.0	15.7
Finance costs and other finance expenses:
Bank loans and overdrafts	(12.7)	(4.7)	(15.9)
Payable in respect of convertible bonds	(7.4)	(7.2)	(14.6)
Unwinding of discount on decommissioning provision	(7.1)	(2.8)	(8.7)
Long-term debt arrangement fees	(5.6)	(2.3)	(10.5)
Mark to market valuation of foreign exchange contracts	(0.2)	-	-
Others	(3.7)	-	(0.1)
Exchange differences	(2.5)	-	-
Gross finance costs and other finance expenses	(39.2)	(17.0)	(49.8)
Interest capitalised during the year	5.3	-	5.4
	(33.9)	(17.0)	(44.4)

 

 

5. EARNINGS/(LOSS) PER SHARE

 

The calculation of basic earnings/(loss) per share is based on the profit/(loss) after tax and on the weighted average number of Ordinary Shares in issue during the period.

 

Basic and diluted earnings/(loss) per share are calculated as follows:

	Profit/(loss) after tax Unaudited		Weighted average number of shares		Earnings/(loss) per share
	Six months to 30 June 2010	Six months to 30 June 2009 (restated)	Six months to 30 June 2010	Six months to 30 June 2009	Six months to 30 June 2010	Six months to 30 June 2009 (restated)
	$ million	$ million	million	million	cents	cents
Basic	62.0	(27.3)	115.6	102.4	53.6	(26.7)
Outstanding share options	-	-	5.0	*	*	*
Diluted	62.0	(27.3)	120.6	102.4	51.4	(26.7)

 

 

*

The inclusion of the outstanding share options in the 2010 calculation produces diluted earnings per share. The outstanding share options number includes any expected additional share issues due to future share-based payments. The outstanding share options have been excluded from the 2009 calculation as they are anti-dilutive. At 30 June 2010 9,337,340 (2009: 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 2010.

 

 

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 2010	123.9	107.7	-	231.6
Exchange movements	(9.2)	-	-	(9.2)
Additions during the period	56.5	4.7	0.2	61.4
Exploration expenditure written off	(34.5)	-	(0.1)	(34.6)
At 30 June 2010	136.7	112.4	0.1	249.2
At 30 June 2009	94.5	101.2	-	195.7

 

 

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 2010	1,161.8	729.4	193.5	13.5	2,098.2
Exchange movements	-	-	-	(0.7)	(0.7)
Additions during the period	67.8	174.2	14.5	0.6	257.1
At 30 June 2010	1,229.6	903.6	208.0	13.4	2,354.6
Amortisation and depreciation:
At 1 January 2010	430.4	160.8	113.1	7.9	712.2
Exchange movements	-	-	-	(0.4)	(0.4)
Charge for the period	69.9	15.5	9.1	1.0	95.5
At 30 June 2010	500.3	176.3	122.2	8.5	807.3
Net book value:
At 31 December 2009	731.4	568.6	80.4	5.6	1,386.0
At 30 June 2010	729.3	727.3	85.8	4.9	1,547.3
At 30 June 2009 (restated)	741.4	409.7	83.4	4.8	1,239.3

 

 

Other fixed assets include items such as leasehold improvements, motor vehicles and office equipment.

 

Amortisation and depreciation of 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 on an entitlement basis at the end of the period plus production in the period, on a field-by-field basis. Proved and probable reserves 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. FINANCIAL INSTRUMENTS

 

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 provide written principles on the use of financial derivatives.

 

It is group policy that all transactions involving derivatives must be directly related to the underlying business of the group. The group does not use derivative financial instruments for speculative exposures. Premier undertakes oil and gas price hedging periodically within Board limits to protect operating cash flow against weak prices.

 

Oil and gas hedging is undertaken with collar options, reverse collars, swaps and hedges embedded in long-term crude offtake agreements. The hedges embedded in long-term crude offtake agreements are not fair valued as they qualify for 'own use' exemption under IAS 39 - 'Financial Instruments: Recognition and Measurement'. Oil is hedged using Dated Brent oil price options. Indonesian gas is hedged using HSFO Singapore 180cst, which is the variable component of the gas price.

 

Oil

At 30 June 2010, the group had 6.7 million barrels of Dated Brent oil hedged with collars at an average floor price of US$48.29/bbl and an average cap of US$84.89/bbl, all of which were embedded through an offtake agreement to the end of 2012. An additional 700,000 barrels of oil are covered under swap arrangements at an average forward price of US$75.63/bbl for the second half of 2010. An unrealised fair value gain was calculated on the swaps for the period of US$9.8 million (2009: loss of 19.6 million) which has been recognised directly in equity reserves as the swaps are 100 per cent effective under hedge accounting rules.

 

The group also has oil collars with banks which are marked to market through profit or loss. Additionally the group was able to execute reverse collars with certain oil trading companies at strike prices identical to the bank collars. Like the bank collars, these reverse collars are derivatives that must be marked to market through profit or loss, and with equal and opposite fair values. They effectively offset each other resulting in no net impact on the income statement or balance sheet.

 

Indonesian gas

No changes have been made to the group's hedging position in Singapore 180 HSFO, which underlies the pricing mechanism for gas sold into the Singapore market. Approximately 342,000 metric tonnes (mt) of future production from the existing contract is hedged to the period ending mid-year 2013, with a floor of US$250/mt and a cap of US$500/mt.

 

Fair value of commodity collars and swaps

 

Asset/(liability)	Oil $ million	Gas $ million	Total $ million
At 1 January 2010	(107.3)	(29.8)	(137.1)
Cash settlement for 2009 swaps	15.0	-	15.0
Deduction against sales revenues	(1.2)	-	(1.2)
Credit to income statement for the period	44.3	12.4	56.7
Credit to equity reserves for the period	9.8	-	9.8
At 30 June 2010	(39.4)	(17.4)	(56.8)
At 30 June 2009	(74.2)	(18.2)	(92.4)

 

 

Fair value of commodity reverse collars

 

Asset/(liability)	Oil $ million	Gas $ million	Total $ million
At 1 January 2010	80.9	-	80.9
Charge to income statement for the period	(43.4)	-	(43.4)
At 30 June 2010	37.5	-	37.5
At 30 June 2009	33.6	-	33.6

 

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 and trade and other payables. The key variable which affects the fair value of the group's hedge instruments is market expectations about future commodity prices.

 

Deferred revenue

Deferred revenue of US$46.9 million has been created due to first-day gains arising from commodity reverse collars. This deferred revenue will be amortised over the life of each individual reverse collar arrangement. For the period ended 30 June 2010, a total of US$7.2 million (2009: US$4.2 million) was released to the income statement in respect of this deferred revenue.

 

Asset/(liability)	Oil $ million	Gas $ million	Total $ million
At 1 January 2010	(54.1)	-	(54.1)
Credit to income statement for the period	7.2	-	7.2
At 30 June 2010	(46.9)	-	(46.9)
At 30 June 2009	(29.5)	-	(29.5)

 

 

9. NOTES TO THE CONDENSED CONSOLIDATED CASH FLOW STATEMENT

 

 

	Six months to 30 June 2010 Unaudited	Six months to 30 June 2009 (restated) Unaudited	Year to 31 December 2009
	$ million	$ million	$ million
Profit before tax for the period/year	111.6	19.0	79.9
Adjustments for:
Depreciation, depletion, amortisation and impairment	95.5	91.5	180.8
Exploration expense	34.6	18.5	57.0
Pre-licence exploration costs	11.0	6.7	20.3
Acquisition of subsidiaries	-	(11.6)	(11.6)
Net operating charge for long-term employee benefit plans less contributions	-	-	0.2
Provision for share-based payments	28.1	8.3	27.3
Interest revenue and finance gains	(1.3)	(9.0)	(5.9)
Finance costs and other finance expenses	33.9	17.0	44.4
Mark to market revaluation of commodity hedges	(20.5)	44.2	61.1
Operating cash flows before movements in working capital	292.9	184.6	453.5
Decrease/(increase) in inventories	11.1	(12.1)	(10.3)
Decrease/(increase) in receivables	28.8	(36.1)	(10.8)
(Decrease)/increase in payables	(61.3)	4.4	(15.5)
Cash generated by operations	271.5	140.8	416.9
Income taxes paid	(50.8)	(29.1)	(71.5)
Interest income received	1.4	1.7	2.3
Net cash from operating activities	222.1	113.4	347.7

 

 

Analysis of changes in net (debt)/cash:

	Six months to 30 June 2010 Unaudited	Six months to 30 June 2009 Unaudited	Year to 31 December 2009
	$ million	$ million	$ million
a) Reconciliation of net cash flow to movement in net (debt)/cash:
Movement in cash and cash equivalents	198.5	(130.2)	(73.1)
Proceeds from long-term loans	(305.1)	(238.0)	(353.0)
Repayment of long-term loans	90.0	-	-
Non-cash movements on debt and cash balances	(3.5)	(3.2)	(6.8)
Decrease in net cash in the period/year	(20.1)	(371.4)	(432.9)
Opening net (debt)/cash	(315.6)	117.3	117.3
Closing net debt	(335.7)	(254.1)	(315.6)

 

b) Analysis of net debt:
Cash and cash equivalents	449.1	193.5	250.6
Long-term debt*	(784.8)	(447.6)	(566.2)
Total net debt	(335.7)	(254.1)	(315.6)

 

 

*	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$2.7 million (2009: US$3.3 million) and debt arrangement fees of US$14.3 million (2009: US$18.1 million) respectively.

 

 

10. RESTATEMENT

 

In the prior year the group completed the acquisition of the entire issued share capital of Oilexco North Sea Limited (ONSL) and its wholly-owned subsidiary Oilexco North Sea Exploration Limited (ONSEL) for a consideration of US$574.2 million.

 

The transaction was accounted for by the purchase method of accounting with an effective date of 21 May 2009, being the date on which the group gained control of ONSL. Information in respect of the assets acquired was still being assessed at the time of announcement of the group's 2009 half yearly results and so the fair values of the identifiable assets and liabilities presented were provisional in nature.

 

These provisional fair values were reassessed in the second half of 2009 in order to reflect additional information which became available concerning conditions that existed at the date of acquisition, in accordance with the provisions of IFRS 3 - 'Business Combinations'. The final fair values were presented in the group's Annual Report and Financial Statements for the year ended 31 December 2009. The corresponding amounts for the half year 2009 comparative period have been restated accordingly.

 

The principal adjustments were a reduction in the carrying value of the Shelley field in oil and gas properties, recognition of additional pre-acquisition receivables and inventories acquired on completion. This in turn has reduced the charge for amortisation and depreciation of oil and gas properties and increased the charge for deferred tax for the period. These changes reduced the fair value of the net assets acquired over the purchase consideration, thereby reducing the credit to the income statement in respect of the acquisition of subsidiaries.

 

The effect of these changes on the June 2009 comparative information is detailed below:

 

 

Restatement of June 2009 comparatives: Income statement

 

	Six months to 30 June 2009 as originally reported	Adjustment	Six months to 30 June 2009 as restated
	$ million	$ million	$ million
Sales revenues	213.9	-	213.9
Cost of sales	(117.5)	1.1	(116.4)
Exploration expense	(18.5)	-	(18.5)
Pre-licence exploration costs	(6.7)	-	(6.7)
Acquisition of subsidiaries	60.3	(54.7)	5.6
General and administration costs	(6.7)	-	(6.7)
Operating profit	124.8	(53.6)	71.2
Interest revenue, finance and other gains	9.0	-	9.0
Finance costs and other finance expenses	(17.0)	-	(17.0)
Mark to market revaluation of commodity hedges	(44.2)	-	(44.2)
Profit before tax	72.6	(53.6)	19.0
Tax	(45.7)	(0.6)	(46.3)
Profit/(loss) for the period	26.9	(54.2)	(27.3)

 

 

Restatement of June 2009 comparatives: Balance sheet

 

	At 30 June 2009 as originally reported	Adjustment	At 30 June 2009 as restated
	$ million	$ million	$ million
Non-current assets:
Intangible exploration and evaluation assets	195.7	-	195.7
Property, plant and equipment	1,320.7	(81.4)	1,239.3
Deferred tax asset	137.0	(6.3)	130.7
	1,653.4	(87.7)	1,565.7
Current assets:
Inventories	26.7	10.4	37.1
Trade and other receivables	443.0	11.8	454.8
Cash and cash equivalents	193.5	-	193.5
	663.2	22.2	685.4
Total assets	2,316.6	(65.5)	2,251.1
Current liabilities:
Trade and other payables	(427.9)	(0.1)	(428.0)
Current tax payable	(80.1)	-	(80.1)
	(508.0)	(0.1)	(508.1)
Net current assets	155.2	22.1	177.3
Non-current liabilities:
Convertible bonds	(206.3)	-	(206.3)
Other long-term debt	(219.9)	-	(219.9)
Deferred tax liabilities	(186.9)	-	(186.9)
Long-term provisions	(302.6)	11.4	(291.2)
Long-term employee benefit plan deficit	(7.8)	-	(7.8)
Deferred revenue	(29.5)	-	(29.5)
	(953.0)	11.4	(941.6)
Total liabilities	(1,461.0)	11.3	(1,449.7)
Net assets	855.6	(54.2)	801.4
Equity and reserves:
Share capital	97.0	-	97.0
Share premium account	223.6	-	223.6
Retained earnings	489.2	(54.2)	435.0
Capital redemption reserve	4.3	-	4.3
Translation reserves	2.1	-	2.1
Equity reserve	39.4	-	39.4
	855.6	(54.2)	801.4

 

 

The above changes are reflected in the June 2009 comparatives throughout the condensed financial statements.

 

11. DIVIDENDS

 

No interim dividend is proposed (2009: US$nil).

 

 

 

INDEPENDENT REVIEW REPORT TO PREMIER OIL PLC

 

We have been engaged by the company to review the condensed financial statements in the half yearly financial report for the six months ended 30 June 2010 which comprise the condensed consolidated income statement, the condensed consolidated statement of comprehensive income and expense, the condensed consolidated balance sheet, the condensed consolidated statement of changes in equity, the condensed consolidated cash flow statement and related notes 1 to 11. 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 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 financial statements included in this half yearly financial report have 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 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 financial statements in the half yearly financial report for the six months ended 30 June 2010 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, UK

25 August 2010

 

WORKING INTEREST PRODUCTION BY REGION

 

	Six months to 30 June  2010	Full year 2009
	kboepd	kboepd
North Sea and West Africa
UK:
Balmoral area1	8.6	5.0
Kyle	2.4	2.7
Scott/Telford	4.0	3.3
Shelley	1.3	2.0
Wytch Farm	2.6	2.8
Other UK	0.5	0.4
	19.4	16.2
West Africa:
Chinguetti (Mauritania)	0.7	0.9
	0.7	0.9
Asia
Indonesia:
Anoa	8.9	8.8
Kakap	2.4	2.3
	11.3	11.1
Middle East-Pakistan
Pakistan:
Bhit/Badhra	3.6	3.4
Kadanwari	1.3	1.2
Qadirpur	3.6	4.2
Zamzama	6.7	6.9
	15.2	15.7
Egypt:
Al Amir	-	0.3
	-	0.3
Total	46.6	44.2

 

1 Includes Brenda, Nicol, Glamis and Stirling fields.

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