Annual Results

RNS Number : 1531J

Premier Oil PLC

25 March 2010

 

Press Release  

Annual Results for the year ended 31 December 2009

 

Premier is a leading FTSE 250 independent exploration and production company with oil and gas interests in the North Sea, South East Asia and in the Middle East-Pakistan regions. Our strategy is to add significant value for shareholders through exploration and appraisal success, astute commercial deals and optimal asset management.

 

Highlights

 

Operational

·; Production increased by 21 per cent to 44.2 kboepd (2008: 36.5 kboepd)

·; Reserves increased by 12 per cent to 255 mmboe (2008: 228 mmboe). Reserves and resources increased to 468 mmboe (2008: 382 mmboe) an increase of 23 per cent

·; Acquisitions completed in UK and Vietnam now successfully integrated and outperforming expectations

·; Ongoing material progress on the Chim Sáo and Gajah Baru development projects with first oil and gas on schedule for 2011

·; Five out of nine exploration and appraisal wells drilled were successful, including important discoveries in Norway and Vietnam

 

Financial

·; Record profit after tax of US$113.0 million (2008: US$98.3 million), including effects of tax allowances acquired with Oilexco

·; Operating cash flow of US$347.7 million (2008: US$352.3 million), despite a 37 per cent fall in Brent oil price year-on-year

·; Financing in place to fund current development and exploration programme. Debt facilities expanded and maturities extended

·; Pro forma net debt at 2009 year-end, including cash held in escrow of US$70 million, was US$245.4 million (2008: US$117.3 million - net cash). Cash on hand and in escrow and undrawn bank facilities were US$649 million at year-end (2008: US$599 million)

 

2010 Outlook

·; Stable production levels from existing assets year-on-year, on track to meet medium-term production target of 75 kboepd

·; Construction phase of Gajah Baru and Chim Sáo progressing well. Chim Sáo jacket scheduled for load-out shortly. Development drilling to commence later this year on both projects, scheduled for 2011 first oil and gas

·; Final development sanction for North Sumatra Block A and Huntington projects expected during the year with first oil and gas in 2012 or earlier

·; Work on pre-development portfolio is focused on Bream, Bugle and Frøy all of which are targeting 2013 first oil

·; 12 exploration and appraisal wells planned for 2010 programme focused on North Sea and South East Asia; encouraging start to 2010 exploration with the Blåbaer oil discovery in Norway

 

"2009 was a year of important acquisitions, increasing production, great strides in our development projects and successful exploration drilling. We have a busy and exciting programme of activity planned for 2010 which will continue to build on our three growing regional businesses."

 

 

Mike Welton, Chairman Simon Lockett, Chief Executive

25 March 2010

 

ENQUIRIES
Premier Oil plc	Tel: 020 7730 1111
Simon Lockett
Tony Durrant
Pelham Bell Pottinger
James Henderson	Tel: 020 7337 1501 / 07774 444 163
Gavin Davis	Tel: 020 7337 1515 / 07910 104 660

 

 

A presentation to analysts and investors will be held at 10.30am today at the offices of Premier Oil, 23 Lower Belgrave Street, London SW1W 0NR. A live webcast of this presentation will be available via Premier's website at www.premier-oil.com.

 

CHAIRMAN'S STATEMENT

 

"Premier Oil offers material and profitable future growth for shareholders through a reliable and long-life production base, good quality projects under development and in the pre-development phase and an exciting exploration programme, in areas we know well."

 

Financial and operating performance

Despite low oil and gas prices in the early part of the year, increased production, supported by price recovery in the second half, generated sales revenues of US$621.1 million in 2009 (2008: US$655.2 million). Average production for the year rose 21 per cent to 44,200 barrels of oil equivalent per day (boepd) (2008: 36,500 boepd) taking into account both the Oilexco North Sea Ltd (Oilexco) acquisition and continuing strong demand in both Singapore and Pakistan for our gas production.

 

Operating cash flow after tax was US$347.7 million (2008: US$352.3 million) more than covering exploration and development investments of US$303.1 million (2008: US$217.3 million). Two significant acquisitions were completed during the year: Oilexco for US$505 million and Delek Energy (Vietnam) LLC for US$72 million. These were funded by a combination of new equity (US$252 million), an increase in bank borrowings and existing cash resources. As a result, pro forma net debt at year-end stood at US$245.4 million (2008: US$117.3 million - net cash).

 

Profits after tax were at record levels of US$113.0 million (2008: US$98.3 million) benefitting from the acquisition of significant UK tax allowances during the year. Operating profits for the year were US$169.7 million (2008: US$261.7 million).

 

Oil and gas proven and probable reserves increased to 255 million barrels of oil equivalent (mmboe) (2008: 228 mmboe). Contingent resources are 213 mmboe (2008: 154 mmboe), resulting in a 23 per cent increase in reserves and resources to 468 mmboe (2008: 382 mmboe). This included 60 mmboe acquired with the Oilexco acquisition in the UK.

 

Considerable progress was made in advancing our major development projects. The wellhead platforms for the Chim Sáo and Gajah Baru projects in Vietnam and Indonesia respectively are progressing well through their construction phases and the Chim Sáo jacket will begin moving to its offshore location shortly. Development drilling will commence later this year on both projects. Our first development project from the Oilexco portfolio, the UK Huntington field, is also progressing well. We have a number of North Sea projects, in both the UK and Norway, which are targeted for development approval during 2010.

 

Our exploration programme in 2009 delivered five successes from nine exploration and appraisal wells. Notably, this included two successes drilled from our first two wells in Norway and the Cá Rồng Đỏ discovery in Vietnam, which opens up a large and unexplored area on the Vietnamese/Indonesian border. A series of successful wells on the NW Gemsa permit in Egypt led to a profitable exit through a sale of our 10 per cent interest in the block. Our programme of wells in Norway and in South East Asia continues in 2010.

 

Our efforts to maintain the highest levels of health, safety and environmental performance have continued, as supported by our industry leading statistics. In the International Association of Oil and Gas Producers' safety performance indicators report, Premier's drilling function was ranked number one across the industry for the lowest total recordable injury frequency. We were also ranked in the top quartile for production operations. We have retained our inclusion in the FTSE4Good Index.

 

Shareholder returns

Despite the significant volatility in equity markets and in the price of oil, Premier's share price increased by 12 per cent during the year, after adjusting for the rights issue completed in May. Over the five‑year period to 31 December 2009, Premier's share price has increased by 109 per cent.

 

Board change

I was delighted to take over Chairmanship of your company with effect from 15 October 2009. I would like to pay tribute to the achievements and leadership of Sir David John, who retired after 11 years as Chairman of the company. Premier is extremely well positioned to grow its production base, engage in further development projects and add material reserves through exploration. The quality and potential of its asset position is a tribute to the hard work of my predecessor and the high calibre team here at Premier

 

Mike Welton

Chairman

 

CHIEF EXECUTIVE'S REVIEW

Group strategy

Five years ago, the then new management team established a number of strategic objectives for future growth of the business:

§ Increasing our production from 33 kboepd (2005) to 50 kboepd;

§ Monetising previously discovered resources through commercial negotiation and field development;

§ Adding to the portfolio of development projects and discoveries through exploration success;

§ Seeking value-adding acquisitions in core areas; and

§ Creating strong regional businesses with full capability in production, development and exploration operations.

 

Over the subsequent five-year period, Premier has made significant strides in meeting all these objectives:

§ 2009 production averaged 44.2 kboepd, exceeding 50 kboepd in the second half of the year. Projects now under development are expected to add a further 25 kboepd by 2012;

§ Booked 2P reserves have increased by 45 per cent and reserves and resources have more than doubled over the five-year period;

§ Premier's Chim Sáo discoveries in Vietnam in 2006 and 2007 have been followed up with 2009 successes in Vietnam and Norway. Further drilling in Norway and Vietnam and other exploration targets in the UK and Indonesia are included in the 2010 programme;

§ Acquisitions in 2006/7 and in 2009, coinciding with periods of relatively low oil prices, have been completed successfully in the UK, Indonesia and Vietnam; and

§ The North Sea and South East Asia regional businesses are well-established. We are actively seeking opportunities to extend from our Pakistan business base across the Middle East region.

 

Building on the existing strategy, we expect significant further growth over the coming years:

§ A production target of 75 kboepd from existing projects by 2013;

§ The potential to add significant further production in the medium-term from projects currently within the pre-development portfolio;

§ An exploration programme, targeting reserve additions of 200 mmboe net to Premier, from existing geological areas of expertise; and

§ Acquisition and new venture activity which will provide future growth potential based on existing skills within the group.

 

We expect to maintain a conservative balance sheet through the investment cycle, facilitating our growth opportunities.

 

OPERATIONS REVIEW

 

Production, development and reserves

A strong increase in production was achieved in 2009, principally due to the acquisition of the Oilexco producing assets completed in May 2009. Significant progress on the development portfolio was also achieved with both Gajah Baru in Indonesia and Chim Sáo in Vietnam achieving final project approvals. Both projects are now in the construction phase with expected first oil and gas in 2011. Existing producing fields, together with new production from our development projects will keep the company on track to achieve our 75,000 boepd target in the medium-term.

 

In line with guidance, average working interest production for the full-year was 44.2 kboepd (2008: 36.5 kboepd) of which 7.4 kboepd came from the former Oilexco production portfolio acquired on 21 May 2009. Also in the UK, the Kyle and Wytch Farm fields performed strongly though the Scott field remained at 2008 levels, underperforming somewhat due to facilities issues. Production in other areas remained steady, as strong gas demand and good production performance were experienced in both Pakistan and Indonesia/Singapore.

 

Production (boepd)	Working interest		Entitlement
	2009	2008	2009	2008
Asia	11,050	11,700	7,300	7,100
Middle East-Pakistan	16,000	14,550	15,850	14,550
North Sea	16,200	9,300	16,200	9,300
West Africa	950	950	800	800
Total	44,200	36,500	40,150	31,750

 

In the wake of the global financial crisis and the significant fall in oil prices, cost levels in the industry also fell. The company achieved material development project cost reductions by optimising and retendering the Chim Sáo and Gajah Baru projects. Both these projects are now under construction with first production scheduled for 2011. Further progress on our North Sumatra Block A project in Indonesia could not be achieved because of a delay in the PSC extension. This is expected to be resolved shortly but has caused first gas to be delayed to 2012. Premier and its partners are working on a fast track solution to develop the Huntington field in the UK, a former Oilexco asset. FPSO tenders are being evaluated, alongside tie-back options to nearby infrastructure, with concept selection expected imminently followed by sanction in the third quarter of 2010. First oil is targeted for 2012. 

 

As at 31 December 2009 proven and probable reserves, on a working interest basis, based on Premier and operator estimates were 255 mmboe (2008: 228 mmboe). These reserves comprised 32 per cent liquids and 68 per cent gas. The equivalent volume on an entitlement basis amounted to 229 mmboe (2008: 198 mmboe) using a price assumption of US$75/bbl Brent (2008: US$60/bbl Brent).

 

Booked reserve additions were driven principally by the acquisitions of Oilexco and Delek during the year. Contingent resources at year-end increased by 59 mmboe to 213 mmboe (2008: 154 mmboe) driven by resources within the acquired portfolios and by new resources added with the discoveries at Grosbeak in Norway and Cá Rồng Đỏ in Vietnam.

 

	Proven and probable reserves (mmboe)	2P reserves and 2C contingent resources (mmboe)
Start of 2009	228	382
Production	(16)	(16)
Net additions and revisions	43	102
End of 2009	255	468

 

Asia

In South East Asia, we are seeking to develop the full potential of our Natuna Sea and North Sumatra gas positions in Indonesia and our growing presence in the Nam Con Son Basin in Vietnam. Our well established presence in the region allows us to bring relationships, knowledge and technical skills to all business opportunities in the area.

 

Indonesia

During 2009, the Premier-operated Natuna Sea Block A in Indonesia sold an overall average of 153 billion British thermal units per day (BBtud) (gross) from its gas export facility (up 8 per cent on 2008), whilst the non-operated Kakap Block contributed a further 42 BBtud (gross). Liquids production from the Block A Anoa field averaged 1,920 barrels of oil per day (bopd) (gross) and the Kakap fields 3,540 bopd (gross). Overall, net production from Indonesia amounted to 11,050 boepd (2008: 11,700 boepd) on a working interest basis.

 

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 Engineering, Procurement, Construction and Installation (EPCI) contract was completed on 16 March 2009 with resultant gross costs savings of approximately US$100 million. Total capital expenditure for the Gajah Baru project is forecast at around US$700 million (gross). Maximum routine gas sales will be in the order of 140 million standard cubic feet per day (mmscfd) and recoverable reserves from the three new fields are expected to be 500 billion cubic feet (bcf). Fabrication of both the wellhead platform jacket and deck continue in Batam. The project was 33 per cent complete at year-end for the construction phase, slightly ahead of schedule. Development well drilling is scheduled to commence in October 2010 and the project remains on track to deliver first gas on schedule in October 2011.

 

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, Front End Engineering Design (FEED) studies were completed in 2009 and work continues on optimising the project prior to EPCI bids. Negotiation of fully termed agreements for use of ExxonMobil facilities for transportation of gas and liquids continued. However, the Ministerial Decree relating to the PSC extension remains unsigned; the delay is impacting the project schedule with first gas scheduled for 2012 from Alur Rambong and 2013 from Alur Siwah.

 

Vietnam

Substantial progress was made during the year with the Chim Sáo development. The lower oil prices at the end of 2008 prompted a review of the Chim Sáo project in which the well design and producing facilities were optimised lowering capital expenditure estimates and a new Floating Production, Storage and Offtake vessel (FPSO) supply contract was negotiated. The re-designed project has all the necessary partner and government approvals and the prime contracts for EPCI, FPSO and the drilling rig have been executed. At year-end, the Chim Sáo platform jacket was 83 per cent complete and its topsides 51 per cent complete, on schedule to allow the main facilities to be installed in summer 2010. Work on the conversion of the Lewek Emas into an FPSO commenced in the Keppel shipyard. Development drilling is expected to start in mid-2010 and the FPSO to be installed in the second quarter of 2011. First oil production is forecast for mid-2011. Project costs are in line with budget.

 

PetroVietnam Exploration Production Corporation (PVEP) exercised its back-in right for 15 per cent equity in Block 12W in April 2009. Premier increased its interest in the block to 53.125 per cent through the acquisition of Delek Energy (Vietnam) LLC which completed in July 2009.

 

India

No progress has been made in 2009 with the Government of India in signing the Ratna licence. Premier will close its representative office in Delhi in 2010.

 

 

North Sea and West Africa

The acquisition of Oilexco in May 2009 significantly increased Premier's presence in the North Sea, adding some 60 mmboe of reserves and resources and a capable operating team in the UK. The acquired assets have been integrated with our existing UK portfolio and are managed from the new Premier office in Aberdeen, opened in December. Premier's office in Stavanger in Norway continues to focus on the current Norwegian exploration programme and the integration of our significant technical database across the North Sea. The North Sea business unit also manages our remaining assets in West Africa.

 

UK

Total North Sea production was 16,200 boepd for 2009 (2008: 9,300 boepd), of which 7,400 boepd was generated by the acquired Oilexco portfolio. This represents production from the acquisition completion date of 21 May 2009, averaged over the full year.

 

There has been a strong underlying performance from Wytch Farm and Kyle, both of which performed ahead of expectations in 2009. The Wytch Farm oil field contributed 2,770 boepd net production to Premier, representing a 7 per cent reduction on last year but still producing ahead of expectations. The operator has temporarily suspended further drilling on Wytch Farm while the inventory of future drilling targets is upgraded. It is anticipated that investment in drilling will resume in early 2011. Production from Kyle was 2,660 boepd (2008: 2,500 boepd) without significant field investment during 2009.

 

The Scott field produced 3,240 boepd (2008: 3,525 boepd) under-performing expectations as a result of both facilities issues and the failure of the first of the four well infill programme. Two of the successful infill wells produced relatively high levels of hydrogen sulphide H2S and at the end of 2009 the operator was focusing on the management of H2S levels.

 

In the area surrounding the Scott field, Premier is co-operating with other interest owners to progress the development of a series of discoveries over the Scott facility. The partners in Bugle agreed to drill an appraisal well which was spudded in February 2010. Premier will have a 50 per cent equity share in Block 15/23d which contains the original Bugle discovery. The cost of the well is shared equally with the participants in the neighbouring Block 15/23c. If successful, the Bugle field will be tied back to Scott along with the smaller Blackhorse discovery.

 

Premier took control of the Balmoral Floating Production Vessel (FPV) following the Oilexco acquisition, and as a result of detailed analysis three key risers were replaced during the annual shut-down period, as part of a longer-term replacement programme which will be completed in 2011.

 

Further work was carried out on the Balmoral platform to increase the capacity of the gas lift, power generation and water handling systems. The Burghley field will be tied into these facilities in the third quarter. Premier is working on a Balmoral field infill opportunity that will be matured in 2010.

 

Following the acquisition of the Oilexco portfolio, Premier successfully negotiated a new contract with Sevan Marine ASA pertaining to the Shelley field. The Sevan Voyageur FPSO was hooked up to the field and commenced production on 6 August at an initial rate of 11,000 boepd. At year-end the rate had dropped to around 2,200 boepd. It is anticipated that the field abandonment will commence in 2010.

 

On the Huntington development project, FPSO bids were received in December and are currently being evaluated along with tie backs to infrastructure in the vicinity. It is expected that the development concept will be selected imminently, with project sanction occurring before year-end 2010. It is anticipated that Premier will hold the dominant equity position in the field.

 

Norway

On the Frøy project in Norway, the joint venture pursued two new work programmes. The first was to re-evaluate the stand-alone development concept in the light of substantial changes in the contractor market which occurred as a result of the financial crisis in 2008 and the related drop in oil price and industry activity. This work indicated that a reduction in costs is feasible, and is now being pursued in the 2010 work programme. In parallel, the joint venture entered into an area co-operation study with Statoil and Total who also hold reserves in the area. This study was recently completed and may lead to further consideration of tie-back opportunities and potentially a joint project for Frøy with one or more other fields. Given successful outcomes of the work on either option, a project sanction decision could be taken in 2010 with first oil targeted for 2013.

 

Mauritania

In Mauritania, 2009 production from the Chinguetti field averaged 950 boepd net to Premier (2008: 950 boepd, net), higher than earlier expectations. The operator continues to assess production performance from the field.

 

The joint venture partnerships are currently in discussions with the Mauritanian Government to extend the existing PSCs covering the remaining potential in the area. In particular, the operator is undertaking gas development studies for the Banda and Tevet fields, including potential domestic gas markets, with the aim of concluding this work during 2010. The operator is also re‑evaluating the Tiof field development concept options.

 

Middle East-Pakistan

Our Middle-East Pakistan business unit seeks to maximise the value of our high quality Pakistan producing gas fields and to extend our technical skills to new regional opportunities, including with our regional joint venture partner, EIIC. The joint venture company, Premco, is based in Abu Dhabi.

 

Pakistan

Average production of 15,720 boepd in 2009 surpassed the previous record average production of 14,550 boepd in 2008 by 8 per cent. Gas demand in 2009 increased year-on-year and was met primarily from additional production capacity at the Zamzama and Bhit/Badhra fields. This was achieved through new infill wells, gas plant expansions and shorter maintenance periods.

 

The Qadirpur gas field produced an average of 4,150 boepd in 2009 (2008: 4,060 boepd). The project to enhance Qadirpur plant capacity was commissioned in January 2009 and has resulted in reduced maintenance downtime. A compression project was initiated in 2009 to mitigate the declining field deliverability. Completion is expected by August 2010. As scheduled, permeate gas of low heating value will be supplied to Sui Northern Gas Pipelines Ltd from February 2010, for utilisation at Engro's newly constructed power plant near Qadirpur. This supply of permeate gas will also reduce the quantity of gas flared at the Qadirpur field. Additional stand-by permeate compressors will be installed at Qadirpur during 2010, to ensure continuous supply of the permeate gas. During 2009, eight new production wells were successfully drilled and connected to the production system (including production from the SML horizon of the Qadirpur Deep-1 exploration well).

 

The Kadanwari gas field produced an average of 1,250 boepd in 2009 (2008: 1,225 boepd). The K-14B well was completed and tied into the system in 2009, helping to sustain field production levels in the year. As a result of successful negotiations with the government, the Kadanwari lease expiry date was extended for a further 10 years (to 2022), whilst capping the gas price at an equivalent price of US$8.50 per million British thermal units. The lease extension will now allow full exploitation of the discovered gas reserves. Two additional wells, K-19 and K-20, were also drilled during 2009. K‑19 has discovered new gas and came on-stream in March 2010 with an initial flow-rate of 22 mmscfd. K-20 did not initially flow due to tight reservoir properties but following fracturing has shown positive results.

 

The Zamzama gas field produced an average of 6,890 boepd in 2009 (2008: 6,075 boepd). After modifications, the Phase-2 plant was re-commissioned in March 2009 and achieved production of 127 mmscfd of High Calorific Value (HCV) gas. Further modifications were planned for November 2009 to increase the capacity to 150 mmscfd, but these have been deferred to April 2010, in order to maximise gas revenues during the high winter gas demand period. The Zamzama North well (commissioned in March 2009), as well as two infill wells drilled during the year, were tied into the production system, resulting in 13 per cent higher production in 2009 than in 2008.

 

The Bhit/Badhra gas fields produced an average of 3,430 boepd in 2009 (2008: 3,190 boepd). The increase was due to higher available plant capacity, as well as acceptance by the buyer of some sales gas at slightly less than specification, in order to satisfy their own commitments during the high gas demand in winter. The drilling of the Bhit-10 well in April 2009 and installation of wellhead compressors on some wells allowed field deliverability to be maintained at a high level. The Bado Jabal-1 (exploration well) did not encounter commercial gas in its primary targeted zones and was side-tracked to be completed as an additional producer in the Badhra gas field (from the existing Mughalkot reservoir). First gas was achieved in March 2010.

 

Front End Engineering Design (FEED) was completed in 2009 for the Zarghun South gas field development. First gas is scheduled for the fourth quarter of 2011. Substantially all of Premier's capital and operating costs for its 3.75 per cent working interest are carried by the operator.

 

Egypt

First oil was achieved at the end of February 2009 from two Al Amir SE wells on the NW Gemsa Licence in Egypt. This was followed by successful appraisal of the Al Amir SE area and the exploration discovery at Geyad on the same block. In total, the block produced an average of 2,880 bopd (gross) for the period to 23 December 2009. On this date, Premier completed the sale of its 10 per cent interest in the permit to Sea Dragon Energy Inc for a final consideration of US$14.8 million, recording a profit on sale of US$8.4 million.

 

EXPLORATION REVIEW

 

Exploration is a fundamental part of Premier's growth strategy with a target to add over 200 mmboe of net 2P reserves by 2015. The exploration strategy is to focus on areas and geological themes where Premier has demonstrable skills and expertise, namely the exploration of rift basins in South East Asia and the North Sea, and onshore fold-belt provinces, as exemplified by Premier's acreage in Pakistan and Eastern Indonesia.

 

In 2009, Premier participated in nine exploration and appraisal wells of which five were successful. Successes included the new oil and gas discoveries at Cá Rồng Đỏ (Vietnam) and Grosbeak (Norway), appraising the resource base in the Bream discovery (Norway), and step-out drilling adding reserves to the Kadanwari field (Pakistan).

 

Premier continues to acquire the best quality data sets in support of the exploration and appraisal drilling campaigns, and in 2009 acquired over 1,800km² of 3D to advance the interpretations in preparation for 2010/2011 drilling in Vietnam and Indonesia. The acquisition of Oilexco presented an opportunity to purchase 3D data sets across the UK Central North Sea which, when combined with the Premier data sets in Norway, have established a competitive seismic database across the whole of the Central North Sea (UK and Norway). In support of the longer-term growth ambitions, three new licences were acquired in the UK sector of the Central North Sea.

 

The 2009 exploration and appraisal programme delivered a contingent resource base of approximately 29 mmboe, subject to further appraisal, at an overall success rate of 55 per cent.  

 

Asia

Vietnam

Cá Rồng Đỏ (CRD), the first well drilled by Premier in Block 07/03, intersected approximately 90m net 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 gas, through a 48/64" choke, with no water production.

 

Premier acquired and processed 1,006km² 3D seismic over the eastern third of Block 07/03 to determine future exploration and appraisal activity. Premier's second exploration well Cá Rồng Vàng, located 6km from CRD, was drilled to a total depth of 3,980m BRT and intersected the reservoir intervals on prognosis. However, wireline logging indicated the well did not encounter significant hydrocarbons and the well was plugged and abandoned. The results of the wells are now being integrated with the 3D seismic to determine the best location to appraise CRD and to identify future exploration drilling targets for 2011 drilling.

 

During 2009, Pan Pacific Petroleum (Vietnam) Pty Ltd acquired 5 per cent and PVEP acquired 10 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 CRD well. Both transactions will require approval from the Government of Vietnam, which was requested in early 2010.

 

Elsewhere in Vietnam, the Block 12W exploration acreage outside the Chim Sáo and Dua field areas was surrendered in November 2009 at the end of the statutory exploration period, and planning started for the acquisition of 3D seismic data on Block 104-109/05 in 2010.

 

Indonesia

On the Premier-operated Tuna Block, plans have been updated following the success in Premier's Vietnam Block 07/03 immediately to the north in the Nam Con Son Basin. Following interpretation of the 2,400km 2D, an 850km2 3D seismic survey was acquired in September 2009. Interpretation of this survey is ongoing. Prospect selection will follow, ahead of drilling two exploration wells in 2010.

 

On Natuna Sea Block A, a five-year exploration plan has been developed for the block, and due to re-phasing of the nearby development drilling programme, the Anoa Deep exploration well will now be drilled in 2011.

 

Elsewhere, on the Japex-operated Buton Block, the 250km 2D seismic survey begun in 2008 was completed by mid-year. Prospect maturation is currently under way and a well is planned for the fourth quarter of 2010. On the Medco-operated North Sumatra Block A, further work to define prospects for drilling in 2011 is ongoing.

 

Premier continues to review opportunities to expand its acreage position in Indonesia and joint study activities under three agreements with Migas, the Indonesian government authority, in North Merak (offshore Java), East Asahan (onshore Sumatra) and East Bangkanai (onshore Kalimantan) were completed in 2009. The East Bangkanai review has justified follow-up work to be completed in early 2010.

 

Philippines

In the non-operated SC43 Licence, Premier relinquished its 21 per cent participating interest and withdrew from the licence at the end of 2009.

 

North Sea and West Africa

UK

The Oilexco acquisition significantly increased Premier's UK exploration portfolio to a total of 38 blocks. From this expanded portfolio, Premier plans to drill three exploration and appraisal wells in 2010. The Bugle North well is in licence P815, Block 15/23d, and spudded in February. Catcher is a Paleocene amplitude play in licence P1430 Block 28/9 and is due to spud in April. Premier is in advanced discussions with an interested party to farm down 15 per cent equity in Block 28/9 as part of ongoing portfolio management activity. Premier will retain 35 per cent equity in the licence.

 

In early 2010 Premier secured a 50 per cent equity and operatorship of Block 22/19c containing the Oates and Bowers prospects. Block 22/19c covers an extension of the prolific Paleocene Forties reservoir unit, 10km south of the Huntington development. A well on the Oates prospect will spud in June 2010.

 

Premier was awarded two further licences as part of the UK 25th Licence Round. The two licences awarded were P1628 Block 29/7b near the Kyle field and P1559 Block 15/23e, adjacent to the Scott/Telford production facilities. Block 29/7b contains the Paleocene prospects Gladius and Scutum, whilst Block 25/23e has the Upper Jurassic Cornet and Corniche prospects.

 

Premier is now looking to the UK 26th Licence Round, announced in February 2010, as an opportunity to grow the UK exploration portfolio for future drilling campaigns in 2011 and beyond.

 

Norway

In 2009, Premier participated in its first two exploration and appraisal wells in Norway, both of which were successful. The programme is continuing into 2010.

 

On PL407, operated by BG, an appraisal well on the Bream field was drilled and penetrated 18.5m net pay and tested at a maximum flow rate of 2,516 boepd. This has provided sufficient information for the joint venture to start development planning, and the concept screening phase was completed in 2009. A decision on commerciality and further progression of the project will be taken in 2010. On the nearby Premier-operated PL406 licence, preparations were advanced for the drilling of the Gardrofa prospect in the third quarter of 2010.

 

On the Wintershall operated PL378, a discovery was made at Grosbeak. The well encountered oil and gas pay in the Brent and Sognefjord Formations respectively. Preliminary recoverable volumes range from 25 to 190 mmboe. The Grosbeak discovery will be appraised in the fourth quarter of 2010, and an exploration well will be drilled to test the adjacent Gnatcatcher prospect.

 

Since year-end, a well on the Greater Luno prospect on PL359 encountered oil shows but has been plugged and abandoned as a non-commercial well. On PL374S, a well on the Blåbaer prospect proved oil in the Lower Jurassic reservoir rocks, which is being appraised with a sidetrack well. Premier continues to evaluate options to grow the exploration portfolio in Norway and the APA and Norway 21st Licence Rounds will be reviewed in 2010.

 

Congo

On the Premier-operated Marine IX Licence, the Frida exploration well was drilled to a target depth of 3,250m. Wireline logging indicated that the well did not encounter significant hydrocarbons, and the well was plugged and abandoned. In advance of the well, Premier reduced its equity in the block to 31.5 per cent and consequently reduced the net financial exposure in the well to US$8.4 million. The results of the Frida well are being incorporated into the existing 3D seismic database prior to deciding whether to enter the next exploration phase in the fourth quarter of 2010.

 

SADR

Premier awaits resolution of sovereignty issues before pursing exploration activities in this prospective area. The four SADR licences currently remain in force majeure.

 

Middle East-Pakistan

Pakistan

The K-19 exploration step-out well was drilled in the non-operated Kadanwari lease. The well encountered 12m of high quality net gas pay in the E-sand interval of the Lower Goru Formation. The E-sand interval tested gas at a maximum flow rate of 31 mmscfd at a flowing wellhead pressure of 3,743 psig with a 40/64" choke. The well has been tied into the system in March and is producing gas at a rate of 22 mmscfd.

 

The Bado Jabal-1 exploration well was drilled in 2009 in Area A of the Badhra Block, as a deepening to the Mughalkhot reservoir development well. This 5,000m deep well identified both Lower Goru and Chiltan target formations, but commercial quantities of gas were not encountered.

 

Since year-end, a well targeting the Pirkoh limestone in the Qadirpur licence has been drilled. It reached target depth in March and is being plugged and abandoned as a dry hole.

 

Egypt

In the non-operated NW Gemsa Licence, a well on the Geyad prospect in May encountered oil-bearing sands in the Kareem Formation and the field commenced production shortly thereafter. The Shehab-1 prospect on the same block was dry. Due to lack of materiality of the block to Premier as a whole, Premier's 10 per cent equity in the licence was sold for a consideration of US$14.8 million in December 2009.

 

Egypt continues to represent a target growth area for the company, and consistent with our focus on rift basin geology Premier successfully bid for the South Darag Block, in the Gulf of Suez, in the EGPC 2009 Bid Round. The block is in the process of being awarded to Premier subject to formal government approvals. A work commitment comprising seismic reprocessing, geological and geophysical studies will be carried out during the initial exploration period.

 

 

FINANCIAL REVIEW

 

Economic environment

The early part of 2009 was a turbulent period for the world economy, the global capital markets and for oil and gas prices. Brent oil prices opened the year at US$35/bbl but recovered quickly, peaking at US$79/bbl in December and averaging US$62/bbl for the year. The crisis in the financial services industry had more far-reaching consequences and access to capital for many smaller companies in the oil and gas sector remained challenging. Premier was able to take advantage of its strong balance sheet and continued access to capital to conclude successfully two material acquisitions during this period.

 

The sharp deterioration in the oil price environment during the second half of 2008 led to reduced levels of activity in the industry and downward pressure on exploration and development costs during 2009. Premier was able to capture the benefits of falling costs in rig rates and project construction costs, and cost levels have now stabilised.

 

Income statement

Production levels in 2009, on a working interest basis, averaged 44,200 boepd compared to 36,500 boepd in 2008, an increase of 21 per cent. On an entitlement basis, which under the terms of our PSCs allows for additional government take at higher oil prices, production was 40,150 boepd (2008: 31,750 boepd). Realised oil prices, before hedging, averaged US$66.3/bbl compared with US$94.5/bbl for 2008.

 

Gas production averaged 156 mmscfd (2008: 148 mmscfd) during the year or approximately 61 per cent of total production. Average gas prices for the group were US$5.18 per thousand standard cubic feet (mscf) (2008: US$6.57/mscf). Gas prices in Singapore, which are linked to High Sulphur Fuel Oil (HSFO) pricing, in turn closely linked to crude oil pricing, averaged US$11.0/mscf (2008: US$15.2/mscf) for the year.

 

Total sales revenue from all operations was US$621.1 million (2008: US$655.2 million) with higher production largely offsetting the decline in commodity prices. Cost of sales was US$361.4 million (2008: US$317.6 million). Unit operating costs were higher at US$12.2 per barrel of oil equivalent (boe) (2008: US$9.5/boe) reflecting the higher than average costs of production associated with the acquired assets in the UK North Sea.

 

Amortisation includes the effect of an impairment charge, as a result of a reserves downgrade, of US$24.0 million in respect of the Chinguetti field in Mauritania. Underlying unit amortisation (excluding impairment) rose to US$9.6/boe (2008: US$8.0/boe). Exploration expense and pre‑licence exploration costs amounted to US$57.0 million (2008: US$42.9 million) and US$20.3 million (2008: US$15.8 million) respectively. Exploration expense includes all costs relating to dry holes drilled in 2009 and the write-off of previously capitalised exploration costs relating to PSC B in Mauritania, amounting to US$19.2 million. Net administrative costs were stable at US$18.3 million (2008: US$17.2 million) despite our growing presence in Aberdeen, Norway and Vietnam.

 

In accordance with IFRS 3 - 'Business Combinations', we have included in the income statement for the year an amount of US$11.6 million, representing the excess of fair values recorded in respect of the Oilexco acquisition over and above cost. These fair values were reviewed at year-end to reflect the additional information which has become available concerning conditions that existed at the date of acquisition. For this purpose values were only allocated to assets with booked proven and probable reserves. A deferred tax asset of US$140.8 million was also recorded on the acquisition, reflecting the future value of UK corporation tax allowances acquired with Oilexco.

 

Operating profits were US$169.7 million (2008: US$261.7 million). Finance costs, net of interest revenue and other gains were US$28.7 million (2008: US$12.4 million) reflecting the increase in borrowings arising from our acquisition and capital investment programmes. Pre‑tax profits were US$79.9 million (2008: US$277.6 million) after charging mark to market revaluation of the group's hedges of US$61.1 million (2008: US$28.3 million, gain).

 

Current tax charges in 2009 of US$48.2 million (2008: US$192.9 million) are significantly lower due to the utilisation of acquired tax allowances in the UK. The current tax charge has also been more than offset by a deferred tax credit representing the value of future tax allowances in the UK. The net tax credit is US$33.1 million (2008: US$179.3 million, charge). The additional deferred tax asset recognised at year-end is based on a long-term oil price of US$70/bbl. US$275 million of UK tax allowances remain unrecognised at year-end. Profit after tax is therefore a record US$113.0 million (2008: US$98.3 million) resulting in basic earnings per share of 104.1 cents (2008: 99.0 cents, restated).

 

Cash flow

Cash flow from operating activities, before movements in working capital, amounted to US$453.5 million (2008: US$478.1 million). After working capital items and tax payments, cash flow from operating activities was US$347.7 million (2008: US$352.3 million) despite the fall in oil and gas prices. Cash flow from the Oilexco producing assets was consolidated from completion of the acquisition on 21 May 2009.

 

Capital expenditure in 2009 for exploration and development activities totalled US$303.1 million (2008: US$217.3 million).

 

Capital expenditure (US$ million)	2009	2008
Fields/development projects	192.5	124.0
Exploration	107.5	90.5
Other	3.1	2.8
Total	303.1	217.3

 

The principal field and development projects were Gajah Baru, Chim Sáo, Shelley, the Scott well infill programme, the Balmoral FPV riser replacement and the Qadirpur gas compression project.

 

Acquisitions and disposals

The group completed two very significant acquisitions during the year and also initiated a number of disposals of assets which were not material for our operations. On 25 March 2009, Premier announced the acquisition of Oilexco North Sea Ltd (ONSL) for US$505 million. ONSL was a company active in the UK Central North Sea which had been placed into administration by its lending banks on 7 January 2009. The acquisition provided the group with a significantly greater presence in the North Sea, 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 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, raising gross proceeds of approximately £171 million (US$252.2 million);

§ New credit facilities comprising initially of a US$175 million 18-month bridge facility, a US$225 million three-year revolving credit facility and US$63 million and £60 million (US$99 million) three-year letter of credit facilities; and

§ The groups existing cash resources.

 

The acquisition was completed on 21 May 2009 for a final consideration of US$500.7 million, after certain working capital adjustments for transactions between the effective date and completion. Total consideration, as disclosed in the financial statements, of US$574.2 million includes $63.0 million of cash paid by the group, which is held in trust for future abandonment obligations, and direct acquisition costs of US$10.5 million.

 

On 20 July 2009, the group announced that it had completed the acquisition of Delek Energy (Vietnam) LLC, the holding company for a 25 per cent interest in Block 12W in the Nam Con Son Basin, offshore Vietnam. The purchase price for the interest was US$72 million in cash which after completion adjustments amounted to US$83.9 million. Future payments of up to a total of US$10 million are contingent on the development of new fields in Block 12W other than Chim Sáo. Following completion of the Delek acquisition and the exercise of PetroVietnam Exploration Production Corporation's (PVEP) back-in right to acquire a 15 per cent interest in the PSC, Premier's interest in the block increased from an initial 37.5 per cent to 53.125 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. The licence contained the producing Al Amir field and the 2009 discovery at Geyad. On 22December 2009 the transaction was completed for an adjusted price of US$14.8 million in cash.

 

On 19 November 2009, Premier announced the sale of its 6.45 per cent equity interest in the Janice/James fields for a production royalty interest. The acquirer, Maersk Oil, will assume future operating costs, capital expenditure and abandonment obligations of the assets. The transaction was completed on 5 March 2010.

 

At the same time, Premier also announced that it had reached agreement for the sale of certain UK blocks containing the Caledonia field, the Sheryl discovery and the Catcher prospect for a consideration of US$12 million in cash and future contingent payments of US$13 million. The acquirer failed to achieve the necessary UK regulatory approvals and the agreement was terminated. Discussions continue with potential purchasers of the group's interest in the Caledonia field.

 

Acquisitions and disposals (US$ million)	2009
Oilexco North Sea Ltd	574.2
Delek Energy (Vietnam) LLC	83.9
Sale of NW Gemsa Licence, Egypt	(14.8)
Acquisitions (net of disposals)	643.3

 

Net debt position

Net debt at 31 December 2009 amounted to US$315.6 million (2008: net cash of US$117.3 million). Cash and cash equivalents of US$250.6 million excludes an amount of £43.0 million (US$70.2 million) held in an abandonment trust and classified in the balance sheet under trade and other receivables. It is anticipated that this cash will be replaced by bank letters of credit following the resolution of certain tax issues regarding the winding-up of the trust.

 

Net (debt)/cash (US$ million)	2009	2008
Cash and cash equivalents	250.6	323.7
Convertible bonds *	(213.2)	(206.4)
Other long-term debt **	(353.0)	-
Total net (debt)/cash	(315.6)	117.3

 

* Excluding unamortised issue costs and allocation to equity

** Excluding unamortised issue costs

 

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. Following the rights issue in April 2009, the bonds carry an adjusted equity conversion price of £13.56 per share.

 

New credit facilities of US$550 million were arranged in connection with the acquisition of Oilexco. During subsequent syndication and the restructuring of the 18-month bridge facility, the total facility size was increased to US$789 million with a maturity of 31 March 2012. As at 31December 2009, drawn borrowings were US$353 million and issued letters of credit/bank performance bonds were US$126 million. Undrawn borrowing facilities were US$328 million which, together with cash on hand or held in escrow, amounted to US$649 million.

 

Financial risk management

Consistent with its conservative financial approach, 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 is consistent with the business plan. These floors are supplemented by forward sales to meet other short-term financial objectives. Floors are purchased for cash or via collars, funded by selling caps at a ceiling price when market conditions are considered favourable. All transactions are matched as closely as possible with expected cash flows to the group; no speculative transactions are undertaken.

 

During 2009, oil price collars for 2.5 million barrels (mmbbls) matured at a cost of US$nil (2008: US$8.1 million). At year-end, a total of 8.3 mmbbls of Dated Brent oil were hedged via collars for the period to end-2012 with an average floor price of US$49/bbl and an average cap of US$84/bbl. This volume represents approximately 41 per cent of the group's expected liquids production over the period.

 

During the year, gas price collars for 120,000 metric tonnes of High Sulphur Fuel Oil (HSFO) matured. No changes were made to the group's existing gas hedges during the year which cover approximately 400,000 metric tonnes, representing approximately 22 per cent of expected Indonesian gas production for the period to June 2013.

 

In connection with the Oilexco acquisition, 1.3 million barrels of oil were sold forward at an average price of US$55.0/bbl. Subsequent to year-end a further 1 million barrels were sold forward at an average price of US$83.5/bbl. From 1 January 2010 therefore, forward sales of oil amounting to 1.4 million barrels or 20 per cent of expected 2010 liquids production were in place with an average weighted price of US$76.0/bbl. In aggregate, cash premia of US$12.5 million were paid during 2009 to put in place new hedges or enhance existing ones.

 

Premier's gas hedging is required to be marked to market at the balance sheet date. The aggregate valuation is a US$29.8 million liability (2008: US$2.9 million) generating a US$26.9 million charge in the income statement.

 

Oil hedges have typically been incorporated within the pricing terms of physical offtake agreements for the underlying oil production avoiding the requirement to revalue the hedges at year-end. At the time of the Oilexco acquisition however, it was not possible to embed new hedges within the terms of existing offtake agreements. Accordingly, a charge of US$29.0 million is recorded in the 2009 income statement. From 1 January 2010, following new offtake arrangements, further revaluations over the life of these hedges will not impact the income statement, and the existing provision of US$29.0 million will be credited to income in the years 2010 and 2011.

 

Premier operates and reports in US dollars. Exchange rate exposures relate only to local currency receipts and expenditures within individual business units. Local currency requirements are acquired on a short-term basis. The group recorded a gain of US$2.8 million on such short-term hedging during 2009 (2008: US$2.5 million, loss).

 

Cash balances are invested in short-term bank deposits and AAA rated liquidity funds, subject to Board approved limits and with a view to minimise counter-party risks.

 

The group undertakes a significant insurance programme to reduce the potential impact of the physical risks associated with its exploration, development and production activities. In addition, business interruption cover is purchased for a proportion of the cash flow from producing fields.

 

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. Further details of the group funding facilities and liquidity position will be included in the 2009 Annual Report and Financial Statements.

 

Despite economic volatility, the directors consider that the headroom provided by the available borrowing facilities gives them confidence that the group has adequate resources to continue as a going concern. As a result they continue to adopt the going concern basis in preparing the 2009 Annual Report and Financial Statements.

 

Business risks

Premier is an international business which has to face a variety of strategic, operational, financial and external risks. Under these distinct classes, the company has identified certain risks pertinent to its business including: exploration and reserve risks, loss of key human resources, drilling and operating risks, security risk in area of operations, costs and availability of materials and services, economic and sovereign risks, market risk, foreign currency risk, loss of or changes to production sharing or concession agreements, joint venture or related agreements, and volatility of future oil and gas prices.

 

Effective risk management is critical to achieving our strategic objectives and protecting our assets, personnel and reputation. Premier manages its risks prudently by maintaining a balanced portfolio, through compliance with the terms of its agreements and strict application of appropriate policies and procedures, and through the recruitment and retention of highly skilled individuals throughout the organisation. Further, the company has mitigated risks by focusing 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 the company's website (www.premier-oil.com).

 

Key performance indicators

	2009	2008	Change Improvement/ (deterioration)
LTI and RWDC frequency*	0.55	0.40	(0.15)
Production (kboepd)	44.2	36.5	7.7
Cash flow from operations (US$ million)	347.7	352.3	(4.6)
Operating cost per boe (US$)	12.2	9.5	(2.7)
Gearing**	32.5%	0%	(32.5%)
Realised oil price per barrel (US$)	65.5	94.5	(29.0)
Realised gas price per mscf	5.18	6.57	(1.39)

 

*	Lost time injuries (LTI) and restricted work day cases (RWDC) per million man-hours worked.
**	Gearing is net debt divided by net assets. For 2008 the group had a net cash position.

 

CONSOLIDATED INCOME STATEMENT

For the year ended 31 December 2009

 

	2009	2008
	$ million	$ million
Sales revenues	621.1	655.2
Cost of sales	(361.4)	(317.6)
Exploration expense	(57.0)	(42.9)
Pre-licence exploration costs	(20.3)	(15.8)
Acquisition of subsidiaries	5.6	-
General and administration costs	(18.3)	(17.2)
Operating profit	169.7	261.7
Interest revenue, finance and other gains	15.7	14.6
Finance costs and other finance expenses	(44.4)	(27.0)
Mark to market revaluation of commodity hedges	(61.1)	28.3
Profit before tax	79.9	277.6
Tax	33.1	(179.3)
Profit after tax	113.0	98.3
Earnings per share (cents):
Basic	104.1	99.0
Diluted	103.9	98.2

 

The results relate entirely to continuing operations.

 

 

 

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

For the year ended 31 December 2009

 

	2009	2008
	$ million	$ million
Profit for the year	113.0	98.3
Cash flow hedges - losses arising during the year:
On commodity swaps	(9.8)	-
On interest rate swaps	(0.8)	-
Exchange differences on translation of foreign operations	8.7	(5.6)
Actuarial losses on long-term employee benefit plans	(3.5)	(2.1)
Total comprehensive income for the year	107.6	90.6

 

 

CONSOLIDATED BALANCE SHEET

As at 31 December 2009

 

	2009	2008
	$ million	$ million
Non-current assets:
Intangible exploration and evaluation assets	231.6	157.9
Property, plant and equipment	1,386.0	767.4
Deferred tax asset	190.6	5.8
	1,808.2	931.1
Current assets:
Inventories	35.3	14.6
Trade and other receivables	445.7	181.2
Cash and cash equivalents	250.6	323.7
	731.6	519.5
Total assets	2,539.8	1,450.6
Current liabilities:
Trade and other payables	(419.7)	(202.8)
Current tax payable	(46.5)	(73.8)
	(466.2)	(276.6)
Net current assets	265.4	242.9
Non-current liabilities:
Convertible bonds	(210.1)	(202.7)
Other long-term debt	(337.2)	-
Deferred tax liabilities	(179.8)	(188.8)
Long-term provisions	(307.6)	(143.2)
Long-term employee benefit plan deficit	(13.5)	(6.8)
Deferred revenue	(54.1)	(33.6)
	(1,102.3)	(575.1)
Total liabilities	(1,568.5)	(851.7)
Net assets	971.3	598.9
Equity and reserves:
Share capital	97.0	73.6
Share premium account	223.7	9.7
Retained earnings	603.2	472.9
Capital redemption reserve	4.3	1.7
Translation reserves	7.1	(1.6)
Equity reserve	36.0	42.6
	971.3	598.9

 

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

For the year ended 31 December 2009

 

	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	226.2	-	-	-	-	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

 

*	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.

 

CONSOLIDATED CASH FLOW STATEMENT

For the year ended 31 December 2009

 

	2009	2008
	$ million	$ million
Net cash from operating activities	347.7	352.3
Investing activities:
Capital expenditure	(303.1)	(217.3)
Pre-licence exploration costs	(20.3)	(15.8)
Acquisition of subsidiaries	(574.2)	-
Acquisition of oil and gas properties	(83.9)	-
Proceeds from disposal of oil and gas properties	14.8	3.1
Net cash used in investing activities	(966.7)	(230.0)
Financing activities:
Issue of Ordinary Shares	252.2	0.4
Expenses of issue of Ordinary Shares	(12.2)	-
Purchase of shares for ESOP Trust	(2.5)	(17.9)
Purchase of own shares	-	(47.2)
Loan drawdowns	353.0	-
Debt arrangement fees	(25.6)	-
Repayment of long-term financing	-	(53.0)
Interest paid	(21.2)	(10.9)
Net cash from/(used in) financing activities	543.7	(128.6)
Currency translation differences relating to cash and cash equivalents	2.2	(2.0)
Net decrease in cash and cash equivalents	(73.1)	(8.3)
Cash and cash equivalents at the beginning of the year	323.7	332.0
Cash and cash equivalents at the end of the year	250.6	323.7

 

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the year ended 31 December 2009

 

 

1 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.

 

This preliminary announcement was authorised for issue in accordance with a resolution of the Board of Directors on 24 March 2010.

 

The above financial information does not constitute statutory accounts within the meaning of Section 434 of the Companies Act 2006. A copy of the statutory accounts for 2008 has been delivered to the Registrar of Companies and those for 2009 will be delivered following the company's Annual General Meeting (AGM). The auditors' report on those accounts was unqualified and did not contain statements under section 498(2) or (3) of the Companies Act 2006.

 

Basis of preparation

The financial information has been prepared in accordance with the recognition and measurement criteria of International Financial Reporting Standards (IFRS) adopted for use in the European Union. However, this announcement does not itself contain sufficient information to comply with IFRS. The company will publish full financial statements that comply with IFRS on or before 30 April 2010.

 

The financial information has been prepared under the historical cost convention except for the revaluation of financial instruments and certain oil and gas properties at the transition date to IFRS. These financial statements are presented in US dollars since that is the currency in which the majority of the group's transactions are denominated.

 

Accounting policies

The announcement is prepared on the basis of accounting policies as stated in the 2008 financial statements, with the exception of standards, amendments and interpretations effective in 2009. The following standards, amendments and interpretations to published standards were adopted by the group for the financial year beginning 1 January 2009:

 

·; 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 1 (revised 2007) - 'Presentation of Financial Statements'. The revised standard requires the separate presentation of owner and non-owner changes in equity by introducing the statement of comprehensive income. The statement of total recognised income and expense is no longer presented. Whenever there is a restatement or reclassification, an additional balance sheet, as at the beginning of the earliest period presented, will be required to be published. There was no effect on the group's reported income or net assets as a result of the adoption of this revised standard.

·; IAS 23 (revised 2007) - '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.

·; Improving Disclosures about Financial Instruments (Amendments to IFRS 7 - 'Financial Instruments: Disclosures'). The amendments to IFRS 7 expand the disclosures required in respect of fair value measurements and liquidity risk. The group has elected not to provide comparative information for these expanded disclosures in the current year in accordance with the transitional reliefs offered in these amendments.

·; 'Classification of Rights Issues - Amendment to IAS 32'. The amendment is effective for annual periods beginning on or after 1 February 2010, with early adoption permitted. The group has elected to adopt the amendment in advance of the effective date and, as required by IAS 8 - 'Accounting Policies, Changes in Accounting Estimates and Errors', has applied the amendment retrospectively. The amendment requires that rights issues, options or warrants to acquire a fixed number of the entity's own equity instruments for a fixed amount of any currency are equity instruments if the entity offers the rights issues, options or warrants pro rata to all of its existing owners of the same class of its own non-derivative equity instruments. The offer of rights by Premier Oil plc to its shareholders on 25 March 2009 was accounted for as an equity instrument, as required by the amendment, in the consolidated financial statements of the group.

 

At the date of authorisation of these financial statements, the group has not applied the following Standards and Interpretations which are in issue but not yet effective:

 

·; IFRS 1 (amended)/IAS 27 (amended) - 'Cost of an Investment in a Subsidiary, Jointly Controlled Entity or Associate'

·; IFRS 3 (revised 2008) - 'Business Combinations'

·; IAS 27 (revised 2008) - 'Consolidated and Separate Financial Statements'

·; IAS 28 (revised 2008) - 'Investments in Associates'

·; IFRIC 17: 'Distributions of Non-cash Assets to Owners'

·; Improvements to IFRSs (April 2009)

 

The directors do not expect that the adoption of these Standards and Interpretations in future periods will have a material impact on the financial statements of the group.

 

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.

 

	2009	2008 (restated)
	$ million	$ million
Revenue:
North Sea and West Africa*	351.7	324.5
Asia	146.4	203.6
Middle East-Pakistan	123.0	127.1
Total group sales revenue	621.1	655.2
Interest and other finance revenue	2.2	12.5
Total group revenue	623.3	667.7
Group operating profit/(loss):
North Sea and West Africa*	31.4	89.4
Asia	75.9	102.0
Middle East-Pakistan	76.5	86.0
Unallocated**	(14.1)	(15.7)
Group operating profit	169.7	261.7
Interest revenue, finance and other gains	15.7	14.6
Finance costs and other finance expenses	(44.4)	(27.0)
Mark to market revaluation of commodity hedges	(61.1)	28.3
Profit before tax	79.9	277.6
Tax	33.1	(179.3)
Profit after tax	113.0	98.3
Balance sheet
Segment assets:
North Sea and West Africa*	1,249.8	442.1
Asia	822.6	527.8
Middle East-Pakistan	135.9	146.3
Unallocated**	331.5	334.4
Total assets	2,539.8	1,450.6
Liabilities:
North Sea and West Africa*	(459.1)	(301.4)
Asia	(267.7)	(166.0)
Middle East-Pakistan	(103.1)	(60.2)
Unallocated**	(738.6)	(324.1)
Total liabilities	(1,568.5)	(851.7)

 

 

 

	2009	2008
	$ million	$ million
Other information
Capital additions and acquisitions:
North Sea and West Africa*	637.6	89.2
Asia	266.6	105.2
Middle East-Pakistan	26.1	29.6
Total capital additions and acquisitions	930.3	224.0
Depreciation, depletion, amortisation and impairment:
North Sea and West Africa*	131.8	95.3
Asia	31.4	27.8
Middle East-Pakistan	17.6	17.5
Total depreciation, depletion, amortisation and impairment	180.8	140.6

 

*	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, assets and liabilities include amounts of a corporate nature and not specifically attributable to a geographical segment. These items include cash, mark to market valuations of commodity hedges, convertible bonds and other long-term debt.

 

 

3 Cost of sales

 

	2009	2008
	$ million	$ million
Operating costs	196.7	127.1
Stock overlift/underlift movement	(31.1)	33.1
Royalties	15.0	16.8
Amortisation and depreciation of property, plant and equipment:
Oil and gas properties	155.2	107.2
Other fixed assets	1.6	1.5
Impairment of oil and gas properties	24.0	31.9
	361.4	317.6

 

 

4 Tax

 

	2009	2008
	$ million	$ million
Current tax:
UK corporation tax on profits	(23.4)	47.5
UK petroleum revenue tax	23.2	34.0
Overseas tax	73.0	111.6
Adjustments in respect of previous periods	(24.6)	(0.2)
Total current tax	48.2	192.9
Deferred tax:
UK corporation tax	(67.1)	0.9
UK petroleum revenue tax	(23.6)	(7.6)
Overseas tax	9.4	(6.9)
Total deferred tax	(81.3)	(13.6)
Tax on profit on ordinary activities	(33.1)	179.3

 

The tax charge for the year can be reconciled to the profit per the consolidated income statement as follows:

 

	2009	2008
	$ million	$ million
Group profit on ordinary activities before tax	79.9	277.6
Group profit on ordinary activities before tax at 59.9% weighted average rate (2008: 61.0%)	47.9	169.3
Tax effects of:
Income/expenses that are not taxable/deductible in determining taxable profit	(10.5)	5.5
Tax and tax credits not related to profit before tax (including UK petroleum revenue tax)	(19.2)	(4.3)
Unrecognised tax losses	40.7	8.7
Utilisation and recognition of tax losses not previously recognised	(135.6)	(1.5)
Adjustment in respect of previous periods	(19.3)	1.6
Effect of change in tax rates	27.2	-
Timing differences for which deferred tax not recognised	35.7	-
Tax (credit)/expense for the year	(33.1)	179.3
Effective tax rate for the year	(41.4%)	64.6%

 

The weighted average rate is calculated based on the tax rates weighted according to the profit or loss before tax earned by the group in each jurisdiction. The change in the weighted average rate year on year relates to the mix of profit and loss in each jurisdiction. The standard tax rate of UK ring fence profits is 50 per cent.

 

There are no significant unrecognised temporary differences associated with undistributed profits of subsidiaries, associates and joint ventures. The amount of unused tax losses for which no deferred tax asset is recognised in the balance sheet in the absence of suitable ring fence and non-ring fence forecast profits is US$367.1 million in the UK (2008: US$6.8 million). This gives rise to a potential deferred tax asset of US$163.3 million (2008: US$1.9 million).

 

 

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 year. The denominators for the purposes of calculating both basic and diluted earnings per share for the prior year 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		Weighted average number of shares		Earnings per share
	2009	2008	2009	2008	2009	2008
				(restated)		(restated)
	$ million	$ million	million	million	cents	cents
Basic	113.0	98.3	108.6	99.3	104.1	99.0
Outstanding share options	-	-	0.2	0.8	*	*
Diluted	113.0	98.3	108.8	100.1	103.9	98.2

 

* 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 31 December 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 year to 31 December 2009.

 

In accordance with IAS 33 - 'Earnings per Share' the comparatives have been restated to take into account the rights issue by the company during 2009.

 

 

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 2008	64.3	89.0	-	153.3
Exchange movements	(7.6)	-	-	(7.6)
Additions during the year	52.5	42.8	2.5	97.8
Transfer to tangible fixed assets	-	(40.8)	(1.9)	(42.7)
Exploration expenditure written off	(15.1)	(27.2)	(0.6)	(42.9)
At 1 January 2009	94.1	63.8	-	157.9
Exchange movements	11.2	-	-	11.2
Additions during the year	59.9	57.9	4.2	122.0
Transfer to tangible fixed assets	(0.2)	(1.1)	(1.2)	(2.5)
Exploration expenditure written off	(41.1)	(12.9)	(3.0)	(57.0)
At 31 December 2009	123.9	107.7	-	231.6

 

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			Other fixed assets	Total
	North Sea and West Africa	Asia	Middle East-Pakistan
	$ million	$ million	$ million	$ million	$ million
Cost:
At 1 January 2008	552.4	424.6	146.8	9.0	1,132.8
Exchange movements	-	-	-	(1.3)	(1.3)
Additions during the year	34.2	62.1	27.0	2.9	126.2
Disposals	-	-	-	(0.9)	(0.9)
Transfer from intangible fixed assets	-	40.8	1.9	-	42.7
At 1 January 2009	586.6	527.5	175.7	9.7	1,299.5
Exchange movements	-	-	-	0.8	0.8
Acquisitions	486.5	83.9	-	-	570.4
Additions during the year	88.5	124.7	21.6	3.1	237.9
Disposals	-	(7.8)	(5.0)	(0.1)	(12.9)
Transfer from intangible fixed assets	0.2	1.1	1.2	-	2.5
At 31 December 2009	1,161.8	729.4	193.5	13.5	2,098.2
Amortisation and depreciation:
At 1 January 2008	205.7	102.1	79.4	6.1	393.3
Exchange movements	-	-	-	(1.1)	(1.1)
Charge for the year	62.4	27.4	17.4	1.5	108.7
Impairment loss	31.9	-	-	-	31.9
Disposals	-	-	-	(0.7)	(0.7)
At 1 January 2009	300.0	129.5	96.8	5.8	532.1
Exchange movements	-	-	-	0.6	0.6
Charge for the year	106.4	31.3	17.5	1.6	156.8
Impairment loss	24.0	-	-	-	24.0
Disposals	-	-	(1.2)	(0.1)	(1.3)
At 31 December 2009	430.4	160.8	113.1	7.9	712.2
Net book value:
At 31 December 2008	286.6	398.0	78.9	3.9	767.4
At 31 December 2009	731.4	568.6	80.4	5.6	1,386.0

 

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

 

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 of 10 per cent. 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 on an entitlement basis 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 Notes to the cash flow statement

 

	2009	2008
	$ million	$ million
Profit before tax for the year	79.9	277.6
Adjustments for:
Depreciation, depletion, amortisation and impairment	180.8	140.6
Exploration expense	57.0	42.9
Pre-licence exploration costs	20.3	15.8
Acquisition of subsidiaries	(11.6)	-
Net operating charge for long-term employee benefit plans less contributions	0.2	(3.0)
Provision for share-based payments	27.3	20.1
Interest revenue and finance gains	(5.9)	(14.6)
Finance costs and other finance expenses	44.4	27.0
Mark to market revaluation of commodity hedges	61.1	(28.3)
Operating cash flows before movements in working capital	453.5	478.1
(Increase)/decrease in inventories	(10.3)	7.9
(Increase)/decrease in receivables	(10.8)	34.5
(Decrease)/Increase in payables	(15.5)	21.7
Cash generated by operations	416.9	542.2
Income taxes paid	(71.5)	(203.1)
Interest income received	2.3	13.2
Net cash from operating activities	347.7	352.3

 

 

Analysis of changes in net (debt)/cash

 

	2009	2008
	$ million	$ million
a) Reconciliation of net cash flow to movement in net (debt)/cash:
Movement in cash and cash equivalents	(73.1)	(8.3)
Proceeds from long-term loans	(353.0)	-
Repayment of long-term loans	-	53.0
Non-cash movements on debt and cash balances	(6.8)	(6.4)
(Decrease)/increase in net cash in the year	(432.9)	38.3
Opening net cash	117.3	79.0
Closing net (debt)/cash	(315.6)	117.3

 

b) Analysis of net (debt)/cash:
Cash and cash equivalents	250.6	323.7
Long-term debt*	(566.2)	(206.4)
Total net (debt)/cash	(315.6)	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$3.1 million (2008: US$3.7 million) and debt arrangement fees of US$15.8 million (2008: US$nil) respectively.

 

 

9 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:

 

1. 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$252.2 million);

2. New credit facilities consisting initially of a US$175 million 18-month bridge facility, a US$225 million three-year revolving credit facility and US$63 million and £60 million (US$97 million) three-year letter of credit facilities; and

3. 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. The fair values of the identifiable assets and liabilities have been reassessed since the half year, to reflect additional information which has become available concerning conditions that existed at the date of acquisition in accordance with the provisions of IFRS 3 - 'Business Combinations'. The final fair values, together with the changes since the half year, are set out in the following table:

 

 

	Provisional fair values as included in the half yearly report	Adjustment	Final fair values
	$ million	$ million	$ million
Net assets acquired:
Property, plant and equipment - oil and gas properties	569.0	(82.5)	486.5
Deferred tax asset	146.5	(5.7)	140.8
Current assets	92.3	22.2	114.5
Current liabilities	(39.6)	-	(39.6)
Deferred tax liabilities	(2.1)	-	(2.1)
Long-term provisions	(125.7)	11.4	(114.3)
Total acquired net assets	640.4	(54.6)	585.8
Total consideration*	(574.1)	(0.1)	(574.2)
Excess of fair value over cost**	66.3	(54.7)	11.6

 

*	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$10.5 million.
**	This excess of fair value over cost has been recognised immediately in the consolidated income statement for the year under review, and has been offset by related acquisition expenses of US$6.0 million.

 

The principal adjustments from the half year valuation were a reduction in the carrying value of the Shelley field in oil and gas properties, recognition of additional pre-acquisition receivables and determination of fair value for inventories acquired on completion.

 

The final payments made by the group 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 half yearly balance sheet date. On 1 July 2009, the assets were transferred from ONSL into another group company as part of an internal restructuring of the group.

 

If the acquisition of ONSL had been completed on the first day of the financial year, group revenues for the year would have been US$686.4 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 final assigned values are judgemental in nature.

 

 

10 Dividends

The directors do not propose any dividend.

 

 

11 External Audit

This Preliminary Announcement is consistent with the audited financial statements of the group for the year-ended 31 December 2009.

 

 

12 Publication of financial statements

A full set of financial statements will be published on or before 30 April 2010. Copies will be available at the company's head office, 23 Lower Belgrave Street, London SW1W 0NR, and on the company's website (www.premier-oil.com) by this date.

 

 

13 Annual General Meeting

The Annual General Meeting will be held at Institute of Directors, 116 Pall Mall, London SW1Y 5ED on Friday 21 May 2010 at 11.00am.

 

 

Working Interest Reserves at 31 December 2009

	Working Interest Basis
	North Sea and West Africa		Middle East - Pakistan		Asia		TOTAL
	Oil and NGLs	Gas	Oil and NGLs	Gas	Oil and NGLs	Gas	Oil and NGLs	Gas3	Oil, NGLs and gas
	mmbbls	bcf	mmbbls	bcf	mmbbls	bcf	mmbbls	bcf	mmboe
Group proved plus probable reserves:
At 1 January 2009	22.4	19	2.3	322	24.8	675	49.5	1,016	227.5
Revisions	(1.4)	1	(0.2)	7	0.2	-	(1.4)	8	(0.2)
Discoveries and extensions1	-	-	0.5	3	-	-	0.5	3	1.0
Acquisitions and divestments2	30.4	15	(1.3)	-	9.5	9	38.6	24	43.0
Production	(5.7)	(3)	(0.2)	(36)	(0.4)	(18)	(6.3)	(57)	(16.1)
At 31 December 2009	45.7	32	1.1	296	34.1	666	80.9	994	255.2
Total group developed and undeveloped reserves:
Proved on production	25.7	17	0.3	87	1.9	135	27.9	239	71.2
Proved approved/justified for development	5.7	5	0.5	127	22.8	337	29.0	469	109.8
Probable on production	8.9	6	0.2	50	0.5	23	9.6	79	23.2
Probable approved/justified for development	5.4	4	0.1	32	8.9	171	14.4	207	51.0
At 31 December 2009	45.7	32	1.1	296	34.1	666	80.9	994	255.2

 

 

 

Notes:

1	Includes reserves discovered at Geyad (Egypt) and Kadanwari (Pakistan). Further discovered volumes at Kadanwari together with discoveries at Cá Rồng Đỏ (Vietnam) and Grosbeak (Norway) are included as 28 mmboe working interest contingent resources and are not shown here.
2	Includes acquisition of Oilexco North Sea Ltd; acquisition of additional 21.25 per cent interest (25 per cent less 15 per cent PVEP 'back-in') in Chim Sáo (Vietnam); and sale of North West Gemsa Licence (Egypt).
3	Proved plus probable gas reserves include 71 bcf fuel gas.

 

 

Premier Oil plc categorises petroleum resources in accordance with the 2007 SPE/WPC/AAPG/SPEE Petroleum Resource Management System (SPE PRMS).

 

Proved and probable reserves are based on operator, third-party reports and internal estimates and are defined in accordance with the Statement of Recommended Practice (SORP) issued by the Oil Industry Accounting Committee (OIAC), dated July 2001.

 

The group provides for amortisation of costs relating to evaluated properties based on direct interests on an entitlement basis, which incorporates the terms of the Production Sharing Contracts in Indonesia, Vietnam, Mauritania and Egypt. On an entitlement basis reserves increased by 31.2 mmboe giving total entitlement reserves of 229.0 mmboe as at 31 December 2009 (2008: 197.8 mmboe). This was calculated in 2009 using an oil price assumption of US$75.0/bbl (2008: US$60.0/bbl).

 

 

 

This information is provided by RNS

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