2007 ANNUAL REPORT AND FINANCIAL STATEMENTS GROWTH AND DEVELOPMENT

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1 2007 ANNUAL REPORT AND FINANCIAL STATEMENTS GROWTH AND DEVELOPMENT

2 OUR STRATEGY IS TO ADD SIGNIFICANT VALUE PER SHARE THROUGH EXPLORATION AND APPRAISAL SUCCESS, DEVELOPMENT PROJECTS AND ASTUTE ASSET MANAGEMENT

3 2007 HIGHLIGHTS Production up 8 per cent to 35.8 kboepd (2006: 33.0 kboepd) Reserves increased by 39 per cent to 212 mmboe. Reserves and resources up 28 per cent to 369 mmboe. Reserve replacement of 460 per cent Material progress on major development projects commercialising past exploration successes and adding value to recent acquisitions New gas sales agreements in Singapore and Indonesia Successful acquisitions adding low cost barrels in UK and Indonesia New exploration and appraisal acreage acquired in Norway and Vietnam Operating cash flow up 10 per cent to US$269.5 million (2006: US$244.8 million) Operating profit up 35 per cent to US$219.4 million (2006: US$162.6 million) Low cost financing in place to fund development programme of ~US$1 billion in Strong balance sheet with cash resources of US$332.0 million Premier is extremely well placed to meet its stated production target of 50,000 boepd by end 2010 from existing assets. Our focus is turning to the next phase of growth through exploration, appraisal and acquisition. Simon Lockett, Chief Executive Officer From top to bottom: Simon Lockett, Chief Executive Officer Robin Allan, Director of Business Development Tony Durrant, Finance Director Neil Hawkings, Operations Director

4 CONTINUED GROWTH PREMIER S STRATEGY OF DELIVERING GROWTH BOTH FROM THE PRODUCTION BASE AND FROM HIGH POTENTIAL EXPLORATION IS BACKED BY A SOLID FINANCIAL POSITION. EXISTING CASH RESOURCES, BANK FACILITIES AND STRONG CASH FLOWS WILL ALLOW US TO FUND EXISTING AND NEW DEVELOPMENT PROJECTS FINANCIAL ACHIEVEMENTS Our year-end net cash position of US$79.0 million reflects strong cash generation and a disciplined approach to expenditure Value-adding acquisitions were funded from existing bank facilities and cash Our future development programme will be funded by existing low-cost financial resources 2007 Net cash US$ 79.0m 2007 Operating cash flow US$ 269.5m

5 A GROWING ASSET BASE SIGNIFICANT PROGRESS ON PROJECTS IN THE PORTFOLIO GIVES US CONFIDENCE THAT PREMIER WILL ACHIEVE ITS STATED PRODUCTION TARGET OF 50,000 BOEPD BY THE END OF Gas from Gajah Baru will be piped to the Sembgas facility in Singapore 1 INDONESIA Gajah Baru In the fourth quarter of 2007 Premier announced the signature of Heads of Agreement with Sembcorp Gas Pte Ltd for gas sales into the Singapore market, and with PT Perusahaan Listrik Negara and PT Universal Batam Energy for domestic gas sales into Batam. Development of the Gajah Baru field in the Natuna Sea will now commence with project sanction expected later this year and first gas planned for INDONESIA North Sumatra Block A A Gas Sale and Purchase Agreement (GSPA) was concluded in December The GSPA will govern the sale of gas from the Alur Rambong, Julu Rayeu, and Alur Siwah fields in North Sumatra to the PIM fertilizer plant on the northern Aceh coast. A field development plan has been submitted for approval. 3 Chim Sáo and Dua were drilled by the Ocean General and first production is on target for VIETNAM Chim Sáo Premier discovered oil on the Dua and Chim Sáo (formerly Blackbird) prospects in 2006 and Project development work has made good progress during Outline development plan approval, approval of the field development plan, and project sanction are all expected in First production from Chim Sáo is on target for UK Scott Equity in the Scott field was increased to per cent via acquisition during 2007, adding over 5,000 boepd to Premier s net production. An infill drilling programme was successfully completed in 2007, and a further campaign will commence during With higher oil prices and a strong production performance, payback of Premier s acquisition cost of US$53 million was achieved within the first six months.

6 2 Gas from North Sumatra Block A will power the PIM fertilizer plant 4 An infill drilling programme will commence on Scott in 2008

7 EXPLOITING OUR STRONG POSITION ASIA > THE FULL RANGE OF EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES > STRATEGY We seek to maximise the potential of our Natuna Sea, North Sumatra and Nam Con Son Basin assets, bringing relationships, knowledge and technical skills to bear and developing new business opportunities in related technical or geographical areas

8 > 2007 HIGHLIGHTS AND ACHIEVEMENTS Acquisition of additional equity in North Sumatra Block A Agreements signed for gas sales from North Sumatra Block A and further gas sales from Natuna Sea Block A PSCs signed for new exploration blocks in Indonesia (Tuna and Buton) and a PSC awarded in Vietnam (Block /05) Completion of farm-in on Block 07/03 (Vietnam) allowing Premier to assume operatorship with 45 per cent interest Rig secured for drilling on Block 12W for up to 24 months Following successful Chim Sáo drilling in early 2007, progressing combined Chim Sáo/Dua project towards development approval We are continuing to build our portfolio across the exploration, development and production spectrum in the areas where we have deep knowledge. This is delivering long-term growth to the business. Barry O Donnell Asia Regional Manager THAILAND VIETNAM > OUTLOOK Approval of Chim Sáo oil development plans targeted for the second quarter of 2008 Block 12W Block 07/03 Completion of gas sales agreements on Natuna Sea Block A, formal government approval of field development plans and award of major construction contracts expected in 2008 Approval of North Sumatra Block A gas development plans and award of major construction projects expected in 2008 North Sumatra Block A MALAYSIA Kuala Lumpur Anoa Kakap Kakap N Kakap S West Natuna Block A Tuna Exploration prospects on Block 12W to be drilled in the second and third quarter of 2008 Dumai SINGAPORE Seismic and other technical work to be progressed for 2009 drilling programmes in Vietnam and Indonesia SUMATRA I N D O N E S I A Premier interests Gas fields Oil & gas fields Pipeline

9 EXTENDING OUR FOOTPRINT MIDDLE EAST PAKISTAN > RELATIONSHIP SKILLS AND NEW VENTURE INITIATIVES > STRATEGY Building on our well-established and successful position in Pakistan s rapidly growing gas market we are also seeking to extend our footprint into the hydrocarbon-prolific areas of the Middle East and North Africa through partnerships and business development activities

10 > 2007 HIGHLIGHTS AND ACHIEVEMENTS De-merger of Pakistan interests from Premier-KUFPEC Pakistan joint venture Continued production growth leading to record Pakistan production in excess of 12,600 boepd net to Premier Successful drilling of K-18 well on Kadanwari and deeper prospect on Qadirpur New production from Badhra Conclusion of joint venture agreements with Emirates International Investment Company LLC (EIIC) for activities across the region > OUTLOOK Testing of deep Qadirpur gas discovery Production enhancement and expansion projects at Qadirpur, Bhit and Kadanwari New high calorific value gas production from Zamzama Phase 2 project Pursuit of opportunities across the Middle East and North Africa with our Abu Dhabi-based joint venture partner Premier remains committed to deriving full value from its world class assets in Pakistan and extending its growth potential both in country and across the region. Zaffar Chida Pakistan Country Manager Premier interests Gas producing fields AFGHANISTAN Islamabad Lahore P A K I S TA N Quetta Zarghun South Qadirpur IRAN Kadanwari Zamzama Bhit Badhra Sukkur INDIA Karachi

11 RETURNING TO GROWTH NORTH SEA > SELECTIVE ACQUISITIONS AND OPTIMISATION OF OUR EXISTING RESERVE BASE > STRATEGY We will grow our position in the North Sea through participation in new licensing rounds and an active exploration programme in Norway and the UK. This includes the development of discoveries already held in the portfolio. In the UK we seek to maximise output from our current production base and will acquire additional assets in the areas which we know well > 2007 HIGHLIGHTS AND ACHIEVEMENTS Completed acquisition of per cent equity in the Scott field for US$53 million, adding over 5,000 boepd to Premier s net production Significant rise in Kyle field production following successful completion of gas lift project Award of five licences in the Norwegian APA Licensing Round in January 2007

12 34/2 Premier interests Oil producing fields 34/5 36/10 35/8, 35/9 35/12 31/3 32/1 Frøy Area NORWAY Scott, 16/1(part), 16/4 Telford 15/24a 17/8,9,11,12 14/25a 15/25f 18/7,10 18/11 8/3 22/2a St Fergus 9/1 Cruden Bay 21/7b 23/22b SCOTLAND 20/10b, 20/15a Kyle 21/6a, 21/11b Angus Flora Fife Fergus 39/2b 39/7 > OUTLOOK Infill well programmes planned on the Scott, Telford, and Wytch Farm fields Submission of development plans for the Frøy field expected during 2008 Bream appraisal well planned for the second quarter of 2008 First operated exploration programme in Norway will commence in 2008 with first well to be drilled in 2009 IRELAND UK WALES ENGLAND NETHERLANDS Wareham Wytch Farm FRANCE BELGIUM Since its expansion into Norway, the North Sea business has made excellent progress towards building a balanced portfolio of exploration and development projects as well as our existing production assets in the UK. We are looking forward to our programme of exploration and appraisal drilling in the UK and Norway this year, as well as continuing our efforts to maximise output from our current producing assets across the region. Nigel Wilson North Sea Regional Manager

13 HIGH-IMPACT EXPLORATION WEST AFRICA > TECHNICAL CAPABILITIES AND COMMERCIAL DEAL-MAKING We use our technical skills to assess high-impact opportunities, including deep water potential, and our commercial skills to optimise the group s exposure to drilling opportunities. Steve Bottomley West Africa Regional Manager SADR MAURITANIA Premier interests Oil & gas fields A F R I C A > STRATEGY The West African Business Unit will seek to deliver a programme of high-impact exploration opportunities, which on success will deliver material increases in asset value over time. Critical to this programme will be our profile and businessgovernment relationships, backed by technical skills in the region > 2007 HIGHLIGHTS AND ACHIEVEMENTS CONGO Detailed evaluation of deep water exploration acreage in Congo and identification of high-potential prospects Strategic exit from Dussafu Block in Gabon ATLANTIC OCEAN > OUTLOOK Planning and execution of two well high-impact programme in Congo Optimisation of Chinguetti production and other future development potential in Mauritania Evaluation of new venture proposals in the region with a view to building a pipeline of future high-impact opportunities

14 TECHNICAL EXPERTISE > THE CORE WORK OF OUR GEOLOGISTS AND ENGINEERS IS TO APPLY SCIENCE TO SECURE THE OPTIMUM DISCOVERY AND EXTRACTION OF OIL AND GAS Our professionals use the latest technological tools to keep us at the forefront of the industry and we employ the best available specialists in all of the projects that we undertake. Before drilling, we assess the risks from every angle, and fully evaluate the hydrocarbon potential. We manage our portfolio to ensure that our focus is on the best prospects. For our development projects, we consider all the possible options, including appropriate new technology, and assess the range of possible outcomes before selecting the optimal design. We place great value on the imagination and creativity of our geologists, geophysicists and engineers. This enables us to work in previously overlooked areas, so that, armed with new scientific concepts, innovative technologies and state-of-the-art equipment, we can operate in such areas more successfully than in the past.

15 SOCIAL PERFORMANCE > PREMIER ASPIRES TO BE AN INDUSTRY LEADER IN SOCIAL PERFORMANCE, WHICH COVERS THE AREAS OF SOCIAL RESPONSIBILITY, HEALTH AND SAFETY, AND ENVIRONMENTAL IMPACT Our stated policy is to ensure that the risks and impacts of our activities are reduced to as low as reasonably practicable at all times. We set targets with reference to our historical performance, the performance of our peer group and standards set by external agencies. We publish a Social Performance Report every two years, and from now on in intermediate years we will prepare a Communication on Progress. These will be available on our website > 2007 HIGHLIGHTS AND ACHIEVEMENTS Among our local infrastructure initiatives, Premier sponsored construction of two community halls, two kindergarten buildings and a clean water supply to five villages in Indonesia, as well as four bridges in Vietnam. We also supported various health-related training programmes and farming projects and donated emergency equipment to the Cachar district in India during severe flooding Premier again exceeded its internal target of lost time injury and restricted workday case frequency. This target has been consistently reduced for the last five years Our global drilling function is certified to ISO and OHSAS and successfully underwent a number of assessments and surveillance audits. ISO and OHSAS are internationally recognised standards to which a company s environmental and health and safety management system may be certified We reduced our greenhouse gas emissions in tonnes per thousand tonnes of production from 232 in 2006 to 171 in 2007 > OUTLOOK As we progress the development of new operated production projects in Vietnam and Indonesia we will continue to target the highest standards of performance with respect to social responsibility, health and safety and environmental impact

16 PREMIER OPERATES WORLDWIDE IN FOUR REGIONAL BUSINESSES, EACH WITH PRODUCTION, DEVELOPMENT AND EXPLORATION OPERATIONS. IT HAS A RESERVE AND RESOURCE BASE OF 369 MMBOE UK Exploration and Production 9,850 boepd Wytch Farm 12.38% Kyle 40.00% Scott 21.83% Telford 0.82% Fife 15.00% Pakistan Production and Development 12,700 boepd Zamzama 9.37% Kadanwari 15.79% Qadirpur 4.75% Bhit & Badhra 6.00% Zarghun South 3.75% Norway Exploration and Development Bream 20.00% Frøy 50.00% Vietnam Exploration and Development Chim Sáo 37.5% Dua 37.5% SADR Exploration Egypt Exploration Philippines Exploration Mauritania Exploration, Development and Production 1,200 boepd India Development Chinguetti 8.12% Tiof 9.23% Banda 4.62% Congo Exploration Indonesia Exploration, Development and Production 12,000 boepd Anoa 28.67% Gajah Baru 28.67% Kakap 18.75% North Sumatra Block A 41.67%

17 PREMIER IS A LEADING FTSE 250 INDEPENDENT EXPLORATION AND PRODUCTION COMPANY WITH OIL AND GAS INTERESTS IN ASIA, MIDDLE EAST AND PAKISTAN, THE NORTH SEA AND WEST AFRICA CONTENTS Highlights 01 Chairman s Statement 02 Section 1: PERFORMANCE Chief Executive s Review 04 Financial Review 12 Social Performance Review 15 Section 2: GOVERNANCE Board of Directors 20 Corporate Governance Report 22 Report of the Directors 28 Remuneration Report 31 Statement of Directors Responsibilities 41 Accounting Policies 42 Section 3: FINANCIAL STATEMENTS Independent Auditors Report group 48 Consolidated Income Statement 49 Consolidated Statement of Total Recognised Income and Expenses 49 Consolidated Balance Sheet 50 Consolidated Cash Flow Statement 51 Notes to the Consolidated Financial Statements 52 Independent Auditors Report parent company 73 Parent Company Financial Statements 74 Section 4: ADDITIONAL INFORMATION Five Year Summary 87 Shareholder Information 88 Oil and Gas Reserves 89 Worldwide Licence Interests 90 PERFORMANCE GOVERNANCE FINANCIAL STATEMENTS ADDITIONAL INFORMATION

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19 HIGHLIGHTS 01 OPERATIONAL Production up 8 per cent to 35.8 kboepd (2006: 33.0 kboepd) Reserves increased by 39 per cent to 212 mmboe. Reserves and resources up 28 per cent to 369 mmboe. Reserve replacement of 460 per cent Material progress on major development projects commercialising past exploration successes and adding value to recent acquisitions New gas sales agreements in Singapore and Indonesia Successful acquisitions in the UK and Indonesia adding low cost barrels at around US$2 per barrel; Scott field acquisition achieved payback by year-end New exploration and appraisal acreage awarded in Norway and Vietnam Significant joint venture established with Emirates International Investment Company LLC for opportunities in the Middle East and North Africa FINANCIAL Operating cash flow up 10 per cent to US$269.5 million (2006: US$244.8 million) Operating profit up 35 per cent to US$219.4 million (2006: US$162.6 million) Profit after tax of US$39.0 million (2006: US$67.6 million), after deducting non-cash hedging charges Low cost financing in place to fund development programme of ~US$1 billion in Strong balance sheet with cash resources of US$332.0 million and net cash of US$79.0 million (2006: US$40.9 million). Undrawn facilities at year-end were US$223.8 million 2008 OUTLOOK Development approvals expected on three major projects during 2008 Increasing production to meet 50,000 boepd target by end 2010 Extensive drilling programme in Vietnam for up to 24 months 13 well exploration and appraisal programme

20 02 Sir David John KCMG Chairman CHAIRMAN S STATEMENT Premier's operating results for 2007 reflect rising production and strong oil and gas prices. With success in commercialising undeveloped reserves, confidence in our growth profile is increasing. Financial and operating performance Rising oil and gas prices, notably in the second half of the year, generated sales revenues of US$578.2 million in 2007 (2006: US$402.2 million) further benefiting from strong gas demand in both Singapore and Pakistan. Average production for the year rose 8 per cent to 35,750 barrels of oil equivalent per day (boepd) (2006: 33,000 boepd). Production from the Scott field, where we increased our interest during the year to per cent, boosted our UK production and paid back our acquisition consideration during the first six months of ownership. Operating cash flow after tax was US$269.5 million (2006: US$244.8 million) for the year, funding all of our investments in exploration, development projects and acquisitions completed during the year. In May 2007, a convertible debt offering of US$250 million was heavily over-subscribed and provides seven-year funding at a coupon rate of only per cent. Cash resources at 31 December 2007 were US$332.0 million (2006: US$40.9 million). Undrawn facilities at year-end were US$223.8 million. Operating profit for the year rose 35 per cent to US$219.4 million (2006: US$162.6 million). Profit before tax for the year was US$147.0 million (2006: US$156.6 million) after recognising a US$64.9 million charge representing a mark to market revaluation of our existing hedging arrangements. This is a non-cash charge which is expected to reverse out over the life of the hedges. Profit after tax and mark to market revaluation charge was US$39.0 million (2006: US$67.6 million). Oil and gas proven and probable booked reserves increased to 212 million barrels of oil equivalent (mmboe) (2006: 152 mmboe). We also increased our contingent resources by a net 20 mmboe bringing total reserves and resources to 369 mmboe (2006: 289 mmboe). Significant reserve additions included the acquisition of the Scott field interest and an additional 25 per cent equity in North Sumatra Block A. Reserves associated with our development project in the Natuna Sea (Gajah Baru) which commercialises previous exploration successes have been booked for the first time. A major achievement in 2007 was the progress made in advancing new projects both technically and commercially. Agreement with gas customers in Singapore, Batam and North Sumatra has been reached on attractive terms. These projects are scheduled for final investment approval during 2008, together with our oil development in Vietnam. Our exploration programme in 2007 delivered four successes from 11 exploration and appraisal wells. The Chim Sáo (formerly Blackbird) sidetrack, drilled early in 2007, encouraged us to move into the development stage for that project. We are returning to Vietnam to drill the Chim Sáo North appraisal well in March 2008 and continue a potentially high-impact programme for a further three wells. Altogether we plan around 13 exploration and appraisal wells and 18 development wells in We also continue to build our programmes for future years with new licence awards in Norway and Vietnam, seismic surveys under way in Norway, Vietnam and Indonesia and a two-well exploration programme planned for Congo in late 2008 or early Our efforts on improving our health, safety and environmental performance standards have again resulted in us beating our internal targets. We seek continued improvements year-onyear in this area. For the first time our policies will include a focus on carbon emission targets. Our 2007 Social Performance Report will be published in April 2008.

21 03 A major achievement in 2007 was the progress made in advancing new projects both technically and commercially. Agreement with gas customers in Singapore, Batam and North Sumatra has been reached on attractive terms. Shareholder returns During 2007, Premier shares increased in value by 6 per cent, contributing to an increase of 352 per cent over the five year period to 31 December This strong performance and the attractive returns expected from our investment programme have reinforced our policy to reward shareholders principally through share price growth and to utilise cash flows within the business. Board changes We were pleased to announce the appointments of David Lindsell and Michel Romieu as non-executive directors in January Both have had distinguished careers in their respective fields and will provide invaluable input to the Board. Two non-executive directors, Scott Dobbie and Ron Emerson, will retire in June 2008 after combined service of 14 years on the Board. We are enormously grateful for their outstanding contributions over a long period of time. Outlook Current production has exceeded 40,000 boepd during the early months of Significant milestones have already been achieved on our key development projects. We have commercialised previous exploration successes and added to our booked reserve base. This gives us increasing confidence that our production target of 50,000 boepd by the end of 2010 will be achieved. Further significant progress will be made on these projects during also offers potential to add a new generation of projects with drilling campaigns in Vietnam, Norway and Congo being planned and executed. This combination of exploration, appraisal and development projects offers shareholders a wide portfolio of growth opportunities which our strong financial position allows us to pursue. Sir David John KCMG Chairman

22 04 Simon Lockett Chief Executive CHIEF EXECUTIVE S REVIEW Proved and probable reserves (mmboe) Production and reserves 2007 has seen key milestones in a number of our development projects. These are material steps forward in achieving, at a minimum, our production target of 50,000 boepd by end 2010 and in growing our portfolio of four regional businesses. Working interest production for 2007 averaged 35,750 boepd. Comparable production from 2006 was 33,000 boepd. Production comprised 34 per cent liquids and 66 per cent gas, with Pakistan and Indonesia accounting for 36 per cent and 34 per cent of the total respectively, the UK 28 per cent and West Africa the remainder. On an entitlement basis, group production for the year was 31,450 boepd (2006: 28,900 boepd). 50 Working interest Entitlement Production boepd boepd boepd boepd Asia 12,000 11,550 7,900 7,800 Middle East-Pakistan 12,700 12,150 12,700 12,150 North Sea 9,850 6,850 9,850 6,850 West Africa 1,200 2,450 1,000 2,100 Total 35,750 33,000 31,450 28,900 As at 31 December 2007 proven and probable reserves, on a working interest basis, based on Premier and operator estimates, were 212 mmboe. This represents a 39 per cent increase in net proven and probable reserves since 31 December Proven and probable reserves mmboe Reserves and contingent resources mmboe Start of Production (13) (13) Net additions and revisions End of At year-end, reserves comprised 18 per cent liquids and 82 per cent gas. The equivalent volume on an entitlement basis amounted to 183 mmboe (2006: 132 mmboe). Booked reserve additions and revisions include an increase in booked reserves in Indonesia West Natuna Sea Block A resulting from an additional Gas Sales Agreement (GSA), and the North Sumatra Block A gas development for which a GSA has been signed with the PIM Fertilizer Plant. Significant reserve additions also included the acquisition of the Scott field interest. There were reserves increases on the Kakap field in Indonesia and the Zamzama field in Pakistan. In the UK, a reduction in Wytch Farm reserves was offset by increased reserves on the Kyle field. Contingent resource bookings have increased to include the Banda gas discovery in Mauritania, the Kuala Langsa gas discovery in North Sumatra Block A, the Bream discovery in Norway and the Chim Sáo oil field in Vietnam where an Outline Development Plan was submitted. These volumes, together with others in the process of being commercialised, give increased total reserves and contingent resources of 369 mmboe (2006: 289 mmboe).

23 05 "Premier is extremely well placed to meet its stated production target of 50,000 boepd by end 2010 from existing assets. Our focus is turning to the next phase of growth through exploration, appraisal and acquisition. Exploration and appraisal Premier has continued to drill up and expand its exploration portfolio during It has participated in 11 exploration and appraisal wells giving four successes; eight of these wells have been drilled by Premier s operations team. It has acquired new seismic data, and reprocessed old data, to generate new prospects for 2008 and subsequent drilling, and it has sought out and signed new licences in Norway and Vietnam. Exploration spend on drilling and seismic in 2007 was US$104.7 million pre-tax (post-tax and recoveries: US$77.5 million). Costs of the exploration programme were reduced from original estimates by prudent farm-outs in the UK, India and Guinea Bissau. A focus of exploration effort in 2007 was in Vietnam on our Block 12W Production Sharing Contract (PSC); our Chim Sáo sidetrack, drilled early in 2007, confirmed the down-dip extent of the 2006 Chim Sáo discovery. Subsequently a large 3D survey (1,600km 2 ) was acquired over the block, enabling us to confirm several other prospects that are to be drilled in our 2008 programme. Premier s farm-in to the adjacent block, the 07/03 (formerly Block 7&8/97) PSC, was ratified by the Vietnamese authorities during the year, allowing us to assume operatorship and to accelerate the exploration of this large, under-explored block; a 2D survey is planned in 2008 with drilling planned for We have been actively building up our Vietnamese knowledge and have been granted another, previously underexplored, licence Block /05, formally signed in February PERFORMANCE Premier also had an active year in Indonesia, with two discoveries, Pancing and Ibu Lembu, the signing of two new blocks, the Tuna and Buton PSCs, and the purchase of additional equity in our North Sumatra Block A acreage. These new blocks provide an exciting set of exploration prospects, and in the case of the North Sumatra acreage will in addition include appraisal of earlier discoveries. In Pakistan we participated in the successful Qadirpur Deep-1 well, targeting hitherto undrilled reservoir zones below the Qadirpur field. A similar well, targeting sands below the Badhra field was spudded in January Premier also drilled some high-potential but high-risk exploration wells during the year; in advance of drilling we prudently reduced our financial exposure by farming out the well costs on favourable terms. These wells included Masimpur-3 in India, Peveril in the UKCS, two wells offshore Guinea Bissau and the Anne-1 well offshore Pakistan. In the North Sea region we evaluated new opportunities and subsequently acquired new exploration licences: five in Norway and one in the UK. Looking ahead to 2008, the exploration focus will be in South East Asia, where we plan to drill several exploration wells in Vietnam Block 12W that, if successful, will enhance and extend our Chim Sáo development hub. We will acquire 2D seismic surveys in the contiguous Block 07/03 in Vietnam and Tuna in Indonesia, defining prospects for a 2009 drilling campaign. We will be active with the drill-bit in the North Sea where we will be targeting a shallow oil prospect in Block 23/22b in the UK having farmed-out the well costs on favourable terms, and in Norway where an appraisal well will be drilled on the Bream oil discovery. In West Africa we have firmed up large prospects in the Congo Marine Block IX permit and are in the early stages of planning our first well to be drilled in late 2008 or early 2009 depending on rig availability. Planned spend on exploration and appraisal drilling and seismic in 2008 is US$110.0 million pre-tax (post-tax and recoveries: US$75.0 million).

24 06 CHIEF EXECUTIVE S REVIEW (CONTINUED) Asia India Vietnam Philippines Indonesia Premier s core asset in Indonesia is in the West Natuna Sea, where it operates the Anoa field in Block A (28.67 per cent interest) and is a partner in the Kakap field (18.75 per cent interest). These fields supply gas under a long-term sales contract to Singapore. In 2007, Premier sold an average of 137 billion British thermal units per day (BBtud) gross from the Anoa field and a further 66 BBtud gross from the non-operated Kakap field, under this agreement. Indonesia Gross oil and condensate production from these two fields averaged 2,498 barrels of oil per day (bopd) for Anoa (2006: 2,581 bopd) and 7,977 bopd for Kakap (2006: 6,998 bopd). Anoa is showing a slow natural oil decline as it matures, but has the potential for further drilling in 2009 to reverse this trend. Kakap meanwhile has benefited from the drilling of the Jangkar well in 2006 and enjoyed improved performance and a full year s net production in 2007 of 1,495 bopd (2006: 1,312 bopd). Overall net production from Indonesia increased to 12,000 boepd in 2007 (Anoa contributing 8,190 boepd and Kakap 3,810 boepd), compared with 11,550 boepd in The improvement is attributable to increased gas demand from Singapore and increased oil production on Kakap. On the Gajah Baru development, Premier met its 2007 goal to have definitive agreements in place for further gas sales from Natuna Sea Block A and retains its target to start producing this gas in Heads of Agreement were signed with Sembcorp Gas Pte Ltd for supply of gas to Singapore and with PT Palayanan Listrik Nasional Batam and PT Universal Batam Energy for domestic supply of gas to Batam. Engineering work confirmed the development concept for the three fields supplying the gas (Gajah Baru, Naga and Iguana) and a draft Plan of Development was submitted to the government. Negotiations with the Singapore buyer were completed on 29 February 2008 and the current focus is on conclusion of ancillary agreements. Formal government approval of field development plans and the award of major construction contracts are expected later in saw three exploration wells drilled in Indonesia. In Natuna Sea Block A, the Ibu Lembu-1 well was drilled to prove the hydrocarbon potential in the adjacent up-dip structure to the 2006 Lembu Peteng-1 discovery. The well encountered gas in the primary target but following the running of an extensive data acquisition programme was plugged and abandoned as sub-economic. The second well, Gajah Sumatera-1 was drilled to appraise a potential extension to the Gajah Puteri field in Natuna Sea Block A. While the well encountered some gas shows while drilling, wireline logs indicated that no significant hydrocarbons were encountered and the well was plugged and abandoned. Further technical studies are being carried out in the area to define the hydrocarbon-bearing sand distribution proven by adjacent wells. The Pancing-1 well was drilled in the Kakap Block to test a deep structure close to existing infrastructure. The well flowed oil although at subeconomic rates, however the well s results are significant in encountering hydrocarbons in an under-explored play in the area, raising the possibility of further exploration potential exploration activities within Natuna Sea Block A will focus on maturing and highgrading the existing prospects and leads for an anticipated 2009 drilling programme. Premier completed the joint acquisition with Medco of ConocoPhillips 50 per cent share of North Sumatra Block A in January 2007, bringing our interest to per cent. Negotiations to sell gas from the undeveloped Alur Siwah, Alur Rambong and Julu Rayeu fields progressed well through the year culminating in a December signing of a Gas Sales and Purchase Agreement with two fertilizer plants owned by PT Pupuk Iskandar Muda (PIM), a state-owned entity, for the delivery of 110 BBtud gross for seven years. A second gas sale to Palayanan Listrik Nasional (PLN) for local electricity generation is progressing well with an expectation of completing agreements in the first quarter of Development studies were ongoing through the year with a Plan of Development submitted in December. Project sanction is anticipated by mid-2008.

25 07 Technical studies including field mapping and sampling took place on the Buton PSC on the south-eastern side of Buton Island, Sulawesi, with the aim of firming up multiple leads originally identified from satellite imagery. Towards the end of the year a contract was awarded for the acquisition of 265km of 2D seismic data across the block. The survey commenced in January 2008 and is expected to take approximately six months to complete. The data will help to high-grade the acreage and focus on identifying a high-impact drilling opportunity for Premier has a non-operated 30 per cent equity interest in the block. In March, Premier was awarded a 65 per cent operating equity interest in the Tuna PSC in the North East Natuna Sea. The block covers 4,992km 2 and lies south of Premier s operated Block 07/03 and Block 12W in Vietnam and to the east of the Natuna Sea Block A and Kakap PSCs in Indonesia. The Tuna PSC represents an under-explored area in the middle of a region in which Premier has a strong technical understanding. Multiple leads have been identified which will be followed up in 2008 with the acquisition of new seismic data leading to the drilling of two wells on the block. Vietnam Following the discovery of the Chim Sáo and Dua oil fields in 2006, Premier acquired and interpreted 3D seismic data in the first half of The development plan is to produce first oil in 2010 from two wellhead platforms on the Chim Sáo field with production from a third wellhead platform on the Dua field following in Oil will be processed and stored on a leased FPSO facility located between the fields. During December, Premier submitted reserve reports and development plans for these fields to the Government of Vietnam. The Reserve Assessment Report was approved on 4 March Approval of the development plan is targeted for mid During 2007, Premier and the Government of Vietnam agreed the merger of Block 12E into Block 12W and extension of the exploration period of the merged PSC until late Detailed interpretation of the 3D seismic data acquired in 2007 defined several exploration prospects. These will be drilled with the Wilboss jack-up rig; drilling will commence in mid-march 2008 with a well in the northern part of the Chim Sáo field. The rig will then drill three exploration wells including the Chim Ung (Falcon) well, which will test a prospect on trend with Chim Sáo, and the high-impact Chim Công (Peacock) prospect. The programme will target reserves in excess of 200 million barrels (mmbbls) with the ability to tie-back discoveries into the core Chim Sáo development. Premier operates a 37.5 per cent exploration working interest in Block 12W. PERFORMANCE During 2007, Premier assumed the operatorship of Block 07/03 with a 45 per cent exploration working interest. A comprehensive interpretation of the existing seismic data identified several potentially high-impact prospects over which further seismic will be acquired in Premier is actively seeking a drilling unit to drill exploration wells in Block 07/03 during India Discussions continue with the Government of India to resolve outstanding issues with respect to the Ratna field development. The Ratna fields lie in shallow water offshore Mumbai and are estimated to contain around 80 mmbbls. Premier has a 10 per cent carried interest and is the operator. The Masimpur-3 well in Cachar was successfully drilled with costs being carried in part. The well did not flow commercial gas or oil volumes during testing and was plugged and abandoned. The PSC will now terminate since no commercial discovery has been made during the exploration period. Philippines Premier entered 2007 holding a 42.5 per cent operated participating interest in Philippines Licence SC43 located in the Ragay Gulf area of SE Luzon. During the course of the year Premier farmed-out the operatorship of SC43 and a 21.5 per cent participating interest, leaving Premier with a 21 per cent participating interest. In exchange for this consideration all of Premier s costs relating to the Monte Cristo-1 exploration well, which is expected to be drilled in the first half of 2008, will be carried. In the fourth quarter of 2007 a 371km 2D marine seismic survey was carried out on the same licence over a prospective trend in the Panaon Limestone formation. This data is currently being processed.

26 08 CHIEF EXECUTIVE S REVIEW (CONTINUED) Pakistan Middle East-Pakistan Pakistan Production in 2007 surpassed the previous record levels achieved in Production net to Premier in 2007 was 12,700 boepd, an increase of 5 per cent on last year (2006: 12,150 boepd). This additional volume was due to increased gas demand and was primarily met through additional supply from the Zamzama field. Egypt Qadirpur produced an average of 3,980 boepd from Premier s net interest of 4.75 per cent (2006: 3,866 boepd). The project to enhance Qadirpur plant capacity from 500 million standard cubic feet per day (mmscfd) to 600 mmscfd continued during 2007 and first gas from that increased capacity is expected by the end of April In addition to the above, negotiations are ongoing with the existing gas buyer for an additional supply of 75 mmscfd permeate gas (equivalent to 40 mmscfd processed gas) for subsequent use in power generation. First gas is expected in The Qadirpur Deep-1 well was drilled to a depth of 4,681 metres in 2007 encountering hydrocarbons in several zones. The well was suspended following higher than anticipated temperatures and pressures. Specialised equipment has since been ordered and testing of the well is expected to resume in the second quarter of On Kadanwari, the K-18 well was drilled and tested successfully during 2007, and brought onstream in February Additional production from K-18 will more than compensate for the natural field decline in In 2007 the field produced an average of 1,260 boepd (2006: 1,200 boepd) from Premier s per cent net interest. An additional well is planned to be drilled in the second half of Zamzama produced an average of 4,620 boepd in 2007 (2006: 4,140 boepd) from Premier s 9.37 per cent interest. Work continued in 2007 on the Zamzama Phase 2 development project, to produce gross 150 mmscfd High Calorific Value (HCV) gas for sale, but plant problems mean that only Medium Calorific Value (MCV) gas can currently be supplied. HCV deliveries are expected to be achieved later in Bhit production was 2,840 boepd in 2007 (2006: 2,944 boepd) from Premier s 6.00 per cent working interest. The slight fall in production in 2007 was due to an extended shut down for Phase 2 tie-in work. Work on the Phase 2 project to enhance Bhit plant capacity to 315 mmscfd is now complete allowing accelerated Bhit field production and delivery of first gas from Badhra reserves. The Badhra South-1 well spudded in January 2008 to prove additional reserves in the Mughalkot reservoir. In the event of success, the well will be deepened to test three identified sand lobes. The well is expected to complete in the third quarter of On Zarghun South, negotiations on the Pipeline Tariff Agreement were concluded with the gas buyer (a condition precedent for the already agreed GSA). First gas is planned for the first quarter of Premier s interest of 3.75 per cent in this asset is carried by the operator during the development and production phases of the field. Egypt In September 2007 Premier reduced its equity in the North West Gemsa Concession from 37.5 per cent to 10.0 per cent resulting in a reimbursement of some previous costs from the operator. During the latter part of the year, the operator conducted geological studies to define the SE Al Amir prospect which is scheduled for drilling in March Abu Dhabi Shareholder agreements were executed in December with Emirates International Investment Company LLC (EIIC), forming two new joint venture companies. These companies will pursue the acquisition of upstream oil and gas assets across the Middle East and North Africa, and will be headquartered in Abu Dhabi. The first joint venture, to be known as PREMCO, will be owned 49 per cent by Premier and 51 per cent by EIIC and will hold all joint venture assets which are acquired in the U.A.E. In the event of a change of control of Premier, EIIC will have a pre-emptive right to purchase Premier s 49 per cent of this joint venture at fair market value.

27 09 The second joint venture, to be known as PREMBV, will be owned 50 per cent by Premier, 50 per cent by EIIC, and will hold all joint venture assets which are acquired in the Middle East and North Africa (excluding the U.A.E). At the formation of the joint ventures, there will be no assets or profits attributable to these new entities. Future acquisitions of new assets by each joint venture will be funded by Premier and EIIC in accordance with their relevant percentage holding. This joint venture partnership will enable Premier to access acquisition opportunities across the Middle East and North Africa via EIIC s relationship networks, whilst EIIC will benefit from Premier s industry expertise and operating capabilities. North Sea United Kingdom Norway During 2007, Premier continued with its stated strategy of building the North Sea exploration portfolio to seek high-impact exploration drilling opportunities while maximising the value from existing production and development assets. UK Production in the UK amounted to 9,850 boepd (2006: 6,850 boepd) representing 28 per cent of the group total (21 per cent in 2006). The increase, compared to 2007, is due to a combination of improved field performance across most of the producing assets and the impact of the Scott field acquisition completed on 17 May The Wytch Farm oil field contributed 2,960 boepd net production to Premier, down 8 per cent on last year. Production was adversely impacted by problems with the M19 well, offset by an A08 sidetrack well which was drilled and completed in September. Drilling is continuing on the M20 water injection well, to be completed in 2008 as part of the Phase 1 water handling project. Seawater injection service was also reinstated after a prolonged outage. The shortfall in production due to the drilling problems was partly compensated by better than expected production rates from the remaining wells and successful workover activities. PERFORMANCE Net production from Kyle was 2,470 boepd, an improvement of 26 per cent on last year from better well performance. The gas lift project was completed for all four production wells resulting in a substantial boost in production with initial gross rates around 9,000 boepd. The K-16 well has been delayed until at least 2009 pending further evaluation. Premier completed the purchase of an additional per cent equity in the Scott field in May 2007 adding an average of 5,240 boepd net over the remainder of the year. As a result of this transaction, Premier s working interest has become per cent. The Scott field gross production for the year was 27,750 boepd; this amounted to a full year average of 3,630 boepd net to Premier at the combined equity levels. Telford produced slightly below expectations during 2007 following disappointing results from the Marmion well; gross field production averaged 9,560 boepd (70 boepd net to Premier) saw the completion of a substantial infill drilling programme consisting of six wells on Scott and one well on Telford. Future targets are being evaluated for a further campaign starting in the fourth quarter of In the Fife Area, Premier s net production amounted to 720 bopd, below expectation due to major integrity issues with the flexible risers. The operator has made a recommendation to suspend production in May 2008 and remove the Uisge Gorm floating production unit. Premier has retained the right to redevelop the area with an alternative facility. Premier operated the Peveril prospect well, located only 10km south of the Fife field, which was completed within budget at no cost to Premier. The Peveril well encountered an unexpectedly thick interval Kimmeridge Clay and no target Fife reservoir sands. In the UK 24 th Licensing Round, Premier was awarded a split portion of 15/24a. The firm work programme includes seismic reprocessing and study work. In February 2008, agreement was reached with Oilexco for a well to be drilled on the Sparrow prospect, on P1181. This will be spudded mid-march Oilexco will carry Premier through the well and Premier will retain a 25 per cent interest post completion.

28 10 CHIEF EXECUTIVE S REVIEW (CONTINUED) Norway On the Frøy field in Norway, development planning is progressing. Following concept selection in September, lease/purchase bids were sought for the jack-up production drilling storage and offtake unit. These show significant increases on previous budgetary estimates submitted by suppliers; the operator has been requested to implement a major cost reduction exercise to bring investment down to an acceptable level. The operator is also investigating third-party business opportunities and exploration upside to improve the robustness of the project as well as tackling other key issues such as contract guarantees. The partnership issued a Declaration of Continuation at the beginning of January; submission of the Plan of Development is expected during 2008 provided viability of the chosen concept can be confirmed. Premier was awarded a further five licences in the APA Licensing Round in January Building on the APA 2005 portfolio, Premier was successful in capturing two of the most sought after blocks in the 2006 APA round: the Bream appraisal licence and the adjacent Bream exploration licence, PL407 and PL406 respectively. The Bream field was initially discovered in 1971 but no development decision was reached. Interpretation of the 2005 PGS 3D dataset across the structure suggests that between mmbbls reserves may be present. The planning for the commitment appraisal well is at an advanced stage and is scheduled to be drilled in the first half of The exploration licence adjacent to Bream is Premier s first operated licence in Norway. This has the potential to add between mmbbls reserves to the proven Bream accumulation. Premier will be acquiring 500km 2 of new 3D across the PL406 licence in March 2008 using PGS s Ramform Sovereign vessel with a firm well on PL406 planned for mid The three other licences Premier was awarded were PL418 and PL419, down-dip from the Gjoa discovery and PL417 adjacent to our existing licence PL378. West Africa SADR Mauritania Congo Mauritania Chinguetti production averaged 14,800 boepd (1,200 boepd net to Premier) in Drilling of the Chinguetti-18 well was completed in the first quarter of 2007, in line with expectations, and a work-over was conducted on Chinguetti-14. Operational planning was progressed for the Phase 2B development of Chinguetti in 2008 comprising two new production wells and three work-overs. High resolution 3D seismic surveys were recorded over the Chinguetti and Tiof areas in Integration of newly acquired data into existing field models is currently being finalised. A 4D seismic survey was also recorded over the Chinguetti field, which greatly assists selection of production well locations for the Phase 2B development programme. In 2007, Premier terminated discussions with a preferred bidder for its Mauritanian operations. In late 2007, Petronas acquired Woodside Energy s assets, and operatorship, in Mauritania PSC A, PSC B and Chinguetti. Opportunities and development options on PSCs A and B continue to be evaluated with the new operator. The PSC B joint venture plans to drill the Banda-NW well in April 2008 with the objective of further defining Banda gas and oil resources, and to assess its commercial viability. In addition, Tiof will be re-evaluated with the integration of 2007 high resolution 3D seismic data with an expectation of progressing this discovery to a development decision. The joint venture will re-assess the exploration potential of the blocks during The Atwood Hunter drilling rig has been contracted for the Chinguetti Phase 2B and Banda-NW appraisal programme, which is expected to commence in April 2008 and to be concluded by August 2008.

29 11 Guinea Bissau Premier operated a two-well exploration programme during the first half of the year, using the Global Santa Fe jack-up rig Baltic. The wells were completed within budget and without incident. Premier reduced its exposure to the drilling costs by farming out some of its interests. The Espinafre-1 well was plugged and abandoned on 23 March 2007 after encountering hole stability problems. The Eirozes-1 well was plugged and abandoned on 24 April This well encountered a significant reservoir section but no hydrocarbons. Following post-well analyses and re-assessment of the remaining prospectivity of the Sinapa and Esperança Permits, Premier effectively withdrew from both concessions in Guinea Bissau in December Gabon The Themis Permit (non-operated) is located in the Gamba play fairway, offshore southern Gabon. The Themis PSC joint venture commenced drilling the Themis Admiral Marin-1 (THAM-1) well in December 2007; the well was plugged and abandoned with hydrocarbon shows on 13 January The Dussafu Permit (non-operated) is located south of Themis, adjacent to the Congolese border. The PSC was extended to a Second Exploration Term effective May 2007, with a 2D seismic commitment. In December 2007, Premier signed a Sale and Purchase Agreement with a qualified party to acquire Premier s 25 per cent participating interest in the Dussafu PSC. The transaction was completed on 8 March Congo Significant progress has been made in the evaluation of the deep water Marine Block IX exploration acreage. Premier, as operator, has conducted a detailed evaluation of Albian raft prospectivity, the characteristic proven play in the area. This has identified the Frida and Ida prospects, both in excess of 250 mmbbls gross potential. The joint venture is also mapping the potential of Tertiary channel sands that have proven productive in the adjacent Haute Mer Concession. PERFORMANCE Premier and its joint venture partner are actively progressing planning for a discretionary drilling programme of up to two wells in late 2008, or early Completion of this programme is subject, among other issues, to rig availability. Premier is in advanced discussions with a party to farm-in to Premier s equity interest in Marine Block IX in return for a carry of its costs. SADR The company s exploration rights in the Saharawi Arab Democratic Republic (SADR) remain under force majeure, awaiting resolution of sovereignty under a United Nations mandated process.

30 12 Tony Durrant Finance Director FINANCIAL REVIEW Operating profit ($ million) Economic environment 2007 was another year of record oil and gas commodity prices, approaching US$100 per barrel (bbl) towards the end of the year. The Brent oil price, which began the year at US$60.1/bbl, averaged US$72.7/bbl, reaching a peak of US$95.8/bbl during November. Gas prices worldwide were also boosted according to the degree of linkage with crude oil. The early part of 2008 has seen increased volatility in commodity prices. The fragile health of the global economy has put downward pressure on average 2008 prices but this has been more than offset by supply concerns and average 2008 prices are currently above US$90/bbl. The sustained period of stronger commodity prices and increased industry activity levels have put further pressure on both operating and development costs. Rig rates and other drilling service costs are at historically high levels. Shortages of experienced staff and longer lead times for development equipment added further cost pressures on the industry. The industry is responding to cost and availability issues by optimising the use of available resources, innovative resource-sharing and focussing on fast track development solutions. Income statement Production levels in 2007, on a working interest basis, averaged 35,750 boepd compared to 33,000 boepd in On an entitlement basis, which allows for additional government take under the terms of our PSCs, production was 31,450 boepd (2006: 28,900 boepd). Realised oil prices averaged US$72.3/bbl compared with US$64.9/bbl in the previous year. Gas production averaged 135 mmscfd (23,500 boepd) during the year, or approximately 66 per cent of total production. Average gas prices for the group were US$5.60 per thousand standard cubic feet (mscf) (2006: US$5.11/mscf). Gas prices in Singapore, which are linked to High Sulphur Fuel Oil (HSFO), have moved broadly in line with crude pricing, averaging US$11.30/mscf (2006: US$9.43/mscf) during the year. Following the group s decision to terminate discussions with a preferred bidder, the financial results for Mauritanian operations are no longer required to be presented separately. The corresponding amounts for 2006 have been re-presented accordingly. During the year, the group also restructured its business in Pakistan by de-merging interests from the Premier-KUFPEC Pakistan joint venture and now fully consolidates its share of operations in Pakistan. This restructuring had no impact on the consolidated financial statements. Total sales revenue from all operations was 44 per cent higher than 2006 at US$578.2 million (2006: US$402.2 million) as a result of higher production and commodity prices. Cost of sales was US$267.5 million (2006: US$179.2 million) after including a cost of US$26.8 million for inventory acquired with the Scott field acquisition. The year-end inventory position moved from a stock overlift to an underlift position, driven by the timing of liftings around each year-end, and resulted in a charge to cost of sales of US$27.3 million (2006: credit of US$22.4 million). After excluding the effect of inventory movements, underlying unit operating costs were higher at US$9.0 per barrel of oil equivalent (boe) (2006: US$7.1/boe) due to one-off cost increases in Indonesia and increased production from the Scott field in the North Sea. Unit amortisation amounted to US$8.2/boe (2006: US$7.9/boe). Exploration expense and pre-licence exploration costs amounted to US$65.3 million (2006: US$21.8 million) and US$8.3 million (2006: US$21.8 million) respectively, after taking into account a US$25.7 million write-down of costs in Guinea Bissau. Administrative costs were stable at US$17.7 million (2006: US$16.8 million). This included a charge of US$4.7 million (2006: US$5.7 million) in respect of current year and future provisions for long-term incentive plans.

31 13 Total sales revenue from all operations was 44 per cent higher than 2006 at US$578.2 million (2006: US$402.2 million) as a result of higher production and commodity prices. Cash flow from operating activities ($ million) Operating profits were US$219.4 million, a 35 per cent increase from the prior year. Finance charges net of interest income totalled US$7.5 million (2006: US$4.0 million). Pre-tax profits were US$147.0 million (2006: US$156.6 million). This included a significant non-cash item relating to mark to market revaluation of the group's oil and gas hedges totalling US$64.9 million (pre-tax). Such accounting losses arise as oil and gas prices increase, however, given the current range of spot and forward prices it is not expected that the hedging programme will have any material cash flow impact on the group. The tax charge totalled US$108.0 million (2006: US$89.0 million) due to underlying higher taxable profits. Basic earnings per share amounted to 47.6 cents (2006: 82.6 cents). Cash flow Cash flow from operating activities, before movements in working capital, amounted to US$408.1 million (2006: US$310.8 million). After working capital items and tax payments, cash flow from operating activities amounted to US$269.5 million (2006: US$244.8 million). Capital expenditure was US$261.2 million after inclusion of asset acquisition costs of US$88.6 million. Capital expenditure $ million $ million Fields/developments Exploration Acquisitions Other Total PERFORMANCE The principal development projects were the Kyle gas lift project in the UK, the West Lobe development in Indonesia and the Zamzama Phase 2 development in Pakistan. Exploration costs of US$104.7 million take into account savings of US$30.9 million due to farm-outs in Guinea Bissau, the UK and India. Net cash position Net cash at 31 December 2007 amounted to US$79.0 million (2006: net cash of US$40.9 million) following the successful completion of a US$250 million convertible bonds issue in June. This funding provides seven-year fixed rate debt at a cash coupon of per cent and, together with our undrawn bank facilities, contributes substantially towards the financing of Premier's significant development programme over the next three years. Net cash $ million $ million Cash and cash equivalents Convertible bonds* (200.0) Other long-term debt** (53.0) Net cash * Excluding unamortised issue costs and allocation to equity. ** Excluding unamortised issue costs.

32 14 FINANCIAL REVIEW (CONTINUED) Net cash/(debt) ($ million) Hedging and risk management The Board s policy remains 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 by selling calls 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 2007 zero cost collar oil hedges for a further 2.4 mmbbls were entered into by extending the maturity of the collars to the end of This increased the average floor price from US$38.55/bbl to US$39.3/bbl whilst maintaining the cap at US$100.0/bbl. During 2007 hedges for 1.8 mmbbls matured for which no cash settlement under the terms of the collars was made. At the end of 2007 a four and a half-year physical off-take agreement for the sale of certain oil production was entered into with effect from 1 July This agreement for 8.1 mmbbls incorporates the parameters of existing oil collars and effectively replaces the equivalent amount of hedging. In addition, zero cost collars for a further 150,000 metric tonnes (mt) of HSFO were entered into which raised the average floor price from US$245/mt to US$250/mt whilst maintaining the cap at US$500/mt. During 2007 hedges for 120,000 mt matured for which a small payment under the terms of the hedges was made during the year. At the end of 2007, a total of 642,000 mt of HSFO was hedged (approximately 120,000 mt per annum) representing approximately one third of Indonesian gas production, until June Under International Financial Reporting Standard (IFRS) zero cost collar hedges are required to be marked to market at the balance sheet date. The aggregate valuation is a US$65.2 million liability (2006: US$0.3 million liability) generating a US$64.9 million non-cash pre-tax charge in the 2007 income statement. The entry into the physical off-take agreement for oil production from 1 July 2008 will reduce the volatility of mark to market revaluations on the income statement. The existing US$37.9 million provision in respect of oil hedges will be written back to the income statement over the life of these hedges. Since the group now reports in US dollars, exchange rate exposures relate only to Sterling receipts and expenditures, which are hedged in dollar terms on a short-term basis. The group recorded a loss of US$0.4 million on such hedging at year-end. Cash balances are invested in short-term bank deposits, AAA managed liquidity funds and A1/P1 commercial paper subject to Board approved limits. The group undertakes an insurance programme to reduce the potential impact of the physical risks associated with its exploration and production activities. In addition, business interruption cover is purchased for a proportion of the cash flow from producing fields. Key performance indicators Change LTI and RWDC frequency rate* Up 50% Production (kboepd) Up 8% Cash flow from operations ($ million) Up 10% Operating cost per boe ($) Up 27% Gearing** 0% 0% Realised oil price per barrel ($) Up 11% Realised gas price per mcf ($) Up 10% * Lost time incidents (LTI) and restricted workday cases (RWDC) per million man-hours worked. ** Gearing is net debt divided by net assets.

33 15 SOCIAL PERFORMANCE REVIEW Introduction Premier aspires to be an industry leader in social performance, which we define as covering the areas of social responsibility, health and safety, and environmental impact. We set targets for these areas with reference to our historical performance, that of our peer group and the standards set by external agencies. It is our stated policy to ensure that the risks and impacts of our activities are reduced to as low as reasonably practicable (ALARP) at all times. We continue to publish a Social Performance Report every two years, and from now on in intermediate years will prepare a Communication on Progress, both of which will be available on our website. Our Social Performance Report is prepared in line with the International Petroleum Industry Environmental Conservation Association (IPIECA) Oil and Gas Industry Guidance on Voluntary Sustainability Reporting (2005). The report also takes full account of the requirements of other key organisations such as the United Nations Global Compact (UNGC) principles, FTSE4Good, the World Resources Institute Greenhouse Gas Protocol and the International Finance Corporation Equator Principles. Social responsibility Premier is keenly aware of its responsibilities as a corporate citizen. Backed by a strong Board-level commitment, we have designed and implemented a coherent set of policies that lay down the principles by which we manage our relationships with communities, the health and safety of our people and our impact on the environment. During 2007, we continued to work closely with local communities, business partners and regulatory authorities to make a positive difference within the localities where we operate. PERFORMANCE Community and society We continue to actively support social and community projects in the areas that we work. In Indonesia, we have been pleased to see delivery of projects identified by our Community Development Baseline Study, developed in close collaboration with BPMIGAS (the Indonesian oil and gas regulator) and the local community, on Matak and surrounding islands. Projects included construction of two community halls in Terempa (Siantan Island) and Payalaman (Matak Island) and the supply of clean water to five villages on Palmatak Island. Within these communities we have maintained our support for local education and welfare, including the completion of two kindergarten buildings, the sponsorship of a maternal and child health training programme and local paramedic training. We handed over management of the Anoa Kindergarten to the local community, after eight years of Premier management. We remain committed to supporting the school and have provided additional assistance through support of a pre-school teacher training programme with the aim of establishing three more schools. We have also maintained our support for the Natuna Malay Art Revitalisation Programme to preserve and promote this culture. Two local arts students were also sponsored to study a four-year course at the Institut Kesenian Jakarta. In Vietnam, we sponsored the construction of four bridges in the Mekong Delta to reduce the safety risk to local people who were previously crossing on unsafe wooden structures. We also supported the relief efforts following severe typhoon damage in the Vung Tau region.

34 16 SOCIAL PERFORMANCE REVIEW (CONTINUED) In India, we supported local charities aiding cancer patients in Delhi and the Tamanna School Project which provides free education to Delhi s street children. In the Cachar district, close to our 2007 well operations, we also supported projects in two villages to provide clean water, sanitation and waste management, and a fish farming project in conjunction with the local government. We also donated emergency equipment when the area suffered extensive flooding. Employment practices We aim to attract, develop and retain talented and committed people in order to maintain the capability of the group to deliver our business objectives. Premier s policy is to ensure equal opportunity in career development, promotion, training and reward for all our employees. We aim to ensure that all our employees understand our business goals and our values. As an international group we believe that our workforce should reflect the communities in which we operate and so it is important that we increase the quality and experience of our local employees. We also actively encourage employee exchanges between different offices and nationalities. Our objective at all times is to adhere to the highest standards of business ethics in all of our activities. We recently conducted an employee satisfaction survey, in which employees generally expressed a high level of satisfaction with respect to their working lives and a belief that social performance issues were very relevant to their work. Health and safety It is our stated policy to ensure that the risks to our employees, and contractors working on our behalf, are reduced to ALARP. We strive to continually improve our performance in the areas of both occupational health and safety, and process safety. Occupational health and safety 2007 was a year of high activity for Premier particularly with respect to exploration drilling. We conducted an offshore seismic survey in Vietnam, drilled five operated offshore exploration wells, drilled a major onshore exploration well in India, and maintained a high level of offshore drilling and production activity at the Anoa field in Indonesia. We report our safety performance in terms of significant injuries including fatalities, lost time injuries, and restricted workday cases. During the 2007 work programme we incurred seven such incidents. Four involved relatively minor injuries, two were lost time injuries and one was a contractor fatality. The resultant combined significant injury frequency was 1.8 per million man-hours for the year. We have consistently set ourselves improving safety targets over the past five years (reducing from 3.4 to 1.9). We have set our target for 2008 at 1.7 significant injuries per million man-hours. Number of lost time injuries (LTIs) 3 4 Number of restricted workday cases (RWDCs) 4 Man-hours worked (millions) Target LTI/RWDC frequency (per million man-hours worked) Actual LTI/RWDC frequency (per million man-hours worked) We benchmark our health and safety performance by contributing our data to an industry database compiled and published by the Association of Oil and Gas Producers (OGP) and our safety performance has been in line with or better than the OGP average over the past three years.

35 17 In 2007 we enhanced our improvement processes by focusing on high-potential incidents; near miss or minor incidents that could potentially have had serious consequences. This was done throughout the business by involving senior management in the review of highpotential incidents and by issuing safety alerts focusing on the lessons learnt. After embedding this process in 2007 we have now included a high-potential incident frequency target as a key performance indicator in We underwent a number of independent Occupational Health and Safety Advisory Service (OHSAS) assessments and surveillance audits on our worldwide operations to confirm compliance of our health and safety management systems with this standard. Our global drilling function retained the certification it had first achieved in June 2004 though our Indonesian production operations have further assessment ongoing. We are seeking to improve the health and wellbeing of all our employees and therefore all persons working offshore or in remote areas must undertake fitness for work health examinations. We have introduced a travel risk assessment process to ensure all business travellers are made fully aware of any specific or new health risks and appropriate contingency measures. Process safety Premier aims to utilise best industry practice wherever we operate. In Indonesia, although not a local requirement, we have adopted the UK Safety Case regime for our operated production facilities which includes a review every five years to ensure that changes to facilities have been accounted for and that risks to personnel remain ALARP. Premier will ensure that a similar regime is applied to any new operated projects that we develop elsewhere in the world. In 2007 Premier assessed the implications for our operations of findings on safety culture from recent major incidents on other facilities in the oil industry. To deliver confidence that process safety systems are fully functional, we are enhancing our maintenance management system to better monitor the performance of safety critical equipment. We continue to work towards a full, independently assessed verification scheme. Another area identified for improvement is that of operating staff competence, where we are aiming to introduce new initiatives geared to providing international vocational qualifications to help address this. PERFORMANCE In line with our desire for a robust process safety management system we have upgraded our drilling management system to strengthen the requirement therein for an independent assessment of the condition, functionality and maintenance regime of all safety critical equipment on newly contracted rigs. To capture this new process we reviewed the content of our Health, Safety and Environmental Well Assessment Measurement and have set new targets. Environmental impact Our environmental policy is to ensure that our environmental emissions and discharges are ALARP. We will also adhere to the precautionary approach outlined in the UNGC to which Premier is a signatory. Accordingly, we intend to conduct an ALARP assessment for each operated project/activity as part of its environmental aspects analysis.

36 18 SOCIAL PERFORMANCE REVIEW (CONTINUED) Premier aims to have its environmental management systems certified to International Organization for Standardization (ISO) In 2006 we achieved this goal for our Indonesian production operations, however, as a result of an audit performed in 2007, this certification was suspended. We are currently resolving the issues that were raised in order that the certification can be reinstated in We have successfully maintained ISO certification for our global drilling operations since We specifically include a requirement to assess risks to biodiversity in our Corporate Health, Safety, Environment and Security Policy and include this assessment as part of our Environmental Impact Assessment (EIA) process. We have also maintained our membership of the United Nations Environment Programme Proteus Initiative which seeks to provide the best available biodiversity data wherever practicable. We continue to engage with local stakeholders to ensure that we have all available data and that this is reflected in our EIAs. Environmental indicators In line with IPIECA we report environmental performance in the following four core areas: Oil in produced water (parts per million) Oil spills (tonnes) Greenhouse gases (tonnes per thousand tonnes of production) Energy use (gigajoules per tonne of production) For further information please refer to the 2007 Social Performance Report on our website, Spills and discharges There was no significant change in the volume of produced water discharged from our Anoa production facilities from 2006 to The concentration of oil in produced water, which improved from 21 to 20 parts per million, remained well within the limits set by the Indonesian Government. In 2007 there were 15 reported environmental incidents worldwide, down from 29 in Most of these incidents involved small spills of hydraulic oil, diesel or chemical to the deck and were not discharged overboard. We incurred four significant incidents, three of which were from the same drilling rig and involved the spill of 13.7 tonnes of synthetic oil-based mud to sea. The other significant spill involved the discharge of 28.0 tonnes of water-based mud to sea following a flowline valve failure. The spills had a very minor effect on the environment and quickly dissipated. However, three out of four of the incidents were classified as high-potential. These have been thoroughly investigated and corrective actions taken, including the aforementioned revisions to the drilling management system.

37 19 Emissions We calculate our greenhouse gas (CO 2 equivalent) emissions both in tonnes emitted and in tonnes per thousand tonnes of production for both operated and joint venture operations across our global portfolio. In 2007 we emitted approximately 222,000 tonnes of greenhouse gas in total. When based on our net production this equated to 171 tonnes per thousand tonnes of production. This shows a marked improvement compared with 2006 when we emitted 232 tonnes per thousand tonnes of production. The improvement is due in part to the efforts we have made to enhance gas compressor reliability at our production facilities. The consequent decrease in compressor downtime has resulted in a significant reduction in flaring. We benchmark our environmental performance by contributing our data to an industry database compiled and published by the OGP. Our greenhouse gas emissions performance has been in line with the OGP average over the past three years. Resource use The main sources of energy that power our facilities are fuel gas and diesel. There has been little variation in our energy use over the last few years, and energy use (gigajoules per tonne of production) in 2007 remained between 1.8 and 1.9. PERFORMANCE

38 20 BOARD OF DIRECTORS Sir David John (69), became non-executive Chairman in March He was nonexecutive Chairman of the BOC Group plc from January 1996 until January 2002 and is currently Chairman of Balfour Beatty plc and the British Standards Institution. Sir David is a Member of the CBI s International Advisory Board, and is the Chairman of Premier s Nomination Committee. Robin Allan (48), joined Premier from Burmah Oil in July 1986, working initially as a geologist. After technical and new venture roles he spent six years in South East Asia, initially managing Premier s Asian existing and new venture business and later becoming Premier s Country Manager in Indonesia. He became a member of the Premier Board on 9 December 2003 as Director of Business Development. Joe Darby (59), joined Premier s Board as a non-executive director in September Mr Darby has over 35 years of experience in the energy sector, including eight years with Shell Petroleum before becoming Managing Director of Thomson North Sea Ltd. He has held a number of senior roles, including Chief Executive, with LASMO plc. Mr Darby is currently the senior independent director at British Nuclear Fuels plc. He has held non-executive roles at Mowlem plc and Centurion Energy Inc and was Chairman of Mowlem plc ( ) and Faroe Petroleum plc ( ). Mr Darby is a member of Premier s Audit and Risk, Remuneration and Nomination Committees. Scott Dobbie (68), joined Premier s Board as a non-executive director in December He has a career background in stockbroking, as Managing Director of Wood Mackenzie and subsequently Chairman of NatWest Securities. He is currently Chairman of the Securities & Investment Institute, The Edinburgh Investment Trust plc and of Standard Life European Private Equity Trust. He is also a Commissioner of the Jersey Financial Services Commission. Mr Dobbie is a member of Premier s Audit and Risk, Remuneration and Nomination Committees. Mr Dobbie will retire from the Board at the close of the 2008 AGM. Tony Durrant (49), joined Premier in June After qualifying as a Chartered Accountant with Arthur Andersen, he joined Lehman Brothers in London, initially as an oil sector analyst. He joined the investment banking division of Lehman in 1987 and from 1997 was a Managing Director and Head of the European Natural Resources Group. In this role, he managed both client relationships and numerous transactions for a variety of European and North American clients. He is a non-executive director of Clipper Windpower plc. He joined the Premier Board on 1 July 2005 as Finance Director. Ronald Emerson (61), joined Premier s Board as a non-executive director in March He has held a number of senior positions in the banking sector, including roles at Bank of America, Nomura Bank and, most recently, with Standard Chartered Bank where he was Chief Executive of their Malaysian operations before becoming the Group Head of Corporate Banking. He was a Senior Advisor to the Bank of England between 1997 and 1998, and to the Financial Services Authority between 1998 and He is a non-executive director of Ace European Group Ltd, Noventa Ltd and the Habib Group. Mr Emerson is Chairman of Premier s Audit and Risk Committee, and a member of the Remuneration and Nomination Committees. Mr Emerson will retire from the Board at the close of the 2008 AGM. Neil Hawkings (46), joined Premier in May 2005 after more than 20 years with ConocoPhillips where he worked in a variety of engineering, commercial and management roles around the world, undertaking assignments in the UK, Dubai and Indonesia. He joined the Premier Board on 23 March 2006 as Operations Director. David Lindsell (60), joined Premier s Board in January 2008 as a non-executive director. Mr Lindsell has recently retired from Ernst & Young LLP, where he was a partner for nearly 30 years. He has extensive experience across a range of industry sectors, with a strong knowledge of the oil and gas sector. He is a member of the Financial Reporting Review Panel, a member of the Standards Advisory Council of the International Accounting Standards Board and a member of the Supervisory Board of the European Financial Reporting Advisory Group. Mr Lindsell is a member of Premier s Audit and Risk Committee. Simon Lockett (43), Chief Executive, joined Premier in January 1994 from Shell and has worked in a variety of roles for Premier, including the management of investor relations, as Commercial Manager in Indonesia and as Country Manager in Albania. He became a member of the Premier Board on 9 December 2003 as Operations Director. He was appointed Chief Executive on 24 March John Orange (65), joined Premier s Board as a non-executive director in February He held a variety of senior international management and legal posts during his 30 years with the BP Group. Mr Orange is Premier s senior independent non-executive director, Chairman of the Remuneration Committee and a member of the Audit and Risk and Nomination Committees. Professor David Roberts (64), joined Premier in June 2006 as a non-executive director. Professor Roberts has over 30 years experience in all aspects of exploration worldwide and extensive knowledge of deep water areas, sedimentary basins, stratigraphy and prospect assessment. He spent 22 years with BP in a number of technical roles, including Global Exploration Adviser and Distinguished Exploration Adviser. On his retirement from BP in 2003, Professor Roberts established his own geoscience consultancy. He is a visiting professor and fellow of Royal Holloway, University of London, the University of Southampton and IFP School in Paris. He is a non-executive director of GETECH plc. Professor Roberts is a member of Premier s Remuneration and Nomination Committees. Michel Romieu (68), joined Premier s Board as a non-executive director in January Mr Romieu has over 30 years experience in the international energy sector, including 25 years with the Elf Group, where he held several senior positions including Chief Executive Officer of Elf UK and the group s Gas Division. During his period as CEO of Elf UK, he was elected President of the UK Offshore Operator s Association for the year On his retirement from Elf in 2000, Mr Romieu became Director for Gas of CRE, the French energy regulator, a position he held until He has established his own consultancy specialising in providing advice to the gas industry, and is a lecturer at the French Petroleum Institute. Mr Romieu is also President of Uprigaz.

39 21 Sir David John Simon Lockett Tony Durrant Robin Allan Neil Hawkings Joe Darby Scott Dobbie Prof. David Roberts David Lindsell Ronald Emerson John Orange Michel Romieu GOVERNANCE