Premier Oil plc. Half-yearly Results for the six months to 30 June 2011

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1 Press Release Premier Oil plc HIGHLIGHTS Operational Production averaged 36,900 boepd over the period (: 46,600 boepd) as strong gas demand from Singapore and good infill drilling results in Pakistan were offset by increased maintenance activity in the UK Run rate of around 60,000 boepd by year-end: Gajah Baru ready to produce, awaiting government approvals for early production Final preparations for first oil at Chim Sáo being completed Interests in the Wytch Farm, Solan and Fyne fields in the UK acquired at a purchase and carry cost of around US$5 per barrel 10 exploration and appraisal wells drilled in the period: seven successfully found hydrocarbons including further discoveries in the Catcher area and appraisal successes in Norway and Vietnam; new licences added in the UK and offshore Kenya Financial Operating cash flow of US$242.3 million (: US$222.1 million), an increase of 9 per cent Profit after tax of US$88.5 million (: US$62.0 million), an increase of 43 per cent Cash resources stand at US$482.9 million (: US$449.1 million) with available undrawn bank facilities of US$804 million (: US$404 million). A private placement of US$350 million of seven and 10 year notes was successfully completed in June OUTLOOK Full-year production for is estimated at between 40,000 boepd and 45,000 boepd (: 42,800 boepd). Estimated year-end run rate of 60,000 boepd Continuing progress on 12 new projects through the development phase for first oil and gas in the period 2012 to 2016 Key wells planned for the remainder of the year include: Gardrofa, adjacent to our Bream development in Norway East Fyne, Erne and Bluebell in the UK North Sea, close to existing Premier interests Anoa Deep in Natuna Sea Block A Quả Mít Vàng (Jackfruit) in Vietnam, expected to spud shortly Up to 20 exploration and appraisal wells planned for the next 12 months targeting around 300 mmboe of unrisked net resources 1

2 Simon Lockett, Chief Executive, commented: We are delighted with the progress made by our Asian development projects, the ramp up of which, together with anticipated stronger production performance in the North Sea, will see Premier reach a year-end run rate of around 60,000 boepd. Good progress continues to be made on our pipeline of development projects, including the transition of the Catcher project into the development planning phase; with the acquisition of significant equity stakes in the Solan, Wytch Farm and Fyne fields, we remain confident of reaching our targeted 100,000 boepd in the medium-term. We also look forward to a significant exploration programme for the rest of the year with planned drilling in all our operating areas. ENQUIRIES Premier Oil plc Tel: + 44 (0) Simon Lockett Tony Durrant Pelham Bell Pottinger Tel: + 44 (0) Gavin Davis Henry Lerwill There will be a presentation to analysts at the company s offices at 10:00am today which will be webcast live on the company s website at Following changes in the UK company disclosure regulations in 2008, it is not a requirement for halfyearly financial statements to be sent to shareholders. Accordingly, Premier will not be printing and distributing a Half-Yearly Report. A copy of this announcement is available for download from our website at and hard copies can be requested by contacting the company ( premier@premier-oil.com or telephone: +44 (0) ). 2

3 INTERIM MANAGEMENT REPORT CHAIRMAN S STATEMENT A strong commodity price environment and continuing good production performance outside the UK have delivered solid first half financial results. Ramp up of our Asian development projects, together with new projects in the UK, will deliver significant growth as we move into Average production during the first half of the year was 36,900 barrels of oil equivalent per day (boepd), compared to 46,600 boepd in the corresponding period in. This was primarily because of unplanned maintenance work in the UK. These issues have now been resolved and improved UK production uptime is anticipated for the second half of the year. Outside the UK, we have seen continuing good production performance in Indonesia and increasing gas demand from Singapore. Our development project teams in Asia have achieved great success. The Premier-operated Chim Sáo project in Vietnam is expected to achieve first oil in the next few weeks and ramp up quickly thereafter. In Indonesia, production at the Premier-operated Gajah Baru project is ready to begin ahead of the planned 1 October date for first gas. Net investment by Premier in these two fields will be around US$620 million, in line with original approved project budgets. These developments are testimony to the strength and depth of Premier s operating and cost management skills, which we continue to apply across our current and rapidly growing development portfolio. In the first half of, Premier again demonstrated its ability to identify and execute value-enhancing acquisitions. The Wytch Farm acquisition, announced in June, will see Premier increase its stake to 30.1 per cent in a long-life producing oil asset with significant upside potential. Premier also acquired a 60 per cent operated equity stake in the Solan field and exercised an option to become the operator of the Fyne field with a 39.9 per cent equity stake. These two opportunities are now progressing towards project sanction. In aggregate, these three acquisitions will add approximately 43 million barrels of oil equivalent (mmboe) of reserves and resources at an acquisition and carry cost of around US$5 per barrel (bbl). Looking forward, progress has been achieved on two UK development projects, Huntington and Rochelle, with both scheduled to commence production in The financial difficulties of Sevan Marine (Sevan), the floating production storage and offtake vessel (FPSO) supplier for the Huntington project, have been well-publicised, although Sevan has recently agreed a US$36.1 million bridging facility with its bondholders in order to meet its short-term working capital needs. Delivery of the FPSO is now targeted for the second quarter of This timetable is, however, dependent on further refinancing by Sevan, scheduled to complete in the coming months. We remain focused on our exploration target of achieving 200 mmboe of reserve additions by 2015, of which around 75 mmboe have already been achieved. The first half of has seen success with further discoveries in the Catcher area in the UK, as well as the successful appraisal of Grosbeak in Norway and Cá Rồng Đỏ in Vietnam. We continue to focus our exploration programme on the Nam Con Son Basin in South East Asia and the Central North Sea area of the UK. We have also continued to 3

4 build the portfolio for future drilling with the signing in May of two production sharing contracts (PSCs) for offshore exploration blocks L10A and L10B in Kenya. Oil and gas prices remained strong during the period, with Brent crude oil prices trading in a range of US$93/bbl to US$126/bbl. The average for the period was US$111/bbl against US$77/bbl in the corresponding period last year. Operating cash flows were US$242.3 million (: US$222.1 million) in the first half and are expected to grow substantially in the second half as new production comes onstream. Profit after tax for the period was US$88.5 million (: US$62.0 million) benefiting from an increase in the value of our UK tax position. We continue to place the highest priority on health, safety and environmental matters. We have retained our ISO and OHSAS certification for both production operations in Indonesia and our global drilling function, and have recently achieved certification to OHSAS to complement our existing ISO for our North Sea operations. We also continue to retain our inclusion in the FTSE4Good Index. Outlook We remain committed to our stated growth strategy and the prudent financing principles which support it. Our development skills have been proven by the successful execution of our Asian projects. We now seek to apply these to our pipeline of future developments, particularly in the North Sea. We also continue to seek value-adding acquisitions in our core areas of activity. In the second half of, our exploration programme will deliver around 10 exploration wells across our core areas. In the Natuna A PSC in Indonesia, we are planning to drill our first well to assess the potential of the reservoir formations underlying the producing layers in the Anoa oil and gas field. The Quả Mít Vàng well in Vietnam, which is a potential play opener, is due to spud shortly. Premier s first operated exploration well in Norway, on the Gardrofa prospect, will be drilled in the third quarter of. In the UK, two wells are planned in the Fyne area along with a well on the Bluebell prospect close to our Balmoral infrastructure. For 2012, we expect to drill 12 to 15 exploration and appraisal wells, including the Carnaby well in the Greater Catcher area, the Luno II well in Norway and the Biawak Besar well in Indonesia. The first half of this year has seen us deliver good value acquisitions, progress towards first oil and gas on new fields, and achieve positive results in both appraisal and exploration. We look forward to further successes in the second half of the year. Mike Welton Chairman 4

5 OPERATIONAL REVIEW ASIA Premier has successfully managed two complex multi-year projects, the Chim Sáo and Gajah Baru field developments. These projects will drive Premier s production growth in the second half of the year. Ongoing development activities will continue with the Pelikan and Naga projects in the Natuna Sea, the gas developments on Block A Aceh and evaluation of the Dua and Cá Rồng Đỏ projects in Vietnam. Exploration in both Indonesia and Vietnam continues with at least five further wells planned in the next six months. Production and development Indonesia During the first half of, Singapore demand for West Natuna gas was 373 billion British thermal units per day (BBtud) with the Premier-operated Natuna Sea Block A in Indonesia selling an overall average of 154 BBtud (gross) from its gas export facility, up 3 per cent from first half. This represented a market share of 41 per cent against a contractual share of 36.7 per cent. The non-operated Kakap Block (Premier per cent) also contributed a further 42 BBtud (gross). Liquids production from the Block A Anoa field averaged 1,700 barrels of oil per day (bopd) (gross) and the Kakap field 3,400 bopd (gross). Overall, net production from Indonesia amounted to 10,800 boepd (: 11,300 boepd) on a working interest basis. Production levels from Natuna Sea Block A will rise significantly in the second half of as the Gajah Baru field begins to supply into a second gas sales contract. Liquid production from the Anoa field is also expected to increase by over 70 per cent in the second half of the year due to A22, a new oil producing well, which was brought on-stream in June. We anticipate achieving first gas from the Gajah Baru project on budget and ahead of schedule. Production is ready to commence pending final approvals from the Government of Indonesia. Gajah Baru is the first of a number of fields to be developed to supply additional gas to domestic buyers in Batam, Indonesia and internationally to Singapore. Development work on the Pelikan and Naga fields is targeting first gas in late Final project sanctions are expected in the second half of. The Pelikan and Naga fields will be tied in to the new Gajah Baru central processing platform for export via the West Natuna Transportation System. Work will then commence on the next development project, the tie-in of the Gajah Puteri field. The extension of the PSC for the non-operated Block A Aceh was executed in the fourth quarter of last year. Work has started on developing the fields and the EPCI tender documents for the facilities have been issued with final contract award expected by year-end. Final project sanction is expected in early 2012 and first gas is targeted for the fourth quarter of

6 Vietnam The Chim Sáo field development is on schedule to deliver first oil in the next few weeks. The Lewek Emas FPSO arrived at the Chim Sáo oil field on 14 July for commissioning and tie-in to the gas export pipeline. Development drilling is ongoing and six producing wells and three water injection wells will be available at first oil with a further three production wells to be brought on-stream before the end of the year. One of the development wells for the Chim Sáo project, the N2P well, intersected the shallow part of a previously undrilled fault terrace to the north west of the Chim Sáo field. Initial data indicates the well encountered a 20 metre oil column in an independent closure within good quality Upper Dua sandstones. A plan is now being prepared for the further evaluation of this near-field tie-back opportunity. Other candidates for in-field production wells have been identified during the current development drilling campaign and are being assessed for drilling in Front end engineering and design (FEED) studies are complete for the Dua oil field, which is planned to be developed as a tie-back to Chim Sáo, and the government sanction process has commenced. The Cá Rồng Đỏ discovery, appraised earlier this year, has recently moved into the development evaluation phase. Exploration and appraisal Indonesia On the Premier-operated Tuna Block, Gajah Laut Utara was drilled to a total depth of 15,380 feet (4,688 metres). The well encountered oil shows over a 350 metre interval of interbedded sandstones and shales in the Oligocene Gabus formation, but wireline logging indicated that the majority of the reservoirs were water wet with low porosity and permeability. One zone within the Oligocene section was sampled and gas was recovered. Subsequent to the period end, the Belut Laut well was drilled in the adjacent sub-basin. Oil shows with high gas readings were reported throughout a gross 155 metre Oligocene interval. However, sandstones at this depth were of poor porosity. Subsurface work will now focus on prospects at shallower depths where good reservoir properties are preserved up-dip from the now proven source rocks. At least five such prospects have been identified in this Tuna Block and in the neighbouring Block 07/03 in Vietnam. The 12-well development drilling campaign on the Natuna Sea Block A, which was initiated in the second half of, will conclude with the drilling of two exploration wells, Anoa Deep and Biawak Besar, in the fourth quarter of this year and the first quarter of 2012, respectively. The results of these two wells, along with the block-wide prospect inventory review which was completed in the second quarter, will be used to develop drilling and appraisal plans for the next five years. On Block A Aceh, Matang-1 is expected to spud in the first quarter of 2012 and will test a Miocene-aged carbonate prospect up-dip of proven gas. The joint venture partners have also been in discussions about the location of a second exploration well. The two candidate prospects are Peudawa Rayeu, which is an 6

7 appraisal of an existing gas discovery, and Alur Kacang, a carbonate build up syncline separated from the Alur Siwah field, now under development. Elsewhere in Indonesia, the operator of the Buton licence plans to spud Benteng-1 late in the fourth quarter. Onshore construction projects are complete and the partners are now in the final stages of rig procurement. Benteng-1 will be drilled to test a Cretaceous-aged carbonate in a sub-thrust trap, onshore Buton Island. Vietnam In April, Premier appraised the exploration success at Cá Rồng Đỏ (CRD) in Block 07/03. Well CRD-2X targeted Miocene sandstones and was deepened to evaluate previously untested Oligocene sandstones. Two drill stem tests of hydrocarbon bearing sands in the Oligocene section were conducted. The first zone tested flowed gas and condensate at rates of 9.7 million standard cubic feet per day (mmscfd) and 870 bopd respectively through a 40/64 inch choke. The second zone tested flowed gas and condensate at rates of 17 mmscfd and 1,730 bopd respectively through a 56/64 inch choke. The well was sidetracked to further evaluate the distribution of hydrocarbons in the Miocene sands. Commercial development of the CRD accumulation is now under review along with further interpretation of the exploration potential of the rest of Block 07/03. The Premier-operated Quả Mít Vàng exploration well in Block /05 offshore northern Vietnam is expected to spud shortly. Quả Mít Vàng is testing the hydrocarbon potential of a basement structure on the margin of the Song Hong Basin. MIDDLE EAST, AFRICA AND PAKISTAN Pakistan gas production remains broadly stable as natural decline is offset by infill successes and compression upgrades. Our oil production in Mauritania is also stable. We continue to build our exploration portfolio in Egypt, tracking the geology south to Kenya. Production and development Pakistan Average production in Pakistan during the first half of was 14,900 boepd net to Premier (: 15,200 boepd), which is stable when compared to production figures for full year. Production was maintained by maximising output from existing gas fields through infill drilling and the implementation of front end compression projects. Average production from the Qadirpur gas field during this period was 3,800 boepd (net to Premier), about 6 per cent higher than in the first half of (3,600 boepd) due to a wellhead compression project coming on-stream in the fourth quarter of. In addition, the extended reach development well QP-42, which tested the SML zone and was completed in June, has been tied to the facility by a temporary 8 inch pipeline and is already on production. Work is also in progress to complete the installation of the Pirkoh 7

8 front end compressors by June These will supplement the existing wellhead compressors and, in so doing, help maintain future production levels at Qadirpur. On the Kadanwari gas field, average production was 2,300 boepd (net to Premier) during the period, 77 per cent higher than in the first half of (1,300 boepd). This was mainly due to the drilling and tie-in of exploration well K-19 in the second half of and the successful K-18 sidetrack well, which came onstream in February. Contributing to future deliverability of the Kadanwari gas field is the exploration well K-27, which exceeded expectations and tested at 51 mmscfd in April. This well is expected to be tied into existing infrastructure in November. The average production from the Zamzama gas field was 5,400 boepd (net to Premier) during the period, 19 per cent lower than in the first half of (6,700 boepd). This decline in production can be attributed to the delays in the implementation of the front end compression project. However, this project has now been completed and production from the field is expected to increase in the second half of. On the Bhit/Badhra gas fields, average production was 3,400 boepd (net to Premier) during the first half of, about 6 per cent less than the corresponding period in (3,600 boepd). This small reduction resulted from the deferral to April of the field s annual maintenance shutdown, originally scheduled to be carried out in the second half of. Mauritania In Mauritania, the Chinguetti field averaged 700 boepd net to Premier for the first six months of and natural decline of the field continues to be less than expected. Negotiations between the government and the joint venture partners for the extension of PSC A and PSC B continue. Exploration and appraisal Pakistan On the Bhit/Badhra gas fields, Premier plans to drill Badhra-6 Parh in the fourth quarter of and the Badhra-Area-B appraisal well in 2012, subject to the Government of Pakistan s approval of the lease extension. On the Kadanwari gas field, the K-27 exploration well, which was completed in June and exceeded expectations, tested flow rates of up to 51 mmscfd. It is anticipated that K-27 will contribute about 50 bcf of resources (gross) and will be tied into existing infrastructure by mid-november. The test results of the Kadanwari K-25 Dir-A and K-26 exploration wells were less encouraging due to tight reservoir conditions and discussions among the joint venture partners about whether to tie these two wells to existing infrastructure are ongoing. The K-29 and K-30 exploration wells are expected to spud in the fourth quarter of and, if successful, will increase the deliverability of the Kadanwari gas field. In addition, tight gas potential has been identified in the Kadanwari gas field and is in the process of being assessed for development. More 8

9 generally, Premier is reviewing both its existing and potential assets in Pakistan for new exploration and farm in opportunities in light of the country s recently issued Tight Gas Policy. Egypt The award of the South Darag Block in the Gulf of Suez is awaiting formal government ratification. This has now been delayed until after the Egyptian parliamentary elections, which are scheduled for later in the year. Premier farmed into the North Red Sea Block 1 in December taking a 20 per cent interest. The NRS-2 (Cherry) exploration well was drilled to a total depth of 5,200 metres. The well encountered hydrocarbon shows during drilling but did not intersect reservoir quality sandstones. These results are now being integrated with geologic and seismic data to assess the further prospectivity of the block. Premier continues to look for acquisition and new venture opportunities in Egypt. Kenya In May, Premier entered Kenya with the signing of two PSCs for offshore exploration blocks L10A and L10B. The forward plan is for the joint venture partners to acquire 2D and 3D seismic data across the area in early 2012, for better definition of the numerous leads and prospects. Iraq We have pre-qualified for the Iraq fourth licensing round which is expected to take place early in NORTH SEA Production performance in the UK in the first half of was hampered by downtime on key producing assets. These issues have now been resolved and Premier is expecting a stronger production performance in the second half of the year. The development portfolio has moved forward significantly with new projects under construction (Huntington and Rochelle), new projects acquired (Solan and Fyne), and several new developments progressing to project sanction. Exploration and appraisal continues, with at least four wells planned for the second half in UK and Norway. Production and development UK Total North Sea production was 10,500 boepd in the first half of compared to 19,400 boepd for the corresponding period in. Most of this decline can be attributed to unplanned facilities downtime in the UK in the first half of. In particular, production via the Premier-operated Balmoral floating production vessel (FPV) was suspended from 15 December until 8 March due to certification and testing requirements and again from 12 June to 7 July due to a subsea hydraulic leak. Both episodes affected the Balmoral FPV subsea fields, notably Balmoral, Brenda, Nicol and Stirling, and accounted for a loss of production of 3,600 boepd in the first half of. Production from the Wytch Farm field was also suspended during January due to concerns over the integrity of a subsea pipeline. Production from the 9

10 Scott field was restricted in January and February due to a fracture in the gas export line. These unplanned maintenance issues have now been resolved, leading to an expected stronger production performance in the UK in the second half of the year. The Huntington project, which was sanctioned in November, progressed well in the first half of. Key milestones in the first half of the year included the commencement of development drilling in April, ahead of schedule, and the initiation of phase 1 subsea installation at the end of June. Commercial agreements for pipeline tie-in and gas transportation have also been signed with the CATS pipeline group and a strategy for oil marketing has been agreed between the joint venture partners. As previously reported, the original schedule of January 2012 for first oil for Huntington has been impacted by the financial difficulties of Sevan. A recent US$36.1 million bridging facility which Sevan agreed with its bondholders in July, is being used to support the short-term working capital needs of Sevan and, in particular, the upgrade of the Sevan Voyageur. As a result, sail away of the Voyageur is now targeted for the second quarter of 2012, with first oil for Huntington expected in the third quarter, though this schedule remains dependent on the longer-term refinancing for Sevan. In the first half of, good progress was made on the UK development project Rochelle, which comprises East and West Rochelle. The Rochelle project, in which Premier will hold a 15 per cent unitised equity stake, will be developed in two almost parallel phases. Phase 1 will see East Rochelle developed for first gas, which is to be produced via the Scott platform, in November East Rochelle received development sanction in January. Phase 2 will entail the tie-in of the West Rochelle project to the East Rochelle subsea production manifold. Sanction of the West Rochelle development is targeted for the third quarter of. Premier has further strengthened its UK asset base by acquiring operated interests in the Solan and Fyne projects and an additional interest in Wytch Farm. In May, Premier signed a sale and purchase agreement under which Premier will become the development operator of the Solan field at sanction with a 60 per cent equity interest. Further engineering studies are under way and first oil is targeted for Also in May, Premier exercised an option to become the operator of the Fyne field with a 39.9 per cent equity stake. We have since progressed the pre-development work of the project with the aim of sanctioning development in early 2012 for first oil in The joint venture partners are currently evaluating the development options for the area. In June, Premier announced the acquisition of an additional per cent in Wytch Farm for an initial cash consideration of US$96 million. On completion later this year, this will bring the group s total interest in Wytch Farm to 30.1 per cent. Premier will support the transition of operatorship to Perenco UK Ltd, who, on completion of a related transaction, will hold 50.1 per cent of Wytch Farm. 10

11 Norway In Norway, development plans for the Frøy field received Premier support for moving to the next phase. However, the operator has indicated that, due to limited resources and commitments elsewhere, they will not be proceeding with the project at this time. Dialogue with the operator for commercial arrangements to progress Frøy continues and a decision is expected to be taken later this year. Discussions also continue with the preferred contractor for the Bream field development regarding the timing and availability of the selected FPSO for the project. A formal development plan is expected to be submitted in the first half of Exploration and appraisal UK During the period, Premier followed up on the previous Catcher and Varadero discoveries by participating in two further exploration wells on Block 28/9, Catcher North and Burgman. Catcher North encountered 14 feet of net oil pay in the targeted Cromarty reservoir along with 20 feet of net gas pay in the Tay sandstones. The initial Burgman well encountered hydrocarbons in the Upper and Lower Tay, but indicated that the Cromarty and Fulmar reservoirs were not hydrocarbon bearing at this location. A sidetrack to Burgman was subsequently drilled and successfully encountered 64 feet of net vertical oil pay at an average porosity of 38 per cent in the Lower Tay sandstone. Commercial quantities of hydrocarbons have now been proved and the joint venture is working towards a Catcher area development for possible first oil in Elsewhere in the UK North Sea, Premier exercised its option to drill the East Fyne appraisal well under the joint venture and earn-in agreement. By exercising its option, Premier acquired a 39.9 per cent operated interest in Block 21/28a, which contains the Fyne field, in return for a carry of up to US$50 million towards the development costs, including the cost of the appraisal well. Premier has since secured the Transocean Sedco 704 semi-submersible rig to drill the East Fyne well, which is scheduled to spud in the fourth quarter of. Premier also signed a heads of agreement in June to gain additional acreage in the Greater Fyne area by participating in the Erne exploration well on Block 21/29d. The Erne well, which is scheduled to spud in the fourth quarter, will target the Eocene Tay formation oil prospect located between the Fyne and Guillemot NW fields in the UK Central North Sea. A successful Erne exploration well along with the results of the East Fyne appraisal well will be taken into account as development planning for the Fyne field continues. The Bluebell prospect on P1466 Block 15/24c in the Central North Sea is due to spud in the second half of the year. In late, Premier agreed a farm out deal to drill an exploration well on the Bluebell prospect with the farminee paying per cent of the cost of the well in return for a 40 per cent equity interest in the prospect. 11

12 Norway In Norway, the Grosbeak discovery, which was drilled in 2009 and is close to nearby infrastructure, was appraised by 35/12-4S and 35/12-4A in the first half of. The results of the appraisal established a 40 metre oil column in the Middle Jurassic sandstones, which flowed on test at a rate of 4,900 bopd. Post-appraisal evaluation remains ongoing. On the same block, the Gnatcatcher exploration well encountered minor hydrocarbon shows in the Upper Jurassic and was plugged and abandoned. During the period, Premier was granted permission by the Norway Petroleum Safety Authority to drill Premier s first operated well in Norway, the Gardrofa well. Success at the Gardrofa well, which is scheduled to spud in the third quarter of, may impact development options for the nearby Bream field development. 12

13 FINANCIAL REVIEW Income statement Group production, on a working interest basis, averaged 36,900 boepd in the first half of compared to 46,600 boepd in the corresponding period of, and 42,800 boepd for the full year. This reflects a good underlying performance from the Anoa field in Indonesia, on the back of strong gas demand in Singapore, more than offset by a high level of facility maintenance on a number of our UK fields. Entitlement production for the period was 33,800 boepd (: 42,600 boepd). Oil and gas prices have generally been strong during the first half of with an average Brent oil price of US$111.1/bbl and a trading range of US$93/bbl to US$126/bbl. Premier's average realised oil price for the period was US$109.7/bbl (: US$78.1/bbl) before hedging losses. Average realised gas price for Indonesian production was US$18.5 per thousand standard cubic feet (mscf) (: US$13.8/mscf), in line with higher crude prices, and in Pakistan was US$3.7/mscf (: US$3.3/mscf). The combined effect of production, price changes and hedging losses was to reduce turnover to US$342.2 million (: US$366.8 million). Cost of sales in the period was US$200.3 million (: US$188.7 million). Underlying operating costs were US$14.0 per barrel of oil equivalent (boe) (: US$12.9/boe) reflecting the largely fixed nature of operating costs in the UK North Sea, spread across lower production levels. Amortisation of oil and gas properties rose from US$94.5 million to US$102.8 million and on a unit basis from US$11.2/boe to US$15.4/boe. This is largely due to increased estimates for future abandonment costs. There was a net reversal of previous impairment charges in the period amounting to US$5.5 million (: US$nil). Exploration expense and pre-licence exploration costs amounted to US$80.6 million (: US$34.6 million) and US$10.2 million (: US$11.0 million) respectively. The exploration write-off costs relate principally to the Gajah Laut Utara (Indonesia) and Cherry (Egypt) wells drilled in the first half. Interest revenue, finance and other gains for the period were US$1.5 million (: US$1.3 million) offset by finance charges of US$27.6 million (: US$33.9 million). Finance costs capitalised during the period totalled US$12.0 million (: US$5.3 million). Net interest movements reflect lower interest rates generally offset by increased debt taken on in conjunction with our investment programme. Net finance charges also reflect the non-cash unwinding of discounting in relation to the outstanding convertible bonds and future abandonment obligations. In total, a net credit of US$16.3 million (: US$20.5 million) is recorded in the first half in respect of derivative financial instruments, reflecting movement in the valuation of existing hedges and the release of deferred revenue. The majority of the group's oil collars are now embedded in long-term crude offtake arrangements. Being sales of production in the ordinary course of business, such embedded collars are not required to be marked to market. However, deferred revenue booked in prior years in respect of oil hedging arrangements is being credited to the income statement over the remaining life of the relevant 13

14 hedges. A total of US$13.1 million was credited in this period. In addition, mark to market movements in respect of High Sulphur Fuel Oil (HSFO) hedges, which underlie the pricing mechanism for gas sold into the Singapore market, amounted to a credit of US$4.7 million in the period. Realised cash losses arising from hedging activities amounted to US$58.2 million (: US$1.2 million). These losses arose as oil and gas prices during the period exceeded caps contained within our collar hedges and are deducted from sales revenues. The group has a tax credit for the period of US$56.0 million (: charge of US$49.6 million) principally arising from a UK deferred tax credit of US$131.8 million, more than offsetting overseas tax charges of US$46.0 million and UK petroleum revenue tax (PRT) of US$30.4 million. This addition to the deferred tax asset is mainly due to the substantial increase in the UK tax rates for upstream companies, which increases the value of our pool of UK tax losses and allowances that we expect to utilise in the future. Profit after tax in the period was US$88.5 million compared to US$62.0 million for the first half of. Basic earnings per share for the period were 19.0 cents (: 13.4 cents), which take into account the 4:1 share split conducted by the company in May. Cash flow Cash flow from operating activities amounted to US$242.3 million (: US$222.1 million), compared to capital expenditure in the period of US$296.8 million (: US$212.4 million). Capital expenditure Half year $ million Half year $ million Fields/developments Exploration Other Total Development spend in the first half was focused primarily on the Chim Sáo and Gajah Baru projects in Vietnam and Indonesia respectively as these two projects near completion. Exploration spend in the first half was US$118.7 million (: US$69.4 million). Acquisitions In April, Premier exercised its option to drill the East Fyne appraisal well in the UK Central North Sea under a joint venture and earn-in agreement. Under the terms, Premier will have a 39.9 per cent operated interest in Block 21/28a containing the Fyne field in return for carry of up to US$50 million towards the development costs, including the East Fyne appraisal well. 14

15 In May, Premier signed a sale and purchase agreement to acquire equity in Licence P164 in order to participate in the development of the Solan field in the UK for an upfront consideration of US$10 million. A further consideration of US$10 million is payable at project sanction. Costs incurred in relation to the Solan and Fyne acquisitions have been classified as exploration expenditure pending booking of reserves on these two projects. In June, Premier agreed to acquire an interest of per cent in Wytch Farm for an initial cash consideration of US$96 million. The acquisition is conditional upon satisfaction of certain customary conditions and a deposit of US$86.5 million was paid in the period. Balance sheet Net debt at 30 June was US$581.9 million (: US$335.7 million) including cash resources of US$482.9 million (: US$449.1 million). Half year $ million Half year $ million Cash and cash equivalents Convertible bonds* (224.2) (216.7) Other long-term debt** (840.6) (568.1) Net debt (581.9) (335.7) Long-term borrowings are made up of convertible bonds, senior loan notes and bank debt. The bonds have a par value of US$250 million and a final maturity date of 27 June They carry a conversion price of 3.39 per share. During June, the group undertook a private placement of senior loan notes of US$350 million. These have a weighted average cost of 5.5 per cent with maturities between 2018 and At 30 June, undrawn credit facilities, including letter of credit facilities with banks, were US$804 million. Financial risk management A portion of expected future production has been hedged, using oil and gas price floors at a level which protects the cash flow of the group and the business plan. Such floors are purchased for cash or funded by selling caps at a ceiling price according to market conditions. As at 30 June the group had 3.4 million barrels (mmbbls) of Dated Brent oil hedged with collars at an average floor price of US$44.95/bbl and an average cap of US$90.53/bbl covering the period to the end of The group also maintains a hedging position in Singapore 180 HSFO, which underlies the pricing mechanism for gas sold into the Singapore market. A total of 222,000 metric tonnes (mt) have been hedged to the period ending mid-year 2013 with a floor of US$250.0/mt and a cap of US$500.0/mt. Premier operates and reports in US dollars. Foreign exchange exposure therefore relates only to certain sterling and other local currency expenditures. These exposures are covered by the purchase of local currency on a spot or short-term forward basis. The average sterling/dollar rate achieved for transactions 15

16 maturing in the first half of was US$1.590 : 1. Forward foreign exchange contracts outstanding at 30 June had a mark to market valuation gain in the period of US$0.5 million. Although the group s main borrowing facilities are defined in floating rate terms, substantially all current drawings effectively have been converted to fixed interest rates using the interest rate swap markets, given the very low level of fixed interest rates available relative to historical rates. At 30 June, 96 per cent of the group s total debt of US$1,064.8 million was denominated in fixed rate instruments, or locked into fixed rate costs using the interest rate swap market. Mark to market valuations of such interest rate and foreign exchange swaps showed a movement of US$2.0 million for the period which, under hedge accounting rules, is recorded as an adjustment to retained earnings. There have been no material changes to, or material transactions with, related parties as described in note 24 of the Annual Report and Financial Statements for the year ended 31 December. 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 potentially 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. Despite economic uncertainty, the directors consider that the expected operating cash flows of the group and the headroom provided by the available borrowing facilities give 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 half-yearly condensed 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 areas 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. 16

17 A summary of the principal risks facing the company and the way in which these risks are mitigated is provided on pages 34 and 35 of the Annual Report and Financial Statements. Those risks and uncertainties which were identified at the year-end have not changed and still remain appropriate. 17

18 STATEMENT OF DIRECTORS RESPONSIBILITIES The directors confirm that, to the best of their knowledge the attached condensed financial statements have been prepared in accordance with International Accounting Standard (IAS) 34 Interim Financial Reporting, and that the Interim Management Report includes a fair review of the information required by DTR 4.2.7R (an indication of events during the first six months and a description of the principal risks and uncertainties for the remaining six months of the year) and DTR 4.2.8R (disclosure of related parties transactions and changes therein) of the Disclosure and Transparency Rules. The directors of Premier Oil plc are listed in the group s Annual Report and Financial Statements. A list of current directors is maintained on our website which can be found at By order of the Board S C Lockett Chief Executive A R C Durrant Finance Director 24 August 24 August Disclaimer This report contains certain forward-looking statements that are subject to the usual risk factors and uncertainties associated with the oil and gas exploration and production business. Whilst the group believes the expectations reflected herein to be reasonable in light of the information available to it at this time, the actual outcome may be materially different owing to factors beyond the group s control or otherwise within the group s control but where, for example, the group decides on a change of plan or strategy. Accordingly, no reliance may be placed on the figures contained in such forward-looking statements. 18

19 CONDENSED CONSOLIDATED INCOME STATEMENT Year to 31 December Note $ million $ million $ million Sales revenues Cost of sales 3 (200.3) (188.7) (530.5) Exploration expense (80.6) (34.6) (68.2) Pre-licence exploration costs (10.2) (11.0) (18.9) General and administration costs (8.8) (8.8) (18.3) Operating profit Interest revenue, finance and other gains Finance costs and other finance expenses 6 (27.6) (33.9) (68.0) Gain on derivative financial instruments Profit before tax Tax (49.6) 29.0 Profit for the period/year Earnings per share (cents): Basic Diluted CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME AND EXPENSE Year to 31 December $ million $ million $ million Profit for the period/year Cash flow hedges gains/(losses) arising during the period/year: On commodity swaps (20.1) 9.8 (2.2) On interest rate and foreign exchange swaps (2.0) (11.8) (12.1) Exchange differences on translation of foreign operations 7.9 (10.3) (1.9) Actuarial gains on long-term employee benefit plans Other comprehensive expense (14.2) (12.3) (15.6) Total comprehensive income for the period/year

20 CONDENSED CONSOLIDATED BALANCE SHEET Non-current assets: At 30 June At 30 June At 31 December Note $ million $ million $ million Intangible exploration and evaluation assets Property, plant and equipment 9 1, , ,732.8 Deferred tax assets Current assets: 2, , ,328.9 Inventories Trade and other receivables Tax recoverable Cash and cash equivalents , Total assets 3, , ,025.9 Current liabilities: Trade and other payables (639.4) (406.2) (446.8) Current tax payable (107.8) (57.5) (56.4) Short-term borrowings (175.0) - - (922.2) (463.7) (503.2) Net current assets Non-current liabilities: Convertible bonds (222.2) (214.0) (218.1) Other long-term debt (648.3) (553.8) (466.4) Deferred tax liabilities 5 (218.9) (174.5) (183.7) Long-term provisions (590.4) (345.4) (473.2) Long-term employee benefit plan deficit (16.4) (14.6) (15.2) Deferred revenue (22.8) (46.9) (35.9) (1,719.0) (1,349.2) (1,392.5) Total liabilities (2,641.2) (1,812.9) (1,895.7) Net assets 1, , ,130.2 Equity and reserves: Share capital Share premium account Retained earnings Capital redemption reserve Translation reserves 13.1 (3.2) 5.2 Equity reserve , , ,

21 CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY Share capital Share premium account Retained earnings Capital redemption reserve Translation reserves Equity reserve Total $ million $ million $ million $ million $ million $ million $ million At 1 January Issue of Ordinary Shares (32.1) Purchase of shares for ESOP Trust - - (8.3) (8.3) Provision for share-based payments Transfer between reserves* (7.1) - Total comprehensive income (1.9) At 31 December ,130.2 Issue of Ordinary Shares (20.0) Purchase of shares for ESOP Trust - - (0.9) (0.9) Provision for share-based payments Transfer between reserves* (3.7) - Total comprehensive income At 30 June ,220.8 At 1 January Issue of Ordinary Shares (32.1) Purchase of shares for ESOP Trust - - (11.8) (11.8) Provision for share-based payments Transfer between reserves* (3.4) - Total comprehensive income (10.3) At 30 June (3.2) ,037.5 * 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. 21

22 CONDENSED CONSOLIDATED CASH FLOW STATEMENT Year to 31 December Note $ million $ million $ million Net cash from operating activities Investing activities: Capital expenditure (296.8) (212.4) (514.1) Pre-licence exploration costs (10.2) (11.0) (18.9) Deposit for acquisition of oil and gas properties (86.5) - - Acquisition of oil and gas properties - - (7.4) Proceeds from disposal of oil and gas properties Recovery of cash previously held in a decommissioning trust Net cash used in investing activities (393.5) (203.0) (450.8) Financing activities: Proceeds from issuance of Ordinary Shares Purchase of shares for ESOP Trust (0.9) (11.8) (8.3) Proceeds from drawdown of long-term bank loans Proceeds from issuance of senior loan notes Debt arrangement fees (1.8) (3.9) (17.9) Repayment of long-term bank loans (10.0) (90.0) (178.0) Interest paid (20.8) (18.8) (40.9) Net cash from financing activities Currency translation differences relating to cash and cash equivalents 2.3 (1.4) (1.3) Net increase in cash and cash equivalents Cash and cash equivalents at the beginning of the period/year Cash and cash equivalents at the end of the period/year

23 NOTES TO THE CONDENSED FINANCIAL STATEMENTS 1. BASIS OF PREPARATION General information Premier Oil plc is a limited liability company incorporated in Scotland and listed on the London Stock Exchange. The address of the registered office is 4 th Floor, Saltire Court, 20 Castle Terrace, Edinburgh, EH1 2EN, United Kingdom. The condensed financial statements for the six months ended 30 June were authorised for issue in accordance with a resolution of the Board of Directors on 24 August. The information for the year ended 31 December contained within the condensed financial statements does not constitute statutory accounts within the meaning of section 434 of the Companies Act Statutory accounts for the year ended 31 December were approved by the Board of Directors on 23 March and delivered to the Registrar of Companies. The report of the auditors on those accounts was unqualified, did not contain an emphasis of matter paragraph and did not contain any statement under section 498(2) or 498(3) of the Companies Act The financial information contained in this report is unaudited. The condensed consolidated income statement, condensed consolidated statement of comprehensive income and expense, condensed consolidated statement of changes in equity and the condensed consolidated cash flow statement for the six months, and the condensed consolidated balance sheet as at 30 June and related notes, have been reviewed by the auditors and their report to the company is attached. Basis of preparation The condensed financial statements for the six months ended 30 June have been prepared in accordance with IAS 34 Interim Financial Reporting, as adopted by the European Union and with the requirements of the Disclosure and Transparency Rules issued by the Financial Services Authority. These condensed financial statements should be read in conjunction with the annual financial statements for the year ended 31 December, which have been prepared in accordance with International Financial Reporting Standards as adopted by the European Union. The condensed financial statements have been prepared on the going concern basis. Further information relating to the going concern assumption is provided in the Financial Review. Accounting policies The accounting policies applied in these condensed financial statements are consistent with those of the annual financial statements for the year ended 31 December, as described in those annual financial statements. A number of amendments to existing standards and interpretations were applicable from 1 January. The adoption of these amendments did not have a material impact on the group s financial statements for the half-year ended 30 June. 23

24 2. OPERATING SEGMENTS The group s operations are located and managed in three regional business units North Sea, Asia and Middle East, Africa and Pakistan. These geographical segments are the basis on which the group reports its segmental information. Revenue: Year to 31 December $ million $ million $ million North Sea* Asia Middle East, Africa and Pakistan* Total group sales revenue Interest and other finance revenue Total group revenue Group operating profit/(loss): North Sea* (26.9) 45.1 (36.1) Asia Middle East, Africa and Pakistan* Unallocated** (6.4) (6.4) (13.1) Group operating profit Interest revenue, finance and other gains Finance costs and other finance expenses (27.6) (33.9) (68.0) Gain on derivative financial instruments Profit before tax Tax 56.0 (49.6) 29.0 Profit after tax Balance sheet - Segment assets: North Sea* 1, , ,345.1 Asia 1, ,142.1 Middle East, Africa and Pakistan* Unallocated** Total assets 3, , ,025.9 * During the current period, the decision was made to combine the results of the group s African operations with those of its operations in the Middle East and Pakistan. Accordingly, the segmental information has been re-presented to reflect this change. ** Unallocated expenditure and assets include amounts of a corporate nature and not specifically attributable to a geographical segment. These items include pre-licence exploration costs, cash and mark to market valuations of commodity contracts. 24

25 3. COST OF SALES Year to 31 December $ million $ million $ million Operating costs Stock overlift/underlift movement - (21.8) 35.6 Royalties Amortisation and depreciation of property, plant and equipment: Oil and gas properties Other fixed assets Impairment (reversal)/charge on oil and gas properties (5.5) TAX Current tax: Year to 31 December $ million $ million $ million UK corporation tax on profits UK petroleum revenue tax Overseas tax Adjustments in respect of prior years (0.6) (18.4) (21.4) Total current tax Deferred tax: UK corporation tax (131.8) 22.5 (73.9) UK petroleum revenue tax (2.7) 1.5 (20.8) Overseas tax Total deferred tax (104.5) 24.5 (90.4) Tax on profit on ordinary activities (56.0) 49.6 (29.0) 25

26 5. DEFERRED TAX At 30 June At 30 June At 31 December $ million $ million $ million Deferred tax assets Deferred tax liabilities (218.9) (174.5) (183.7) (8.0) UK deferred corporation tax: At 1 January Exchange movements (Charged)/ credited to income statement At 30 June $ million $ million $ million $ million Fixed assets and allowances (269.7) (254.9) Decommissioning Deferred petroleum revenue tax (3.6) - (2.5) (6.1) Tax losses and allowances Unrecognised tax losses and allowances (70.2) - (16.7) (86.9) Deferred revenue (2.7) 7.2 Total UK deferred corporation tax UK deferred petroleum revenue tax Overseas deferred tax 2 (183.7) (5.2) (30.0) (218.9) Total (5.2) The UK deferred petroleum revenue tax relates mainly to temporary differences associated with decommissioning provisions. The overseas deferred tax relates mainly to temporary differences associated with fixed asset balances. The group's unutilised tax losses and allowances at 30 June are recognised to the extent that taxable profits are expected to arise in the future against which the tax losses and allowances can be utilised. Whilst there has been no change to the amount of unutilised ring fence losses, the recognised deferred tax asset has increased due to additional losses generated and the increase in the supplementary charge detailed below. On 23 March it was announced that the supplementary charge on UK oil and gas production was to be increased from 20 per cent to 32 per cent with effect from 24 March, thereby increasing the combined rate of tax on UK oil and gas production from 50 per cent to 62 per cent for non-prt fields (75 per cent to 81 per cent for PRT fields). The impact of the increase in tax rate on UK oil and gas production has been split between the revaluation of opening balances and current year impact for the purposes of deferred tax. The revaluation of opening deferred tax balances results in a US$61.6 million credit to the income statement, which has been recognised in full in the half-yearly results. 26

27 6. INTEREST REVENUE AND FINANCE COSTS Interest revenue, finance and other gains: Year to 31 December $ million $ million $ million Short-term deposits Mark to market valuation of foreign exchange contracts Others Finance costs and other finance expenses: Bank loans and overdrafts (17.7) (12.7) (35.0) Payable in respect of convertible bonds (7.7) (7.4) (15.2) Unwinding of discount on decommissioning provision (9.2) (7.1) (16.2) Long-term debt arrangement fees (3.2) (5.6) (15.6) Mark to market valuation of foreign exchange contracts - (0.2) (0.4) Others (1.2) (3.7) (0.3) Exchange differences (0.6) (2.5) (2.2) Gross finance costs and other finance expenses (39.6) (39.2) (84.9) Finance costs capitalised during the period/year (27.6) (33.9) (68.0) 7. EARNINGS PER SHARE The calculation of basic earnings per share is based on the profit after tax and on the weighted average number of Ordinary Shares in issue during the period. In May, the company conducted a 4:1 share split. In accordance with IAS 33 Earnings per Share the comparatives have been restated accordingly. Basic and diluted earnings per share are calculated as follows: Profit after tax Weighted average number of shares Earnings per share (restated) (restated) $ million $ million million million cents cents Basic Outstanding share options * * Diluted * The inclusion of the outstanding share options in the and calculations produces diluted earnings per share. The outstanding share options number includes any expected additional share issues due to future share-based payments. At 30 June 37,349,360 ( restated: 37,349,360) potential Ordinary Shares in the company that are underlying the company s convertible bonds and that may dilute earnings per share in the future have not been included in the calculation of diluted earnings per share because they are anti-dilutive for the period (: anti-dilutive). 27

28 8. INTANGIBLE EXPLORATION AND EVALUATION (E&E) ASSETS Cost: Oil and gas properties North Asia Middle Total Sea East, Africa and Pakistan $ million $ million $ million $ million At 1 January * Exchange movements Additions during the period Transfer to property, plant and equipment (35.7) - (2.8) (38.5) Exploration expense (10.4) (32.2) (38.0) (80.6) At 30 June At 30 June * * During the current period, the decision was made to combine the results of the group s African operations with those of its operations in the Middle East and Pakistan. There was no impact on the segmental information as a result of this change. 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. 28

29 9. PROPERTY, PLANT AND EQUIPMENT Cost: Oil and gas properties Asia North Sea Middle East, Africa and Pakistan Other fixed assets Total $ million $ million $ million $ million $ million At 1 January * 1, , ,708.4 Exchange movements Additions during the period Transfer from intangible E&E assets At 30 June 1, , ,051.6 Amortisation and depreciation: At 1 January * Exchange movements Charge for the period Impairment charge/(reversal) (10.0) - (5.5) At 30 June ,074.4 Net book value: At 31 December * ,732.8 At 30 June , ,977.2 At 30 June * ,547.3 * During the current period, the decision was made to combine the results of the group s African operations with those of its operations in the Middle East and Pakistan. Accordingly, the segmental information has been re-presented to reflect this change. Other fixed assets include items such as leasehold improvements, motor vehicles and office equipment. The impairment charge relates to the Balmoral field in the UK. The impairment reversal relates to the Chinguetti field in Mauritania. The impairment charge and reversal were calculated by comparing the future discounted cash flows expected to be derived from production of commercial reserves against the carrying value of the asset. The future cash flows were estimated using an oil price assumption equal to the Dated Brent forward curve in, 2012 and 2013, and US$75 per barrel thereafter, and were discounted using a discount rate of 10 per cent. Assumptions involved in impairment measurement include estimates of commercial reserves, future oil and gas prices and the level and timing of expenditures, all of which are inherently uncertain. Amortisation and depreciation of oil and gas properties is calculated on a unit-of-production basis, using the ratio of oil and gas production in the period to the estimated quantities of proved and probable reserves on an entitlement basis at the end of the period plus production in the period, on a field-by-field basis. Proved and probable 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. 29

30 10. FINANCIAL INSTRUMENTS Financial risk management objectives and policies The group s principal financial liabilities, other than derivative financial instruments (derivatives), comprise accounts payable, bank loans, convertible bonds and senior loan notes. The main purpose of these financial instruments is to manage short-term cash flow and raise finance for the group s capital expenditure programme. The group has various financial assets such as accounts receivable and cash and short-term deposits, which arise directly from its operations. It is group policy that all transactions involving derivatives must be directly related to the underlying business of the group. The group does not use derivative financial instruments for speculative exposures. The main risks that could adversely affect the group s financial assets, liabilities or future cash flows are commodity price risk, cash flow interest rate risk, foreign currency exchange risk, credit risk and liquidity risk. The group uses derivative financial instruments to hedge certain of these risk exposures. The use of financial derivatives is governed by the group s policies and approved by the Board of Directors, which provide written principles on the use of financial derivatives. Derivative financial instruments The group uses derivatives to manage its exposure to oil and gas price fluctuations and to changes in interest rates and foreign currency. Oil and gas hedging is undertaken with collar options, reverse collars, swaps and hedges embedded in long-term crude offtake agreements. Oil is hedged using Dated Brent oil price options. Indonesian gas is hedged using HSFO Singapore 180cst which is the variable component of the gas price. Commodity price risk Oil At 30 June, the group had 3.42 million barrels of Dated Brent oil hedged with collars at an average floor price of US$44.95/bbl and an average cap of US$90.53/bbl, all of which were embedded through offtake agreements to the end of The group also has oil collars with banks which are marked to market through profit or loss. Additionally, the group has executed reverse collars with certain oil trading companies at strike prices identical to the bank collars. Similar to the bank collars, these reverse collars are derivatives that must be marked to market through profit or loss. They effectively offset each other, resulting in no net impact on the income statement or balance sheet. The hedges embedded in long-term crude offtake agreements are not fair valued as they qualify for own-use exemption under IAS 39 Financial Instruments: Recognition and Measurement. During the period, oil hedges for 1.62 million barrels matured, generating a net cost of US$50.4 million (: US$1.2 million). 30

31 10. FINANCIAL INSTRUMENTS (continued) Indonesian gas No changes have been made to the group s hedging position in Singapore 180 HSFO, which underlies the pricing mechanism for Indonesian gas sold into the Singapore market. As at 30 June, 222,000 metric tonnes (mt) of future production from the existing contract is hedged to the period ending mid-year 2013, with a floor of US$250.0/mt and a cap of US$500.0/mt. During the period, Singapore 180 HSFO contracts for 60,000 metric tonnes matured generating a cash cost of US$7.8 million (: US$nil). All of these contracts have been designated as cash flow hedges and were assessed to be effective. In the current period, US$4.7 million of the movement in the fair value of these contracts was credited to the income statement (: credit of US$12.4 million), as this movement related to the time-value portion of hedges under IAS 39. The remaining movement, being a charge of US$20.1 million (: US$nil), related to the intrinsic value of such instruments and was recognised directly in retained earnings. Movement in commodity collar and swap contracts Asset/(liability) Oil $ million Gas $ million Total $ million At 1 January (74.1) (21.5) (95.6) Cash settlement for swaps Deduction against sales revenues (50.4) (7.8) (58.2) (Charge)/credit to income statement for the period (70.6) 4.7 (65.9) Charge to retained earnings for the period - (20.1) (20.1) At 30 June (188.3) (38.3) (226.6) At 30 June (39.4) (17.4) (56.8) Movement in commodity reverse collars Asset/(liability) Oil $ million Gas $ million Total $ million At 1 January Credit to income statement for the period At 30 June At 30 June The fair values, which have been determined from counterparties with whom the trades have been concluded, have been recognised in the balance sheet in trade and other receivables and trade and other payables. The key variable that affects the fair value of the group s hedge instruments is market expectations about future commodity prices. 31

32 10. FINANCIAL INSTRUMENTS (continued) Deferred revenue related to oil reverse collars Deferred revenue has been created due to first-day gains arising from offtake agreements and related oil reverse collars. This deferred revenue is being released to the income statement over the life of each individual offtake agreement as shown below: Asset/(liability) Oil $ million Gas $ million Total $ million At 1 January (35.9) - (35.9) Credit to income statement for the period At 30 June (22.8) - (22.8) At 30 June (46.9) - (46.9) 11. NOTES TO THE CONDENSED CONSOLIDATED CASH FLOW STATEMENT Year to 31 December $ million $ million $ million Profit before tax for the period/year Adjustments for: Depreciation, depletion, amortisation and impairment Exploration expense Pre-licence exploration costs Provision for share-based payments Interest revenue and finance gains (1.5) (1.3) (2.5) Finance costs and other finance expenses Gain on derivative financial instruments (16.3) (20.5) (38.6) Operating cash flows before movements in working capital (Increase)/decrease in inventories (8.5) (Increase)/decrease in receivables (26.0) Increase/(decrease) in payables 44.2 (61.3) (25.8) Cash generated by operations Income taxes paid (3.6) (50.8) (67.9) Interest income received Net cash from operating activities

33 11. NOTES TO THE CONDENSED CONSOLIDATED CASH FLOW STATEMENT (continued) Analysis of changes in net debt: a) Reconciliation of net cash flow to movement in net debt: Year to 31 December $ million $ million $ million Movement in cash and cash equivalents Proceeds from drawdown of long-term bank loans (14.8) (305.1) (310.0) Proceeds from issuance of senior loan notes (350.7) - - Repayment of long-term bank loans Non-cash movements on debt and cash balances (3.9) (3.5) (7.2) Decrease in net cash in the period/year (176.2) (20.1) (90.1) Opening net debt (405.7) (315.6) (315.6) Closing net debt (581.9) (335.7) (405.7) b) Analysis of net debt: Cash and cash equivalents Borrowings * (1,064.8) (784.8) (705.4) Total net debt (581.9) (335.7) (405.7) * Borrowings consist of the short-term borrowings, the convertible bonds and the other long-term debt. The carrying values of the convertible bonds and the other long-term debt on the balance sheet are stated net of the unamortised portion of the issue costs of US$2.0 million (June : US$2.7 million) and debt arrangement fees of US$17.3 million (June : US$14.3 million) respectively. 12. DIVIDENDS No interim dividend is proposed (: US$nil). 33

34 INDEPENDENT REVIEW REPORT TO PREMIER OIL PLC We have been engaged by the company to review the condensed set of financial statements in the halfyearly financial report for the six months ended 30 June which comprise the condensed consolidated income statement, the condensed consolidated statement of comprehensive income and expense, the condensed consolidated balance sheet, the condensed consolidated statement of changes in equity, the condensed consolidated cash flow statement and related notes 1 to 12. We have read the other information contained in the half-yearly financial report and considered whether it contains any apparent misstatements or material inconsistencies with the information in the condensed set of financial statements. This report is made solely to the company in accordance with International Standard on Review Engagements (UK and Ireland) 2410 Review of Interim Financial Information Performed by the Independent Auditor of the Entity issued by the Auditing Practices Board. Our work has been undertaken so that we might state to the company those matters we are required to state to it in an independent review report and for no other purpose. To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the company, for our review work, for this report, or for the conclusions we have formed. Directors' responsibilities The half-yearly financial report is the responsibility of, and has been approved by, the directors. The directors are responsible for preparing the half-yearly financial report in accordance with the Disclosure and Transparency Rules of the United Kingdom s Financial Services Authority. As disclosed in note 1, the annual financial statements of the company are prepared in accordance with IFRSs as adopted by the European Union. The condensed set of financial statements included in this half-yearly financial report has been prepared in accordance with International Accounting Standard 34 Interim Financial Reporting as adopted by the European Union. Our responsibility Our responsibility is to express to the company a conclusion on the condensed set of financial statements in the half-yearly financial report based on our review. Scope of review We conducted our review in accordance with International Standard on Review Engagements (UK and Ireland) 2410 Review of Interim Financial Information Performed by the Independent Auditor of the Entity issued by the Auditing Practices Board for use in the United Kingdom. A review of interim financial information consists of making inquiries, primarily of persons responsible for financial and accounting matters, and applying analytical and other review procedures. A review is substantially less in scope than an audit conducted in accordance with International Standards on Auditing (UK and Ireland) and 34

35 consequently does not enable us to obtain assurance that we would become aware of all significant matters that might be identified in an audit. Accordingly, we do not express an audit opinion. Conclusion Based on our review, nothing has come to our attention that causes us to believe that the condensed set of financial statements in the half-yearly financial report for the six months ended 30 June is not prepared, in all material respects, in accordance with International Accounting Standard 34 as adopted by the European Union and the Disclosure and Transparency Rules of the United Kingdom's Financial Services Authority. Deloitte LLP Chartered Accountants and Statutory Auditor London, United Kingdom 24 August 35

36 WORKING INTEREST PRODUCTION BY REGION (UNAUDITED) North Sea UK: kboepd Year to 31 December kboepd Balmoral area Kyle Scott/Telford Shelley Wytch Farm Other UK Asia Indonesia: Anoa Kakap Middle East, Africa and Pakistan Pakistan: Bhit/Badhra Kadanwari Qadirpur Zamzama Mauritania: Chinguetti Total Includes Brenda, Nicol and Stirling fields. 36