Half-Yearly Results 2012

Press Release

Premier Oil plc

Half-Yearly Results for the six months to 30 June 2012

HIGHLIGHTS

Operational

·; Production averaged 58,400 boepd (2011: 36,900 boepd) during the first half of the year, up 58 per cent, with performance in the second quarter averaging 61,000 boepd

·; Significant progress made on all operated development projects, with government approval of the Solan, Pelikan, Naga and Dua projects achieved, underpinning the near-term growth in the underlying value of the business

·; Exploration successes in the first half with the play opening Anoa Deep well on Natuna Sea Block A and the Carnaby well on the western side of the Catcher licence

·; Significantly increased materiality of exploration portfolio through acquisition and new venture activity in Vietnam, Iraq, Norway and the UK

- Unrisked net prospective resource portfolio increased to 2.7 billion boe

·; Post period-end announced farm-in to Rockhopper's interests in the Falkland Islands, adding around 200 mmboe of discovered resources and significantly increasing the group's future exploration potential

Financial

·; Record half-year financial results; continued strong operating cash flow growth

·; Record profit before tax of US$194.6 million (2011: US$32.5 million) and profit after tax of US$145.8 million (2011: US$88.5 million)

·; Record operating cash flow of US$325.5 million (2011: US$242.3 million), an increase of 34 per cent

·; Successful completion of new bank and bond funding, raising US$585 million in the period

·; Cash resources and undrawn bank facilities at US$1.3 billion (31 December 2011: US$1.1 billion) at 30 June

Outlook

·; Full-year production is estimated to be 60,000 boepd (FY 2011: 40,400 boepd), up 49 per cent

·; Estimated run rate of 75,000 boepd once the Huntington and Rochelle fields are on-stream, rising to 100,000 boepd in the medium-term once the Catcher fields are on-stream

·; Material wells planned including Luno II (Norway), Lacewing (UK) and Ca Voi (Vietnam)

·; Rising cash flows and strong funding position fully finance forward development spend, exploration programme and dividend commitment with flexibility for other opportunities

·; Announced intention to commence dividend payments for 2012 re-confirmed post Rockhopper transaction

Simon Lockett, Chief Executive Officer, commented:

"We are delighted with our achievements in the first half of the year with another set of record financial results, underpinned by strong production from our portfolio of fields. We anticipate a further significant step up in production as our two new UK development projects come on-stream, and a high impact exploration programme with key wells such as Luno II, Lacewing and Ca Voi in the coming months. We continue to secure new high quality projects, as demonstrated through the recent Sea Lion acquisition. With a fully funded programme and dividend commitment, our shareholders can continue to look forward to strong growth and attractive returns."

There will be a presentation to analysts at the company's offices at 10:30am today which will be webcast live on the company's website at www.premier-oil.com.

Following changes in the UK company disclosure regulations in 2008, it is not a requirement for half-yearly financial statements to be sent to shareholders. Accordingly, Premier will not be printing and distributing a 2012 Half-Yearly Report. A copy of this announcement is available for download from our website at www.premier-oil.com and hard copies can be requested by contacting the company (e-mail: [email protected] or telephone: +44 (0)20 7730 1111).

INTERIM MANAGEMENT REPORT

CHAIRMAN'S STATEMENT

Strong performance from our producing fields and a favourable oil price environment have delivered record half-year financial results. Progress on our UK development projects will deliver short and medium-term production increases. The announced farm-in to Rockhopper's interests in the Falkland Islands significantly enhances the group's resource base and future growth potential.

Average production during the first half of the year was 58 per cent higher at 58,400 barrels of oil equivalent per day (boepd) (2011: 36,900 boepd) benefitting from the new fields in Indonesia and Vietnam brought on line in the fourth quarter of last year. Production performance from existing fields in the UK, Pakistan and Indonesia was strong across the portfolio.

While follow-on projects in Indonesia and Vietnam are moving forward, the focus of development activity has moved to the UK North Sea where the Huntington and Rochelle fields are scheduled to be on-stream by year-end and where there has been significant progress with the operated Solan and Catcher projects. In Norway, the Bream project is expected to be submitted for government approval in the second half of the year. Premier increased its interest in this project and the surrounding acreage through a sale and purchase agreement during the first half.

The purchase of 60 per cent of Rockhopper's interests in the Falkland Islands, which is scheduled to complete shortly, will be a material addition to the group and represents an excellent fit both from a financial and an operational point of view. We look forward to working with both Rockhopper and the Falkland Islands Government on developing the large potential of the Sea Lion project and surrounding acreage.

We are encouraged by continuing resource additions in our core exploration areas of the Central North Sea and the Natuna Sea in South East Asia. The Carnaby discovery on the western side of the Catcher Block in the UK and the Anoa Deep gas discovery underneath our existing gas infrastructure in Indonesia support the potential for ongoing valuable near field successes in both areas. Our exploration teams have also been focused on growing our acreage portfolio for the future. We continue to participate in new study areas in Indonesia and in the UK and Norway licensing rounds. We are pleased with progress made on seismic work in Kenya and Norway on new licences acquired last year, targeting drilling campaigns in 2013 and 2014. We have added new acreage in Iraq and Vietnam in underexplored areas which, though new to the group, have geological settings which play to our knowledge from existing areas. We are also delighted to have reached commercial arrangements with the management teams of EnCore and Rockhopper such that we will continue to work closely with them, and benefit from their knowledge base, in their respective areas of exploration expertise.

Crude oil prices remained strong during the first half and local market conditions drove up fuel oil pricing which dictates the gas market terms in Singapore. Brent crude traded in a range of US$88.7 per barrel (bbl) to US$126.6/bbl, averaging US$113.7/bbl (2011: US$111.1/bbl). Against this background, operating cash flows were up 34 per cent at US$325.5 million (2011: US$242.3 million). Profit after tax for the period was US$145.8 million (2011: US$88.5 million), again a record for the group.

With new operated producing assets, and continuing construction work in progress, we place the highest priority on health, safety and environmental matters. We remain committed to operating safely, responsibly and sustainably in every part of our business. Success in these areas protects our assets, our revenue and our reputation. Our safety and environmental management systems are key drivers to deliver this success and their certification to OHSAS 18001 and ISO 14001 demonstrates we are meeting international standards. We continue to retain this certification for our Balmoral and Anoa production operations in the UK and in Indonesia, and for our global drilling function. We are pleased to report that our new production facility in Indonesia, Gajah Baru, has also recently been awarded certification. We also continue to retain our inclusion in the FTSE4Good Index.

Outlook

The Board recently re-confirmed, following an extensive review, its commitment to a high return growth strategy and to the prudent financing principles which support it. We plan to invest in, and execute well, high quality development projects. We will continue to access reserves and resources to do so through successful exploration and acquisition, in basins where we have the knowledge and capability to compete. This strategy has resulted in an impressive increase in underlying net asset value per share over time, independent of oil price fluctuations. The Board has also considered other ways than capital growth in which shareholders can be rewarded for their investment and, as announced at our AGM in May, we intend to initiate an appropriate dividend starting with our final results for the 2012 financial year.

The first half of this year has seen us deliver good value acquisitions, progress on operated developments and strong financial performance. In the second half of the year, we have material exploration activities in the UK and Norway. We expect to exit the year with further growth in production from new fields, generating stronger cash flows for re-investment and attractive returns for shareholders.

Mike Welton

Chairman

OPERATIONAL REVIEW

ASIA

Good performance from the operated Chim Sáo and Gajah Baru fields underpinned the ramp-up in production achieved in the first half of the year. Ongoing development activities continue apace with government approvals received for the Pelikan, Naga and Dua projects. These operated near field developments will help to maintain Premier's future production profile in Asia. Premier has also seen exploration success in Indonesia with the Anoa Deep well, which opened up a new play for the company. This, together with recent prospect maturation and new venture activity, has significantly enhanced the materiality of Premier's future drilling programme.

Production and development

Indonesia

During the first six months of 2012, the Anoa and Gajah Baru fields on the Premier-operated Natuna Sea Block A sold an overall average of 215 billion British thermal units per day (BBtud) (gross) (2011: 154 BBtud) with the Anoa facility delivering 10 per cent over its contractual market share under GSA1 at around 47 per cent. The non-operated Kakap field contributed a further 33 BBtud (gross) (2011: 42 BBtud). Gross liquids production averaged 2,600 barrels of oil per day (bopd) (2011: 1,700 bopd) from the Block A Anoa field and 4,000 bopd (2011: 3,400 bopd) from Kakap. Overall, average net production from Indonesia amounted to 14,700 boepd during the first half of 2012 (2011: 10,800 boepd) on a working interest basis.

The Gajah Baru field, which came on-stream in October 2011, supplies gas to Singapore under a second Gas Sales Agreement (GSA2). The facility performed well during the period, although the build-up of production rates has been slower than anticipated due to end-user project delays. In addition to being able to meet all of Singapore customer demand under GSA2, the Gajah Baru facility was able to lend gas to GSA1 as required, ensuring an increased reliability of supply of natural gas into Singapore from Natuna Sea Block A.

Premier, in collaboration with the Indonesian state-owned gas regulator, continues to discuss with potential buyers the sale of additional gas (approximately 40 BBtud) from Gajah Baru into the Indonesian domestic market via a swap agreement (GSA5). However, Premier does not expect any gas to be delivered under this swap agreement in 2012.

The Anoa facility is being upgraded through a series of engineering projects, collectively known as Phase 4, and this is well under way. The first phase of offshore construction commenced in July and the pre-fabricated compression modules are now being installed on the platform. The second phase of offshore construction will take place in the summer of 2013. This project, which will develop around 200 billion cubic feet (bcf) of undeveloped proven reserves on Natuna Sea Block A and increase the capacity of the Anoa facility to 200 BBtud, will be completed in the second half of 2013.

The operated Pelikan and Naga projects continue to progress to schedule with partner and government sanction achieved in the first half of 2012. The engineering, procurement, construction and installation (EPCI) contract for two wellhead platforms and connecting pipelines was awarded in May and detailed engineering and procurement activities are already in progress. Fabrication of the jacket and topsides have commenced at the SMOE yard in Batam. In parallel, a tendering process has been initiated to secure a rig to drill three development wells on each of the fields. First gas from the Pelikan and Naga gas fields, which are estimated to have total reserves of 150 bcf, is targeted for 2014.

On the non-operated Block A Aceh, evaluation of a development scheme to deliver first gas in 2015 is ongoing, as the EPCI re-tender resulted in higher than anticipated bids. Negotiations with the Indonesian Government and the ultimate gas buyers over the gas price are expected, while discussions on facility sharing with the operator of the nearby Arun Block are progressing.

Vietnam

The Premier-operated Chim Sáo oil field averaged 26,000 boepd (gross) in the first half of 2012 against an original forecast of 25,000 boepd. Following a maintenance shutdown in March, production has been maintained at an average of 31,000 boepd. Water injection to the Chim Sáo wells, which commenced in June, is being ramped up to maintain reservoir pressure.

A two-well supplementary drilling programme, which was initiated to develop additional reservoirs, was successfully completed in June. The first of the two wells (CS-N17XP) was drilled to produce from the north west extension to the Chim Sáo field and was brought on-stream in August, with initial extended production test rates averaging 4,000 bopd. The second well, which accesses the shallower MDS-1 reservoir, is expected to be on production shortly.

The development of the Premier-operated Dua oil field as a near field tie-back to the Chim Sáo facilities received partner sanction in the second quarter of 2012 and Prime Minister approval in August with a plan to deliver first oil in 2014.

Exploration and appraisal

Indonesia

Two out of the three wells that Premier drilled in the first half of the year in Indonesia encountered hydrocarbons. The most significant of these was the Premier-operated Anoa Deep well (WL-5X) which discovered gas beneath the Anoa field on Natuna Sea Block A. This discovery, which tested at 17 million standard cubic feet per day (mmscfd) from fractured Lama Formation sandstone reservoirs, has opened up a new play for Premier. Integrated studies are now being conducted to mature follow-on Lama prospects identified on the block for drilling, with the first well planned for the second half of 2013.

Elsewhere on Natuna Sea Block A, the Biawak Besar well was spudded in April to test the concept of stratigraphically trapped gas-bearing reservoirs in the vicinity of the Iguana and Bison fields. While the well penetrated seismic attribute anomalies that indicated the presence of gas, the sandstone reservoirs encountered were water bearing. Further post well work is ongoing to determine the future prospectivity of the targeted play.

In April, Premier participated in the Benteng-1 well on the non-operated Buton Block (Premier equity 30 per cent). Benteng-1 was the first new-field wildcat well drilled in over 20 years in the basin. The well discovered a potentially commercial oil accumulation in the shallow (750 metres) limestone reservoirs of the Tondo Formation. Post well work is in progress to determine the commercial viability of the discovery and the follow-on potential across the Buton Block as a whole.

On the non-operated Block A Aceh, preparations for the first exploration well on the block (Matang-1) are complete. Premier expects the well to spud in the fourth quarter of 2012. Meanwhile, offshore North Sumatra, the Andaman II joint study (Premier equity 40 per cent, non-operated) was awarded in May and approximately 1,000km of 2D seismic data will be acquired and processed in the second half of the year.

On the Premier-operated Tuna Block, post well studies from the 2011 drilling programme were completed with two prospects - Kuda Laut and Singa Laut - identified for drilling in 2013.

Vietnam

On Block 12W, the Chim Sáo North West appraisal well, CS-3X, reached a total depth of 4,235 metres in August. The appraisal well was drilled to determine whether the Chim Sáo North West area, discovered in 2011, extended into a separate fault segment to the north. The well targeted the Upper and Middle Dua sands. While 135 metres of sandstone reservoir were penetrated in the Upper Dua interval there was no indication of hydrocarbons. In the Middle Dua interval 165 metres of sands were drilled, where oil shows were encountered. The information gained from the appraisal well, which has been plugged and abandoned, will be integrated with Premier's existing knowledge of the basin to better understand the potential in the other untested areas adjacent to the Chim Sáo discovery. The earlier discovery to the south has now been brought on-stream.

Major integrated studies of both the Cá Rồng Đỏ discovery and of the further exploration potential of Block 07/03 are nearing completion. Based on these studies, an exploration well will be drilled in 2013 to target the proved Miocene and Oligocene reservoirs for which the discovery well CRD-2X was a play opener in 2011.

In the second quarter, Premier farmed into the Block 121 for a non-operated participating interest of 40 per cent, subject to formal Vietnamese Government approval. Premier has already identified one prospect, known as Ca Voi, which it plans to drill in early 2013, subject to rig availability. The prospectivity of Ca Voi centres on the untested Oligocene play fairway, which Premier recognises as being geologically similar to that of the Cau Formation successfully explored in Blocks 12W and 07/03 in the Nam Con Son Basin to the south. A successful Ca Voi well would also de-risk multiple leads elsewhere on the block, including the nearby Swordfish and East Ca Voi prospects.

NORTH SEA

Improved facility uptime at key UK producing assets resulted in higher production during the first half of the year. The North Sea development projects, which continue to move forward as shown by the sanction of the Premier-operated Solan project, will deliver short and medium-term production increases. Exploration in the North Sea continues to seek to push the proven plays wider and deeper with notable first half success at the Premier-operated Carnaby well in the western part of the Catcher area.

Production and development

UK

UK production averaged 13,600 boepd for the first half of the year (2011: 10,500 boepd). The 30 per cent increase in production is mainly due to significantly improved facility uptime at Wytch Farm and Scott, as well as from the Balmoral floating production vessel, which produces oil from the Balmoral, Brenda, Nicol and Stirling fields. Production from the Brenda and Nicol fields was further aided by the successful replacement of the subsea pump. In addition, Premier's share of Wytch Farm production increased following the completion of the acquisition of an additional 17.7 per cent equity interest in the field in December 2011.

The increase in production was partly offset by the temporary loss of production from the Kyle field (forecast 2012 production of 1,800 boepd). As previously announced, exceptionally adverse weather in December 2011 caused the Banff floating production, storage and offtake vessel (FPSO), which handles Kyle production, to lose its anchors which resulted in severe damage to the subsea risers. The Banff FPSO is currently anchored in Scapa Flow, Orkney, where the reinstatement project is ongoing. The Kyle field is expected to be back on-stream in 2014. The lost production from the Kyle field is the subject of an ongoing business interruption insurance claim.

Good progress continues to be made offshore on the non-operated Huntington project in the UK North Sea. The sixth and final well was completed in July and the rig has moved off location, marking the end of a successful development drilling campaign. With three of the four producers coming in above expectations, it is hoped that the Huntington field will achieve good initial run rates once on production. The FPSO upgrade is nearing completion and the vessel is now being inspected by the operator ahead of providing confirmation to the subsea installation vessel in early September of an October installation window. At this stage, the operator continues to forecast sail away of the Voyageur FPSO in September and is targeting first oil by year-end.

At Rochelle, the subsea installation programme is under way, with the arrival of the pipe lay vessel anticipated for September, while the related upgrade to the Scott platform continues on schedule. The first of the two development wells, which spudded in July, is expected to be completed in October. This well will be tied into the Scott platform ahead of first gas by the end of the year, with a second well to follow.

The Premier-operated US$850 million Solan project, West of Shetland, advanced considerably during the first half of the year. The project received field development plan approval from the Department of Energy and Climate Change in April and all of the significant contracts for the project were awarded. The drilling rig contract, for development drilling in 2013 and 2014, was awarded to Awilco for the WilPhoenix semi-submersible rig, while the procurement and fabrication of the topsides and jacket will be undertaken by Burntisland Fabrications in Fife, Scotland. In addition, Drydocks World - Dubai has been awarded the contract for the fabrication of the subsea storage tank and Heerema will carry out all of the installation work. Construction of the topsides has already commenced while development drilling is scheduled to start in the first quarter of 2013. First oil from the 40 million barrel field is expected in the fourth quarter of 2014.

In January 2012, the acquisition of EnCore Oil plc was completed and, as a result, Premier increased its equity interest in the Catcher project from 35 per cent to 50 per cent and was appointed operator. Technical studies on the project were progressed significantly during the first half of the year and, in August, Premier made a development concept recommendation to the joint venture partners. Changes in ownership of the Catcher fields over the last six months have significantly reduced the uncertainty surrounding the funding for the development project, though the approval process for concept selection will now take longer. As a result, and subject to the outcome of ongoing discussions with key contractors, Premier now models early 2016 for first oil from the Catcher field.

Norway

In May, Premier purchased an additional 20 per cent equity interest in the Bream project offshore Norway, bringing Premier's equity interest in the development to 40 per cent. The acquisition was completed in July following receipt of approval from the Ministry of Petroleum and Energy and the Ministry of Finance. A number of contracts are under tender for the facilities and drilling programme ahead of formal project sanction in the second half of 2012.

Work on a stand-alone development of the Frøy field is on hold while the operators of six fields in the Frøy area are undertaking technical and commercial studies to evaluate the possibility of an area development. The current phase of these studies is expected to be complete by year-end ahead of possible concept selection in the fourth quarter of 2013.

Exploration and appraisal

UK

Premier drilled five wells - four of which were operated by Premier - in the UK North Sea in the first half of the year. The Premier-operated Carnaby exploration well, which was drilled in the second quarter of 2012, discovered good quality oil in the western part of the Catcher area. Pressure data and sampling indicated that the oil was of similar quality to the main Catcher discovery, although the oil water contact was at the shallower end of expectations. The high quality data acquired from the well is now being used to calibrate the remaining exploration potential in this part of the Catcher Block, as well as to determine what contribution the Carnaby discovery will make to the overall Catcher development.

Premier expects to return to exploration on the Catcher licence in the second quarter of 2013 with the drilling of the Bonneville prospect. Additional prospects in the Catcher area are being matured for drilling at later dates.

Premier drilled the high risk Coaster exploration well on UK Block 28/10 in June 2012, immediately after the Carnaby well. Although the well was plugged and abandoned as a dry hole, Premier considered it an important well to drill given its proximity to the Catcher licence. In recognition of the risks, Premier took the precaution of farming out 50 per cent of its equity on a promoted basis.

Premier also farmed out 67 per cent of the cost of the high risk Bluebell well which was drilled in the first quarter of 2012. The Palaeocene target was encountered on prognosis and the logs showed excellent sand quality but the reservoir was water wet. The East Fyne appraisal well was also drilled in licence P077, which was plugged and abandoned as a sub-commercial oil discovery. The non-operated Stingray exploration well (Premier equity 50 per cent), which was attempting to push the Jurassic play fairway to the north, was also unsuccessful.

Premier continues to seek to push the proven plays wider and deeper in the UK North Sea. The next well to be drilled will test the Spaniards East prospect on Block 15/25a, close to the producing Scott field. The same rig will then move to the Cyclone prospect on Block 21/7b. Elsewhere in the UK North Sea, the high pressure high temperature (HPHT) Lacewing prospect on Block 23/21 is expected to spud in the last quarter of 2012.

Premier remains a committed explorer in the UKCS, and new venture activities continued apace during the first six months of the year. In addition to increasing its exploration acreage in the UK North Sea, as a result of the acquisition of EnCore in January, Premier submitted applications for 15 licences (10 as operator) in the UK 27th Round. The results of this round are anticipated before year-end. Further, Premier signed an exclusive agreement with EnCounter Oil, led by the former management of EnCore, under which EnCounter will seek to identify additional exploration opportunities in the Central and Northern North Sea. Premier hopes to harness the proven exploration skills of the EnCounter staff in order to improve further the quality and materiality of its exploration programme in the UK sector.

Norway

In the Norwegian North Sea, a material oil discovery known as Skarfjell was made on PL418 in April 2012. Mapping of the structure shows the discovery extending into PL378, in which Premier has a 20 per cent interest and which contains the Grosbeak discovery. An appraisal well on the Skarfjell extension is planned for 2013 and may have further implications for prospectivity on PL378 as well as facilitating the future development of Grosbeak.

Elsewhere in Norway the Luno II prospect, in which Premier has a 30 per cent interest and which is located on the southwest margin of the productive Utsira High, is expected to spud in the fourth quarter of this year.

Premier has continued to build its exploration portfolio in the Norwegian North Sea with the acquisition of an additional 20 per cent interest in PL406, which contains the Mackerel discovery and the Herring prospect. The Mackerel discovery will be incorporated into the Bream concept select decision later this year, while the Herring prospect is being matured for drilling.

Data on the three Norwegian exploration licences which Premier acquired at the end of 2011 were integrated with the company's existing data on its nearby PL567 Freki licence (Premier equity 60 per cent) during the first six months of the year. Leads and prospects in the Greater Freki area continue to be worked up and it is expected that this acreage will deliver at least one high impact exploration well in early 2014.

Work continues to evaluate the licences acquired in early 2012 as a result of the APA 2011 Round. In particular, a 500km2 3D seismic survey was acquired in July over Premier-operated licence PL622, with decisions expected on exploration drilling later in the year. In addition, preparations continue for the APA 2012 and the Frontier 22nd Exploration Rounds with applications due in the second half of the year.

MIDDLE EAST, AFRICA AND PAKISTAN

Pakistan gas production increased as natural decline was more than offset by infill successes and compression upgrades. Near field exploration success continued with step-out discoveries on the Kadanwari and Bhit/Badhra gas fields. Elsewhere in the region, at least one prospect will be drilled on Premier's Kenyan acreage in 2013, following the encouraging results to date of the seismic programme, while a number of high impact opportunities were added to the exploration portfolio through Premier's entry into Iraq.

Production and development

Pakistan

Average production in Pakistan during the first half of the year was 15,900 boepd net to Premier, approximately 7 per cent higher than in the corresponding period in 2011 (14,900 boepd). Natural decline was more than offset by additions to production from the successful tie-in of three exploration wells (K-27, K-28 and K-30) on Kadanwari, the completion of two extended reach wells at Qadirpur and additional perforation work on three wells at Zamzama.

Average production from the Qadirpur gas field during the period was 3,900 boepd net to Premier (2011: 3,800 boepd). Production was maintained at this level as a result of the successful installation of wellhead compressors and the completion of two extended reach wells. Work is also in progress for the installation of two supplementary front end compressors. This will maintain production plateau from the Qadirpur gas field during 2013.

Production from the Kadanwari gas field averaged 2,400 boepd net to Premier in the first half of 2012 (2011: 2,300 boepd). Kadanwari achieved record production of 130 mmscfd (gross) during the period due to the tie-in of additional new exploration wells. In addition, the K-29 development well was completed in April and is expected to be tied in to the production system in the fourth quarter of 2012. This will further help to maintain production plateau in 2013.

Average production from the Zamzama gas field was 6,100 boepd net to Premier during the period (2011: 5,400 boepd). This improved production performance was due to the commissioning of the front end compressors during the second half of 2011 and additional perforation at three of the Zamzama wells. An additional infill well (Zam-8) was successfully drilled in July and is expected to be tied in to production by November. This, along with two further infill wells - Zam-9, which is currently drilling, and Zam-10 - will help to maintain production levels from the Zamzama field in the future.

Production from the Bhit/Badhra gas fields averaged 3,500 boepd (2011: 3,400 boepd) net to Premier. The field is currently at plateau with the use of wellhead compressors. While natural production decline is expected to set in from the last quarter of 2012, this will be partly offset by the re-staging of existing wellhead compressors.

Premier also has a 3.75 per cent non-operated interest in the Zarghun South gas field development. The reserves at this field have been certified by an independent third party as tight gas and, as a result, the operator has submitted a revised development plan to the government to obtain approval for the higher price associated with tight gas. Government approval of the revised development plan is expected in the third quarter, with first gas from the field targeted for early 2014.

Mauritania

Production from the Chinguetti field averaged 500 bopd net to Premier in the first half of 2012 (2011: 700 bopd). This reduction was due to natural decline and an unplanned field shutdown caused by a subsea control module fault which was subsequently rectified.

The undeveloped discoveries of Banda, Tiof and Tevet continue to be held by the joint venture partners. Pre-development technical and commercial studies on the Banda field are ongoing with front end engineering and design (FEED) work expected to begin shortly. In parallel, gas sales arrangements for Banda are currently under discussion with potential buyers and the Mauritanian Government. The operator is targeting first gas for 2015.

Exploration and appraisal

Pakistan

The Badhra B North-1 appraisal well (Badhra-7) was spudded in May 2012. The aim of the appraisal well was to prove the extension of the Mughalkot reservoir in Area B of the Badhra lease. The well, which reached a total depth of 2,450 metres in August, discovered a better than expected reservoir with over 55 metres of net gas pay penetrated, 44 metres of which is in hitherto untested sands. The pre-drill P50 gross resource estimate was 63 bcf. The well is being tested and is expected to be tied back into the existing export infrastructure by the end of October 2012.

On the Kadanwari gas field the K-30 exploration well, which was completed in March, tested gas with a flow rate of 52 mmscfd through a 60/64 inch choke. The well was tied in to existing infrastructure at the end of the second quarter. The K-32 exploration well is expected to spud in the second quarter of 2013.

The first of a three-well pilot programme to test the tight gas potential of Kadanwari was drilled in the second quarter. The vertical well (K-3 Dir-B) encountered five separate zones. Fracturing and testing of three of the five tight sands has been undertaken with gas flowing to the surface. The remaining two zones will now be tested ahead of the second well which is expected to spud in September. The aim of the first two wells, which are vertical wells, is to understand the best zone in which to drill future tight gas wells. The third well, which is expected to spud in December, is planned as a horizontal well targeting the tight G-Sand level.

Mauritania

Geological studies continue on the non-operated production sharing contract (PSC) C-10 (Premier equity 6.23 per cent) to determine the optimum locations for the two planned commitment wells. It is expected that the first of the two commitment wells will be drilled in early 2013.

Kenya

Premier holds 20 per cent and 25 per cent non-operated working interests in offshore Kenya exploration blocks L10A and L10B, respectively. Fast track 3D data and inboard 2D seismic data have been acquired, with processing due for completion later this year. A new 3D seismic survey will now be acquired over the inboard play to further evaluate leads identified on the 2D data. Initial results of the survey data are encouraging and it is expected that at least one prospect on the acreage will be drilled in the second half of 2013.

Iraq

Premier has agreed to join Bashneft on Block 12, an 8,000 km2 block in the underexplored Salman Zone in southern Iraq, with a 30 per cent equity, subject to final approval from the authorities. The block contains a variety of leads at various stratigraphic levels with estimated gross prospective resources in excess of 1 billion barrels. The current plan is to acquire seismic data over the block in 2013.

Egypt

The award of the South Darag Block in the Gulf of Suez is awaiting formal government ratification. This remains delayed by the lengthening political transition process in Egypt and is now anticipated by year-end. Elsewhere in Egypt, Premier holds a 20 per cent non-operated working interest in the North Red Sea Block 1. Studies are continuing to assess the further prospectivity of the block and to identify potential well locations.

Congo

Premier has now completed the formal withdrawal process from the Marine IX licence in the Democratic Republic of the Congo.

SADR

Premier's exploration rights in the Saharawi Democratic Republic (SADR) remain under force majeure while awaiting resolution of sovereignty under a United Nations mandated process. Premier's interests now include the offshore Laguera Block as a result of the EnCore acquisition in January 2012.

FINANCIAL REVIEW

Income statement

Group production, on a working interest basis, averaged 58,400 boepd in the first half of 2012 compared to 36,900 boepd in the first half of 2011 and 40,400 boepd for the full-year 2011. This reflects good underlying performance across the portfolio of producing fields and, in particular, the contribution of the Chim Sáo and Gajah Baru fields in Vietnam and Indonesia respectively, which came on-stream in late 2011. Entitlement production for the period was 52,400 boepd (2011: 33,800 boepd).

Oil and gas prices were strong during the first half of 2012 with an average Brent oil price of US$113.7/bbl. Premier's average realised oil price for the period was US$110.5/bbl (2011: US$109.7/bbl) pre-hedges and US$106.2/bbl (2011: US$79.6/bbl) on a post-hedge basis. Average realised gas prices for Indonesian production were US$19.6 per thousand standard cubic feet (mscf) (2011: US$18.5/mscf), in line with higher crude prices. In Pakistan, gas prices across all producing fields averaged US$4.1/mscf (2011: US$3.7/mscf). The combined effect of higher production and realised prices was to increase turnover to US$744.3 million (2011: US$342.2 million).

Cost of sales in the period was US$393.9 million (2011: US$200.3 million). Underlying operating costs were US$14.7 per barrel of oil equivalent (boe) (2011: US$14.0/boe) reflecting the somewhat higher percentage of offshore production in our portfolio of fields.

Amortisation of oil and gas properties rose from US$102.8 million to US$164.0 million but on a unit basis remained steady at US$15.4/boe (2011: US$15.4/boe). Impairment charges for the period amounted to US$22.0 million pre-tax (2011: credit of US$5.5 million).

Exploration expense and pre-licence exploration costs amounted to US$77.9 million (2011: US$80.6 million) and US$14.5 million (2011: US$10.2 million) respectively. The principal write-offs related to the dry holes drilled in the first half in the UK and in Indonesia. Operating profit for the period was US$245.2 million, a 480 per cent increase on corresponding 2011 profits of US$42.3 million.

Interest and other finance charges for the period were US$57.3 million (2011: US$27.6 million), offset by interest revenue, finance and other gains of US$0.7 million (2011: US$1.5 million). Finance costs capitalised during the period totalled US$4.6 million (2011: US$12.0 million). Net interest movements reflect increased long-term debt taken on by the group in conjunction with our growing investment programme. Net finance charges also reflect the non-cash unwinding of discounting in relation to outstanding convertible bonds and future abandonment obligations.

A net credit of US$6.0 million (2011: US$16.3 million) was recorded in the first half in respect of derivative financial instruments. The group's oil collar transactions are embedded in long-term crude offtake arrangements. Such embedded collars are not required to be marked to market. However, deferred revenue booked in prior years in respect of such arrangements is being credited to the income statement over the remaining life of such transactions. A total of US$4.2 million was credited in the period (2011: US$13.1 million) relating to such deferred revenue. Movements in the valuation of hedges of High Sulphur Fuel Oil (HSFO), which underlies the pricing mechanism for gas sold into the Singapore market and which are marked to market, amounted to a credit of US$1.1 million in the period (2011: US$4.7 million).

Realised cash losses arising from hedging activities amounted to US$38.2 million (2011: US$58.2 million). These losses arose as oil and gas prices during the period exceeded caps contained within our collar hedges and the price of forward oil sales crystallising during the period. These cash losses are deducted from sales revenues.

The group had a tax charge for the period of US$48.8 million (2011: US$56.0 million, credit) reflecting overseas tax charges of US$103.3 million (2011: US$46.0 million) and UK petroleum revenue tax (PRT) of US$17.7 million (2011: US$30.4 million). These charges were offset by a deferred credit of US$72.2 million in respect of UK mainstream corporation tax, arising due to the recognition of small field allowances in respect of the now sanctioned Solan field and the inclusion of additional amounts for carried forward ring fence expenditure supplement.

Profit after tax in the period to 30 June 2012 therefore was US$145.8 million (2011: US$88.5 million). Basic earnings per share for the period were 27.8 cents (2011: 19.0 cents).

Cash flow

Cash flow from operating activities amounted to US$325.5 million (2011: US$242.3 million). Capital expenditure in the period (excluding acquisitions) was US$318.2 million (2011: US$296.8 million).

Capital expenditure

Development spend in the first half was focused on the Huntington and Rochelle projects in the UK (targeted to be on-stream by year-end), Solan and Asia development drilling and facility enhancements. Exploration spend in the first half was US$111.0 million (2011: US$118.7 million).

Acquisitions and disposals

In January, the company completed the acquisition of EnCore Oil plc (EnCore). Shareholders representing 93.5 per cent of EnCore's shares elected to take new Premier shares, resulting in the company paying a total of £14.1 million (US$21.6 million) in cash to EnCore shareholders and issuing 60,931,514 new Ordinary Shares to those who chose the share alternative.

Prior to completion of the EnCore transaction, the company reached an agreement with TAQA Bratani Ltd to on-sell the 16.6 per cent interest in the Cladhan area, which it indirectly acquired from the EnCore acquisition, for a consideration of US$54.0 million. This on-sale was completed in March 2012.

In May, Premier agreed to acquire a 20 per cent interest in PL407 and a 40 per cent interest in the adjacent PL406 licence on the Norwegian Continental Shelf. These interests increased Premier's share of the Bream development project to 40 per cent and the company's operated interest in PL406 to 80 per cent. PL406 contains the Mackerel discovery and the Herring prospect which could form part of the Bream area development in the future. Upfront consideration for the acquisition was US$10.0 million with contingent payments of US$17.5 million payable upon certain project outcomes. The acquisition was completed in July 2012.

In July, Premier announced that it had agreed to farm-in to 60 per cent of Rockhopper Exploration plc's (Rockhopper) licence interests in the Falkland Islands, including the Sea Lion development project. The initial payment will be US$231.0 million in cash. In addition, Premier will pay an exploration carry of up to US$48.0 million and, subject to field development plan approval, a development carry of up to US$722.0 million. These will be funded from a combination of Premier's existing cash resources and facilities and future cash flow from operations. Premier and Rockhopper have also agreed to jointly pursue exploration opportunities in the Falkland Islands and analogous plays in selected areas offshore Southern Africa. The acquisition transaction is subject to the approval of the Falkland Islands Government and is expected to complete in September 2012.

Balance sheet

Net debt at 30 June 2012 was US$830.9 million (2011: US$581.9 million) including cash resources of US$290.2 million (2011: US$482.9 million).

Long-term borrowings comprise convertible bonds, senior loan notes and bank debt. The convertible bonds have a par value of US$250.0 million and a final maturity date of 27 June 2014. They carry a conversion price of US$6.69 per share. In February, additional bank facilities of US$350.0 million were negotiated and a second issue of senior loan notes was completed. This second issue, with maturities of seven, 10 and 12 years, amounted to US$202.0 million and €25.0 million. A US$175.0 million term bank loan was repaid during March 2012. Cash and undrawn facilities, including letter of credit facilities, at30 June were approximately US$1.3 billion.

Financial risk management

A portion of expected future production has been hedged, using oil and gas price floors or forward sales, at levels which protect the cash flow of the group and the business plan. Price floors have been funded by selling caps at ceiling prices. As at 30 June, the group had 0.9 million barrels of Dated Brent oil hedged with collars at an average floor price of US$40.0/bbl and an average cap of US$100.0/bbl covering the period to the end of 2012. 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 102,000 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. In addition to volumes sold under collar arrangements, 1.1 million barrels of Dated Brent and 66,000 mt of HSFO have been sold under forward sales contracts for the second half of 2012. These forward sales are at average prices of US$105.3/bbl and US$622.0/mt respectively. Volumes of 1.5 million barrels of oil and 24,000 mt of HSFO have been sold for the first half of 2013 at average prices of US$110.2/bbl and US$683.8/mt respectively. In total, hedges covering 31 per cent of expected oil production and 40 per cent of Indonesian gas production for the twelve months following 30 June 2012 have been executed.

Premier operates and reports in US dollars. Foreign exchange exposure therefore relates only to certain sterling and other local currency expenditures. These exposures are covered by the purchase of local currency on a spot or short-term forward basis. The average sterling/dollar rate achieved for transactions maturing in the first half of 2012 was US$1.59 : £1. Forward foreign exchange contracts outstanding at30 June had a mark to market valuation loss in the period of US$0.7 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, 98 per cent of the group's total debt of US$1,121.1 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$0.5 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 2011.

Going concern

The group monitors its capital position and its liquidity risk regularly throughout the year to ensure that it has sufficient funds to meet forecast cash requirements. Sensitivities are run to reflect latest expectations of expenditures, forecast oil and gas prices and other negative economic scenarios in order 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 volatility, 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's business may be impacted by various risks leading to failure to achieve strategic targets for growth, loss of financial standing, cash flow and earnings, and reputation. Not all of these risks are wholly within the company's control and the company may be affected by risks which are not yet manifest or reasonably foreseeable.

Effective risk management is critical to achieving our strategic objectives and protecting our assets, personnel and reputation and therefore Premier has a comprehensive approach to risk management.

A critical part of the risk management process is to assess the impact and likelihood of risks occurring so that appropriate mitigation plans can be developed and implemented. Risk severity matrices are developed across Premier's business to facilitate assessment of risk. The specific risks identified by departments, project teams, corporate functions and business units are consolidated and amalgamated to provide an oversight of key risk factors at each level from operations through business unit management to Executive Committee and Board level.

For all the known risks facing the business, Premier attempts to minimise the likelihood and mitigate the impact. According to the nature of the risk, Premier may elect to tolerate risk, treat risk with controls and mitigating actions, transfer risk to third parties or terminate risk by ceasing particular activities or operations. Premier has a zero tolerance to financial fraud or ethics non-compliance, and ensures that HSES risks are managed to levels that are as low as reasonably practicable, whilst managing exploration and development risks on a portfolio basis.

The group has identified its principal risks for the next 12 months as being:

·; health, safety, environment and security (HSES);

·; production and development delivery;

·; exploration success and reserves addition;

·; host government - political and fiscal risks;

·; commodity price volatility;

·; organisational capability;

·; joint venture partner alignment; and

·; financial discipline and governance.

Further information detailing the way in which these risks are mitigated is provided on pages 55 to 57 of the 2011 Annual Report and Financial Statements.

STATEMENT OF DIRECTORS' RESPONSIBILITIES

The directors confirm that to the best of their knowledge:

a) the condensed set of financial statements has been prepared in accordance with IAS 34 - 'Interim Financial Reporting';

b) the Interim Management Report includes a fair review of the information required by DTR 4.2.7R (indication of important events during the first six months and description of principal risks and uncertainties for the remaining six months of the year); and

c) the interim management report includes a fair review of the information required by DTR 4.2.8R(disclosure of related parties' transactions and changes therein).

The directors of Premier Oil plc are listed in the group's 2011 Annual Report and Financial Statements. A list of the current directors is maintained on the company's website: www.premier-oil.com.

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 within the group's control but where, for example, the group decides on a change of plan or strategy. Accordingly, no reliance may be placed on the figures contained in such forward-looking statements.

CONDENSED CONSOLIDATED INCOME STATEMENT

CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

All comprehensive income is attributable to the equity holders of the parent.

CONDENSED CONSOLIDATED BALANCE SHEET

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

CONDENSED CONSOLIDATED CASH FLOW STATEMENT

NOTES TO THE CONDENSED FINANCIAL STATEMENTS

1. BASIS OF PREPARATION

General information

Premier Oil plc is a limited liability company incorporated in Scotland and listed on the London Stock Exchange. The address of the registered office is 4th Floor, Saltire Court, 20 Castle Terrace, Edinburgh, EH1 2EN, United Kingdom.

The condensed financial statements for the six months ended 30 June 2012 were authorised for issue in accordance with a resolution of the Board of Directors on 22 August 2012.

The information for the year ended 31 December 2011 contained within the condensed financial statements does not constitute statutory accounts within the meaning of section 434 of the Companies Act 2006. Statutory accounts for the year ended 31 December 2011 were approved by the Board of Directors on 21 March 2012 and delivered to the Registrar of Companies. The auditor reported on those accounts; the report was unqualified, did not draw attention to any matters by way of emphasis and did not contain any statement under section 498(2) or 498(3) of the Companies Act 2006.

The financial information contained in this report is unaudited. The condensed consolidated income statement, condensed consolidated statement of comprehensive income, condensed consolidated statement of changes in equity and the condensed consolidated cash flow statement for the six months to 30 June 2012, and the condensed consolidated balance sheet as at 30 June 2012 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 2012 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 2011, 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 2011, as described in those annual financial statements. A number of amendments to existing standards and interpretations were applicable from 1 January 2012. The adoption of these amendments did not have a material impact on the group's condensed financial statements for the half-year ended 30 June 2012.

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.

3. COST OF SALES

4. INTEREST REVENUE AND FINANCE COSTS

5. TAX

6. DEFERRED TAX

The group's deferred tax assets at 30 June 2012 are recognised to the extent that taxable profits are expected to arise in the future against which the ring fence tax losses and allowances can be utilised. In accordance with paragraph 37 of IAS 12 - 'Income Taxes' the group re-assessed its deferred tax assets at 30 June 2012 with respect to ring fence tax losses and allowances. The corporate model used to assess whether it is appropriate to recognise all of the group's deferred tax assets was re-run, using a long-term oil price assumption of US$85/bbl in 'real' terms. The results of the corporate model concluded that it was appropriate to continue to recognise all of the group's UK ring fence deferred tax assets in respect of tax losses and allowances in full.

In addition to the above, there are non-ring fence UK tax losses of approximately US$218.3 million (2011: US$181.2 million) and current year non-UK tax losses of approximately US$22.3 million (2011: US$69.4 million) for which a deferred tax asset has not been recognised.

None of the UK tax losses (ring fence and non-ring fence) have a fixed expiry date for tax purposes.

A deferred petroleum revenue tax (PRT) asset has been recognised to the extent that it is probable that the asset will reverse when the PRT field is fully decommissioned.

No deferred tax has been provided on unremitted earnings of overseas subsidiaries, following a change in UK tax legislation in 2009 which exempted foreign dividends from the scope of UK corporation tax, where certain conditions are satisfied.

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. Basic and diluted earnings per share are calculated as follows:

* At 30 June and 31 December 2011, a total of 37,349,360 potential Ordinary Shares in the company that are underlying the company's convertible bonds were anti-dilutive and were therefore excluded from the weighted average number of Ordinary Shares for the purposes of calculating diluted earnings per share in 2011. There were no significant anti-dilutive potential Ordinary Shares in 2012.

8. INTANGIBLE EXPLORATION AND EVALUATION (E&E) ASSETS

* Acquisitions in the current period relate to E&E licence interests acquired in the UK in the EnCore transaction (see note 10) and to the purchase of additional equity interests in the PL406 and PL407 licences in Norway.

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.

9. PROPERTY, PLANT AND EQUIPMENT

* Acquisitions in the current period relate to the purchase of assets in the EnCore transaction (see note 10) and for the Solan field.

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

Amortisation and depreciation of oil and gas properties is calculated on a unit-of-production basis, using the ratio of oil and gas production in the period to the estimated quantities of proved and probable reserves on an entitlement basis at the end of the period plus production in the period, on a field-by-field basis. Proved and probable 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.

The 2012 impairment charge relates to assets on the Block A Aceh Production Sharing Contract in Indonesia. The impairment charge was calculated by comparing the future discounted cash flows expected to be derived from production of commercial reserves (the value-in-use) 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 H2 2012, 2013 and 2014, and US$85/bbl in 'real' terms thereafter and were discounted using a discount rate of 12.5 per cent. Assumptions involved in impairment measurement include estimates of commercial reserves and production volumes, future oil and gas prices and the level and timing of expenditures, all of which are inherently uncertain.

10. ACQUISITION OF SUBSIDIARIES

On 16 January 2012, the company completed the acquisition of the entire issued share capital of EnCore Oil plc (EnCore).

EnCore was an AIM listed oil and gas exploration and production company focused on the offshore UK Continental Shelf where its portfolio of assets included interests in the Catcher and Cladhan discoveries, exploration acreage and a 30 per cent holding in Egdon Resources plc, an AIM listed exploration and production company focused on onshore assets with interests in the UK and Europe.

Under the terms of the agreement announced on 5 October 2011, shareholders in EnCore were offered a consideration of 70 pence in cash for each EnCore share held. Alternatively, EnCore shareholders could elect to receive 0.2067 new shares in the company for each EnCore share held instead of part or all of the cash consideration.

On completion, shareholders representing 93.5 per cent of EnCore's shares elected to take new Premier shares, resulting in the company paying a total of £14.1 million (US$21.6 million) in cash to EnCore shareholders and issuing 60,931,514 new Ordinary Shares to those who chose the share alternative. The new shares began trading on 17 January 2012.

As a result of the acquisition, the group increased its stake in the Catcher project from 35 to 50 per cent and became operator of the development.

Prior to completion of the EnCore transaction, the company reached an agreement with TAQA Bratani Ltd (TAQA) to on-sell the 16.6 per cent interest in the Cladhan area which it indirectly acquired from the EnCore acquisition for a consideration of US$54.0 million. TAQA also agreed to farm in to a 50 per cent interest in EnCore's wholly-owned Block 28/10a on a promoted basis whereby it would pay 80 per cent of certain well costs and 50 per cent of back costs on the Coaster prospect. The on-sale of these assets was completed in March 2012.

The transaction has been accounted for by the purchase method of accounting with an effective date of 16 January 2012, being the date on which the group gained control of EnCore. Information in respect of assets acquired is still being assessed and the fair value allocation to the EnCore assets is therefore provisional in nature and will be reviewed in accordance with the provisions of IFRS 3 - 'Business Combinations'.

Goodwill arises principally due to the requirement to recognise deferred tax on the difference between the assigned fair values and the tax bases of assets acquired and liabilities assumed in a business combination. None of the goodwill recognised is expected to be deductible for tax purposes.

During the period, acquisition-related expenses of US$2.8 million were incurred by the group and have been included within general and administration costs.

11. NOTES TO THE CONDENSED CONSOLIDATED CASH FLOW STATEMENT

Analysis of changes in net debt:

12. DIVIDENDS

No interim dividend is proposed (2011: US$nil).

13. EVENTS AFTER THE BALANCE SHEET DATE

In July 2012, the group announced that it had agreed to farm-in to 60 per cent of Rockhopper Exploration plc's (Rockhopper) licence interests in the Falkland Islands, which include the Sea Lion development project. The initial payment will be US$231.0 million in cash. In addition, Premier will pay an exploration carry of up to US$48.0 million and, subject to field development plan approval, a development carry of up to US$722.0 million. These will be funded from a combination of Premier's existing cash resources and facilities and future cash flow from operations. Premier and Rockhopper have also agreed to jointly pursue exploration opportunities in the Falkland Islands and analogous plays in selected areas offshore Southern Africa. The acquisition transaction is subject to the approval of the Falkland Islands Government and is expected to complete in September 2012.

INDEPENDENT REVIEW REPORT TO PREMIER OIL PLC

We have been engaged by the company to review the condensed set of financial statements in the half-yearly financial report for the six months ended 30 June 2012 which comprises the condensed consolidated income statement, the condensed consolidated statement of comprehensive income, the condensed consolidated balance sheet, the condensed consolidated statement of changes in equity, the condensed consolidated cash flow statement and related notes 1 to 13. We have read the other information contained in the half-yearly financial report and considered whether it contains any apparent misstatements or material inconsistencies with the information in the condensed set of financial statements.

This report is made solely to the company in accordance with International Standards 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 group are prepared in accordance with IFRSs as adopted by the European Union. The condensed set of financial statements included in this half-yearly financial report has been prepared in accordance with International Accounting Standard 34 -'Interim Financial Reporting', as adopted by the European Union.

Our responsibility

Our responsibility is to express to the company a conclusion on the condensed set of financial statements in the half-yearly financial report based on our review.

Scope of review

We conducted our review in accordance with International Standards on Review Engagements (UK and Ireland) 2410 'Review of Interim Financial Information Performed by the Independent Auditor of the Entity' issued by the Auditing Practices Board for use in the United Kingdom. A review of interim financial information consists of making inquiries, primarily of persons responsible for financial and accounting matters, and applying analytical and other review procedures. A review is substantially less in scope than an audit conducted in accordance with International Standards on Auditing (UK and Ireland) and consequently does not enable us to obtain assurance that we would become aware of all significant matters that might be identified in an audit. Accordingly, we do not express an audit opinion.

Conclusion

Based on our review, nothing has come to our attention that causes us to believe that the condensed set of financial statements in the half-yearly financial report for the six months ended 30 June 2012 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, UK

22 August 2012

WORKING INTEREST PRODUCTION BY REGION (UNAUDITED)

* Includes Balmoral, Brenda, Nicol and Stirling fields.