Half-Yearly Results for the six months to 30 June Half-Yearly Results for the six months to 30 June 2014

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1

Press Release

Half-Yearly Results for the six months to 30 June 2014

Highlights

● Production averaged 64.9 kboepd (2013: 58.6 kboepd), up 11 per cent and ahead of guidance; new production from Dua (Vietnam), Kyle (UK) and the gas swap (Indonesia)

● Materially rising operating cash flows, up 35 per cent at US$499.4 million (2013: US$371.0 million); profit after tax of US$172.7 million (2013: US$161.1 million)

● Significant momentum across development portfolio: installation of the Solan facilities under way; government sanction of the Catcher project received; and FEED on Bream and Sea Lion progressing well

● Exploration success in Indonesia and Pakistan, including the 100 mmboe (gross) oil and gas discovery at Kuda Laut/Singa Laut on the Tuna Block

● US$190 million of non-core asset sales announced and on track to deliver stated US$300 million disposal programme

● Renewal of principal bank facility completed on improved terms and increased in size to US$2.5 billion

● Continued distributions to shareholders – paid full-year dividend of 5 pence per share and ongoing buyback programme – reflecting confidence in future cash flow profile

● Appointment of Tony Durrant as Chief Executive and Richard Rose as Finance Director Outlook

 Full-year guidance maintained at 58-63 kboepd including disposal adjustments and pending

completion of summer maintenance programmes

 Timing of first oil from Solan is dependent on the successful completion of offshore installation

activities within the weather window and progress of the offshore commissioning programme

 Play-opening wells planned in the next 12 months include Badada, onshore Kenya, Myrhauk,

offshore Norway and Isobel Deep in the Falkland Islands

 Rising cash flows and strong funding position fully finance forward development spend, exploration

expenditure, dividend plans and buyback programme

Tony Durrant, Chief Executive, commented:

“It has been a strong six monthsfor Premier with the company performing well on all fronts. We continue

to exceed our production expectations, have achieved significant milestones on our key developments, had notable exploration success in Indonesia and advanced our non-core asset disposal programme. Increased production has driven significantly rising cash flows and our robust financial position has supported renewal of our principal bank facility on improved terms. Our focus continues to be on maintaining momentum and delivery of our near-term priorities, including first oil from Solan and Sea Lion

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ENQUIRIES

Premier Oil plc Tel: + 44 (0)20 7730 1111

Tony Durrant

Pelham Bell Pottinger Tel: + 44 (0)20 7861 3232

Gavin Davis Henry Lerwill

There will be a presentation to analysts at the company’s Falkland Islands Business Unit Office on Buckingham Palace Road at 10:30am today which will be webcast live on the company’s website at www.premier-oil.com.

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: premier@premier-oil.com or telephone: +44 (0)20 7730 1111).

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3 CHAIRMAN’S STATEMENT

High oil prices prevailed in the first half with some volatility driven by geo-political factors. There are also indications that the trend of rising service costs is slowing or even, in some instances, falling. Against this backdrop, I am delighted that we are reporting excellent financial results. We have generated strong after-tax profits and cash flows by virtue of an improving performance from our producing assets. New production from Asia and the UK in the second half, together with successful monetisation of our non-core non-operated assets, will further strengthen the group’s financial position. Beyond this, our pipeline of high-quality projects has progressed substantially in the first half providing confidence in sustained rising cash flows and growing returns for shareholders.

Average production during the first half was 64.9 thousand barrels of oil equivalent per day (kboepd) (2013: 58.6 kboepd) exceeding the expectations we set ourselves at the beginning of the year. We are particularly proud of the improved performance from our operated assets in the UK and Vietnam where a considerable amount of effort has been invested in improving asset integrity and operating efficiency. We also achieved new production post period end with the reinstatement of the Kyle field in the UK, first gas delivered under the Domestic Swap Arrangement (DSA) in Indonesia and first oil achieved from the Premier-operated Dua field in Vietnam.

We are committed to allocating our capital and resources to our highest quality operated projects where we are best placed to create value. The immediate focus of our development activity is on the Premier-operated Solan project, which is in the final stages of execution, and on progressing our Premier-operated Catcher, Bream and Sea Lion projects. We are delighted to have received government approval for the Catcher area development which is now moving into the execution phase and to have reached key milestones on the Bream and Sea Lion projects as we take them forward. As previously announced, we plan to engage with potential partners for the Sea Lion project prior to final sanction.

We continue to bring new developments into the portfolio through exploration success while maintaining firm capital discipline. In this respect, the first half saw success in Indonesia with material discoveries on the Tuna Block. We look forward to high impact drilling in Kenya and Norway and to the four well 2015 exploration campaign in the Falkland Islands which has the potential to transform the resource base of the company.

Our divestment programme is enabling us to reallocate our financial and human resources to our key projects, realising value from the non-core areas of the portfolio. Year to date, the group has announced the sale of undeveloped resources in Norway and Indonesia and the divesture of mature non-operated

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producing assets in the UK. These assets faced rising operating costs and significant associated decommissioning liabilities. We have also further enhanced the group’s financial liquidity position with the successful refinancing of our principal debt facility on improved terms. Our rising cash flows and balance sheet strength give us flexibility for shareholder distributions via a dividend payment and share buybacks. We will continue with our buyback programme until the share price better reflects the underlying value of the business.

Health, safety and environmental matters continue to be of paramount importance to us. Our production operations management systems at Balmoral in the UK, and at Anoa and Gajah Baru in Indonesia, retained their OHSAS 18001 and ISO 14001 certifications, as did our worldwide drilling management systems. We reiterate our commitment to protecting our people, our assets, our revenues and our reputation through maintaining the highest possible standards. Our annual reporting on Corporate Responsibility performance is aligned with IPIECA Guidance and the Global Reporting Initiative’s Sustainability Reporting. We are also a long-standing member of the FTSE4Good Index and, earlier this year, we joined the Corporate Pillar of the Voluntary Principles on Human Rights and Security.

A major focus for the Board in the first half has been the appointment of a successor to Simon Lockett. After a rigorous and thorough process, I am delighted that the decision was taken to promote Tony Durrant to Chief Executive, after joining Premier in 2005 as Finance Director. I am also extremely pleased that Richard Rose will join Premier’s Board as Finance Director on 8 September. I have every confidence that the Board has the breadth of skills and depth of experience to take Premier forward and create additional value for shareholders.

Outlook

The first half of the year has seen us exceed our production targets, progress our developments, strengthen our financial position and continue our cash returns to shareholders. In the second half, we will seek to maintain our strong production performance, to bring Solan on-stream and to progress the Sea Lion project. Delivery of these priorities will further strengthen Premier’s operational and financial position so that the group will be well placed to take advantage of future investment opportunities. Long-term, Premier remains committed to growing shareholder value through investment in high quality oil and gas projects within our core areas where we can realise superior returns.

Mike Welton Chairman

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5 OPERATIONAL REVIEW

Falkland Islands

Key milestones have been achieved towards the development of the Sea Lion oil field. The functional specification and basis of design for the tension leg platform (TLP) was finalised and the front end engineering design (FEED) contract was awarded in July and is now progressing. Preparations for four well exploration campaign in 2015 are under way and a rig contract was signed in June.

Development

Sea Lion pre-development activities have made good progress following the selection of a phased development scheme involving a TLP at the end of 2013. Based on the latest subsurface studies completed in the first half, recoverable reserves for the Phase 1 of the Sea Lion development are estimated at 308 million barrels (mmbbls). There is an upside of an additional 60 mmbbls if the Chatham well shows that a gas cap is not present in the western side of the field. Phase 2 of development is currently estimated to recover 87 mmbbls of reserves and will be optimised to incorporate any additional exploration success from the Zebedee and Jayne East wells, scheduled to be drilled in 2015.

The functional specification and basis of design for the TLP was finalised during the first half and invitations to tender were issued for FEED. Following evaluation of the proposals from the engineering companies, the TLP FEED contract was awarded in July to Amec who will be responsible for the overall management of the FEED and topsides design. Amec have sub-contracted the work for the hull to Houston Offshore Engineering and the rig design to RDS. The FEED contract for the subsea umbilicals, risers and flowlines (SURF) was awarded in August while the FEED contract for the floating storage and offloading unit (FSO) will be tendered for award in the fourth quarter. A geophysical survey over the planned TLP/FSO location was completed in the first half and a geotechnical survey will be performed later this year for which a vessel has already been mobilised. Both survey results will be incorporated into the FEED process, which is expected to take approximately 12 months to complete.

Market engagement for the engineering, procurement and construction (EPC) of the TLP has commenced with the project team in discussion with global engineering companies and directly with fabrication yards in the Middle East, Asia and the United States. Feedback to date has been positive. In conjunction with this, Premier has been assessing the possibility of securing export credit financing, a competitive source of funds for the project, and initial indications are encouraging.

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Given Premier’s current 60 per cent level of equity the group is seeking a suitable partner for the development project.

Exploration

Preparations for the 2015 Falkland Islands exploration and appraisal campaign are well under way. A drilling rig for the campaign has been secured with a rig contract and rig sharing agreement signed in June. All major service contracts have been tendered with bids evaluated and contracts in the process of being awarded. A temporary dock facility, which will support the multi-operator exploration campaign, is currently being installed at Stanley.

The exploration drilling programme is expected to commence in the second quarter of 2015 and will consist of at least four wells targeting multiple stacked fans in licences PL004 and PL032. Options are available for further wells in the event of success. The first two wells in the programme will target the highest impact prospects, Zebedee and Isobel Deep. Zebedee is a low risk step out from the Sea Lion field, while Isobel Deep is designed to de-risk a new fan complex of Sea Lion scale in the south of PL004. The rig is then scheduled to drill two wells for another operator before returning to the North Falkland Basin. The third well will test the Jayne East prospect to the south east of the Sea Lion field, while the fourth well will test the presence of a gas cap on the western flank of Sea Lion and the deeper potential in the Chatham exploration prospect.

In February, the farm-in was completed by Premier and Rockhopper in PL004a and PL004c, which contains the Isobel Deep and Jayne East prospects among others, resulting in Premier’s equity in both licences increasing to 36 per cent.

INDONESIA

The first half saw a strong performance from Natuna Sea Block A with record daily production rates realised. The Anoa field continued to exceed its contractual share of the first Gas Sales Agreement (GSA1), while additional gas sales from the Gajah Baru field to the domestic market commenced in June. Premier also achieved notable exploration success in Indonesia with the Tuna Block wells discovering 100 million (gross) barrels of oil equivalent (mmboe).

Production and Development

Gas sales from Indonesia exceeded expectations during the first half of 2014. This was driven by strong sales from the Anoa field which averaged 144 billion British thermal units per day (BBtud) (2013: 144 BBtud) and accounted for 48 per cent of deliveries under GSA1 (against a contractual share of 39.4 per

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7 cent). Sales of Gajah Baru gas dedicated to GSA2 averaged 84 BBtud (2013: 81 BBtud). In April, the Anoa and Gajah Baru fields on the Premier-operated Natuna Sea Block A achieved a peak production rate of 391 BBtud, a new record for the assets.

Gas sales from the non-operated Kakap field averaged 29 BBtud (gross) (2013: 34 BBtud) during the first half. Gross liquids production from the Kakap field averaged 3.8 thousand barrels of oil per day (kbopd) (2013: 3.7 kbopd) and 1.6 kbopd from Anoa (2013: 2.0 kbopd). Overall, net production from Indonesia in the first six months was 14.0 kboepd (2013: 14.1 kboepd), on a working interest basis.

Post period end, additional gas sales of up to 40 BBtud from the Gajah Baru field to the domestic market commenced under the DSA. Gas delivered under the DSA replaces gas previously contracted to Batam Island, Indonesia, from the Natuna Sea Block A under GSA3 and GSA4. DSA deliveries will be made until the domestic pipelines are constructed and the GSA3 and GSA4 contracts commence.

Good progress was made during the first half on our further Natuna Sea developments. The Pelikan and Naga gas field platforms were installed and tied into the Gajah Baru platform. Development drilling of the Naga wells is under way. Pelikan and Naga will be brought on-stream to backfill our existing contracts and, when the opportunity arises, to further increase our market share of GSA1. First gas from these new facilities is expected in the second half of 2014. Elsewhere on Natuna Sea Block A, plans are in place to tie-in the 2012 Lama WL-5X gas discovery well to the Anoa production facilities next year, resulting in additional volumes being delivered into Singapore under GSA1.

In June, Premier sold its 41.67 per cent non-operated interest in Block A Aceh onshore Indonesia for an after-tax consideration of US$40 million, as the group continues to focus its capital and people on the higher return projects in its portfolio. Completion of the sale, which is subject to government approvals, is expected later this year.

Exploration and Appraisal

Premier drilled three exploration wells in Indonesia during the first half: the Kuda Laut-1 well and Singa Laut-1 well on the Premier-operated Tuna Block and the Ratu Gajah-1 well on the Premier-operated Natuna Sea Block A.

The Kuda Laut-1 well discovered 183 feet of net oil-bearing reservoir and 327 feet of net gas-bearing reservoir. The well was then side-tracked to test the Singa Laut prospect in the adjoining three-way dip closed structure and penetrated 177 feet of net gas-bearing reservoir quality sands. The two discoveries,

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which are estimated to contain around 100 mmboe (gross), have a high natural liquid content. Assessment of the commercial viability of the discoveries is now under way.

While the Ratu Gajah-1 well flowed gas to surface during testing, less sandstone reservoir than expected was encountered and the discovery itself is sub-commercial. However, the results of this well have been integrated into the group’s broader understanding of the Lama play and, consequently, thicker sands have been identified at the basin margin. We continue to mature and high grade further Lama play prospects in our portfolio with preparations well advanced for the appraisal of the Anoa Deep discovery, scheduled for the first half of 2015.

NORWAY

Good progress was made on the Bream project during the first six months of the year. A formal concept decision on the development scheme was taken and FEED contracts have been awarded. An investment decision continues to be planned for year-end. Following the profitable sale of the Luno II discovery, the exploration team are preparing for the Myrhauk well, which is expected to be drilled in 2015 and will be Premier’s first test of the Mandal High play.

Development

Following extensive engineering, design work and reservoir modelling, the Bream project passed through a formal concept decision in the first half. It is envisaged that the development will focus on recovering 40 mmbbls of resource from the Bream field itself using four production and two water injection wells tied back to a Floating Production, Storage and Offloading vessel (FPSO). The Mackerel discovery in the adjacent PL406 licence is being assessed as part of a second phase of development which would also include any near field exploration success. The chosen development scheme is expected to offer some cost savings against earlier estimates, although these will be worked up and further defined as part of the FEED process.

All FEED contracts were awarded during the first half with the hull and marine FEED being awarded to Sevan, the topsides FEED to Aibel and the subsea FEED to Xodus Group. FEED work is progressing well and is scheduled for completion in the fourth quarter. Premier is targeting a formal investment decision on the project at year-end once the FEED process has been sufficiently advanced.

Work continues on the non-operated Frøy field to identify a viable development concept. Further subsurface and facilities studies were completed in the first half and discussions with other operators in the area are ongoing.

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9 Exploration

Premier has built an extensive acreage position across the Mandal High in the Norwegian North Sea capturing over 1,600 square kilometres of acreage through successful APA licensing rounds and acquisition. Preparations are now well advanced for the Myrhauk well on PL539 which is expected to spud in the first half of 2015 and will be Premier’s first test of the emerging Mandal High play. The primary target of the well is Jurassic age sands within a combined structural-stratigraphic trap located on the eastern margin of the Mandal High. Evaluation and maturation of other potential candidates for follow up drilling is well advanced.

Premier continues to high grade its Norwegian exploration portfolio and to monetise non-core assets. Post period end, Premier announced the profitable sale of its 30 per cent non-operated interest in PL359, which contains the Luno II discovery, for a total after-tax consideration of US$17.5 million.

Pakistan

Premier’s Pakistan fields continue to perform well with the natural decline from existing wells partially offset by new production from additional development wells, intervention work at Zamzama and the tie-in of the successful K-36 exploration well at the Kadanwari field.

Average production in Pakistan during the first half of 2014 was 13.3 kboepd (2013: 15.3 kboepd). Production from the Qadirpur gas field averaged 3.3 kboepd (2013: 3.6 kboepd). The lower production was primarily driven by the natural decline in the field and reduced gas demand following maintenance works at a power plant in the first quarter.

Production from the Kadanwari gas field during the period was 3.5 kboepd, 30 per cent higher than the corresponding period last year (2013: 2.7 kboepd). This increase was due to new production from the K-33 and K-35 development wells which were brought on-stream in December 2013 and February 2014, respectively, and the successful K-36 exploration well which was tied-in to production in April. It is anticipated that the K-37 development well, which flowed gas to surface, will be tied-in by the end of September.

Average production from the Zamzama gas field during the period was 3.4 kboepd (2013: 5.7 kboepd) as natural decline from existing wells was partially mitigated by intervention work carried out at the Zam-4

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production well in May. The joint venture is considering drilling two infill wells, with the first well likely to spud at the end of this year.

Production from the Bhit and Badhra gas fields averaged 3.1 kboepd in the first half of 2014 (2013: 3.3 kboepd). The two new Badhra development wells were brought on-stream in the first quarter of 2014 and two further wells are currently drilling. The compressor reconfiguration project at Bhit, to improve ultimate recovery from the field, commenced in the first half. The project, which will entail the installation of 10 new compressors and the relocation of one existing compressor, is targeted for completion next year.

The Zarghun South gas field is scheduled to come on-stream later this year with an expected initial run rate of 20 million standard cubic feet per day (mmscfd). All costs continue to be carried by the operator.

Four exploration wells – K-36 and K-34 on Kadanwari and Badhra-8 and Badhra South-1 Deep on Badhra – were drilled in the first half of the year. The K-36 exploration well discovered gas and was tied-in to the Kadanwari facilities during April. The K-34 well, which was drilled in the second quarter, was water wet as was the Badhra-8 well which was drilled on the western flank of the Badhra structure. The Badhra South-1 Deep well was also plugged and abandoned after failing to flow gas from the targeted reservoir section. The Bhit South-1 exploration well, which will test the potential of the Mughalkot sands, is expected to spud in October.

Mauritania

Production from the Chinguetti field averaged 500 barrels of oil per day (bopd) net to Premier in the first half (2013: 600 bopd). The fall in production was driven by natural decline from the existing wells as well as a shutdown of the facilities in January for a mooring chain replacement. On the Banda gas development, gas sales negotiations and arrangement of payment guarantees are at an advanced stage. Project approval is targeted for the first half of next year.

The Tapendar-1 exploration well was drilled on PSC C-10 in the first half of 2014 and was plugged and abandoned as a dry hole.

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11 UNITED KINGDOM

Higher production, driven by improved uptime from the Balmoral area field and increased contributions from Huntington and Rochelle, resulted in a strong rise in UK cash flows during the first half. Development activity at Solan continued apace with offshore installation of the facilities now under way. The Catcher project received government approval in the first half. These two projects will underpin the company’s future growing cash flows.

Production

UK production averaged 21.3 kboepd for the first half of the year, an increase of 59 per cent on the corresponding period (2013: 13.4 kboepd).

Strong production was achieved from the Premier-operated Balmoral area which averaged 3.7 kboepd, an increase of 40 per cent (2013: 2.7 kboepd). This was as a result of the reinstatement of four wells and improved performance from existing wells. In addition, operating efficiency improved, averaging 90 per cent in the first six months of 2014, up from 64 per cent for the same period last year. Wytch Farm also exceeded expectations due to improved operating efficiency and four new wells on-stream during the period.

Huntington produced 7.8 kboepd net to Premier during the first half (2013: 1.2 kboepd). Strong well performance was offset by unplanned production interruptions primarily caused by a combination of adverse weather, operational issues and downtime at the CATS riser platform. On 31 July, the field closed for planned maintenance to the Voyageur FPSO. Production is expected to recommence shortly. To date, the impact on Huntington production due to ongoing CATS pipeline restrictions and maintenance has been smaller than anticipated.

Production from Scott, Telford and Rochelle averaged 3.8 kboepd net to Premier over the period (2013: 4.2 kboepd). Performance from these fields was impacted by an unplanned outage on the Scott platform following a compressor valve bolt failure in late March. Rochelle production was also interrupted in late January due to the main valve on the production manifold failing to open following the tie back of the E2 well. This was rectified utilising a diving support vessel with production restarting in March. Following these unplanned outages the fields performed above expectations prior to the commencement of the annual shutdown in late July. On 30 June 2014 Premier agreed the profitable sale of its non-operating interests in the Scott, Telford and Rochelle fields for a consideration of US$130 million. As part of the transaction, all associated decommissioning liabilities will be transferred to the buyer. This disposal is expected to complete in the second half of 2014.

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First oil was achieved from Kyle in July, following the completion of the two year reinstatement project. Flush production has been achieved from the K-12 and K-14 wells, which have reached combined peak production rates of in excess 7 kboepd (gross). The remaining two producer wells are expected to be brought on-stream shortly.

Developments

Material progress was made on the Premier-operated Solan project, west of Shetlands, during the first half with the project now in the final stages of execution. The first producer well has been completed, following the recommencement of development drilling in April, and flowed at good rates. The first injector well is also on track to be completed before the weather window west of Shetlands closes.

Onshore construction of the subsea storage tank, jacket and topsides has been completed and the offshore installation and heavy lift campaign is under way. The subsea storage tank was lowered to the seabed in early August and piling activities are nearing completion while the installation of the jacket by the Heerema Thialf is expected to commence shortly. The topsides are ready for sea fastening onto the barge and load out to the field for installation, which will be timed to coincide with the completion of the installation of the jacket, subject to good weather. Hook up and commissioning will then be undertaken ahead of first oil.

Total cash costs incurred to date on the Solan project are estimated at US$1 billion compared to the previous estimated total project cost of US$1.4 billion. Higher project costs have been incurred to maximise the opportunity to meet the 2014 installation window and due to longer than expected drilling times. Solan continues to be a valuable project with a payback period of approximately two years for Premier. Under existing contractual agreements, Premier will take an enhanced share of the project’s cash flow to recover the loan from our partner in the field, Chrysaor Limited, and until Premier has received a pre-agreed return on its investment. Negotiations are on-going over the possible early refinancing of Premier’s loan and the funding of our partner’s share of future capex requirements for the Solan project.

In June, Premier received government approval of its Catcher area Field Development Plan and the execution phase is progressing to schedule. The Catcher area fields will produce via subsea tie backs to a leased FPSO. The contract for the FPSO was awarded to BW Offshore, who will order a new build hull from Japan for the project, while the topsides will be constructed in the Far East with the integration work to be performed in Singapore. The Engineering, Procurement, Construction and Installation (EPCI) contract for the subsea scope, which includes three pipeline bundles, a riser system and a 10", 60km gas export/import pipeline was awarded to Subsea 7. Ensco was awarded the contract for the development

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13 drilling, which will consist of 14 production wells and eight water injector wells and will commence in 2015. An experienced project team has been assembled to deliver first oil in the summer of 2017.

Exploration

Premier’s exploration focus in the UK North Sea is on maturing prospects within the Catcher area for future drilling and planning for a 2015 appraisal well of the heavy oil discovery at Bagpuss on licence P1453. The combined Bagpuss/Blofeld prospects are estimated to contain in excess of 2 billion barrels of oil in place. Outside of this, Premier continues to rationalise its UK North Sea exploration portfolio, with a further five licences either relinquished or sold in the first half.

VIETNAM

Strong performance was achieved from Chim Sáo in the first half as Premier continues to deliver a number of projects aimed at maximising operating efficiency. First oil from Dua was achieved in July, extending Premier’s continuing operated success story in Vietnam.

The first half saw a strong performance from the Premier-operated Chim Sáo field, with production averaging 15.8 kboepd net to Premier (2013: 15.2 kboepd) and, in August, Chim Sáo surpassed the milestone of 25 million barrels of oil production (gross). Initiatives to improve the reliability of the Chim Sáo facilities were successfully undertaken in the first half and included the installation of additional power generating capacity on the FPSO and additional accommodation and lifeboat facilities designed to increase the maximum persons on board. In addition, significant maintenance work and upgrades were carried out to the FPSO, including the installation of a new flare tip, during the planned maintenance shutdown in June, which was completed on schedule. Further works are planned for later this year to ensure the improved performance of the FPSO while early scoping activities are under way for the next phase of Chim Sáo infill drilling to increase future production and overall recovery.

The subsea tie-back of the Premier-operated Dua field was completed in June with final tie-ins to the Chim Sáo FPSO to receive Dua hydrocarbons completed safely on schedule during a planned Chim Sáo shutdown in April. First production from the Dua field was achieved in July following the completion of the first development well. The field is capable of producing 8-10 kbopd gross and will extend Block 12W’s plateau production and field life.

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During the first half, Premier participated in the acquisition of 1,217km of 2D seismic data across the deep water exploration plays in Block 121 in the Phu Khanh Basin. Data processing is under way with results expected in the fourth quarter.

New Ventures

Premier’s new country exploration team seeks out early stage exploration acreage in selective new areas. The team targets geologies in which the group has built an expertise and where an exploration success has the potential to transform the group’s resource base. In the first half, the focus has been on the evaluation and maturation of emerging plays that the company captured in Brazil and Kenya during 2013.

In Brazil, 3D seismic acquisition commenced in the Foz Do Amazonas Basin where Premier has a non-operated 35 per cent interest in Block FZA-M-90. The new data, which is expected to be available for interpretation later this year, will be acquired as part of a multi-client speculative seismic programme, resulting in a considerable cost saving to Premier. Seismic acquisition across Premier’s operated Blocks CE-M-717 and CE-M-665 in the Ceara Basin is expected to commence in the first half of 2015 and will also be acquired as part of a multi-client survey. Premier plans to drill three exploration wells in Brazil in 2017 and 2018.

In the South Anza Basin in Kenya, new seismic data was acquired across Block 2B, in which Premier has a non-operated interest of 55 per cent. Preparations are well advanced to drill the Badada-1 well, a Tertiary reservoir test of a similar trap configuration as successfully proven in the neighbouring Lokichar and Albertine Basins. The well, which is expected to spud in either late 2014 or early 2015, will target a robust closure estimated to contain gross un-risked prospective resource of 13-90-363 mmbbls. Elsewhere, Premier relinquished its 25 per cent non-operated interest in Block 10B offshore Kenya early in 2014.

In Iraq, work continues onshore Block 12, in which Premier was awarded a non-operated 30 per cent interest in November 2012. Block 12 is an 8,000 square kilometre block in the foreland of the Zagros fold belt, up-dip from producing fields. New 2D and 3D seismic data is being acquired and, subject to its interpretation, an exploration well will be drilled in either 2016 or 2017.

Activity on Premier’s Daora, Haouza, Mahbes, Mijek and Laguara Blocks offshore the Saharawi Arab Democratic Republic (SADR) remains suspended pending resolution of sovereignty under a United Nations mandated process. A permit covering Premier’s Haouza block has been licensed to another operator who plans to drill a well on this block later this year.

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15 FINANCIAL REVIEW

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Profit after tax for the period increased to US$172.7 million (2013 : US$161.1 million). This reflects the strong performance of our producing fields and tax credits associated with our UK operations offset by impairment charges in the UK and an accounting loss on the sale of Block A Aceh, Indonesia.

Group production on a working interest basis averaged 64.9 kboepd in the first half of 2014 compared to 58.6 kboepd in the first half of 2013 and 58.2 kboepd for the full-year 2013. This reflects stable underlying performance from existing producing assets in Indonesia, Vietnam and Pakistan, and an increase in excess of 50 per cent in production from the UK, mainly due to a full contribution from the Rochelle and Huntington fields. Entitlement production for the period was 59.8 kboepd (2013: 53.1 kboepd).

Oil and gas prices remained stable and above US$100 per barrel (bbl) during the first half with the Brent oil price fluctuating between US$103.2/bbl and US$115.8/bbl and averaging US$108.9/bbl (2013: US$107.7/bbl). Premier's average realised oil price for the period was US$109.4/bbl pre-hedge (2013: US$107.2/bbl), and US$107.9/bbl on a post-hedge basis (2013: US$108.0/bbl).

The average realised gas price for Indonesian production sold into Singapore was US$16.8 per thousand standard cubic feet (mscf) (2013: US$17.4/mscf). In Pakistan, gas prices across all producing fields averaged US$4.7/mscf (2012: US$4.3/mscf). The combined effect of significantly higher production and stable realised prices saw a 17 per cent increase in sales revenues to US$884.7 million (2013: US$757.8 million).

Cost of sales in the period was US$646.3 million (2013: US$472.2 million). Underlying operating costs were US$18.5 per barrel of oil equivalent production (boe) (2013: US$16.0/boe) mainly reflecting a larger share of production from higher cost UK fields compared to the corresponding period.

Amortisation of oil and gas properties rose from US$172.5 million to US$224.0 million and on a unit basis from US$16.2/boe to US$19.1/boe. Impairment charges for the period amounted to US$144.0 million (2013: US$77.7 million) on a pre-tax basis. This charge is related to the Balmoral area and Huntington fields in the UK, following a review of the longer-term assumptions used in forecasting operating, maintenance and decommissioning costs and production profiles.

Exploration expense and pre-licence exploration costs amounted to US$49.8 million (2013: US$21.6 million) and include costs relating to the exit from the Kenyan offshore block and exploration wells in Mauritania and Indonesia. There is a loss recorded on the disposal of assets of US$83.9 million which

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17 primarily relates to the anticipated disposal of Block A Aceh in Indonesia. Operating profit for the period was US$92.0 million (2013: US$255.1 million).

Finance costs and other finance expenses were US$68.4 million (2013: US$44.6 million) partially offset by interest revenue, finance and other gains of US$24.9 million (2013: US$5.3 million). Finance costs capitalised during the period totalled US$17.0 million (2013: US$14.0 million).

The group had a tax credit for the period of US$122.3 million (2013: charge of US$53.5 million). This benefit arises from an additional deferred tax credit of US$296.2 million (2013: US$65.6 million) relating to future UK capital allowances, including ring fence expenditure supplement and small field allowance for the Catcher area fields. The tax credit is reduced by overseas tax charges of US$87.4 million (2013: US$101.2 million) and UK Petroleum Revenue Tax of US$85.9 million (2013: US$31.2 million).

Profit after tax for the period to 30 June 2014 was US$172.7 million (2013: US$161.1 million). Basic earnings per share for the period were 32.8 cents (2013: 30.5 cents).

Cash flow

Cash flow from operating activities amounted to US$499.4 million (2013: US$371.0 million). Capital expenditure in the period was US$506.3 million (2013: US$435.7 million). In addition, Premier provided US$104.4 million (2013: US$51.4 million) of partner funding for the Solan project which will be recovered from additional oil production post first oil. Dividends amounting to US$44.0 million (2013: US$40.2 million) were also paid during the first half.

Capital expenditure and partner funding

2014 Half-year $ million 2013 Half-year $ million Fields/developments 365.5 282.9 Partner funding 104.4 51.4 Exploration 137.7 147.4 Other 3.1 5.4 Total 610.7 487.1

The majority of the development expenditure in the first half was for the Solan field in the UK and the Dua field in Vietnam. Exploration spend in the first half was mainly relating to an exploration campaign in Indonesia and pre-development work on the Sea Lion field in the Falkland Islands and Bream in Norway.

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During the first half, Premier announced the proposed sale of the non-operated Scott area assets in the UK North Sea for US$130 million, the sale of Block A Aceh onshore Indonesia for US$40 million, and the sale of PL359, which contains the Luno II discovery offshore Norway, for US$17.5 million. All these transactions are currently going through various forms of approval. All attributable assets and liabilities have been reclassified as current and appear as separate line items on the balance sheet. US$76.9 million has been recognised as the anticipated loss on the sale of Block A Aceh. It is expected that the other sales will result in accounting profits and therefore, in accordance with accounting rules, these will only be recognised upon completion of those transactions. Net profits from these transactions are expected to fully offset the loss being recognised on the Block A Aceh sale.

Balance sheet

Net debt at 30 June 2014 wasUS$1,689.1 million(2013: US$1,315.8 million)including cash resources of

US$255.0 million (2013: US$182.3 million).

2014 Half-year $ million 2013 Half-year $ million

Cash and cash equivalents 255.0 182.3

Convertible bonds (226.3) (222.2)

Other long-term debt (1,717.8) (1,275.9)

Net debt (1,689.1) (1,315.8)

Long-term borrowings consist of convertible bonds, UK retail bonds, senior loan notes and bank debt. The group's principal bank facility was refinanced in July 2014, and now matures in July 2019. Cash and undrawn facilities at 30 June, including committed letter of credit facilities, were approximately US$1.4 billion. On a pro-forma, post the refinancing, cash and undrawn facilities increased to US$2.7 billion.

Financial risk management

The Board’s commodity pricing and hedging policy continues to be to lock in oil and gas prices for a proportion of expected future production at a level which ensures that investment programmes for sanctioned projects are adequately funded. Where investment requirements are well covered by cash flows without hedging, it is recognised that there may be an advantage, in periods of strong commodity prices, in locking in a portion of forward production at favourable prices on a rolling forward 12-18 month basis.

At period end, 5.9 mmbbls of Dated Brent oil were hedged through forward sales for the rest of 2014 and full-year 2015. This volume, including expired hedges in the first half, represents approximately 50 per

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19 cent of the group’s expected liquids entitlement production in 2014 at an average of US$104.3/bbl and 29 per cent of total estimated liquids production from existing fields for 2015 at an average price of US$106.0/bbl. In addition, 234,000 metric tonnes (mt) of high sulphur fuel oil (HSFO), which drives the group’s gas contract pricing in Singapore, has been sold forward for the rest of 2014 and first half of 2015 at an average price of US$613/mt. These hedges cover approximately 36 per cent of our expected Indonesian gas entitlement production for the next 12 months.

During the first half of 2014, forward oil sales of 2.6 mmbbls matured at a net cost of US$8.3 million (2013: net credit US$4.0 million) which has been offset against sales revenue.

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 2014 was US$1.67 : £1.Forward foreign exchange contracts outstanding at 30

June amounted to £35 million at an average rate of US$1.68 : £1.

The group’s main debt facilities include both fixed and floating interest rate borrowings. At 30 June, 72 per cent of the group’s total debt of US$1.9 billion was denominated in fixed rate instruments, or locked into fixed rate costs using the interest rate swap market.

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 2013.

Going concern

The group monitors its capital position and its liquidity risk regularly throughout the year to ensure it has sufficient funds to meet forecast cash requirements. Sensitivities are run to reflect the latest expectations of expenditures, forecast oil and gas prices, and other negative economic scenarios. This is done to manage the risk of funding shortfalls or covenant breaches and to ensure that the group is able to continue as a going concern. The group refinanced its principal US$1.2 billion credit facility (due to expire in March 2015) in July with a new, increased facility of US$2.5 billion (expiring in July 2019). The new facility has been agreed on improved terms, reflecting strong market conditions in the bank market and the group's growing cash flow and resources over the past four years.

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

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adequate resources to continue as a going concern. As a result, they continue to adopt the going concern basis in preparing the half-yearly results for the six months to 30 June 2014.

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 personnel, assets, the communities where we operate, those with whom we interact and our reputation. Premier therefore 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 project and asset teams, business units and corporate functions are consolidated and amalgamated to provide an oversight of key risk factors at each level, from operations through business unit management to the Executive Committee and the Board.

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 take or 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 risk areas 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;

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21 ● 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 71 to 73 of the 2013 Annual Report and Financial Statements. This information is also available on company’s website

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STATEMENT OF DIRECTORS’ RESPONSIBILITIES

Each of the directors of the company confirms that to the best of their knowledge:

a) the condensed set of financial statements, which has been prepared in accordance with

International Accounting Standard 34 – ‘Interim Financial Reporting’ gives a true and fair view of the assets, liabilities, financial position and profit of the company;

b) the Half-Yearly Results statement 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 Half-Yearly Results statement includes a fair review of the information required by DTR 4.2.8R

(disclosure of related parties’ transactions and changes therein).

On behalf of the Board

Tony Durrant

Chief Executive

20 August 2014

Disclaimer

This results announcement 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.

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23 CONDENSED CONSOLIDATED INCOME STATEMENT

Six months to 30 June 2014 Unaudited Six months to 30 June 2013 Unaudited Year to 31 December 2013 Audited

Note $ million $ million $ million

Sales revenues 2 884.7 757.8 1,501.0

Other operating income - - 38.7

Cost of sales 3 (646.3) (472.2) (1,034.8)

Exploration expense (37.4) (7.7) (106.2)

Pre-licence exploration costs (12.4) (13.9) (30.1)

(Loss)/profit on disposal of assets (83.9) - 3.6

General and administration costs (12.7) (8.9) (20.2)

Operating profit 92.0 255.1 352.0

Share of gain in associate 1.9 - -

Interest revenue, finance and other gains 4 24.9 5.3 33.0

Finance costs and other finance expenses 4 (68.4) (44.6) (98.4)

Loss on derivative financial instruments - (1.2) (1.2)

Profit before tax 50.4 214.6 285.4

Tax 5 122.3 (53.5) (51.4)

Profit for the period/year 172.7 161.1 234.0

Earnings per share (cents):

Basic 7 32.8 30.5 44.2

Diluted 7 31.3 29.1 43.2

Notes 1 to 14 form an integral part of these condensed financial statements. CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

Profit for the period/year 172.7 161.1 234.0

Cash flow hedges on commodity swaps:

(Losses)/gains arising during the period/year (17.0) 15.4 (25.0) Reclassification adjustments for losses in the year 7.6 0.9 0.8

(9.4) 16.3 (24.2)

Tax relating to components of other comprehensive income 6 5.8 (8.1) 13.9 Cash flow hedges on interest rate and foreign exchange swaps 6.2 4.5 (0.8) Exchange differences on translation of foreign operations 3.4 (18.0) (17.5) Actuarial losses on long-term employee benefit plans* - - (6.5)

Other comprehensive income/(expense) 6.0 (5.3) (35.1)

Total comprehensive income for the period/year 178.7 155.8 198.9

* Not expected to be reclassified subsequently to profit and loss account

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CONDENSED CONSOLIDATED BALANCE SHEET At 30 June 2014 Unaudited At 30 June 2013 Unaudited At 31 December 2013 Audited

Non-current assets:

Goodwill 240.8 240.8 240.8

Intangible exploration and evaluation assets 8 753.5 681.0 701.0

Property, plant and equipment 9 2,679.5 2,685.2 2,885.9

Investments 8.4 5.5 6.2

Long-term employee benefit plan surplus 1.3 4.8 1.0

Other receivables 316.4 55.0 198.1

Deferred tax assets 6 1,057.2 623.0 762.4

5,057.1 4,295.3 4,795.4

Current assets:

Inventories 44.7 31.7 49.5

Trade and other receivables 473.8 448.2 421.8

Tax recoverable 89.0 78.2 82.4

Derivative financial instruments 12 16.3 23.8 15.9

Cash and cash equivalents 255.0 182.3 448.9

Assets held for sale 10 327.9 97.9 -

1,206.7 862.1 1,018.5

Total assets 6,263.8 5,157.4 5,813.9

Current liabilities:

Trade and other payables (607.3) (474.8) (512.4)

Current tax payable (122.6) (93.3) (92.0)

Provisions (15.7) (43.5) (13.1)

Derivative financial instruments 12 (47.6) (21.4) (38.3)

Liabilities directly associated with assets held for sale 10 (235.5) (26.1) - (1,028.7) (659.1) (655.8)

Net current assets 178.0 203.0 362.7

Non-current liabilities:

Convertible bonds (225.9) (221.7) (223.8)

Other long-term debt (1,707.1) (1,265.6) (1,665.4)

Deferred tax liabilities 6 (296.4) (302.9) (306.8)

Long-term provisions - decommissioning (753.7) (618.9) (824.6)

Long-term employee benefit plan deficit (14.5) (17.9) (13.1)

(2,997.6) (2,427.0) (3,033.7)

Total liabilities (4,026.3) (3,086.1) (3,689.5)

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25 CONDENSED CONSOLIDATED BALANCE SHEET (continued)

Note At 30 June 2014 Unaudited $ million At 30 June 2013 Unaudited $ million At 31 December 2013 Audited $ million Equity and reserves:

Share capital 109.2 110.5 110.5

Share premium account 275.4 275.2 275.3

Merger reserve 374.3 374.3 374.3

Retained earnings 1,453.8 1,287.6 1,342.1

Other reserves 24.8 23.7 22.2

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CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

____________Attributable to the equity holders of the parent___________ Other reserves Share capital Share premium account Retained earnings Merger reserve Capital redemption reserve Translation reserves Equity reserve Total $ million $ million $ million $ million $ million $ million $ million $ million At 1 January 2013 110.5 274.9 1,150.1 374.3 4.3 17.1 22.3 1,953.5

Issue of Ordinary Shares - 0.4 - - - 0.4

Purchase of ESOP Trust shares - - (12.8) - - - - (12.8)

Provision for share-based payments

- - 24.6 - - - - 24.6

Transfer between reserves* - - 4.0 - - - (4.0) -

Dividends paid - - (40.2) - - - - (40.2)

Total comprehensive income - - 216.4 - - (17.5) - 198.9

At 31 December 2013 110.5 275.3 1,342.1 374.3 4.3 (0.4) 18.3 2,124.4

Share buyback (1.3) - (33.3) - 1.3 - - (33.3)

- - 11.6 - - - - 11.6

Dividends paid - - (44.0) - - - - (44.0)

Total comprehensive income - - 175.3 - - 3.4 - 178.7

At 30 June 2014 109.2 275.4 1,453.8 374.3 5.6 3.0 16.2 2,237.5

At 1 January 2013 110.5 274.9 1,150.1 374.3 4.3 17.1 22.3 1,953.5

Purchase of ESOP Trust shares - - (12.1) - - - - (12.1)

- - 14.0 - - - - 14.0

Dividends paid - - (40.2) - - - (40.2)

Total comprehensive income - - 173.8 - - (18.0) 155.8

At 30 June 2013 110.5 275.2 1,287.6 374.3 4.3 (0.9) 20.3 2,071.3

* The transfer between reserves relates to the non-cash interest on the convertible bonds, less the amortisation of the issue costs that were

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27 CONDENSED CONSOLIDATED CASH FLOW STATEMENT

Net cash from operating activities 11 499.4 371.0 802.5

Investing activities:

Capital expenditure (506.3) (435.7) (878.0)

Proceeds from disposal of oil and gas properties - - 61.0

Loan to joint venture partner (104.4) (51.4) (185.9)

Net cash used in investing activities (610.7) (487.1) (1,002.9)

Financing activities:

Proceeds from issuance of Ordinary Shares - 0.3 0.4

Net purchases of ESOP Trust shares - (12.1) (12.8)

Share buyback (33.3) - -

Proceeds from drawdown of bank loans 100.0 200.0 384.1

Proceeds from issuance of senior loan notes - - 156.7

Proceeds from issuance of retail bonds - - 245.8

Debt arrangement fees (1.7) (0.9) (7.1)

Repayment of bank loans (70.0) - (200.0)

Dividends paid (44.0) (40.2) (40.2)

Interest paid (47.2) (35.7) (71.1)

Net cash (used in)/ from financing activities (96.2) 111.4 455.8

Currency translation differences relating to cash and cash equivalents

13.6 (0.4) 6.1

Net (decrease)/increase in cash and cash equivalents (193.9) (5.1) 261.5 Cash and cash equivalents at the beginning of the

period/year

448.9 187.4 187.4

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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 2014 were approved for issue in accordance with a resolution of a committee of the Board of Directors on 20 August 2014.

The information for the year ended 31 December 2013 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 2013 were approved by the Board of Directors on 26 February 2014 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 2014, and the condensed consolidated balance sheet as at 30 June 2014 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 2014 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 Conduct Authority. These condensed financial statements should be read in conjunction with the annual financial statements for the year ended 31 December 2013, 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 2013, as described in those annual financial statements. A number of new standards, amendments to existing standards and interpretations were applicable from 1 January 2014. 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 2014.

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29 2. OPERATING SEGMENTS

The group’s operations are located and managed in seven business units; namely the Falkland Islands, Indonesia, Norway, Pakistan (including Mauritania), the United Kingdom, Vietnam and the Rest of the World.

Some of the business units currently do not generate revenue or have any material operating income.

The group is only engaged in one business of upstream oil and gas exploration and production, therefore all information is being presented for geographical segments.

Six months to 30 June 2014 Unaudited Six months to 30 June 2013 Unaudited Year to 31 December 2013 Audited $ million $ million $ million Revenue:

Indonesia 175.9 154.9 295.9

Pakistan (including Mauritania) 77.0 85.3 165.4

Vietnam 241.3 259.1 468.2

United Kingdom 390.5 258.5 571.5

Total group sales revenue 884.7 757.8 1,501.0

Other operating income (United Kingdom) - - 38.7

Interest and other finance revenue 15.1 3.3 10.9

Total group revenue 899.8 761.1 1,550.6

Group operating profit/(loss):

Indonesia 9.9 102.9 187.0

Norway (2.4) (2.5) (26.5)

Vietnam 107.7 126.3 195.9

United Kingdom (16.4) 6.4 (31.5)

Rest of the World (11.8) (0.6) (8.7)

Unallocated* (21.0) (17.6) (48.2)

Group operating profit 92.0 255.1 352.0

Share of gain in associate 1.9 - -

Interest revenue, finance and other gains 24.9 5.3 33.0

Finance costs and other finance expenses (68.4) (44.6) (98.4)

Loss on derivative financial instruments - (1.2) (1.2)

Profit before tax 50.4 214.6 285.4

Tax 122.3 (53.5) (51.4)

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2. OPERATING SEGMENTS (continued) Six months to 30 June 2014 Unaudited Six months to 30 June 2013 Unaudited Year to 31 December 2013 Audited $ million $ million $ million Balance sheet - Segment assets:

Falkland Islands 358.6 262.3 297.2

Indonesia 765.4 719.8 731.5

Norway 274.2 288.9 231.3

Vietnam 659.1 705.2 648.5

United Kingdom** 3,787.6 2,814.5 3,260.4

Rest of the World 79.0 28.4 62.8

Unallocated* 207.4 206.1 464.8

Total assets 6,263.8 5,157.4 5,813.9

* Unallocated expenditure and assets include amounts of a corporate nature and not specifically attributable to a geographical segment.

These items include corporate general and administration costs and pre-licence exploration costs. ** Includes goodwill. 3. COST OF SALES Six months to 30 June 2014 Unaudited Six months to 30 June 2013 Unaudited Year to 31 December 2013 Audited $ million $ million $ million

Operating costs 216.9 170.1 418.9

Stock overlift/underlift movement 32.0 25.7 9.8

Royalties 24.7 22.2 43.6

Amortisation and depreciation of property, plant and equipment:

Oil and gas properties 224.0 172.5 375.0

Other fixed assets 4.7 4.0 8.8

Impairment of oil and gas properties 144.0 77.7 178.7

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31 4. INTEREST REVENUE AND FINANCE COSTS

Six months to 30 June 2014 Unaudited Six months to 30 June 2013 Unaudited Year to 31 December 2013 Audited $ million $ million $ million Interest revenue, finance and other gains:

Short-term deposits 1.2 0.2 1.5

Gain on forward contracts - - 12.3

Loan to joint venture partner 12.9 - 6.3

Exchange differences and others 10.8 5.1 12.9

24.9 5.3 33.0

Finance costs and other finance expenses:

Bank loans, overdrafts and bonds (25.8) (16.9) (37.8)

Payable in respect of convertible bonds (5.2) (5.1) (10.3)

Payable in respect of senior loan notes (18.2) (15.8) (31.4)

Unwinding of discount on decommissioning provision (21.7) (17.0) (36.4)

Long-term debt arrangement fees (3.3) (3.8) (8.0)

Loss on forward contracts (11.2) - -

Exchange differences and others - - (0.1)

Gross finance costs and other finance expenses (85.4) (58.6) (124.0) Finance costs capitalised during the period/year 17.0 14.0 25.6

(68.4) (44.6) (98.4) 5. TAX Six months to 30 June 2014 Unaudited Six months to 30 June 2013 Unaudited Year to 31 December 2013 Audited $ million $ million $ million Current tax:

UK corporation tax on profits (1.8) - (12.1)

UK petroleum revenue tax 78.8 28.2 100.9

Overseas tax 71.0 61.9 122.7

Adjustments in respect of prior years 2.4 (13.3) (22.3)

Total current tax 150.4 76.8 189.2

Deferred tax:

UK corporation tax (296.2) (65.6) (180.5)

UK petroleum revenue tax 7.1 3.0 (6.4)

Overseas tax 16.4 39.3 49.1

Total deferred tax (272.7) (23.3) (137.8)

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6. DEFERRED TAX Six months to 30 June 2014 Unaudited Six months to 30 June 2013 Unaudited Year to 31 December 2013 Audited $ million $ million $ million

Deferred tax assets 1,057.2 623.0 762.4

Deferred tax liabilities (296.4) (302.9) (306.8)

760.8 320.1 455.6

1 The UK deferred petroleum revenue tax relates mainly to temporary differences associated with decommissioning provisions.

2 The overseas deferred tax relates mainly to temporary differences associated with fixed asset balances.

3 Credit in the period includes US$134.2 million relating to the impact of the ring fence expenditure supplement

The group's deferred tax assets at 30 June 2014 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 2014 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 forward curve oil price assumption up to 31 December 2016 and US$85/bbl in 'real' terms thereafter. The results of the corporate model concluded that it was appropriate 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$323.1 million (2013: US$255.0 million) and current year non-UK tax losses of approximately US$14.6 million (2013: US$7.9 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.

At 1 January 2014 Exchange movements Assets held for sale (Charged)/ credited to income statement Transfer to retained earnings At 30 June 2014 $ million $ million $ million $ million $ million $ million UK deferred corporation tax:

Fixed assets and allowances (828.2) - - (473.9) - (1,302.1)

Decommissioning 321.7 - - 79.9 - 401.6

Deferred petroleum revenue tax (5.4) - - 4.4 - (1.0)

Tax losses and allowances3 _1,203.8 _- _- _561.0 _- _1,764.8

Small field allowances 47.8 - - 124.8 - 172.6

Derivative financial instruments 13.9 - - - 5.8 19.7

Total UK deferred corporation tax 753.6 - - 296.2 5.8 1,055.6

UK deferred petroleum revenue tax1 _8.7 _- _- _(7.1) _- _1.6

Overseas deferred tax2 _(306.7) _0.5 _26.2 _(16.4) _- _(296.4)

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33 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: Six months to 30 June 2014 Unaudited Six months to 30 June 2013 Unaudited Year to 31 December 2013 Audited Earnings ($ millions):

Earnings for the purpose of basic earnings per share being net

profit attributable to owners of the company 172.7 161.1 234.0

Effect of dilutive potential Ordinary Shares:

Interest on convertible bonds 5.2 5.1 10.3

Earnings for the purposes of diluted earnings per share 177.9 166.2 244.3 Number of shares (millions):

Weighted average number of Ordinary Shares for the purpose

of basic earnings per share 527.1 529.1 529.2

Effects of dilutive potential Ordinary Shares:

Contingently issuable shares 40.8 41.7 36.0

Weighted average number of Ordinary Shares for the purpose

of diluted earnings per share 567.9 570.8 565.2

Earnings per share (cents)

Basic 32.8 30.5 44.2

Diluted 31.3 29.1 43.2