Annual Results for the year ended 31 December 2012

PREMIER OIL PLC

Annual Results for the year ended 31 December 2012

Premier Oil plc ("Premier" or "the company"), a leading FTSE 250 independent upstream company, announces its results for the year ended 2012.

Highlights

Operational

Financial

Outlook

Simon Lockett (Chief Executive), commented:

"Premier has built a strong asset portfolio which will act as a springboard for significant further growth over the medium-term. We have a number of development projects coming on-stream in the short-term, an exploration portfolio with increasing materiality and another key leg to our business as a result of our entry into the Falkland Islands.

Over the last seven years, our team has transformed the size and profitability of our business; the strategy we put in place in 2005 has delivered this growth. The next three years will see a further transformation of the business as we increase production and generate significantly greater cash flows."

21 March 2013

A presentation to analysts and investors will be held at 10.00am today at the offices of Premier Oil's Falkland Islands Business Unit, 157-197 Buckingham Palace Road, London SW1W 9SP. A live webcast of this presentation will be available via Premier's website at www.premier-oil.com.

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.

CHAIRMAN'S STATEMENT

The industry context

2012 was a year of difficult macroeconomic conditions and depressed capital markets. The energy industry, however, has performed strongly and continues to present opportunities for growth. Signs of recovery in western economies and world financial markets are at an early stage, but it is encouraging to start 2013 on a stronger note. Commodity prices have remained remarkably stable, providing a healthy backdrop for continuing investment and new opportunities. Although costs are rising in some areas, good projects are still earning attractive rates of return.

Premier's performance

Premier has again achieved strong growth in the value of the underlying assets of the business. In 2012 we increased production by 43 per cent, cash flow by 66 per cent and report record profitability for a fifth successive year. Reserves and resources now amount to 773 million barrels of oil equivalent (mmboe) compared to 513 mmboe at the end of 2011. Four new projects also received development approval during the course of the year. While we invested in excess of US$250 million in acquisitions and US$772 million in development and exploration projects during the year, balance sheet gearing remained stable at 36 per cent and is well within our target range. We continue to have good access to several sources of debt capital, both reducing our average cost of debt and extending its maturity. This strong operational and financial performance supports continuing investment in new opportunities, an increasingly material exploration programme and the initiation of a dividend payout for the year.

Premier's growth plans

Building on the new fields which came on-stream in Indonesia and Vietnam in late 2011, 2012 saw a significant increase in group production. 2012 average production of 57.7 thousand barrels of oil equivalent per day (kboepd) will rise to a run rate of around 75 kboepd as two new fields, Huntington and Rochelle, come on-stream. Looking further ahead, we have made significant steps in progressing the Solan and Catcher projects, which are expected on-stream in 2014 and 2016 respectively. These new fields, together with our existing producing areas, will underpin our medium-term production target of 100,000 boepd.

We continue to invest in new project opportunities where we see the potential for attractive returns for shareholders. We are delighted to have secured the operatorship and a large equity interest in the Sea Lion field in the Falkland Islands. Our project team is already working closely with both the Falkland Islands and the UK Governments to deliver an approved development plan by the middle of 2014. We also look forward to our first exploration campaign in the Falkland Islands which further builds up our increasingly material drilling programme.

Our 2012 exploration programme delivered successes in the UK, Pakistan and Indonesia. These are valuable additions to the portfolio due to their proximity to existing producing assets. In the UK Central North Sea, our exploration drilling programme attempted to replicate the successes we had in the Catcher area in previous years. However, with the exception of the Carnaby discovery in a new play area west of the Catcher development, the programme was unsuccessful. This serves to underline the necessity, as we grow our production and development asset base, to identify new basin opportunities for future exploration away from the more mature areas in the North Sea and South East Asia. Our exploration and new venture teams have done an excellent job in identifying and negotiating entry into such opportunities offshore Kenya, in the North Falklands Basin, in the Phu Khanh basin in Vietnam, in the Mandal High area in Norway and in Southern Iraq. Over the course of 2012, the team added approximately 1 billion barrels of oil equivalent (bnboe) of prospective resources to the portfolio. We look forward to maturing these for drilling over the next two to three years. Success in any of these locations, because of the nature of their play-opening potential, will be transformational for Premier.

Focus of the Board

As the group and its scope of operations expand, the Board has taken a number of initiatives to ensure longer-term plans can be delivered successfully. A comprehensive strategy review incorporating asset profiles, capital allocation and funding plans was completed in the first half of 2012 and has been reviewed again by the Board in the first quarter of 2013.

Significant progress has been made in the way in which risks are identified, analysed and mitigated throughout our operations, reporting back to the Board via the Audit and Risk Committee. The Board's Nomination Committee has, with the help of the senior management team, taken new initiatives in succession planning, career development and competency programmes. Members of the Remuneration Committee have held a number of meetings with key shareholders and advisory bodies to ensure that our remuneration policies achieve an appropriate balance between reward for our investors and incentives for our employees. At the Board level, we continue to devote significant time to the management of the critical issues of health, safety and the environment. The group's improving record in all of these areas is testament to this effort. However, the tragic accident in December in which a crew member on an emergency standby vessel close to our Balmoral facilities lost his life in extreme weather, is a sad reminder of the need for constant vigilance and determination by all industry participants.

Returns to shareholders

We recognise that the upstream industry is a sector in which substantial capital growth can be achieved by companies focused on short-term exploration success. Such exploration activity yields potentially attractive but inconsistent returns. It is our objective to provide investors with consistent growth, above that of the major companies in our industry, but with the potential for higher returns through our exploration activities.

Premier's share price today stands higher than at 1 January 2012 and over a five-year period has significantly outperformed the FTSE AII Share Oil and Gas Producers Index. However, we recognise that the share price has not kept pace with the growth in value of the underlying assets of the business. The onus is on the Board and the executive team to deliver on our growth plan and to demonstrate an improved return on our exploration programme, so that a higher market rating will be achieved.

The Board has also considered again our policy in respect of shareholder distribution. As foreshadowed at the Annual General Meeting in May 2012, the Board intends to propose a 2012 dividend of five pence per share, to be approved by shareholders at the June 2013 Annual General Meeting. The level of future payouts will depend on the progression of cash flow over time and the capital required to fund our investment opportunities, but the Board believes that the payment of a sustainable dividend underlines our confidence in rising cash flows, the strength of our balance sheet and the quality of our asset base. It is a reward too for the loyalty of our shareholders. We also thank our employees, all of whom participate as shareholders through our employee long-term incentive plans, for all of their hard work in 2012. We all look forward to 2013 and the continuing growth in the company as it achieves its medium-term aspirations.

Mike Welton

Chairman

CHIEF EXECUTIVE'S REVIEW

Business model

We focus on growing the underlying value of the business through disciplined investment in high quality projects. Our skill set and experience give us the confidence and capability to take on complex operated development projects, typically offshore and utilising floating production systems. We believe in offering our investors and our employees continuing growth opportunities reflected in rising production targets. We will judge ourselves, and invite others to judge us, by the growth in our net asset value (NAV) per share year-on-year without relying on a rising oil price. We target in excess of 10 per cent NAV growth per share per year and, over the seven-year period to end-2012, have achieved in excess of 15 per cent. Going forward we will source this growth from the development of existing assets, new acquisitions and material organic exploration, while maintaining a strong balance sheet so that we are well-placed to take advantage of attractive opportunities as they arise.

Our achievements over time

In the five-year period since 2007, we have generated impressive growth in all key financial and operational metrics which define our business. Our growing undeveloped reserves and resource base will support substantial future growth.

Our growth rates have significantly exceeded the 54 per cent rise in the oil price over the same five year period. The majority of this growth has been financed by the re-investment of internally generated cash flows or new debt funding. With some US$1.1 billion of cash and undrawn facilities on hand and a gearing ratio stable at 36 per cent, our balance sheet continues to provide a strong platform for further material growth.

Our operations in 2012

Reservoir performance from all our producing fields in 2012 was encouraging and generated a 43 per cent increase in working interest production year-on-year.

Well productivity was supported by improved facility uptime in the UK, Indonesia and Pakistan. We continue to work on the re-development of the Kyle field in the UK which has been shut down since December 2011 following a severe North Sea storm. The supply of additional gas to the Indonesian domestic market which would have generated further gas sales remains under discussion with the Indonesian authorities. These two factors reduced 2012 production by around 4,000 boepd, though value will be recovered by a combination of insurance proceeds and future production. Equipment issues at our Chim Sáo field in Vietnam, notably with power supply, prevented the full application of water injection, limiting our production rates from the field. This is being addressed and overall the field continues to produce above the level originally anticipated in our field development plan.

First oil from the Huntington field is expected at the end of March, in line with our 2013 budget. After a ramp up period, the field is expected to produce 25-30 kboepd (gross), following a successful development drilling programme. The smaller Rochelle field (Premier share: 15 per cent) is now expected on-stream around mid-year after storm damage to the initial development well. The rig is currently drilling the Rochelle West well and will return to Rochelle East after first gas.

Further significant milestones were achieved within our development portfolio during the year, especially on our operated development projects. The Pelikan and Naga projects, which will sustain and grow our position in the Singapore gas market, received development approvals and will add to existing volumes in the Natuna Sea from 2014 onwards. The Dua and Solan fields received project sanction during the course of the year and are progressing well towards first oil in 2014. On our operated Catcher development in the UK North Sea, concept selection was formally agreed in December and various tenders are now under way for key contracts. We expect to submit the field development plan for approval to the UK Government once these tender processes are complete. Targeted first oil date will be driven by the contract negotiation process, notably for the floating production, storage and offtake vessel (FPSO). Elsewhere, we increased our equity interest in the Bream area in Norway and are working with the revised partnership group to finalise development plans. In Mauritania, the partnership submitted a development plan for the Banda gas field, though this remains subject to final agreement on a gas sales contract.

Investment in the Falkland Islands

In line with our stated strategy, we were delighted to acquire operatorship and a significant equity interest in the Sea Lion development project in the Falkland Islands during the course of the year. With some 350 million barrels of appraised oil, a clear fit with our development skills and an attractive fiscal regime, this is a substantial opportunity for Premier. It is also exciting to work in an environment where there is such strong support from both the Falkland Islands and the UK Governments. The location of the islands raises logistical and infrastructure challenges. However, the resourcefulness of our own project team members and that of the Falkland Islanders gives us every confidence that these can be more than adequately addressed. Building on the work that our partner Rockhopper Exploration plc (Rockhopper) had already commenced, we expect to make key development concept decisions during the course of 2013, with final development approval targeted for mid-2014. This should facilitate first oil from the Sea Lion field during 2017. Whilst the geology of the North Falklands Basin is complex, we also see a large number of prospects and leads which offer potential for future exploration. We are working closely with the Rockhopper team to define the targets for the next exploration programme, now expected in late 2014 or early 2015.

Reserves and resources

The Falkland Islands transaction contributed significantly to a 51 per cent increase in reserves and resources year-on-year. While the Sea Lion field has been fully appraised, our reserve booking policy dictates that resources associated with the field will not be booked into the reserves category until further development milestones have been achieved.

As at 31 December 2012, proven and probable (2P) reserves, on a working interest basis, were 292 mmboe (2011: 284 mmboe) giving a reserve replacement ratio of 134 per cent.

The percentage of liquids in total reserves and resources has increased to 67 per cent (2011: 51 per cent). Given that the price we receive for our Indonesian gas volumes exported to Singapore is linked to oil prices, around 88 per cent of our resource base is effectively oil-price driven. Our current development portfolio is dominated by oil-based projects.

Exploration

Premier's exploration programme over time has generated notable successes. Indeed, the largest projects in our portfolio - our gas reserves in the Natuna Sea, our Chim Sáo oil field in Vietnam, our Catcher field in the UK - come from Premier exploration drilling initiatives. In 2009 we set a goal of adding 200 mmboe of net 2P reserves over a five-year period. Based on discoveries to date, the follow-on potential which they have generated and the programme still to come, we are confident that this objective will be achieved.

We added four discoveries to the portfolio during 2012. The Carnaby discovery adds additional reserves on the Catcher block and is encouraging for the ongoing exploitation of the smaller accumulations around the Catcher field itself. The Catcher area near-field exploration has commenced in 2013 with the drilling of the Bonneville prospect. The Anoa Deep well, underneath our existing Anoa facilities in the Natuna Sea, opened up a new play, the Lama play, which extends across a wide area within Premier's Natuna Sea acreage. Plans to follow up on this success with a new drilling campaign in 2014 and 2015 are advanced. In Pakistan, two notable successes were recorded with the K-30 well on the Kadanwari lease and the BBN-1 well on the Badhra field. These two discoveries added 116 billion cubic feet (bcf) (gross) and have both been brought into production post‑discovery.

However, we recognise the need to update the portfolio as prospects are drilled out and as areas like the UK North Sea become mature. This is why we have taken steps to add new areas in Kenya, Iraq, the Falkland Islands, deeper water acreage in Vietnam and the Mandal High area in Norway. We believe in targeting play-opening opportunities which, on success, will deliver not just one discovery but will open up a series of prospects and leads. Success in any of these areas would lead to multiple opportunities and reduced risk over time. Such new acreage additions in 2012 were significant with a total of 30 new licences, amounting to net acreage gain of 11,800 km2.

In 2013, Premier plans to drill 15 exploration and appraisal wells. This includes five high impact exploration wells targeting in excess of 150 mmboe, including the Luno II well which is currently drilling on the south west margin of the Utsira High, and the Lacewing well, Premier's first high pressure high temperature well in the North Sea. In addition, we look forward to the results of the Kuda Laut and Singa Laut wells in Indonesia and the Ca Voi exploration well in Vietnam. The latter is a true frontier exploration well with the potential to open up a new play in Eastern Vietnam. We also hope to replicate our near field exploration success achieved in 2012 by the drilling of six near field wells in 2013, including the Matang well in Indonesia and the Bonneville well in the UK North Sea, both of which are currently drilling.

Our organisation

We continuously review the structure of our organisation to get the most out of our assets and to optimise project delivery. During 2012 we reorganised our teams into six country units - UK, Norway, Indonesia, Vietnam, Pakistan and the Falkland Islands - reflecting the growing critical mass of those units and the need to have strong local presence in all our key business areas. At the same time our exploration teams now report directly to a central exploration function, pulling together all the technical skills in the group into one team and allowing us to make better informed choices about where to allocate our exploration funds. We continue to believe that our organisational model - strong local units supported by a head office team, focused on critical decision points - will deliver our ambitious medium and long-term goals.

BUSINESS UNIT REVIEWS

FALKLAND ISLANDS

Premier's entry into the Falkland Islands was completed in Q4 2012. Our primary focus is to develop the estimated 300 mmboe Sea Lion field, currently targeted for project sanction mid-2014. Working closely with Rockhopper, we have also defined the lead and prospect inventory such that a minimum of three exploration wells are now planned for 2014/2015.

Development

In July 2012, Premier agreed to farm-in to 60 per cent of Rockhopper's licence interests in the Falkland Islands, including the Sea Lion development project. Following the approval of the Falkland Islands Government, the deal was completed in October with an initial cash payment of US$231 million. In addition, Premier will pay an exploration carry of up to US$48 million and, subject to field development plan approval, a development carry of up to US$722 million. These are fully-funded from a combination of existing cash resources, facilities and cash flow from operations. Premier and Rockhopper also agreed jointly to pursue exploration opportunities in the Falkland Islands and analogous plays in selected areas offshore Southern Africa.

The Sea Lion field is located on the Falklands Plateau, 220 kilometres north of the Falkland Islands and lies in 450 metres of water. The geological setting is a north-south Atlantic failed rift with primarily early Cretaceous to Tertiary fill in a typical half graben structure with a large bounding fault in the east. The Sea Lion accumulation is close to the eastern margin. Stacked Early Cretaceous lacustrine fan reservoirs contain waxy 28 degree API crude oil. Oil-in-place is estimated to be over 1.1 billion barrels with 300 million barrels (gross) recoverable. Including the discoveries at Casper and Casper South, the transaction added approximately 230 million barrels of net contingent resources.

The Sea Lion field is expected to be developed by drilling and completing subsea wells in manifold clusters tied back via flexible risers to an anchored FPSO. Water injection and gas and produced water handling facilities will be provided on the FPSO. Gas will be used for fuel or re-injected to boost recovery. Shuttle tankers will collect the crude oil and ship to international markets. Gross estimated capital expenditure costs remain unchanged at US$5 billion. Premier will fund its share from rising cash flows.

On 1 November, Premier formally became operator of all of the licence interests previously operated by Rockhopper, thereby becoming the operator of the Sea Lion development project. A new dedicated project team is undertaking detailed planning of development drilling and the specification and sourcing of production facilities prior to commencing front-end engineering design. Notably, an FPSO market enquiry, which included visits to ship yards, has been undertaken to assess options of conversions or new builds to meet the design life criteria. Technical reviews have also been undertaken to study the option of gas lift instead of hydraulic submersible pumps while design studies of flow line systems have been completed. Health, safety and environmental management plans are being set to safeguard the development and operations phases. Concept selection is targeted for mid-2013 while project sanction is planned for mid-2014 with first oil targeted for Q3 2017. Once on-stream, the Sea Lion development is expected to add 50,000 barrels of oil per day (bopd) of production net to Premier.

Exploration

Since the announcement of the farm-in in July 2012, Premier has been working closely with Rockhopper to define the prospect inventory within its acreage in the North Falklands Basin. To date, we have technical agreement on a programme of between three and six exploration wells for the next drilling programme, which is targeted for 2014/15, subject to rig availability. Wells currently included in the proposed programme include play-opening wells targeting prospects beneath the existing Sea Lion sands, prospects from independent feeder systems along the east flank of the basin, as well as Sea Lion look-alike prospects. 

Premier has received notification from the Falkland Islands Government that licences PL023 and PL024 (Premier interest 60.0 per cent) have been extended to November 2013 pending further seismic interpretation work and that licences PL003 and PL004 (Premier interest 4.5 per cent) have been extended to May 2016 with the addition of a one well commitment.

INDONESIA

Our key asset in Indonesia remains the operated Natuna Sea Block A. With both further development and exploration activity in the area, we are planning to build on our existing strong share of the Singapore gas market. Through our interests in Block A Aceh and ongoing programme of exploration new venture work, we are seeking to take advantage of our long-established relationships and gas marketing expertise to increase our in-country presence.

Production and development

During 2012, the Premier-operated Natuna Sea Block A (Block A) sold an overall average of 217 billion British thermal units per day (BBtud) (gross) (2011: 161 BBtud) from its gas export facilities, a 35 per cent increase, due to a full-year of production from the new Gajah Baru facility and the established Anoa field.

The Anoa facility continued to increase its market share of sales under the first gas sales agreement (GSA1) delivering 7.5 per cent over its contractual market share of 36.9 per cent. In addition, three Anoa development wells were drilled and put on production in 2012, adding 36 million standard cubic feet per day (mmscfd) of gas deliverability. The non-operated Kakap block contributed a further 33 BBtud (gross) (2011: 42 BBtud). Gross liquids production from the Block A Anoa field was steady at an average 2,400 bopd (2011: 2,400 bopd) with a further 3,500 bopd (2011: 3,400 bopd) from Kakap. Overall, production from Indonesia was up substantially to 14,200 boepd (2011: 11,450 boepd) on a working interest basis.

The Pelikan and Naga projects, also on Block A, were sanctioned in April 2012 and are now in full execution mode. The contract for the engineering, procurement, construction and installation of two wellhead platforms and connecting pipelines was awarded in May 2012. The two projects will involve drilling six new development wells to develop an expected 150 bcf of gas reserves. First gas will be delivered in 2014 to supply existing Indonesia and Singapore sales contracts.

In parallel, a major brownfield development project, to upgrade the compression facilities on the Block A Anoa gas production facility, has also progressed through its first phase. In 2012, two cantilever deck extensions, housing a new gas compressor and turbine generator, were fabricated and installed on the Anoa platform. 2013 will see a second major offshore campaign, during which the existing compression equipment will be reconfigured for low pressure production. The project, when complete in September 2013, will extend the field plateau for another three years and develop 200 bcf of gross field reserves.

On the non-operated Block A Aceh, work continued on the gas development project. The focus has been on improving the economics such that the project can be sanctioned by year-end. The tendering process for most facilities is complete with current efforts towards securing higher gas prices with end buyers and the Indonesian Government progressing well. First gas is targeted for Q3 2015.

Exploration

Premier carried out exploration in five production sharing contracts (PSC) in Indonesia: Natuna Sea Block A, Kakap, Tuna, Block A Aceh and Buton. In 2012, Premier drilled three exploration wells on its Indonesian acreage, one of which was successful and opened up a new play.

The Anoa Deep-1 well, drilled as an exploratory tail to the Anoa WL-5X development well, discovered gas below the Anoa field. The well flowed over 17 mmscf/d of gas from fractured sandstones of the Lama Formation. The discovery of gas in the Lama sands provides additional gas resources that can be dedicated to existing gas sales agreements and opens up a new proven play type which can be pursued across Premier's Block A and adjacent West Natuna areas. Prospect development continued in Natuna Sea Block A with the overall prospect inventory being upgraded through seismic reprocessing on selected prospects and prospect development in the newly proven Lama play. Premier expects to start to drill out these prospects in 2014/15.

The Biawak Besar-1 well on Natuna Sea Block A was drilled to test a stratigraphic trap which was assessed on seismic data to have a good possibility of containing gas. Biawak Besar-1 encountered good reservoir development and gas shows but was not deemed commercial.

In the Buton PSC, Premier participated in the Benteng-1 exploration well which was aimed at discovering oil in limestone reservoirs in the Cretaceous Tobelo formation. While the well was successful in proving an oil presence in the area with oil shows in the Miocene Tondo limestones, no commercial oil accumulation was found. Premier and partners will not continue exploring in the Buton PSC and the licence will be relinquished shortly.

In the Block A Aceh PSC in Northern Sumatra, the Matang-1 exploration well was spudded in late November 2012. The objective of the Matang-1 well is to discover gas resources in a Miocene Peutu limestone reservoir. The drilling of the top seal sequence has taken longer than expected with the results now anticipated by the end of March.

In 2011 exploration wells Gajah Laut Utara-1 and Belut Laut-1 were drilled in the Tuna PSC to test the Miocene and Oligocene potential of two prospects. The wells did not find commercial hydrocarbons but, utilising the information gained, two new prospects, Kuda Laut and Singa Laut, were matured in 2012. These prospects are approved for drilling in 2013 with the Kuda Laut-1 and Singa Laut-1 wells expected to spud in the second half of the year.

During the year Premier maintained an active programme of exploration new ventures work aimed at capturing new licences. This work entailed a number of regional basin studies as well as three formal joint studies carried out in conjunction with the Indonesian Government agency MIGAS.

NORWAY

Premier was awarded four new exploration licences through the APA 2011 round in January 2012 and continued to mature a number of prospects towards drill decisions in 2013. The company also built on its acreage position in and around the Mandal High area through the acquisition of three operated licences, which completed in February 2012, and the award of the Skala exploration licence in the APA 2012 round. In addition, the company increased its interest in the Bream field development and the adjacent block at attractive pricing.

Development

In August, Premier acquired a 20 per cent interest in PL407, which contains the Bream field, and a 40 per cent equity interest in the adjacent PL406 licence on the Norwegian Continental Shelf. This increased Premier's share in the Bream project to 40 per cent and the company's operated interest in PL406, which contains the Mackerel oil discovery and the Herring exploration prospect, to 80 per cent. Premier paid an upfront consideration of US$10 million with further payments of up to US$17.5 million contingent upon certain milestones being reached.

Engineering studies for the subsea systems and wells for Bream were completed during 2012 but the studies carried out for the lifetime extension and upgrade of the FPSO targeted for the field demonstrated that the vessel was not suitable. The joint venture partnership has investigated alternative production facility options and a new build vessel has been identified. Commercial negotiations are underway with the contractor for this vessel and it is expected that front end engineering studies will start in the second quarter of 2013.

During 2012, Premier completed subsurface evaluations for the Mackerel discovery. Based on the current results, a subsea tie-back to the Bream FPSO is the most economic solution. An exploration well on the adjacent prospect, Herring, is also planned to be drilled as part of the development project.

Project sanction and submission of development plans to the authorities for the Bream development is expected in early 2014. First oil is targeted for 2017 with an initial production rate of approximately 14,000 boepd net to Premier.

Elsewhere in Norway, commercial discussions have been held with field owners in the Frøy area with the intent of developing a central processing hub for a number of discoveries close to Frøy. This has proved a slow process, however the pace is expected to pick up in 2013 with equity alignment discussions taking place with the operator of a nearby field.

Exploration

Work continued in 2012 to evaluate the Grosbeak discovery in PL378. The partnership is participating in an area forum that is evaluating the best way of developing the resources in the area. In addition, a significant oil discovery (Skarfjell) was made in the adjacent licence in 2012. Current mapping indicates that a significant portion of Skarfjell extends into PL378 and preparations for appraisal drilling have been initiated.

In February 2012, Premier completed its acquisition of three operated exploration licences. These licences are close to Premier's existing Freki licence and are on the margin of the Mandal High in the Southern Norwegian North Sea. Evaluation of this acreage has so far resulted in a drill recommendation being brought forward to our partners in PL539 and we are awaiting a licence decision shortly. Premier built further on its acreage position in and around the Mandal High through the APA 2012 Licensing Round in which it was awarded a 20 per cent operated interest in the Skala exploration licence in January 2013. As a result, Premier now has access to around 200 mmbbls of net prospective resources on and around the Mandal High.

In the operated licence PL622 a 3D survey was successfully acquired during the summer in co-operation with PGS.

Looking forward, the Luno II exploration well in PL359 in the North Sea offshore Norway spudded in March 2013 and the results of the well are expected by the end of April. The well is looking to prove up the Jurassic reservoir sandstones to the south of the Edvard Greig field and is targeting a gross mean unrisked prospective resource of 120 mmboe.

PAKISTAN

Natural decline in production from our producing fields in Pakistan has again been more than offset by successful infill drilling and step-out exploration. Further potential will be tested during 2013. Premier is also seeking, through a programme of pilot wells at Kadanwari, to test the tight gas potential in deeper horizons.

Production and development

Average working interest production in Pakistan during 2012 was 15,600 boepd net to Premier, three per cent higher than in 2011 (15,100 boepd), despite the start of natural production decline in some existing wells. The higher production was mainly due to successful infill drilling and the tie-in of exploration and development wells in the Kadanwari and Bhit/Badhra gas fields.

Production from the Qadirpur gas field was broadly stable in 2012, averaging 3,700 boepd net to Premier compared to 3,750 boepd in 2011. This was due to the good performance of the wellhead compressors and to the better than expected support from the extended reach wells drilled in the northern part of the reservoir. Specifically, the development wells QP-44, QP-45, QP-46 and HRL-6 were successfully drilled, completed and tied-in to production in 2012 while QP-48 and QP-49 are currently being drilled. In addition, the Government of Pakistan has approved a new price for Qadirpur gas, increasing it by 11 per cent, applicable with effect from December 2012.

Production from the Kadanwari gas field averaged 2,600 boepd net to Premier during 2012, 27 per cent higher than in 2011. This was as a result of sustained production from K-19 and the increase in field production following the tie-in to facilities of the successful exploration wells K-27 and K-28 and the K-29 development well.

The pilot programme at Kadanwari to test the tight gas potential in the Lower Goru formation is ongoing. The K-3 DirB vertical well has been tested and is currently being tied-in to the facilities while the testing of the K-1 DirA vertical well commenced in January. Six tight sand intervals were fracked and tested separately at the K-3 DirB well with total initial flow of 3.4 mmscfd which reduced to 1.8 mmscfd upon clean up. This proved that all the tight intervals in the Kadanwari area can flow gas after fracking, while the G-Sand and B-Sand have demonstrated relatively better flow potentials. These two intervals are being tested in the K-1 DirA well where preliminary results are encouraging as the G-Sand flowed 0.5 mmscfd prior to clean up. All fracked B-Sand intervals also flowed gas to the surface while rates are likely to improve after further rigless clean up. The G-Sand will be targeted in the K-31H horizontal pilot well in 2013.

The Zamzama gas field produced 5,800 boepd net to Premier during 2012 (2011: 5,800 boepd). This was mainly due to continuous good performance of front-end compressors and the Zam-8 infill well being tied-in ahead of schedule. Sub-surface studies were completed in early 2012, following which two infill wells, Zam‑8 and Zam‑9, were drilled back-to-back in the second half of the year. While the Zam-8 infill well was tied-in to the system in November, first gas from the Zam-9 infill well was achieved in January 2013.

Production from the Bhit/Badhra gas fields was stable in 2012, averaging 3,500 boepd net to Premier. This was mainly due to the successful drilling and tie in of the Badhra B North-1 exploration well. In addition, the Bhit-15 development well, which was spudded on 4 November, was tied-in to the facilities in January 2013, further helping to offset the natural decline from the existing wells on the Bhit/Badhra gas fields.

A revised development plan for the Zarghun South gas field was submitted to the Pakistan Government in May 2012 following certification of 64 bcf of tight gas in the Dunghan formation and 12 bcf of conventional gas in the Chiltan/Mughalkot formations by independent consultants DeGolyer and MacNaughton. The revised development plan has been approved for application of premium 'Tight Gas Policy' prices and, as a result, the joint venture commenced development work on the project early in 2013. All costs pertaining to Premier's 3.75 per cent interest in the project are carried by the operator.

Exploration

Two exploration wells, K-30 on the Kadanwari gas field, and Badhra B North-1 (BBN-1) on the Badhra gas field, were drilled in 2012. Both wells were successful and have subsequently been tied-in to infrastructure. 

The K-30 exploration well was spudded in January 2012 and tested gas with a flow rate of 52 mmscfd through a 60/64 inch choke. The well was tied-in to the system in April 2012. Following this better than expected result, two more wells are planned in 2013 in the eastern part of the existing lease.

The BBN-1 well was drilled in September 2012 and made a significant gas discovery in the Kirthar Foldbelt. The well was drilled to a total depth of 2,450 metres and encountered a new sand interval, 44 metres thick, in the Mughalkot reservoir formation which tested gas at a flow rate of 31 mmscfd. The well was tied-in to the Bhit facilities in November. The joint venture has agreed to drill an appraisal well, Badhra B North-1 West, in Q2 2013 to assess the full potential of the 100 bcf discovery as part of an appraisal programme submitted to the Government. The planned Badhra-6 development well will be deepened in 2013 to test the potential of the Parh Limestone. In addition, the Badhra South-1 Deep exploration well will be drilled in 2013 to test the potential of a deeper lead at the Lower Goru level.

MAURITANIA

Production and development

In Mauritania, 2012 working interest production from the Chinguetti field averaged 600 bopd (2011: 650 bopd) with a natural decline in the field production.

The undeveloped discovery, Tevet, in PSC B will continue to be held by joint venture partners till May 2013 while development studies are on-going to make a "develop or drop" decision.

In September 2012, the joint venture submitted an application for grant of an Exclusive Exploitation Authorisation (EAA) for the Banda field along with a gas field development plan (FDP) and Declaration of Commerciality to the Government of Mauritania, subject to various conditions precedent. Subsequently, the Government has approved the FDP and awarded the EAA in January 2013. Gas sales arrangements and payment guarantees for Banda are currently under discussion with prospective buyers.

The Tiof discovery was relinquished in November 2012, being sub-commercial, with a request to the Government that the partnership group is re-engaged in the event of a future satellite development of the field.

Exploration

The consolidation of Premier's exploration licences offshore Mauritania was finalised in 2011 with the grant of a new licence, PSC C-10, in which Premier has an equity of 6.23 per cent. Site surveys were completed over two potential drilling locations, and a final decision on the candidate for the first of two commitment wells will be made in the first half of 2013. The well is scheduled for drilling in the fourth quarter of 2013.

UNITED KINGDOMThe pipeline of development projects in our UK portfolio will drive continuing growth for a number of years. Our principal focus will be the successful execution of these projects. We will also pursue exploration opportunities where the balance of risk and reward meets in-house objectives.

Production and development

Production from Premier's UK fields increased to 12,100 boepd compared to 10,300 boepd during 2011 despite no contribution from the Kyle field. The Banff FPSO, which handles Kyle production, was damaged during exceptionally bad weather at the end of 2011. Since then it has been off location while repairs are undertaken. The increased production in the North Sea can be attributed to significantly higher uptime at the Balmoral facility, positive results from the Scott field well intervention programme and our increased stake in the Wytch Farm asset.

Production from Premier's Balmoral area averaged 4,500 bopd during 2012 compared to 3,750 bopd in 2011. An active year of work culminated in a highly successful HSE KP4 audit during August, in which a significant improvement in overall integrity was noted. Safety performance at the Premier-operated Balmoral floating production vessel also improved in 2012 with a marked reduction in incident frequency and severity.

At the end of 2011, Premier increased its equity in the Wytch Farm field to 30.1 per cent. Upgrades to the process plant and improvements to management systems have facilitated increased production efficiency. An infill drilling programme commenced in February 2012, ahead of schedule, and has resulted in the completion of three new wells and seven workovers.

On the Huntington field the six well development programme was successfully completed in July 2012 with three of the four producers coming in above expectations. The FPSO Voyageur Spirit sailed away in September and all five risers have subsequently been installed. Adverse weather conditions late in the fourth quarter delayed the commissioning and installation programme. However, the DSV Polaris is nearing completion of the final subsea tie-in in preparation for first oil, which is anticipated by the end of the month.

On the Rochelle project the subsea pipeline and umbilical installation programme and upgrades to the host Scott platform were successfully progressed in 2012. The East Rochelle well, the first of the two development wells, was damaged during a North Sea storm in February 2013. As a result, drilling operations were suspended safely pending further analysis and the order of the development wells was reversed with the Prospect rig spudding the West Rochelle well in February. First gas from the Rochelle field is now expected either at the end of the second quarter or in the third quarter.

Significant progress was achieved on our UK-operated development assets. Premier was appointed operator of the Solan field, which is located West of Shetland, on 31 January 2012. The Solan project received full DECC and partner approvals in April 2012 and is now in full execution mode with all of the significant contracts awarded. The platform is currently being fabricated in Fife, Scotland while the fabrication of the subsea tank is being undertaken in Dubai. Phase 1 of the development drilling is on track to commence in April 2013; the heavy lift installation work is planned for the summer of 2014. First oil is targeted for the fourth quarter of 2014 with an initial production rate of 24,000 bopd (Premier equity 60 per cent).

In January 2012, Premier completed its acquisition of Encore Oil plc which resulted in the company taking over operatorship of the Catcher project and increasing its stake in the project to 50 per cent. The development concept, which was formally approved by the joint venture in December, consists of a leased FPSO with subsea tie-backs. The project has now entered the design phase and the tender process with the FPSO providers and for the subsea facilities front end engineering and design (FEED) is under way. The design phase is expected to be completed in the third quarter of 2013 and it is anticipated that the partnership will move to joint venture sanction thereafter. Timing of first oil from the Catcher field is dependent on the results of the FPSO tender process. Premier is currently modelling as the second half of 2016..

Exploration

In 2012, Premier drilled seven exploration wells in the UK North Sea, primarily focused on extending the successes of previous years' drilling in the Catcher licence across a wider area of the Central North Sea basin. This resulted in success with the Carnaby well, the first well drilled to date on the western part of the Catcher block, which encountered 51 feet of net oil in excellent quality sandstones. The remaining UK exploration wells that targeted this play in 2012 were either dry or encountered non-commercial discoveries. As a result, the strategy will now focus exclusively on the prospectivity within the Greater Catcher area. In particular, the Bonneville well spudded in early March with the results expected shortly.

In addition to Bonneville, Premier will drill one other well, Lacewing, in the UK Central North Sea in 2013. Lacewing is targeting Triassic reservoirs and is Premier's first high pressure high temperature well. In 2012, Premier transferred a 37.2 per cent interest in Block 23/22b to ConocoPhillips in exchange for a carry for the Lacewing well. As a result, Premier's retained equity in the well is 20.2 per cent. The well, which will be drilled using the Maersk Resilient rig, is expected to spud in April.

In the 27th UK Licensing Round, the company was awarded a total of 12 licences (six operated), building on our acreage position in the UK North Sea. In particular, Premier was awarded four operated licences adjacent to the Catcher area, which offer both near-field and deeper exploration potential. In addition, Premier reached an agreement with EnCounter Oil (the former management team of EnCore Oil plc) jointly to pursue several Mesozoic prospects and leads, primarily in the Inner Moray Firth. Premier also secured a non-operated licence interest in the west of Shetland Basin. It is anticipated that the leads and prospects identified on this newly captured acreage will be matured during 2013, with drilling in 2014 and beyond.

VIETNAM

There is much still to be gained from optimisation of the Chim Sáo and nearby Dua oil fields. We will continue to test the prospectivity on block 07/03 to the south of Chim Sáo and look forward to the Ca Voi exploration well in the first half of 2013, a potential play-opener for the under-explored Phu Khanh basin.

Production and Development

The Premier-operated Chim Sáo field was brought on-stream at the end of 2011 and the first full year of oil and gas production from the field was accomplished safely. 2012 production from the field averaged 15,200 boepd (net to Premier), ahead of the original development plans. The price of oil cargoes sold from the field during the year averaged in excess of US$4.50 per barrel (/bbl) over Brent. 

The Chim Sáo development drilling programme, which comprised nine producing wells and six injection wells, was completed safely and under budget in April 2012. This programme was followed by three additional wells aimed at capturing upside resources identified during development. Two wells were targeted at a fault terrace to the north west of the field: one was successful and commenced production at approximately 3,000 bopd in August; the second well, targeting a separate fault segment to the north, was dry. Separately, a third well was drilled to accelerate production from a shallow reservoir with larger reserves than initially evaluated and was brought on-stream in September at a rate of about 2,000 bopd.

The Chim Sáo field is currently producing 30 kbopd, some 5 kbopd ahead of expectation at sanction, with potential for further increases to deliverability when power constraints currently impacting the FPSO are resolved. The plan is to add power generation capacity to allow the water injection pumps to sustain reservoir pressure at higher production levels, and the compressors to export higher volumes of associated gas.

The development of the Premier-operated Dua oil field as a three well subsea tie-back to the Chim Sáo facilities received partner sanction in the second quarter of 2012 and Prime Ministerial approval in August. Installation of the main pipeline commenced in February 2013. The field, which is forecast to average a gross production rate of 8-10 kboepd in the first 12 months, is expected on-stream in 2014.

Exploration

In July 2012, Premier agreed to farm-in to the Origin Energy-operated Block 121, in the northern part of the under-explored Phu Khanh Basin, offshore central Vietnam, for a 40 per cent working interest. The farm-in received Government approval in February 2013. Premier will pay its participating interest share in the drilling of the high risk Ca Voi prospect which is planned for May 2013. The prospectivety of Block 121 centres on the untested Oligocene play fairway which Premier recognises as being geologically similar to the Cau formation that it has successfully explored in Blocks 12W and 07/03 in the Nam Con Son Basin.

Immediately after the high risk Ca Voi well, the Ocean General will move to drill CRD-3X, which will appraise the Cá Rồng Đỏ (CRD) discovery, on Block 07/03. The rig will then move to spud the wildcat exploration well on the Silver Sillago prospect also on Block 07/03 in mid-2013. The well, 07-CD-1X, will evaluate the petroleum potential of a new sub-basin within the overall Nam Con Son Basin. The Ocean General will then move to Indonesia where it will spud the Kuda Laut well on the Premier-operated Tuna Block.

NEW COUNTRY EXPLORATION

In addition to exploration in the existing business unit areas, Premier looks to open up new frontier geographies in targeted new countries where the geology is assessed to be similar to that of the existing business units where Premier has built expertise. The acreage accessed is dominated by deepwater environments where an exploration success has the potential to transform the resource base of the company. To date Premier has exposure to frontier exploration acreage in selected areas of Africa and the Middle East. We continue to evaluate new areas for potential entry in 2013.

In East Africa, Premier has equity interests in two blocks offshore Kenya, Blocks L10A and L10B. Processing and interpretation of 2D and 3D seismic data on these blocks continued throughout 2012, and a new 2,250 km2 3D seismic acquisition programme took place over the western part of the blocks in late 2012. A prospect inventory is being prepared with a view to drilling the first exploration well in 2014 or potentially in the fourth quarter 2013.

In November 2012, Premier was formally awarded a 30 per cent non-operated interest in Iraq's Block 12. Block 12, an 8,000 square kilometre block in the foreland of the Zagros fold belt up dip from producing fields, lies in a frontier part of one of the world's more prolific oil and gas basins. The forward plan on Block 12 is to reprocess the existing seismic data in 2013 and then acquire new seismic data in 2014. Subject to the interpretation of the new seismic an exploration well will be drilled in 2015 or 2016.

In Egypt, following the drilling of the Cherry prospect in the North Red Sea 1 licence in 2011, Premier has decided to relinquish its equity share of the licence. Premier has also withdrawn from the South Darag block in the Gulf of Suez, due to the lack of formal Government approval of the licence award.

Premier's exploration rights in the Daora, Haouza, Mahbes, Mijek and Laguara blocks offshore the Saharawi Arab Democratic Republic (SADR) remain under force majeure, awaiting resolution of sovereignty under a United Nations mandated process.

FINANCIAL REVIEW

Economic background

Oil prices for the year as a whole were unusually stable, averaging US$111.7/bbl against US$111.3/bbl for 2011, and trading in a range of US$126.7/bbl to US$88.7/bbl. Premier's portfolio of crudes traded at a weighted average of US$3.5/bbl premium to Brent, boosted by favourable prices for our Chim Sáo crude in the Asian markets. Premier's average realisations for the year were US$111.4/bbl (2011: US$111.9/bbl) influenced by the timing of actual crude oil liftings. After taking into account the effect of hedging contracts, this reduced to US$107.5/bbl (2011: US$89.6/bbl).

Average gas prices for the group were US$8.34 per thousand standard cubic feet (mscf) (2011: US$8.51/mscf). Gas prices in Singapore, linked to High Sulphur Fuel Oil (HSFO) pricing and in turn, therefore, linked to crude oil pricing, averaged US$18.7/mscf (2011: US$19.5/mscf). Average prices for Pakistan gas (where only a portion of the contract formulae is linked to energy prices) was US$4.3/mscf (2011: US$3.8/mscf).

Income statement

Production in 2012 averaged 57.7 kboepd (2011: 40.4 kboepd) on a working interest basis. On an entitlement basis, which under the terms of our PSCs allows for additional Government take at higher oil prices, production was 51.6 kboepd (2011: 37.7 kboepd). Working interest gas production averaged 180 mmscfd (2011: 153 mmscfd) or approximately 54 per cent of total production.

Total sales revenue from all operations reached a new record level of US$1,408.7 million (2011: US$826.8 million), driven by higher production and the sustained high oil prices. Cost of sales rose to US$742.4 million (2011: US$414.9 million). Unit operating costs were US$16.2 per barrel of oil equivalent boe (2011: US$15.9/boe) and amounted to US$342.4 million (2011: US$235.2 million). The operating costs per boe in Pakistan and Indonesia remained stable, increased marginally in the UK and were significantly reduced in Vietnam due to one-off production start up costs in the prior year. Underlying unit amortisation (excluding impairment) rose to US$16.4/boe (2011: US$13.8/boe) reflecting increased production from Vietnam, which has a higher amortisation charge per boe compared to the group average.

Exploration expense and pre-licence expenditure costs amounted to US$157.7 million (2011: US$187.5 million) and US$29.2 million (2011: US$23.0 million) respectively. This includes the write-off of the following exploration wells: a Chim Sáo North West well in Vietnam; Benteng in Indonesia, and the Spaniards, East Fyne, Stingray, Cyclone, Bluebell and Coaster wells in the North Sea. Net administrative costs were US$24.2 million against 2011 of US$25.8 million.

Operating profits were US$455.2 million (2011: US$175.6 million). Finance costs and other charges, net of interest revenue and other gains, were US$107.6 million (2011: US$68.1 million). The increase reflects historically low levels of interest rates on cash deposits, increased gross debt levels to fund development projects in Asia and the UK, and in the latter parts of 2012, the US$231 million funding for the acquisition of the Sea Lion discovery in the Falkland Islands. The charge for the unwinding of the discounted decommissioning provision increased to US$33.2 million (2011: US$28.3 million) reflecting increased provisions for future decommissioning as industry cost estimates rise. 

Pre-tax profits of US$359.9 million (2011: US$141.5 million) also show a positive adjustment of US$14.2 million in respect of the group's commodity hedge portfolio (2011: US$34.0 million). This represents the unwinding of prior year provisions in respect of our embedded oil hedging programme, which finished at the end of 2012.

The group tax charge for 2012 is US$107.9 million, an effective tax rate of 30 per cent of our profit before tax. The group's theoretical tax rate is close to 50 per cent, a higher taxation rate in the UK being offset by lower rates in Vietnam and Pakistan. The 2012 tax charge is reduced as a result of a deferred tax credit in the UK, arising from the Ring Fence Expenditure Supplement (RFES) allowance and the small field allowance for the group's Solan field. The group has an estimated US$1.9 billion of carried forward UK corporation tax allowances, which will be utilised against UK ring fence profits over time, and are therefore reflected in the deferred tax asset position at the year end.

Profit after tax is a record US$252.0 million (2011: US$171.2 million) resulting in basic earnings per share of 47.9 cents (2011: 36.6 cents).

Dividend

The Board is proposing a dividend of five pence per share (2011: nil). This dividend is subject to shareholder approval at the Annual General Meeting to be held in London on 7 June 2013. If approved, the dividend will be paid on 14 June 2013 to shareholders on the register as of17 May 2013.

Cash flow

Cash flow from operating activities was US$808.2 million (2011: US$485.9 million) after accounting for tax payments of US$233.1 million (2011: US$44.0 million). The higher cash flow and tax payments reflect increased production in Gajah Baru, Indonesia and Chim Sáo, Vietnam.

Capital expenditure in 2012 totalled US$771.6 million (2011: US$660.5 million).

The principal field and development projects were Solan, Huntington and Rochelle in the UK, Naga and Pelikan in Indonesia and Dua in Vietnam, together with drilling and compression projects in Pakistan.

Exploration and evaluation spend includes costs principally related to the exploration drilling activities in the UK, Vietnam, Pakistan and Norway.

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 elected to take the share alternative.

Prior to completion of the EnCore transaction, the company reached an agreement to on-sell the 16.6 per cent interest in the Cladhan area, which it acquired via the EnCore acquisition, for an adjusted consideration of US$52.4 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.

Also in July, Premier announced 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 was 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. Premier has also agreed to provide additional stand-by funding to complete the project. In the event that Rockhopper chooses to draw down on this facility, Premier will take an enhanced share of entitlement production and cash flows from the Sea Lion and related fields. This enhanced share continues until Premier realises a 15 per cent post tax internal rate of return on its investment. Thereafter cash flows are shared pro-rata to equity interests. Premier's investment in Sea Lion and related fields 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 pursue jointly exploration opportunities in the Falkland Islands and analogous plays in selected areas offshore Southern Africa. The transaction, accounted for as an asset purchase, was completed in October 2012.

Balance sheet position

Net debt at 31 December 2012 amounted to US$1,110.4 million (2011: US$744.0 million), with cash resources of US$187.4 million (2011: US$309.1 million).

* Other debt includes €100.0 million of long-term senior notes, which are valued at year-end US$1.319:€ spot rate. However these will be redeemed at an average of US$1.397:€ due to cross currency swap arrangements.

In February 2012, 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.

In October 2012, further to an offer from the company, holders representing 98.13 per cent of the total principal amount of the US$250 million guaranteed convertible bonds due in 2014 (representing a principal amount of approximately US$245.3 million) elected to exchange their existing bonds for guaranteed convertible bonds due in July 2018. The new bonds have a conversion price of US$7.00 (£4.34) per share and a coupon of 2.5 per cent. This compares with the old convertible bonds, which had a conversion price of US$6.69 per share and a coupon of 2.875 per cent. Following completion of the Exchange Offer, Premier exercised its right under the terms and conditions of the old bonds to redeem the remaining outstanding bonds (in an aggregate amount of approximately US$4.7 million) at par plus accrued interest.

Cash and undrawn facilities, including letter of credit facilities, were approximately US$1,100 million at 31 December.

Financial risk management

Commodity prices

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 year-end, therefore 3.0 million barrels of Dated Brent oil were hedged through forward sales for 2013 at an average price of US$109.0/bbl. This volume represents approximately 25 per cent of the group's expected liquids entitlement production in 2013. 48,000 metric tonnes (mt) of HSFO, which drives our gas contract pricing in Singapore, was subject to collars covering the period to mid-2013 with a cap of US$500/mt (equivalent to around US$85/bbl). An additional 96,000 mt have been sold under monthly forward sales contracts for 2013 at an average price of US$657/mt. These two hedges cover approximately 32 per cent of our expected Indonesian gas working interest production for 2013. 

During 2012, embedded oil price collars and forward oil sales of 3.9 million barrels, and fuel oil collars and forward sales for 246,000 mt expired at a cost of US$60.7 million (2011: US$119.1 million) which has been offset against sales revenue.

Oil hedge collars are incorporated within the pricing terms of physical off take agreements, avoiding the requirement to revalue them for accounting purposes. A credit of US$9.6 million (2011: US$28.0 million) occurred in respect of past mark-to-market provisions for oil hedges, which have now fully expired.

Foreign exchange

Premier's functional and reporting currency is US dollars. Exchange rate exposures relate only to local currency receipts, and expenditures within individual business units. Local currency needs are acquired on a short-term basis. During the year, the group recorded a gain of US$1.5 million on such short-term hedging (2011: loss of US$0.4 million). In 2012, the group also issued €25.0 million long-term senior loan notes which have been hedged under a cross currency swap in US dollars at a fixed rate of US$1.328:€.

Interest rates

Although the group's borrowing facilities are defined in floating rate terms, a majority of its current drawings have been converted to fixed interest rates using the interest rate swap markets. On average, therefore, the cost of drawn bank funds for the year was 4.6 per cent. Mark-to-market movements on these interest rate swaps amounted to US$2.5 million (2011: charge of US$6.4 million), which was credited to other comprehensive income.

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

Insurance

The group undertakes a significant insurance programme to reduce the potential impact of physical risks associated with its exploration, development and production activities. Business interruption cover is purchased for a proportion of the cash flow from producing fields for a maximum period of 18 months. Due to exceptionally bad weather in December 2011, the Banff FPSO - which handled Kyle production - lost its anchors and the risers were severely damaged, stopping Kyle production for the foreseeable future. A claim for business interruption insurance and property damage is being negotiated with the underwriters.

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 funds shortfalls or covenant breaches and to ensure the group's ability to continue as a going concern.

Despite economic volatility, the directors consider 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 2012 Annual Report and 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 to provide an oversight of key risk factors at each level, from operating level through business unit management to 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 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 HSES risks are managed to levels 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 the company's website (www.premier-oil.com)

CONSOLIDATED INCOME STATEMENT

For the year ended 31 December 2012

The results relate entirely to continuing operations.

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

For the year ended 31 December 2012

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

CONSOLIDATED BALANCE SHEET

As at 31 December 2012

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

For the year ended 31 December 2012

\* The transfer between reserves relates to the non-cash interest on the convertible bonds, less the amortisation of the issue costs that were charged directly against equity.

CONSOLIDATED CASH FLOW STATEMENT

For the year ended 31 December 2012

NOTES TO THE PRELIMINARY FINANCIAL STATEMENTS

For the year ended 31 December 2012

1 General information

Premier Oil plc is a limited liability company incorporated in Scotland and listed on the London Stock Exchange. The address of the registered office is 4th Floor, Saltire Court, 20 Castle Terrace, Edinburgh, EH1 2EN, United Kingdom. This preliminary announcement was authorised for issue in accordance with a resolution of the Board of Directors on 20 March 2013.

The financial information for the year ended 31 December 2012 set out in this announcement 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 and those for 2012 will be delivered following the company's Annual General Meeting (AGM). The auditor has reported on these accounts; the reports were unqualified, did not include a reference to any matters to which the auditor drew attention by way of emphasis of matter and did not contain statements under section 498(2) or 498(3) of the Companies Act 2006.

Basis of preparation

The financial information has been prepared in accordance with the recognition and measurement criteria of International Financial Reporting Standards (IFRS) adopted for use in the European Union. However, this announcement does not itself contain sufficient information to comply with IFRS. The company will publish full financial statements that comply with IFRS in April 2013.

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

During the year, management changed the organisational structure of the group and three regional setups were restructured to form seven business units; namely the Falkland Islands, Indonesia, Norway, Pakistan (including Mauritania), the United Kingdom, Vietnam and the Rest of the World. The segmental information for the comparative year has been re-presented to reflect this change.

Accounting policies

The accounting policies applied in this announcement 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 financial statements for the year ended 31 December 2012.

2 Operating segments

During the year, management changed the organisational structure of the group and the three regional setups were restructured to form seven business units; namely the Falkland Islands, Indonesia, Norway, Pakistan (including Mauritania), the United Kingdom, Vietnam and the Rest of the World. The segmental information for 2011 has been re-presented to reflect this change. 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 up-stream oil and gas exploration and production, therefore all information is being presented for geographical segments.

3 Cost of sales

4 Tax

5 Deferred tax

The group's unutilised tax losses and allowances at 31 December 2012 are recognised to the extent that taxable profits are expected to arise in the future against which the tax losses and allowances can be utilised. In accordance with paragraph 37 of IAS 12 - 'Income Taxes' the group re-assessed its unrecognised deferred tax assets at 31 December 2012 with respect to ring fence tax losses and allowances. The corporate model used to assess whether additional deferred tax assets should be recognised was re-run, using an oil price assumption of Dated Brent forward curve in 2013 and 2014, and US$85/bbl in 'real' terms. 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$327.6 million (2011: US$181.2 million) and current year non-UK tax losses of approximately US$26.9 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.

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.

On 23 March 2011 it was announced that tax relief on decommissioning expenditure would be restricted to 50 per cent rather than 62 per cent. This restriction was substantively enacted in the 2012 Finance Bill and has resulted in a deferred tax charge to the income statement of US$27.2 million.

6 Earnings per share

The calculation of basic earnings per share is based on the profit after tax and on the weighted average number of Ordinary Shares in issue during the year.

Basic and diluted earnings per share are calculated as follows:

7 Intangible exploration and evaluation (E&E) assets

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.

8 Property, plant and equipment

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 due to application of a higher discount rate. 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 2013 and 2014, and US$85/bbl in 'real' terms thereafter and were discounted using a discount rate of 12.5 per cent (2011: 10 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.

9 Notes to the cash flow statement

Analysis of changes in net debt:

10 Acquisition of subsidiaries

In 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 29.65 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 to on-sell the 16.6 per cent interest in the Cladhan area which it indirectly acquired from the EnCore acquisition for an adjusted consideration of US$52.4 million. The buyer 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 paid 80 per cent of certain well costs and 50 per cent of back costs on the Coaster prospect, which was drilled as part of the company's 2012 drilling programme. 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 and the fair value allocation to the EnCore assets in accordance with the provisions of IFRS 3 - 'Business Combinations' is as follows:

These fair values have been finalised based on a detailed review of the exploration portfolio and a reassessment of the Catcher area discoveries in December 2012.

Goodwill arises due to the difference between the fair value of assets and the consideration transferred and also due to the requirement to recognise deferred UK corporation tax liabilities in respect of the difference between 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.

All acquisition-related expenses of US$6.9 million incurred by the group in 2011 and 2012 and were included within general and administration costs.

11 Dividends

The Board is proposing a final dividend of five pence per share (2011: nil). The dividend is subject to shareholder approval at the Annual General Meeting to be held on 7 June 2013. If approved, the final dividend is expected to be paid on 14 June 2013 to shareholders on the register as of 17 May 2013.

The following is the dividend timetable for shareholders' information:

12 External audit

This preliminary announcement is consistent with the audited financial statements of the group for the year-ended 31 December 2012.

13 Publication of financial statements

A full set of financial statements will be published on or before 30 April 2013. Copies will be available at the company's head office, 23 Lower Belgrave Street, London SW1W 0NR, and on the company's website (www.premier-oil.com) by this date.

14 Annual General Meeting

The Annual General Meeting will be held at Institute of Directors, 116 Pall Mall, London SW1Y 5ED on Friday 7 June 2013 at 11.00am.

15 Events after the balance sheet date

Additional financing

In March 2013, the group has negotiated an additional £100 million (US$163.0 million) in the letter of credit facilities, increasing them to £316.0 million (US$515.1 million). This facility will expire in 2015.

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Working interest reserves at 31 December 2012

Notes:

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

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

The group provides for amortisation of costs relating to evaluated properties based on direct interests on an entitlement basis, which incorporates the terms of the PSCs in Indonesia, Vietnam and Mauritania. On an entitlement basis reserves were 255.5 mmboe as at 31 December 2012 (2011: 263.8 mmboe). This was calculated in 2012 using an oil price assumption equal to the Dated Brent forward curve in 2013 and 2014 and US$85/bbl in 'real' terms thereafter (2011: Dated Brent forward curve in 2012 and 2013 and US$75/bbl in 'real' terms thereafter).