Annual Results for the year ended 31 December 2010 (5374D)

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	Price Change	% Change	Share Price	Bid Price	Offer Price	High Price	Low Price	Open Price	Shares Traded	Last Trade
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RNS Number : 5374D

Premier Oil PLC

24 March 2011

PREMIER OIL plc

("Premier" or "the Company" or "the Group")

Annual Results for the year ended 31 December 2010

Premier is a leading FTSE 250 independent exploration and production company with oil and gas interests in the North Sea, Asia and in the Middle East-Pakistan regions. Our strategy is to add significant value for shareholders through exploration and appraisal success, astute commercial deals and optimal asset management.

Highlights

Operational

-- 2010 production of 42.8 kboepd (2009: 44.2 kboepd); on target for 75 kboepd in 2012

-- Material progress on operated Chim Sao and Gajah Baru fields, due on-stream in 2011; Huntington on track with first oil and gas expected within 12 months

-- Portfolio of development projects approaching project sanction which will contribute towards production of around 100 kboepd by 2014

-- Eight out of 14 exploration and appraisal wells drilled in 2010 were successful, including the discoveries in the Catcher area in the UK

-- Proven and probable reserves increased to 261 mmboe (2009: 255 mmboe), a reserve replacement ratio of 138 per cent. Reserves and resources increased to 488 mmboe (2009: 468 mmboe)

Financial

-- Record profit after tax of US$129.8 million (2009: US$113.0 million)

-- Operating cash flow of US$436.0 million (2009: US$347.7 million), an increase of 25 per cent

-- US$1,100 million of UK tax allowances mitigating impact of proposed UK tax changes

-- Rising cash flows and increased funding in place to cover ongoing development and growing exploration programme. Debt facilities expanded and maturities extended

-- Net debt was US$405.7 million (2009: US$315.6 million), representing gearing of 36 per cent. Cash and undrawn bank facilities (including letter of credit facilities) of US$1,202 million at year-end (2009: US$649 million)

Outlook

-- New projects on-stream will push first quarter 2012 production run-rate to around 75 kboepd

-- Development drilling on Gajah Baru successfully completed during the first quarter, Chim Sao development drilling continues well and Huntington development drilling programme will commence in the second quarter

-- Final development sanction for several projects expected during the year. Agreement reached to acquire a 60 per cent interest in the Solan field

-- Pre-development planning for the Catcher area under way to follow successful completion of exploration programme

-- Planned 20 exploration wells in 2011 programme targeting 400 mmboe of unrisked potential; encouraging start with first quarter 2011 wells; currently drilling in the UK, Egypt and Vietnam

Simon Lockett, Chief Executive, commented:

"2010 was an excellent year for the group with exploration success and development project progress. We have added significant value for our shareholders and are on track to meet our ambitious production growth targets. 2011 has already built on progress made with development drilling complete, further exploration successes and new licences awarded across our three regional businesses".

 
 Mike Welton, Chairman  Simon Lockett, Chief 
                                   Executive 
                               24 March 2011 
 
 
 ENQUIRIES 
 Premier Oil plc         Tel: 020 7730 1111 
 Simon Lockett 
 Tony Durrant 
 
 Pelham Bell Pottinger   Tel: 020 7861 3232 
 James Henderson 
 Gavin Davis 
 Henry Lerwill

A presentation to analysts and investors will be held at 10.30am today at the offices of Premier Oil, 23 Lower Belgrave Street, London SW1W 0NR. 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

Our business environment

The prospects of recovery in the world economy, led by stronger energy demand in Asia, pushed oil and gas prices higher during the course of 2010. In response to the recession, governments around the world maintained interest rates at historically low levels providing a favourable financing environment for companies with access to the debt capital markets. Though there are concerns about future inflation, the oil industry benefitted during 2010 from a period of comparative cost stability. Against this positive economic background, the industry was reminded of the inherent dangers it faces as the task of finding large quantities of oil and gas becomes more complex. Preservation of our natural environment relies on strict adherence to safety standards. Politically, there are considerable uncertainties in a number of countries in which we are seeking to grow. This instability is mitigated by our spread of activities around the world and we expect our industry to continue to address these challenges in all its operations.

Premier's performance

2010 was a strong year for Premier resulting in considerable added value for its shareholders. Rising oil and gas prices, combined with stable production, generated record revenues and profits for the group. At the same time, great progress in our development projects and success in our North Sea exploration programme validated our growth targets and ambitions. We expect to see first production from our three most advanced oil and gas developments within the next 12 months. Further forward, we can see a clear path to attaining 100,000 boepd of production by 2014. We continue to have good access to the debt capital markets to finance our investments and, from our rising cash flows, we are able to fund a growing exploration programme. As a result, we are confident of not just replacing reserves but adding to our resource base which will form the basis for future growth beyond 2014.

Governance and the Board

Your Board is fully committed to the principles of good corporate governance and responsibility. As Premier's business has expanded, the need to become more sophisticated in the analysis of risk and performance has become more critical. Assessment of risk factors, actions to mitigate risk and the measurement of performance against key indicators are updated and reported to the Board on a monthly basis. Premier's performance in the area of health, safety and environmental management has, over a number of years, significantly improved and the Board continues to focus on this critical area.

In line with the recommendations of the Combined Code, the Board used external advisors this year to review its effectiveness. The conclusions of this review confirmed the Board to be an effective body. Recommendations were made to enhance the performance and effectiveness of the Board and a process of continuous improvement is now under way.

I would like to pay particular thanks to Premier's senior independent director, John Orange, who after 14 years on the Board has decided not to seek re-election at the Annual General Meeting in May 2011. John's experience at Board level, his chairmanship of the Remuneration Committee and his detailed knowledge of the company have been invaluable. I am particularly grateful for his advice and support on my arrival as Chairman during 2009. I am pleased to report that the Board has asked Joe Darby, who joined the Premier Board in 2007, to take on the role of senior independent director.

In August 2010, we were pleased to report that Jane Hinkley, who has extensive experience at management and board level in both the shipping and oil and gas sectors, joined the Board. Jane has also agreed to chair the Remuneration Committee after John's retirement.

Shareholder returns

Premier's share price increased by 76 per cent during 2010, providing shareholders with very significant returns on the rights issue proceeds subscribed in May 2009 to fund the Oilexco North Sea Ltd (Oilexco) acquisition. Over the five-year period to 31 December 2010, Premier's share price, adjusting for the rights issue, has increased by 193 per cent. I would like to pay tribute to the hard work and skills of our employees, partners and suppliers as we look forward together to continued growth and success.

Mike Welton

Chairman

CHIEF EXECUTIVE'S REVIEW

Strategy and targets

Premier's business model is to achieve continuous growth in our production and development portfolio, whilst offering shareholders material upside through our exploration programme.

Our business is organised in three regional units. We seek to grow and improve the quality of each of these businesses through investment in the full range of exploration, development and production activities.

In 2009, following the successful acquisition of Oilexco, we established a production target of 75,000 barrels of oil equivalent per day (boepd) for 2012. It is pleasing to report that, with strong progress on our three principal development projects in Vietnam, Indonesia and the UK, we are on track to meet that target. Beyond those three projects, we have a portfolio of reserves and resources around the world which will form the next generation of developments. As a result of the progress made on many of these projects we are confident that we will reach an average of 100,000 boepd by 2014. The pre-development work carried out during 2010 in the UK on the future Catcher and Solan oil fields and in Indonesia on the Pelikan and Naga gas fields are examples of the good progress made on these projects.

Over and above our existing reserves and resources position, we have set out a plan to add 200 million barrels of oil equivalent (mmboe) from our exploration efforts. This is targeted to increase the overall level of reserves to at least 400 million barrels (mmbbls), capable of sustaining production growth beyond 100,000 boepd. As a result of the exploration success achieved during the year, we are also on track to achieve this ambitious target. We expect to increase expenditure on exploration over time and our new venture teams are working hard to secure new high-quality acreage.

Critical to achieving our growth objectives is the maintenance of a strong balance sheet and good liquidity. This funds our existing development assets, pre-funds future projects and also gives us the capability to add to the portfolio where we see good quality acquisition opportunities.

Overriding all of our corporate growth targets is an absolute commitment to operating responsibly and meeting our health, safety and environmental standards. We are pleased to report that all of our operations have been awarded or have retained OHSAS 18001 and ISO 14001 certifications. Our operated greenhouse gas emissions intensity now shows a consistent downwards trend and average oil in produced water declined significantly. Additional steps have been taken to prevent hydrocarbon spills including the strengthening of our pollution prevention audit process.

2010 Financial and operating performance

Brent oil prices averaged US$79.5 per barrel (bbl) in 2010, some 29 per cent higher than the average of US$61.7/bbl in 2009. Gas prices realised in the Singapore market, which are directly linked to High Sulphur Fuel Oil (HSFO) prices, averaged US$13.9 per thousand standard cubic feet (mscf), a 26 per cent increase on 2009. Combined with continuing strong demand for our gas in Singapore, higher prices generated record sales revenues for the group of US$763.6 million (2009: US$621.1 million). Though overall production remained stable at 42.8 kboepd (2009: 44.2 kboepd), profits after tax of US$129.8 million (2009: US$113.0 million) also reached record levels.

Operating cash flow after tax was US$436.0 million (2009: US$347.7 million), an increase of 25 per cent. Strong cash flows helped to fund the significant investment programme undertaken during 2010, which will drive an increase in production levels during 2011 and 2012. Development expenditure was US$347.1 million (2009: US$192.5 million). We also increased our exploration and appraisal programme, drilling a total of 14 wells at a cost, including seismic and other exploration activity, of US$164.7 million (2009: US$107.5 million). We remained active in the capital markets with two increases in bank facilities during the course of the year, providing capacity not just for current investment but for continuing expansion. At year-end, total debt facilities stood at US$1,822 million, with cash and undrawn bank and letter of credit facilities of US$1,202 million.

Our investment programmes continue to expand our reserves and resources base. Oil and gas proven and probable reserves increased to 261 mmboe (2009: 255 mmboe). Reserves and resources increased to 488 mmboe (2009: 468 mmboe), the principal addition being our discoveries in the Catcher area in the UK North Sea.

Our exploration and appraisal programme in 2010 delivered eight discoveries from 14 wells, most notably with four successful wells in Block 28/9 in the UK, the Catcher area. This series of wells and the ongoing exploration programme across this block are likely to result in the largest new oil project in the UK sector of the North Sea for a number of years. Elsewhere in the North Sea, we also had successful discoveries at West Rochelle in the UK and at Blabaer in Norway.

We continue to build on our acreage position in areas in which we have a good understanding of the geology and a database of subsurface information. We acquired interests in nine new blocks in the 26(th) Licensing Round in the UK Central North Sea and a further two licences in the most recent round in Norway. Building on our knowledge of rift plays in several parts of the world, we have taken an interest in the northern Red Sea block south of the Gulf of Suez and were recently awarded, subject to negotiation of terms, two licences offshore Kenya, further south within the African rift play fairway.

2011 outlook

Our project execution teams in Asia and the North Sea remain focused on delivering our principal development projects on schedule during the coming months. Completion of construction and upgrade work in yards and the development drilling programmes offshore are progressing well.

There is also much focus on future development projects which bring together the full range of subsurface, engineering, project management, business development and financing skills within the group. We anticipate the achievement of further significant milestones on many of these projects during 2011.

Our exploration programme for the year targets 20 wells with unrisked resource potential of around 400 mmboe. We have already discovered further oil and gas in the Catcher area in the UK. The data acquired is now being integrated with our existing knowledge from prior wells on this block. We look forward to the outcome of the ongoing programmes in Egypt, Vietnam, Indonesia, Norway and the UK and to the continuing efforts of our new venture teams to add future drilling opportunities to the portfolio.

OPERATIONS REVIEW

Production, development and reserves

Average working interest production for the full-year was 42.8 kboepd (2009: 44.2 kboepd). This was lower than that achieved in 2009 due to unplanned maintenance requirements on UK North Sea fields in the Balmoral, Scott and Wytch Farm areas and due to some flooding-related downtime at the Zamzama field in Pakistan. Production in other areas remained steady, with strong gas demand and good production performance in both Pakistan and Indonesia.

 
 Production (boepd)       Working interest      Entitlement 
---------------------- 
                             2010      2009     2010     2009 
----------------------  ---------  --------  -------  ------- 
 Asia                      11,650    11,050    7,300    7,300 
 Middle East-Pakistan      14,900    16,000   14,900   15,850 
 North Sea                 15,500    16,200   15,500   16,200 
 West Africa                  700       950      600      800 
----------------------  ---------  --------  -------  ------- 
 Total                     42,750    44,200   38,300   40,150 
----------------------  ---------  --------  -------  -------

Significant progress continued to be made on our operated development projects. Both Chim Sao and Gajah Baru projects remain on track to deliver first oil and gas on schedule in 2011. On Gajah Baru, fabrication of the wellhead platform was completed and successfully installed. Development drilling is in progress and fabrication of the processing platform is on schedule. On Chim Sao, the platform jacket, topsides and in-field pipelines were installed, while the floating production, storage and offtake vessel (FPSO) conversion was 87 per cent complete at year-end. Development drilling has been progressing well.

The Huntington field in the UK North Sea achieved final project sanction in November 2010 with the Department of Energy and Climate Control (DECC) approving the field development plan (FDP). The FPSO charter party agreement was executed and upgrade work on the FPSO has commenced. A drilling rig contract has been awarded and development drilling is planned to commence in April 2011. First oil is planned for early 2012. On the non-operated Block A Aceh (previously known as North Sumatra Block A) in Indonesia, a fully termed extension to the production sharing contract (PSC) was executed and the principal gas sales agreement (GSA) became unconditional. Issuance of engineering, procurement, construction and installation (EPCI) tender documents for the processing facilities is expected in 2011 with first gas planned for mid-2013.

As at 31 December 2010 proven and probable reserves, on a working interest basis, were 261 mmboe (2009: 255 mmboe).

 
                      Proven and probable      2P reserves and 2C 
                            (2P) reserves    contingent resources 
                                  (mmboe)                 (mmboe) 
-------------------  --------------------  ---------------------- 
 Start of 2010                        255                     468 
 Production                          (16)                    (16) 
 Net additions and 
  revisions                            22                      36 
-------------------  --------------------  ---------------------- 
 End of 2010                          261                     488 
-------------------  --------------------  ----------------------

At year-end, the percentage of liquids in total reserves increased from 32 per cent at the end of 2009 to 35 per cent. The equivalent volume of 2P reserves on an entitlement basis amounted to 222 mmboe (2009: 229 mmboe) based on a price assumption of US$75/bbl (2009: US$75/bbl).

Booked reserve additions were mainly due to the exploration successes of Catcher and Varadero in the UK North Sea. Other reserves additions included increases to the Pakistan portfolio following on from exploration successes at Kadanwari. Contingent resources at year-end increased to 227 mmboe (2009: 213 mmboe). Increases in contingent resources included tight gas volumes at Kadanwari, along with discovered volumes at Blabaer and West Rochelle in the North Sea.

Asia

In Indonesia we continued to develop the full potential of our Natuna Sea and Block A Aceh gas positions with the accelerated development of new fields in Natuna Sea Block A to capture additional gas market demand and with the execution of the Block A Aceh PSC extension. In Vietnam, while the Chim Sao development progresses well, we are seeking to grow our presence with work continuing to define the Dua and Ca R ng (CRD) accumulations as well as by undertaking new exploration activities.

Indonesia

During 2010, the Premier-operated Natuna Sea Block A sold an overall average of 160 billion British thermal units per day (BBtud) (gross) (2009: 153 BBtud) from its gas export facility, whilst the non-operated Kakap Block contributed a further 54 BBtud (gross) (2009: 42 BBtud). Gross liquids production from the Block A Anoa field averaged 1,758 barrels of oil per day (bopd) (2009: 1,920 bopd) and 2,993 bopd (2009: 3,540 bopd) from Kakap. The Kakap field experienced downtime during the year as a result of change out of the FPSO vessel. Overall, net production from Indonesia amounted to 11,650 boepd (2009: 11,050 boepd) on a working interest basis.

Significant progress continued to be made on the Gajah Baru project which remains on track to deliver first gas on schedule and within budget in October 2011. Gajah Baru is the first of a number of fields to be developed to supply additional gas to Singapore and to Batam Island in Indonesia under three new GSAs signed in 2008 and reported previously. Fabrication of the wellhead platform was completed and installation successfully achieved to support the start of development drilling in September, with the drilling rig on location during this period. Three of the first phase of five wells have been drilled, logged and tested with results that exceeded expectations. Meanwhile fabrication of the central processing platform at Batam continues as planned. The overall EPCI contract was 75 per cent complete at year-end. The central processing platform and export pipeline are due to be installed during the second quarter of 2011 and detailed hook-up and commissioning planning is being progressed.

Also on the operated Natuna Sea Block A PSC, accelerated development work on the Pelikan and Naga fields is in progress in order to be able to take on additional GSA market share from 2014. The project passed through the concept selection gate, front end engineering and design (FEED) is in progress and final project sanction is expected in 2011.

On the non-operated Block A Aceh, a fully termed extension to the Block A Aceh PSC was executed with the Government of Indonesia and the provincial Government of Aceh on 28 October 2010, with the extended PSC being effective from 1 September 2011. Sales agreements with the principal buyers of gas from the field have been completed and work continues towards optimising the project prior to the issuing of EPCI tender documents for the processing facilities in 2011. First gas is expected in mid-2013. Preparations also commenced for the drilling of the Matang exploration well during 2011.

Vietnam

Progress on the Chim Sao development remained on schedule for first oil during July 2011. In 2010, the platform jacket, topsides and in-field pipelines were installed, and the Chim Sao associated gas export pipeline was tied into the Nam Con Son pipeline. The conversion of the FPSO at Keppel's yard in Singapore, was 87 per cent complete at year-end. Development drilling commenced in June and is on schedule to deliver the wells required for first oil. All cost elements of the development remain in line with budget.

Detailed subsurface and facilities work was undertaken to define the development plan for the Dua field, a tie-in to the Chim Sao FPSO. FEED is in progress and a final project decision is targeted for the second half of 2011.

India

No progress has been made in 2010 with the Government of India in signing the Ratna licence and Premier has closed its representative office in Delhi.

North Sea and West Africa

Building upon the acquisition of Oilexco in 2009, Premier has passed significant milestones in growing our North Sea business. These included achieving project sanction on Huntington, the successful Catcher and Varadero exploration wells (Premier equity 35 per cent), which discovered a significant quantity of high-quality oil reserves, and the West Rochelle boundary well which confirmed the extension of the Rochelle discovery into Block 15/26b. We continue to pursue actively new assets that are capable of delivering near-term production in the North Sea.

Total UK production in 2010 was 15,500 boepd (2009: 16,200 boepd). This included 7,100 boepd (2009: 5,000 boepd) from our fields which utilise the Balmoral facilities and other material contributions from the Scott and Telford, Kyle and Wytch Farm fields.

The lower overall production in 2010 was largely due to unplanned maintenance requirements on the Balmoral, Scott and Wytch Farm areas, although oil revenues increased due to the higher oil price which averaged US$79/bbl across all fields. 2010 average production was also affected by the earlier than planned permanent cessation of production on the Shelley field. However, there was notable production success in the Scott field from the J39 infill well, drilled in January, successful workovers of wells J33 and J24 in March, and the re-perforation of well J37Y in June.

Premier commissioned a gas compression upgrade on the Balmoral floating production vessel (FPV) in February to facilitate the production performance of Premier-operated oil fields Brenda and Nicol. These fields and the non-operated Kyle field delivered strong consistent production throughout the year.

The Burghley field was successfully tied back to the Balmoral FPV in October. The Burghley third party oil production will contribute pro-rata to the FPV shared operating costs, which will lower the costs allocated to the Premier oil fields that are tied back to the vessel.

Premier completed the purchase of an additional 0.80 per cent in the Telford field on 23 December, thereby increasing our equity in Telford to 1.59 per cent. The Telford operator successfully completed two infill wells which will start up in 2011.

The Huntington field (Premier equity 40 per cent) progressed to the development phase following joint venture and DECC approval of the Huntington FDP. The FPSO charter party agreement has been executed and upgrade work on the FPSO has commenced at the yard in Norway. Long lead items for the topsides and key subsea equipment are on order. A drilling rig contract has been awarded and development drilling is planned to commence in April 2011. Installation activities are planned for summer 2011, with the FPSO due to arrive in the field late in the third quarter or early in the fourth quarter. First oil is planned for early 2012.

Reservoir modelling and pre-development engineering conceptual studies were funded during 2010 for the Ptarmigan and Caledonia fields. Economic screening has indicated that it may be commercially feasible to develop Caledonia North by subsea tie-back to the Premier-operated Balmoral FPV. The Caledonia re-development opportunity may be enhanced by the Premier-operated Bluebell prospect, which will be drilled in 2011. Ptarmigan concept studies have been completed based on a subsea tie-back to the Balmoral FPV and are currently being evaluated.

Premier actively pursued business development opportunities in 2010 leading to two new potential field developments: the Solan and Fyne fields. Premier paid US$1.5 million to Chrysaor Limited to fund pre-development conceptual studies for the Solan field in exchange for an option to farm in to a portion of Chrysaor's 100 per cent equity. The field is located in the west of Shetlands in Block 205/26a, to the south of the Schiehallion field. Post year-end, a conditional agreement has been signed with Chrysaor for Premier to take a 60 per cent working interest in the development, in exchange for funding Chrysaor's share of development costs. Premier will also pay US$20 million in consideration. Full development sanction for the Solan field is anticipated for mid-2011. Premier paid US$2 million to Antrim Energy to fund pre-development conceptual studies for the Fyne field in exchange for an option to farm-in to acquire 40 per cent of the Fyne area on Block 21/28a. Antrim currently owns 75 per cent equity and operates the block. Work continues on reviewing field development options in the area.

Norway

In Norway, Premier has made further progress on two significant pre-development assets: Froy (Premier 50 per cent) and Bream (Premier 20 per cent). At Blabaer (Premier 15 per cent), hydrocarbons were discovered in the Lower Jurassic Cook formation; this discovery has the potential to tie-back to the adjoining Jordbaer development.

On the Froy field, the joint venture has continued to mature a stand-alone concept for development. In particular, the joint venture has evaluated an improved drainage strategy with use of water and gas injection. Further studies carried out in the second half of 2010 looked at three third party fields in the Froy area as potential tie-back volumes. The results of these studies indicate that the tie-backs are feasible, though further work is required to complete viable commercial arrangements. Given successful outcomes from the current work programme, the joint venture will be in a position to achieve project sanction later in 2011.

The Bream field development has been advanced during 2010, with a tender exercise for an FPSO being completed and a contractor/vessel being shortlisted. Work on the FPSO and subsea well concept has progressed well, and a project sanction decision is expected to be taken during the second half of 2011.

Mauritania

In Mauritania, 2010 working interest production from the Chinguetti field averaged 700 boepd (2009: 950 boepd), higher than earlier expectations. The operator continues to assess and optimise production performance from the field.

The joint venture partnerships continue discussions with the Mauritanian Government to extend the existing PSCs covering the remaining potential in the area, with the aim of concluding these discussions in 2011. Partners have been undertaking gas development studies for the Banda and Tevet fields, whilst in parallel they have been evaluating the further exploration potential of the areas.

Middle East-Pakistan

Our Middle East-Pakistan business unit continues to focus on enhancing the value of our Pakistan producing assets by maximising production through exploration and development within the existing fields. We are seeking to extend our presence to new areas in the Middle East through new exploration and by evaluating acquisition opportunities.

Pakistan

Average production was 14,900 boepd (2009: 15,720 boepd). This was mainly attributed to natural depletion of our gas fields and to some interruptions at the Zamzama field caused by the very significant flooding suffered in August 2010. Looking forward, production will be boosted by implementing ongoing front-end compression projects, full utilisation of all production facilities, and increased production from the successful exploration and development wells drilled at the Kadanwari field during 2010.

The Qadirpur gas field average production in 2010 was 3,550 boepd (2009: 4,150 boepd). The decrease in 2010 production of 14 per cent was due to natural decline in reservoir pressure. However, after the completion of the installation of front end compressors in October 2010, gas production has been increased from around 480 mmscfd to 600 mmscfd (gross) and this level is expected to be maintained with the installation of additional compressors by the end of 2011. Two production wells (QP-40 and QP-41) were drilled and tied in during the year. Supply of 60 mmscfd permeate gas (a side stream of low heating value gas from process facilities) to local power plants commenced in February 2010 as planned, with the added benefit of simultaneously reducing gas flaring/venting from the facilities.

The Kadanwari gas field average production in 2010 was 1,750 boepd (2009: 1,250 boepd). This increase of 40 per cent was achieved by the drilling and tie-in of two development wells, K21 and K23, and two successful exploration wells, K-19 and K-24. Further development and exploration wells are planned for 2011 to maintain production.

The Zamzama gas field average production in 2010 was 6,050 boepd (2009: 6,890 boepd). The lower production was due to natural decline in reservoir pressure, as well as two production wells having to be shut in from September through December 2010 due to the exceptional floods in the area. In order to mitigate natural decline, the major front end compression project (gross capex of US$145 million) is making good progress and is scheduled for completion in June 2011.

The Bhit/Badhra gas fields average production in 2010 was 3,550 boepd (2009: 3,430 boepd). The wellhead compression project, which commenced in 2009, remained on schedule and by the end of 2010 all wells in Bhit were connected to compression.

Field development at Zarghun South was delayed following higher than expected facilities bids. The joint venture now awaits the passing of the impending "Tight Gas Policy" (presently under approval process by the government) to take advantage of higher gas prices. All costs pertaining to Premier's 3.75 per cent interest are carried by the operator.

EXPLORATION REVIEW

Our exploration strategy, first set out in 2009, envisaged the addition of 200 mmboe of net 2P reserves by 2015. This will be achieved by focusing on geographies and geological themes in which Premier has demonstrable skills and expertise. These are the exploration of rift basins in Asia, North Sea and North Africa, and onshore frontal fold belt provinces as exemplified by our asset base in Pakistan and certain areas of Indonesia. Since 2009, reserves and resources amounting to 56 mmboe have been added towards the 200 mmboe target. With further evaluation and appraisal, we estimate that this could rise to over 100 mmboe of additions.

In 2010, Premier participated in 14 exploration and appraisal wells, of which eight were successful; a success rate of 57 per cent. The most notable successes in 2010 were the three Catcher discoveries in UK Block 28/9, on the western margin of the Central North Sea rift basin. These play-opening successes were followed up by the Varadero discovery at the end of the year. Further wells are planned to test the play in 2011.

In addition to play-opening wells, Premier continues to explore for low risk opportunities adjacent to existing or planned infrastructure, and notable successes were achieved at West Rochelle, near the Scott/Telford facilities in the UK, at Kadanwari in Pakistan and Blabaer in Norway.

During the year, Premier captured 3,022km(2) of net new acreage in the UK (eight licences) and 9,445km(2) in Egypt (one licence). Post year-end, two new licences were awarded in Norway. The Egyptian licence, a frontier play in deeper water, is a step change for Premier, but consistent with our rift basin theme. The exploration well in water depth of 700m commenced in December 2010 with the results expected in the second quarter of 2011.

New business activity in central and northeast Africa resulted in the commencement of negotiations for two production sharing agreements offshore Kenya (Blocks L10A and L10B). Premier will have an average 22.5 per cent interest in these blocks.

Premier continues to acquire high-quality datasets in support of exploration and appraisal drilling and in 2010 1,910km(2) of 3D seismic data were acquired to advance the interpretation in preparation for 2012 drilling in Vietnam and the UK.

20 exploration and appraisal wells are planned for 2011, inclusive of important play tests in Vietnam, Indonesia and Egypt.

Asia

Indonesia

On the Premier-operated Tuna Block, final plans were completed for the drilling of two exploration wells, Gajah Laut Utara and Belut Laut, in the first half of 2011. These wells will follow on from the nearby Ca R ng (CRD) appraisal well in the neighbouring Vietnamese block as part of a three well programme using the same drilling rig.

On Natuna Sea Block A, plans were completed for the drilling of two near-field exploration wells, Anoa Deep and Biawak Besar, scheduled for drilling in the third and fourth quarters of 2011. A review is in progress to refine the remaining prospective resource potential of the entire block. This study is set for completion in the first half of 2011, for incorporation into a five-year exploration plan on the block.

On Block A Aceh, plans were completed for the drilling of one exploration well, Matang, scheduled for drilling in the third quarter of 2011.

Elsewhere, on the Buton Block in Sulawesi, plans were finalised for an exploration well, Benteng, now expected to be drilled in the second half of 2011.

Vietnam

Following the 2009 exploration success at CRD in Block 07/03, Premier integrated the well results into the new 3D seismic data and then sought and obtained Government of Vietnam approval for an appraisal plan for CRD. The first appraisal well on CRD was spudded in February 2011. Continued activity elsewhere on Block 07/03 included the acquisition of 900km(2) of new 3D seismic data over the southern part of the block. Interpretation of these data and of the previously acquired data in the east of the block will allow selection of prospects for exploration drilling in 2012.

In Block 104-109/05, offshore northern Vietnam, 445km(2) of new 3D seismic data and reconnaissance 2D lines were acquired and interpreted to aid the final selection of the location for an exploration well, planned for the third quarter of 2011.

North Sea and West Africa

In April, the Bugle North well was drilled as a joint appraisal well on the boundary of Blocks 15/23c and 15/23d. Premier effectively paid 37 per cent of the joint well cost to earn a 50 per cent equity in 15/23d. The well was targeting the northern extension of the Bugle oil discovery and encountered minor quantities of hydrocarbon, but these are considered insufficient to support a Bugle development at this time.

In May, the Catcher exploration discovery well 28/9-1 (Premier 35 per cent) encountered 80 feet of high-quality oil in the Cromarty reservoir. Catcher East was drilled as a side-track to the main well, approximately 0.5km to the east. This well found hydrocarbons in younger Tay sands which are in communication with the initial discovery in the Cromarty sand. A core recovered 44 feet of net oil bearing Tay sand with an average porosity of 34 per cent.

A second side-track, Catcher South West, encountered 68 feet of net hydrocarbon pay and a common oil water contact with the Catcher main well.

Phase 2 of the Catcher area exploration began with the drilling of the Varadero well. The initial analysis indicated 84 feet of net hydrocarbon pay in the main Tay sandstones, plus a further 22 feet of net pay in thinner sands above the main Tay sands. The oil is of similar good quality to the Catcher discovery well. Further drilling of the block is planned for the first half of 2011.

Premier concluded drilling operations on the Oates farm-in well 22/19c-6 in August, but logging from the Forties target indicated that no hydrocarbons were present. The well was plugged and abandoned. Premier acquired a 50 per cent equity in 22/19c from the farm-in well. Remaining prospectivity on the block is being evaluated in light of the well result.

In October, Nexen operated the drilling of the joint exploration boundary well between West Rochelle Block 15/26c (100 per cent Endeavour) and 15/26b (Premier 50 per cent). Premier earned 25 per cent of 15/26c by promoting part of the joint well. The well confirmed oil and gas pay in excellent quality Kopervik sandstone reservoir and was subsequently side-tracked up dip. The side-track confirmed the presence of gas-bearing Kopervik sands. The contacts and fluids seen in the West Rochelle primary well and side-track are the same as the Rochelle discovery, suggesting a single field. The Rochelle fields will be tied back to the Scott production facility in which Premier has a 21.83 per cent interest. The first phase of the Rochelle development received government approval in early 2011.

In October, Premier received five licence awards across nine blocks in the UK 26(th) Round including two as operator. The awards were:

 
 Block No.               Premier %   Comment 
----------------------  ----------  ----------------------------- 
 14/30b                  50          W Rochelle/Kildare extension 
 15/9, 15/10, 15/14,     50          Fladen Ground Spur margin 
  15/15 
 15/23g*                 50          Blackhorse extension 
 21/7b*                  70          Typhoon prospect 
 22/26c, 22/21c (part)   30          Two Jurassic prospects 
----------------------  ----------  -----------------------------

* Premier operated

Premier was also awarded exploration acreage in the West Orkney Basin in May, following a UK 25(th) Round application.

In December, Premier paid US$2.8 million, funding 50 per cent of the cost of a seismic acquisition on the Eagle prospect (licence P1212, Block 15/13b) to earn a 50 per cent interest in the block.

Norway

The Greater Luno extension well 16/4-5 on licence PL359 (Premier 30 per cent) completed drilling operations in March. The well objective was to test the hydrocarbon potential in Jurassic age sediments and fractured basement. The well was plugged and abandoned as a dry hole. The joint venture has been granted a two-year licence extension to investigate additional prospectivity on PL359.

The Blabaer PL374S exploration well 34/5-1S (Premier 15 per cent) was drilled in the first quarter of 2010 on an adjacent block to the third party Jordbaer discovery. The well successfully discovered hydrocarbons in the Cook formation and was side-tracked across a bounding fault to test an adjacent fault compartment that was water wet. The well results are being integrated into the regional understanding and a potential appraisal campaign, as part of a tie-back to the neighbouring Jordbaer development, is being evaluated.

The Gnatcatcher PL378 exploration well 35/12-3 commenced on 24 December. The well was drilled to test the Upper Jurassic Sognefjord formation. The well encountered minor hydrocarbon shows and was plugged and abandoned as a dry hole. The joint venture plans to appraise the Grosbeak discovery on this licence in 2011.

Premier was awarded two licences in January 2011, one operated, in response to two applications made in the Norwegian 2010 APA Licence Round. The non-operated licence is an extension of the PL378 licence. The operated licence, Block 2/6 in the southern part of the Norwegian North Sea, contains the Freki prospect.

Congo

Following the evaluation of the Frida well results (drilled in 2009), and having integrated this with the regional play understanding, the decision was taken at the end of 2010 to withdraw from the Congo Marine IX licence. Premier is currently working with the remaining partners and the Congolese Government to facilitate Premier's withdrawal from the licence.

SADR

This area remains in force majeure and we await reconciliation of the political situation before progressing further technical evaluation.

Middle East-Pakistan

Pakistan

In the first quarter of 2010, the Pirkoh-1 exploration well was drilled in Qadirpur to test the potential of the shallow Pirkoh Limestone formation. Logging results showed high water saturation and the well was plugged and abandoned.

Testing of the K-19 step-out well in the Kadanwari area was carried out in January and tied in to the system in March 2010. This well is currently producing around 40 mmscfd and has helped in substantially boosting field production during the year.

In the second half of 2010, a step-out appraisal well, K-25, encountered gas. The decision was taken to side-track the well, which targets the reservoir area outside of the K-25 drilled compartment.

The K18-ST exploration well tested gas at a flow rate of 18 mmscfd with a 42/64" choke at 1,980psi wellhead pressure. Tie-in operations of the K18-ST well have commenced, with gas expected on-stream in the first quarter of 2011.

Egypt

The award of the South Darag Block in the Gulf of Suez (Premier 100 per cent) awaits formal government approvals.

Premier farmed into the North Red Sea Block 1 in December 2010, taking a 20 per cent interest, and will contribute to the cost of the NRS-2 (Cherry) exploration well. The well will be the first test of a significant deep water play in the northern Red Sea. The drilling of the well commenced in December 2010, with results expected in the second quarter.

Elsewhere in Egypt, Premier continues to review new venture opportunities, consistent with its exploration rift basin theme.

FINANCIAL REVIEW

Economic background

Oil prices strengthened during the course of 2010 as hopes rose of economic recovery, particularly in Asia. Brent crude prices averaged US$79.5 per barrel (bbl) for the year, against US$61.7/bbl in 2009. Premier's portfolio of crudes sells at an average of 20 cents premium to Brent and, taking into account the timing of our crude oil liftings, average actual realisations for the year were US$79.7/bbl (2009: US$66.3/bbl).

Stronger economic conditions in South and South East Asia, provided a positive backdrop for our gas operations in these regions. Total gas demand in Singapore, driven by increasing population and new industrial developments, mainly on Jurong Island, rose from 814 BBtud in 2009 to 872 BBtud in 2010. According to independent analysts, it is expected to continue to rise over the next few years, allowing our gas sales to steadily increase above current contracted levels. Though LNG import facilities are now under construction in Singapore, there continues to be good prospects for additional pipeline gas sales in the future. Offtake under our existing gas sales contracts in 2010 averaged 160 BBtud (2009: 153 BBtud) with the share of the Premier-operated Block A rising from 41 per cent to 45 per cent, due to strong production performance from the Anoa field.

In Pakistan, gas remains a critical component of the country's energy needs, meeting around 45 per cent of total energy requirement. Total domestic gas production has remained at around 4 billion cubic feet (bcf) per day and with demand continuing to grow at around 10 per cent per annum, an increasing production shortfall is likely to arise in the coming years. With significant gas reserves remaining, we are well placed to maintain or increase production through additional compression facilities and development drilling.

Income statement

Production levels in 2010, on a working interest basis, averaged 42.8 kboepd (2009: 44.2 kboepd). On an entitlement basis, which under the terms of our PSCs allows for additional government take at higher oil prices, production was 38.3 kboepd (2009: 40.2 kboepd). Working interest gas production averaged 156 mmscfd (2009: 156 mmscfd) during the year, or approximately 63 per cent of total production. Average gas prices for the group were US$6.26 per thousand standard cubic feet (mscf) (2009: US$5.18/mscf). Gas prices in Singapore, which are linked to High Sulphur Fuel Oil (HSFO) pricing, in turn closely linked to crude oil pricing, averaged US$13.9/mscf (2009: US$11.0/mscf) for the year.

Total sales revenue from all operations reached record levels of US$763.6 million (2009: US$621.1 million) driven by the higher commodity prices. Cost of sales was US$530.5 million (2009: US$361.4 million). Unit operating costs were US$13.9 per barrel of oil equivalent (boe) (2009: US$12.2/boe) reflecting higher unit costs in the UK sector as production levels declined.

The tie-in in October 2010 of the Burghley field to our Balmoral facility in the UK North Sea will have a positive impact on unit costs during 2011 and beyond as Balmoral complex costs will now be shared pro-rata to production levels.

Amortisation and depreciation includes an impairment charge of US$65.3 million relating to the Scott and Balmoral fields in the UK (2009: US$24.0 million for the Chinguetti field in Mauritania) which mainly arose as a result of a significant increase in estimated future decommissioning costs. The charge was calculated using a long-term Brent crude oil price of US$75/bbl (2009: US$70/bbl). Underlying unit amortisation (excluding impairment) rose to US$12.6/boe (2009: US$9.6/boe) largely as a result of increasing future abandonment provisions.

Exploration expense and pre-licence exploration costs amounted to US$68.2 million (2009: US$57.0 million) and US$18.9 million (2009: US$20.3 million) respectively. This includes the write-off of exploration wells (Oates, Bugle North, Greater Luno) in the UK and Norway sectors. It also includes the effect of an impairment charge of US$12.8 million in respect of the Banda field in Mauritania. Despite extensive discussions with the Mauritanian Government, no agreement has been reached on the nature or terms of a future gas development and it is felt appropriate to write-off capitalised costs relating to this asset.

Net administrative costs were stable at US$18.3 million (2009: US$18.3 million).

Operating profits were US$127.7 million (2009: US$169.7 million). Finance costs and other charges, net of interest revenue and other gains, were US$65.5 million (2009: US$28.7 million) reflecting lower levels of interest income and higher levels of borrowing costs as borrowings from our capital investment programmes increased. Also included in finance costs were fees of US$15.6 million (2009: US$10.5 million) largely relating to the refinancing of US$1.1 billion of Premier's bank facilities in November 2010. The charge arising due to the unwinding of the discounted decommissioning provision increased to US$16.2 million (2009: US$8.7 million) reflecting the increase in total decommissioning provisions.

Pre-tax profits of US$100.8 million (2009: US$79.9 million) also reflect a positive adjustment of US$38.6 million in respect of the group's commodity hedge portfolio (2009: US$61.1 million, charge). This was driven by the unwinding of prior year provisions in respect of our oil and gas hedges.

The current tax charge for 2010 is US$61.4 million, an effective tax rate of 48 per cent of operating profits. This charge is offset by a deferred tax credit of US$90.4 million, resulting in a net tax credit of US$29.0 million (2009: US$33.1 million, credit). The deferred tax credit arises from the setting up of an additional deferred tax asset of US$94.7 million, reflecting higher expected utilisation of UK tax losses in line with generally increased oil prices. As at year-end the group had an estimated US$1,112 million of carried forward UK allowances, of which it is anticipated that US$972 million will be utilised in future years based on a long-term oil price of US$75/bbl. This has resulted in recognition of a total deferred tax asset of US$278.2 million. Profit after tax is therefore a record US$129.8 million (2009: US$113.0 million) resulting in basic earnings per share of 111.9 cents (2009: US$104.1 cents).

Cash flow

Cash flow from operating activities was US$436.0 million (2009: US$347.7 million) after accounting for tax payments of US$67.9 million (2009: US$71.5 million).

Capital expenditure in 2010 totalled US$514.1 million (2009: US$303.1 million).

 
 Capital expenditure ($ 
  million)                       2010    2009 
=============================  ======  ====== 
 Fields/development projects    347.1   192.5 
 Exploration                    164.7   107.5 
 Other                            2.3     3.1 
 Total                          514.1   303.1 
=============================  ======  ======

The principal field and development projects were the Chim Sao, Gajah Baru, and Huntington projects, together with the Balmoral field infill well programme and the abandonment of the UK Shelley field.

Balance sheet position

Net debt at 31 December 2010 amounted to US$405.7 million (2009: US$315.6 million), with cash resources of US$299.7 million (2009: US$250.6 million). Cash of GBP43.3 million (US$69.2 million) previously held in an abandonment trust and classified in the balance sheet under trade and other receivables, was released from the trust in December 2010 and replaced by the equivalent sum in letters of credit.

 
 Net debt ($ million)            2010      2009 
===========================  ========  ======== 
 Cash and cash equivalents      299.7     250.6 
 Convertible bonds*           (220.4)   (213.2) 
 Other long-term debt         (485.0)   (353.0) 
 Total net debt               (405.7)   (315.6) 
===========================  ========  ========

* Convertible bonds have a nominal value of US$250 million, an equity conversion price of GBP13.56 and a final maturity date of 27 June 2014.

Following a successful refinancing in November 2010, total bank facilities amount to US$1,572 million. As at year-end, drawn borrowings were US$485 million and issued letters of credit and performance bonds were US$185 million. Undrawn facilities were therefore US$902 million, which, together with cash on hand, amounted to US$1,202 million.

Financial risk management

Commodity prices

The Board's commodity pricing and hedging policy continues to be to lock in oil and gas price floors for a proportion of expected future production at a level which ensures that investment programmes for sanctioned projects are adequately funded. Floors are purchased for cash or via collars, funded by selling caps at a ceiling price. This policy has provided sensible downside protection for the company over the period since 2008 and going forward to 2012, during which period over US$1 billion will have been invested in new development projects. The requirement for future hedging for 2013 and beyond will be considered as new projects are sanctioned, taking into account expected future cash flows of the group and the size of the relevant investment programme.

At year-end, a total of 5.0 million barrels (mmbbls) of Dated Brent oil were hedged via collars for the period to end 2012 with an average floor price of US$47/bbl and an average cap of US$87/bbl. This volume represents approximately 26 per cent of the group's expected liquids production over the period. 282,000 metric tonnes (mt) of HSFO, which drives our gas contract pricing in Singapore, was subject to collars covering the period to mid-2013. These have a cap of US$500/mt (equivalent to around US$85/bbl) and represents around 19 per cent of our expected Indonesian gas production over the same period.

During 2010, oil price collars for 3.2 mmbbls and fuel oil collars for 120,000 metric tonnes expired at a cost of US$2.7 million (2009: US$nil). In addition, forward sales of 0.4 mmbbls, transacted at the time of the Oilexco acquisition in May 2009, and a further 1.0 mmbbls sold forward in 2010, also matured, with a cash cost of US$5.4 million. No forward sales were outstanding at year-end.

Oil hedges are now incorporated within the pricing terms of physical offtake agreements, avoiding the requirement to revalue the outstanding hedges. A credit of US$18.2 million (2009: US$8.5 million) arises in respect of past mark to market provisions for oil hedges which have now expired.

Gas price hedging is still required to be marked to market as the hedges are held by counterparties independent of physical product sales. A credit of US$20.4 million (2009: US$26.9 million, charge) arises in respect of such mark to market movements, resulting in a total credit to the income statement of US$38.6 million in respect of commodity contracts (2009: US$61.1 million, charge).

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. The group recorded a loss of US$0.4 million on such short-term hedging during 2010 (2009: US$2.8 million, gain).

Interest rates

Although the group's borrowing facilities are defined in floating rate terms, substantially all current drawings effectively have been converted to fixed interest rates using the interest rate swap markets, given the very low level of fixed interest rates available relative to historical rates. On average, therefore, the cost of drawn bank funds for the year was 5.2 per cent. Mark to market movements on these interest rate swaps amounted to US$12.1 million (2009: US$0.8 million), charged 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 minimising counterparty risks.

Insurance

The group undertakes a significant insurance programme to reduce the potential impact of the physical risks associated with its exploration, development and production activities. In addition, business interruption cover is purchased for a proportion of the cash flow from producing fields.

Going concern

The group monitors its capital position and its liquidity risk regularly throughout the year to ensure that it has sufficient funds to meet forecast cash requirements. Sensitivities are run to reflect latest expectations of expenditures, forecast oil and gas prices and other negative economic scenarios in order to manage the risk of funds shortfalls or covenant breaches and to ensure the group's ability to continue as a going concern.

Despite economic volatility, the directors consider that the expected operating cash flows of the group and the headroom provided by the available borrowing facilities gives 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 2010 Annual Report and Financial Statements.

Business risks

Premier is an international business which has to face a variety of strategic, operational, financial and external risks. Under these distinct classes, the company has identified certain risks pertinent to its business including: exploration and reserve risks, loss of key human resources, drilling and operating risks, security risk in area of operations, costs and availability of materials and services, economic and sovereign risks, market risk, foreign currency risk, loss of or changes to production sharing or concession agreements, joint venture or related agreements, and volatility of future oil and gas prices.

Effective risk management is critical to achieving our strategic objectives and protecting our assets, personnel and reputation. Premier manages its risks prudently by maintaining a balanced portfolio, through compliance with the terms of its agreements and strict application of appropriate policies and procedures, and through the recruitment and retention of highly skilled individuals throughout the organisation. Further, the company has mitigated risks by focusing its activities mainly in known hydrocarbon basins in jurisdictions that have previously established long-term oil and gas ventures with foreign oil and gas companies, existing infrastructure of services and oil and gas transportation facilities, and reasonable proximity to markets.

A summary of the principal risks facing the company and the way in which these risks are mitigated is provided on the company's website (www.premier-oil.com).

CONSOLIDATED INCOME STATEMENT