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Premier Oil PLC (PMO)

  Print      Mail a friend       Annual reports

Thursday 22 March, 2012

Premier Oil PLC

Annual Results for the year ended 31 December 2011

RNS Number : 8342Z
Premier Oil PLC
22 March 2012
 



 

Annual Results for the year ended 31 December 2011

 

Premier is a leading FTSE 250 independent exploration and production company with oil and gas interests in the North Sea, South East Asia and in the Middle East, Africa and 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

·              2011 exit rate of 60 kboepd achieved, in line with guidance.  Average production for the year was 40.4 kboepd (2010: 42.8 kboepd)

·              Successful completion of operated Chim Sáo and Gajah Baru fields in the fourth quarter of 2011, with deliverability ahead of expectations

·              EnCore acquisition and assumption of Catcher operatorship achieved January 2012; Solan project receives internal sanction March 2012

·              12 out of 21 exploration and appraisal wells drilled in 2011 were successful, with notable discoveries at Burgman in the UK and at Cá Rồng Đỏ and Chim Sáo North West in Vietnam

·              Proforma proven and probable reserves increased to 296 mmboe (2010: 261 mmboe), a reserve replacement ratio of 333 per cent. Reserves and resources increased to 527 mmboe (2010: 488 mmboe)

 

Financial

·              Record profit after tax of US$171.2 million (2010: US$129.8 million)

·              Operating cash flow of US$485.9 million (2010: US$436.0 million), an increase of 11.4 per cent

·              Year-end net debt of US$744.0 million (2010: US$405.7 million), giving rise to gearing of 30 per cent (2010: 26 per cent), proforma the completed EnCore transaction (36 per cent at year-end)

·              Cash and undrawn bank facilities (including letters of credit) of US$1,116 million at year-end (2010: US$1,202 million) increased to approximately US$1,400 million following successful bank and bond market transactions in early 2012

 

Outlook

·              Production guidance of 60-65 boepd average and 75 boepd by year-end is unchanged and dependent on first oil/gas timing from the Huntington and Rochelle projects

·              Final development sanction for several projects notably Solan expected shortly. On target to reach group's goal of 100 kboepd in the medium-term from existing fully funded projects

·              Up to 20 well exploration programme planned for 2012 targeting 200 mmboe of unrisked potential; encouraging start with successes in Indonesia and Pakistan

·              Accelerated build up of prospect inventory for future drilling with new licences acquired in the UK, Norway and Kenya in 2011 and an active new venture programme going forward

 

Simon Lockett, Chief Executive, commented:

"I congratulate again our teams in Asia for successfully delivering two major operated projects during 2011. This bodes well for delivering on our future growth targets and projects. Our exploration and acquisition teams are focused on accessing further profitable growth opportunities. We are in our strongest ever financial and operational position to take advantage of such opportunities as they emerge."

 

Mike Welton, Chairman

Simon Lockett, Chief Executive

22 March 2012

 

 

 

ENQUIRIES

 

Premier Oil plc

Tel: 020 7730 1111

Simon Lockett

 

Tony Durrant

 

 

 

Pelham Bell Pottinger

Tel: 020 7861 3232

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

 

Many Western economies are in recession and the stability of the Eurozone, in particular, is under threat. As a result, 2011 was a year of depressed financial markets and challenging access to capital. Politically, dramatic changes are taking place, notably in North Africa.  The magnitude of these changes, in difficult economic circumstances, presents significant challenges. Against this background, the energy sector continues to prosper with strength in commodity prices driven by Asian growth and resilient demand elsewhere. Finding and extracting large hydrocarbon accumulations, particularly oil, in mature areas is by definition becoming more challenging. However, with technological change and through accessing unconventional resources, exemplified by the shale revolution in North America, the industry is continuing to respond to consistently strong demand for energy on a global basis.

 

Premier's achievements in 2011 demonstrate that there is a role for companies of our size. The successful completion of our two operated development projects in Asia - commercialising over 100 million barrels of oil and gas, investing some US$1.6 billion on behalf of ourselves and our partners and employing at peak over 3,500 staff and contractors - was a world-class achievement. We will look to maintain and build on those skills within Premier as we move forward with new operated development projects.

 

The new projects in Asia contributed to meeting successfully our 2011 year-end production target of 60 thousand barrels of oil equivalent per day (kboepd). Average production for 2011 was 40.4 kboepd (2010: 42.8 kboepd). In common with many other operators in the North Sea, this was adversely affected by unplanned downtime in a number of our UK North Sea fields in the early part of the year. I am pleased to report that UK production recovered well in the second half of the year, continuing into the early months of 2012.  It remains a top priority for our operations team in Aberdeen not just to maintain production levels, but to ensure the integrity of our production infrastructure as many fields in the North Sea move towards the end of their natural life.

 

Alongside proven operating and development skills, it has never been more important to maintain the balance sheet strength and liquidity to finance such projects. Our strong financial position enabled us to deliver on five acquisitions during the year, adding some 60 million barrels of reserves and resources and building on our existing presence, particularly in the North Sea. Our financial performance continues to improve and the outlook for strong growth in cash flows is robust, even at much lower oil prices than today. We continue to have good access to capital, from both the bank and bond markets, to fund future growth.

 

In exploration, we are consistently adding reserves and resources on an annual basis at an average after-tax cost of around US$5 per barrel (bbl). We are more than replacing our production. In the Natuna Sea in South East Asia and in the Central North Sea in the UK we have leading positions which, given our data and knowledge bases, we believe will translate into further successes. We are constantly reviewing new licence opportunities in existing areas and in analogous geological plays in new countries. These will be the source of future growth and potential upside for our investors.

 

As the group expands, the need for good corporate governance processes and keen attention to risk management becomes ever more critical. Consistent with external recommendations, the Board and its committees pay close attention not just to the future strategy of the company but also to Board composition and the risk identification and mitigation process, as well as performance and remuneration policies. I am grateful for the excellent advice and support received from my fellow directors during the year on all these matters.

 

As in previous years, particular attention at Board level has been given to health, safety and environmental management. The company's management systems have been successfully re-certified to OHSAS 18001 and ISO 14001 standards and key performance indicators for recordable injury frequency and high potential incidents were improved against the prior year. Nevertheless, we are constantly reminded of the need for strong processes, continuous vigilance and determination to learn lessons for the future.

 

Premier's share price dropped by 26 per cent during 2011 in a poor year for all equity markets. Following completion of the EnCore acquisition in January 2012, we have seen a significant recovery. Over the three year period to 31 December 2011, the shares have seen a growth of 80 per cent, significantly outperforming the FTSE All Share Oil and Gas Producers Index.

 

This outperformance is due to the hard work and skills of our employees, partners and suppliers. I would like to pay tribute to all of them as we look forward together to continued growth and success.

 

 

CHIEF EXECUTIVE'S REVIEW

Premier seeks to offer both our investors and our employees above average growth opportunities within business units that are themselves good quality businesses. This will be reflected in a rising production profile from our operations and development activities. We will continue to set ourselves targets - 75,000 boepd by the end of 2012 and 100,000 boepd in the medium-term - which are challenging but achievable. We expect to source further growth from a combination of acquisitions and organic exploration success.  We expect to play a growing role in the places in which we choose to do business, which in itself will generate a stream of future opportunities. Over time, we have greatly widened our access to different sources of capital so that our financial strength has become a real asset to the business.

In 2011, Premier continued to grow through acquisition, development and our own exploration activities. We have taken our skills as a development operator in South East Asia, proved them on new projects and are building up a comparable skill set in the North Sea. Our exploration programme is focused on areas where we have a spread of acreage and a deep understanding of the geology. We are better placed than ever to achieve material resource additions from our planned programmes.

 

Key milestones in achieving our growth in 2011 came from our project teams in Indonesia and Vietnam who achieved excellent results in bringing two major operated projects on-stream on a timely basis and in line with original cost projections. This was a big step forward for our Asian business. Less visibly, but just as valuable for the future, I believe we have made great strides in a number of other areas. Our geologists and geophysicists enhanced their understanding of the petroleum systems in both the Natuna Sea and the UK Central North Sea, adjacent to existing Premier discoveries, and this will be reflected in the drilling programmes established for 2012 and beyond. Our commercial teams in London and Aberdeen have made great progress on the shape, structure and schedules for new projects, especially in the North Sea. Our operations staff have worked tirelessly to ensure that asset integrity, safety and the environment are at the top of our priority list. All such efforts are critical to the overall success of the company.

 

The group is well established in the North Sea and in South East Asia. We expect that the majority of our resources, both personnel and financial, will continue to be directed at these core businesses. We have the ambition over time to develop a third geographic area of expertise, though only when the right opportunities emerge and when the skills we already have in subsurface and engineering can be successfully applied. Leading the way are our new venture teams who are already taking us into new geographies, albeit in ways which seek to address the challenges of new country entry. In 2011, for example, we obtained two new exploration licences in offshore Kenya and significantly expanded our acreage portfolio in the Norwegian sector of the North Sea. Other geographies are under review for 2012.

 

We continually look at potential acquisitions as a way of building up our knowledge of assets in our core areas, though we are in the fortunate position that our internal growth profile is already strong. Completed acquisition transactions have typically happened in times of market dislocation, which creates new opportunities. In 2009, at a low point in the oil price cycle, we completed major acquisitions in the UK and in Vietnam. In 2011, the commodity markets held up well but the capital markets, especially for smaller companies, were weak and development finance scarce. Our recent five completed acquisitions, all in the North Sea, reflected for the most part this opportunity and we are pleased to have added around 60 million barrels of oil equivalent (mmboe) of reserves and resources to the portfolio at a cost of less than US$8/bbl. We expect 2012 to be another active year in the acquisition markets as the challenging conditions, especially in the bank sector, seem destined to continue.

 

We operate in a highly competitive world where both good quality human and natural resources are scarce. We have been successful in retaining our people and in building up teams to execute new projects. Our headcount has doubled from 300 to over 600 in the last four years. Our share-based incentive package offers good upside to employees if the company performs well but also ties in our employees for up to six years before this upside is realised. In my experience people enjoy the challenges offered by a growth programme.

 

On the asset side, continuing access to good quality acreage is critical to the long-term growth of the company. We constantly review new opportunities around the world which come to us via licensing rounds, knowledge of our partners' and competitors' strategies and through strong government relationships in the areas in which we operate.

I believe that our combination of technical skills and financial strength positions us well for the future. Our operations in the Natuna Sea and in the UK Central North Sea are very well established and continue to offer opportunities for further growth. We can see a path to production of 100,000 barrels of oil equivalent per day (boepd) from existing projects in the medium-term. Our portfolio is already positioned for success beyond that with ongoing developments and an active exploration programme.

 

Average working interest production for the full-year was 40.4 kboepd (2010: 42.8 kboepd). Our North Sea business faced challenging conditions due to extended unplanned downtime on key producing assets at the Balmoral, Scott and Wytch Farm fields. However, the year-end target of 60 kboepd was achieved following the return to full production at the UK fields and the start-up of new Asian projects during the fourth quarter. Production in other areas remained steady, with strong gas demand and good production performance in both Pakistan and our existing fields in Indonesia.

 

Production (boepd)

Working interest

Entitlement

2011

2010

2011

2010

Indonesia and Vietnam

14,350

11,650

11,700

7,300

UK

10,300

15,500

10,300

15,500

Pakistan

15,100

14,900

15,100

14,900

Mauritania

650

700

550

600

Total

40,400

42,750

37,650

38,300


 

Major milestones were achieved on our operated development projects. The Chim Sáo development in Vietnam was completed and first oil production was achieved safely and on budget through the Lewek EMAS floating production, storage and offtake vessel (FPSO), with reservoir and well performance exceeding expectations. In Indonesia, the Gajah Baru development was completed with successful installation of a new central processing platform on schedule and budget. The gas export equipment was tied into the existing subsea West Natuna Transportation System pipeline to deliver gas to Singapore. On the same block the Anoa Phase 4 project, to upgrade compression facilities and increase production capacity, has been sanctioned. The project will be completed in 2013 accessing a further 200 billion cubic feet (bcf) of reserves for export.

 

Development activities continued on the Huntington field in the UK with the completion of Phase 1 of the subsea installation and drilling of one injection and three production wells. The upgrade of the Voyageur FPSO is now being progressed and the operator is expecting first oil in the fourth quarter of 2012. The East and West Rochelle subsea fields in the UK North Sea were unitised (Premier equity 15 per cent) in order to facilitate a fast track development programme via the Scott platform host production facility. The field achieved final project sanction with the Department of Energy and Climate Change (DECC) approving the field development plan (FDP) in the second half of 2011. Subsea facilities fabrication and offshore construction on the host Scott platform is progressing to schedule with first gas and condensate anticipated in the fourth quarter of 2012.

 

As at 31 December 2011 proven and probable (2P) reserves, on a working interest basis, were 284 mmboe (2010: 261 mmboe). On a proforma basis the EnCore acquisition, completed in early January 2012, increased reserves to 296 mmboe, giving a reserve replacement ratio of 333 per cent.

 


Proven and probable (2P) reserves

(mmboe)

2P reserves and 2C contingent resources

(mmboe)

Start of 2011

261

488

Production

(15)

(15)

Net additions and revisions

38

40

End of 2011

284

513

EnCore acquisition*

12

14

Proforma total

296

527

 

*  The EnCore acquisition completed in January 2012. Reserve additions exclude EnCore's interest in the Cladhan field which was sold in March 2012.

 

Upon completion of the EnCore acquisition, the percentage of liquids in total reserves increased from 35 per cent at the end of 2010 to 51 per cent. The equivalent volume of 2P reserves on an entitlement basis amounted to 263.8 mmboe (2010: 222.0 mmboe) based on a price assumption equal to the Dated Brent forward curve in 2012 and 2013 and US$75/bbl in 'real' terms thereafter (2010: fixed price of US$75/bbl).

 

Booked reserve additions were mainly due to the acquisition of EnCore (additional 15 per cent equity in Catcher area), progress with the Solan field and the additional equity acquired in Wytch Farm. Other reserves additions included exploration successes at Burgman in the UK and at Kadanwari in Pakistan. Proforma contingent resources at year-end were increased to 231 mmboe (2010: 227 mmboe).

 

 

During 2011, the Premier-operated Natuna Sea Block A sold an overall gross average of 161 billion British thermal units per day (BBtud) (2010: 160 BBtud), including rates in excess of 200 BBtud as Gajah Baru came on-stream. The Anoa facility delivered 5 per cent over its contractual market share at nearly 42 per cent. The non-operated Kakap field contributed a further 42 BBtud (gross) (2010: 54 BBtud). Gross liquids production from the Block A Anoa field increased by over a third to an average 2,400 barrels of oil per day (bopd) (2010: 1,758 bopd) with a further 3,400 bopd (2010: 2,993 bopd) from Kakap. Overall, net production from Indonesia amounted to 11,450 boepd (2010: 11,650 boepd).

 

The Gajah Baru development involved the successful installation in 2011 of a new central processing platform connected to a new wellhead platform on schedule and budget. The gas export equipment was tied into the existing subsea West Natuna Transportation System pipeline to deliver additional gas to Singapore.  During the year, five development wells were successfully completed, providing in excess of 200 BBtud of gas deliverability from this new facility.

 

Volumes from the Gajah Baru field are being supplied in accordance with the second Gas Sales Agreement (GSA2).  Good progress has also been made on a swap agreement (GSA5) under which additional volumes of Gajah Baru gas supplied to Singapore will be swapped with existing supplies from Sumatra to Singapore.  These Sumatra volumes will be re-directed to the Indonesian domestic gas market.  The relevant agreements are expected to be completed shortly and physical supplies of up to 40 BBtud (gross) should commence in the second quarter of this year.  GSA5 will replace gas previously contracted to be supplied to Batam Island, Indonesia, under GSA3 and GSA4 until at least December 2013, when GSA3 and GSA4 contracts are expected to commence.

 

On the Anoa field, workovers were performed on the A7 and A11 wells. These workovers added a further 30 million standard cubic feet per day (mmscfd) of gas deliverability. A new oil well (A22) was successfully completed which added around 1,500 bopd of incremental oil production. A three-well drilling campaign on the Anoa field's West Lobe platform has progressed well and included the discovery of new reserves in the deeper Lama reservoir below Anoa.

 

In order to upgrade the compression facilities and to increase production capacity on the producing Anoa field, a major 'brown-field' development project has been sanctioned, extending the assumed field plateau and developing some 200 bcf of gross field reserves. This project, known as Anoa Phase 4, will be completed in 2013.

 

Elsewhere on the block, tendering commenced for the engineering, procurement, construction and installation (EPCI) contract for two wellhead platforms and connecting pipelines for the development of the Pelikan and Naga fields. Final project sanction and contract award is expected in mid-2012, to provide future supply to existing Singapore and Indonesia sales contracts.

 

On the non-operated Block A in Aceh a fully termed production sharing contract (PSC), extending the licence term for 20 years, became effective from 1 September 2011.  Work continued on the gas development project in support of two firm Gas Sales Agreements (GSA).  However, the EPCI contract for the facilities will be re-tendered and first gas is now scheduled for 2015. 

 

First oil production from the Chim Sáo oil field was achieved safely and on budget in October, followed by the commencement of gas export in early December. By year-end, close to 2.0 million barrels had already been produced from six production wells. A further three production wells will be available to come on-stream in early 2012 when the four well water injection system will also commence. Further valuable opportunities have been identified in the Chim Sáo area. A well deepened into the Oligocene directly beneath the main field proved an estimated 17 metres of net hydrocarbon-bearing pay, and an additional well to be drilled in early 2012 will accelerate production from a shallow reservoir which has larger reserves than initially evaluated.

 

The CS-N2P well, a development production well for the Chim Sáo project, intersected the shallow part of a previously undrilled fault terrace to the north west of the Chim Sáo field. The well encountered a 20 metre oil column in an independent closure within good quality Upper Dua sandstones. The plan is to further appraise this new accumulation in 2012 as a near-field tie-back opportunity.

 

In December the Government of Vietnam approved the outline development plan for the Dua field and orders were placed for the equipment required to develop Dua as a tie-back to Chim Sáo. We are targeting full production from Dua in early 2014.

Our North Sea business Unit continued to grow with the acquisition of EnCore Oil plc (which held an additional 15 per cent in the Catcher area) and the purchase of an additional 17.7 per cent equity in Wytch Farm. The development portfolio has moved forward significantly with the Huntington field targeting first oil and the Rochelle area achieving project sanction for first gas during 2012. Significant concept engineering work was completed on newly acquired projects, with the Solan project achieving Premier Board sanction in March 2012.

 

Production performance in the first half of 2011 was hampered by downtime on key producing assets. These maintenance issues have been resolved and Premier is now seeing a stronger production performance from existing fields in 2012.

 

2011 production net to Premier was 10,300 boepd (2010: 15,500 boepd). Production was negatively affected by extended unplanned downtime on key producing assets. The Balmoral area fields were shut-in in the first quarter due to topside integrity issues and in mid-year due to a subsea leak. The non-operated Wytch Farm field was shut-in during January due to a flow line leak which occurred late in 2010 giving rise to a full pipeline integrity study. Production from the non-operated Scott field was restricted in the first quarter due to a fracture in the gas export line which required restricted production from high gas/oil ratio wells to comply with the gas flare consent. Production from the Balmoral area improved in the second half of 2011 as the immediate issues that affected our production performance in the first half of the year were resolved. The December 2011 B-Block production rate was significantly better at around 7,500 boepd (net to Premier) compared to the 2011 full-year average of 3,750 boepd.

 

The non-operated Kyle field contributed strong production until gale force winds in December damaged the mooring system of the host Banff FPSO production facility, forcing it 270 metres off location and causing damage to the Banff field subsea risers, umbilicals and possibly the FPSO turret. The damage is currently being assessed by the operator of Banff but it is likely that the Kyle field will be shut-in until mid-2013. Premier is currently processing insurance claims under its business interruption and property damage policies.

 

Several significant acquisitions were negotiated in 2011, the most significant of which being the purchase of EnCore Oil plc which included 15 per cent equity and operatorship of the Catcher area. Premier now owns 50 per cent of the Catcher area and is therefore in a strong position to progress the development of the Catcher area's discovered resources towards first oil in 2015. Development studies are well under way and a decision on the conceptual design is targeted for the first half of 2012. In addition to Catcher, Premier acquired additional licences via the EnCore acquisition including the Cladhan discovery and the Coaster prospect. Premier agreed to sell its newly acquired 16.6 per cent equity interest in Cladhan for US$54 million and farm down 50 per cent of the acquired 100 per cent equity in the Coaster prospect on a promoted basis. The sale of Cladhan was completed in March 2012.

 

Acquisition of an additional 17.7 per cent equity in the Wytch Farm producing asset was completed in late December at a final cost of US$90 million, increasing Premier's equity to 30.1 per cent of remaining reserves and adding approximately 2,500 boepd of net production.

 

A new pre-development asset was acquired by the purchase of a 60 per cent equity in the Solan field (P164, Block 205/26a) which is located west of Shetland. Premier was appointed as development operator in January 2012. The upfront acquisition cost was US$10 million with Premier providing a carry and financing package to the prior owner during the development phase. The Solan project received internal Premier approval in March 2012 and is expected to receive DECC development sanction approvals shortly.  The field is expected to produce around 42 million barrels following first oil in 2014 with capital expenditure of around US$850 million.

 

Premier also exercised an option to become the operator of the Fyne field with a 39.9 per cent equity stake, in return for providing a carry through ongoing exploration and appraisal work. The results of the nearby Erne discovery well, drilled in the fourth quarter of 2011, and the East Fyne appraisal well, completed in 2012, are currently being evaluated by the joint venture partners. However, at this stage, potential developments in the Greater Fyne area do not meet the company's economic thresholds.

 

Significant progress was achieved on other development assets. The Phase 1 subsea installation for the Huntington field has been successfully completed and one injection and three production wells have been drilled with production rates testing at over 10,000 bopd per well. Earlier schedule slippage on the Voyageur FPSO was addressed by a change in ownership of the vessel. The FPSO upgrade is now progressing in Norway and the operator is expecting first oil during the fourth quarter.

 

The East and West Rochelle subsea fields were unitised (Premier equity 15 per cent) to facilitate the fast track Rochelle development programme via the Scott platform host production facility. A processing tariff was agreed with the Scott owners and initial Rochelle modifications were made to the Scott topside facility during the year. The development programme has made good progress towards first gas from Rochelle in November 2012. The subsea fabrication work is on schedule and drilling rigs have been contracted to drill the Rochelle development wells this summer.

 

The Caledonia field redevelopment project, close to the Balmoral area, made progress during 2011 and is now part of a project to bring fuel gas to Balmoral. Project sanction is expected later in 2012 for first oil and gas in 2014.

 

 

Progress has been made on the Bream development during 2011. After engineering evaluation of a number of different alternatives, the selected development concept is an FPSO and subsea wells with artificial lift. A specific FPSO has been identified and front end engineering studies are being conducted for both this vessel and the associated subsea systems and wells. A project sanction decision will be taken after the engineering studies and FPSO contract negotiations are completed in the second quarter of 2012. A licence extension until February 2013 has been granted. The first oil date for the field would be late 2015.

 

The Frøy project made a technical concept selection in the first quarter of 2011. However, the operator decided not to continue the project in its current form for strategic reasons. Further work has been completed during the year on a potential area development, which would take resources from a number of fields within a 10-20km distance to a central processing hub.

 

 

Natural decline in gas production in Pakistan was more than offset by ongoing infield development, exploration successes and compression upgrades. Oil production in Mauritania also remained stable. While the focus has been on enhancing the value of our Pakistan producing assets, we continue to build our exploration portfolio elsewhere in the region.

 

Average net to Premier production in Pakistan during 2011 was 15,100 boepd, marginally higher than in 2010 (14,900 boepd).

 

Net to Premier, the Qadirpur field averaged 3,750 boepd (2010: 3,550 boepd). The increased production was the result of the wellhead compression project coming on-stream at the end of 2010. Work is in progress for the installation of two front end compressors by September 2012 in order to maintain production levels. The development extended reach wells (ERW) QP-42 and QP-43 have been successfully drilled, completed and tied-in to production during 2011, while drilling of QP-44 (also ERW) is in progress. Two centrifugal compressors for the compression and re-cycling of permeate gas (a side stream) were commissioned in July and October 2011. This has minimised the flaring of permeate gas and resulted in a corresponding increase of sales gas (25-30 mmscfd, gross).

 

Average production net to Premier from the Kadanwari field was 2,050 boepd (2010: 1,750 boepd) and included increased contributions from successful exploration and development wells.

 

The Zamzama field averaged 5,800 boepd net to Premier (2010: 6,050 boepd). The decrease in production was primarily due to natural decline. Front end compression was commissioned in July. Sub-surface studies were conducted during the year, following which two infill wells (Zam‑8 and Zam‑9) are now planned to be drilled in the second half of 2012, while an additional infill well (Zam-10) is under consideration for drilling in the first quarter of 2013.

 

The Bhit/Badhra fields produced 3,500 boepd net to Premier (2010: 3,550 boepd). The slight decrease in production was because the field's annual maintenance programme, originally scheduled to be carried out in the second half of 2010, was deferred to April 2011. The Bhit-13 development well was successfully drilled and completed in the second half of 2011 and was tied-in to facilities in January 2012. The installation and commissioning of a wellhead compressor at Badhra gas field was successfully completed at the end of 2011.

 

In Mauritania, 2011 working interest production from the Chinguetti field averaged 650 bopd (2010: 700 bopd) with the decline rate continuing to be lower than expected.

 

Negotiations between the government and the joint venture partners have been completed for extensions to PSC A and PSC B.  Their respective exploration areas have been merged into a new PSC, C-10, in which Premier holds a 6.23 per cent working interest.  The undeveloped discoveries (Banda, Tiof and Tevet) in PSC A and PSC B will continue to be held by joint venture partners for up to 18 months while development studies are undertaken.  Potential gas sales arrangements for Banda are currently under discussion.

 

 

 

In 2011, Premier participated in 21 exploration and appraisal wells, of which 12 were successful, an overall success rate of 57 per cent. The most notable successes were in the UK Central North Sea and the Nam Con Son Basin in Vietnam. In Vietnam, the 2009 Cá Rồng Đỏ discovery in Block 07/03 was successfully appraised with oil, gas and condensate being encountered. The gas and condensate was found in a deeper reservoir sequence than the oil and this opens up a new play fairway within Premier's acreage in the Nam Con Son Basin. In the UK Central North Sea the discovery at Burgman continued the successful exploration drilling on the Catcher licence, UK Block 28/9.

 

Premier also explores for near-field resources capable of being tied back to its existing infrastructure. In Pakistan, three near field exploration wells encountered gas in untested fault block compartments within the Kadanwari field area and, in Vietnam, oil was discovered in a previously untested trap immediately north west of the Chim Sáofield on Block 12W.

 

Premier continues to apply the most advanced seismic interpretation techniques in maturing its lead and prospect inventory to drillable status and, in 2011, acquired new 3D seismic data in the Catcher licence and surrounding acreage.  On non-operated acreage, a new 3D survey was acquired in Norway in the Blåbaer licence, and 2D and 3D seismic data was acquired in Kenya.

 

2011 was a significant year for new acreage capture with a total of 25 licences being secured by year-end, amounting to a net acreage gain of 3,885km2. A total of 12 licences were acquired in the UK Central North Sea and two in Ireland, in the Celtic Sea, via the EnCore acquisition. In addition, four new blocks were offered for award through EnCore as part of the deferred 26th Round awards in early January 2012 - three of these are in the Central North Sea and one is in the Solent. 

 

In Norway, Premier acquired two new blocks in February 2011 as a result of the 2010 APA awards. In the latter half of 2011, three licences in the Norwegian portion of the Central North Sea were acquired from Nexen for a cost of US$5.5 million. Early in 2012, Premier was also awarded equity in four new licences via the 2011 APA Licence Round, three licences in the North Sea and one offshore mid-Norway. All acreage awards in Norway were acquired on a drill or drop option basis and the target is to deliver prospects from this new portfolio for drilling in the 2013/2014 time frame.

 

In Mauritania, the exploration PSC extension was signed and ratified in 2011, resulting in a new PSC. The new PSC, in which Premier holds a 6.23 per cent equity interest, has a gross area of 10,725km2. The plan is to drill the first of two exploration wells on this new PSC in the latter half of 2012.

 

Additional acreage was secured in East Africa via Premier's entry into two new PSCs, offshore Kenya. Offshore East Africa was an industry focus in 2011 with the discovery of significant resources offshore Mozambique and Tanzania. Premier's acreage offers the potential to extend these successful plays northwards into offshore Kenya.

Premier plans to drill between 15 and 20 exploration and appraisal wells in 2012, including a further exploration well on the UK Catcher Block and two wells, Coaster and Spaniards, on acreage acquired through the EnCore acquisition. In Norway, the Luno II well is planned for the fourth quarter and, in Asia, the appraisal of the north west Chim Sáodiscovery will take place, as well as four exploration wells in Indonesia.

 

On the Premier-operated Tuna PSC, exploration wells Gajah Laut Utara and Belut Laut were drilled to test the Miocene and Oligocene potential of two prospects on the block.  Gajah Laut Utara spudded in May 2011 and was followed by Belut Laut which spudded in July. Both wells encountered good oil and gas shows in the Oligocene section, proving the existence of a working petroleum system in both of these previously undrilled sub-basins.  Post-well studies will continue into 2012 with further drilling in the Nam Con Son Basin planned after integration of the 2011 results.

 

On Natuna Sea Block A, a block-wide prospect inventory review was carried out to characterise the remaining exploration potential on the block. Two exploration wells, Anoa Deep (WL-5X) and Biawak Besar, were scheduled for drilling in early 2012. In February 2012, it was announced that the Anoa Deep well had successfully encountered some 300 feet of fractured Lama Formation sandstone, which tested gas at a rate of 17 mmscfd from a 112 feet interval.

 

In North Sumatra, preparations are at an advanced stage for the drilling of the Matang-1 exploration well during 2012 on Block A Aceh.

 

Planning and preparation has continued on the non-operated Buton Block, for the drilling of the Benteng-1 exploration well, which is now scheduled to drill in the first half of 2012.

Following the exploration discovery at Cá Rồng Đỏ (CRD) in Block 07/03, Premier drilled and tested the CRD-2X appraisal well into the Oligocene sands that had not been tested by the discovery well. Drill stem tests of the hydrocarbon bearing sands in the Oligocene section flowed gas and condensate at potentially commercial rates, and the well was then side-tracked to provide further data on the distribution of hydrocarbons in the Miocene sands. Evaluation of the CRD discovery and the surrounding exploration acreage continued throughout the year.

 

The high risk Qua Mit Vang well, drilled in Block 104-109/05, was plugged and abandoned after flowing gas with 99 per cent carbon dioxide from fractured basement rock, with well costs substantially carried via a farminee.

 

In Block 12W, two development wells drilled into a fault terrace to the north west of the Chim Sáo field proved the presence of oil in this previously undrilled area, encountering columns of 15 and 89 metres of oil bearing sands within good quality Upper Dua sandstones. A dedicated appraisal well will be drilled into this discovery in 2012.

Premier continued its success in the Catcher area licence P1430, Block 28/9 with discoveries at Burgman and Catcher North in 2011, both of which will contribute to a Catcher area development plan. The joint venture also acquired 455km2 3D seismic data across Block 28/9 and 190km2 3D data on the surrounding open acreage.

 

Premier became operator of Central Fyne in May 2011 with a 39.9 per cent equity interest by exercising a farm-in option to drill the East Fyne well in licence P077, Block 21/28a. Premier also agreed to participate in the Erne exploration well in nearby licence P1875, Block 21/29d. The Erne well was drilled in December and was suspended as a potential tie-back to any future developments in the Greater Fyne area. Subsequent to year-end, the East Fyne appraisal well was also drilled. Despite encountering oil and gas-bearing sands, the well was plugged and abandoned. The results of the wells are currently being incorporated into the plans for the Greater Fyne area by the partnership group.

 

The Bluebell prospect on P1466, Block 15/24c, was farmed down from a Premier 100 per cent equity position to a farminee who funded 67.67 per cent of the well cost in return for a 40 per cent interest. Post year-end, it was announced that the Palaeocene target encountered excellent sand quality but was water wet.

 

During the year, two wells were drilled on the PL378 licence which contains the 2009 Grosbeak discovery. The first well, an exploration well on the Gnatcatcher prospect, was dry. The second well, an appraisal on the Grosbeak discovery, delivered mixed results. The primary bore was on prognosis and confirmed the oil water contact seen in the discovery well. The subsequent side-track came in deep with the target sands penetrated below the contact. The partnership is now focusing on commercialising Grosbeak, together with other discoveries in the nearby area.

 

Premier drilled an operated exploration well on the southern segment of the Gardrofa prospect in licence PL406 in the third quarter of 2011. The well was plugged and abandoned as a dry hole.

 

Premier made good progress in building its portfolio in 2011, with significant new acreage awards and acquisition. Premier was awarded two licences early in the year from the 2010 APA Licence Round: one, operated in the Central North Sea (PL567), on which the work programme comprises seismic reprocessing; and the second, PL378B, as protection acreage to the PL378 Grosbeak licence. Further additions were captured in the third quarter when a transaction to acquire three operated exploration blocks in the North Sea was agreed with Nexen. Two of these blocks, PL539 and PL566S are close to PL567.

 

An application was submitted for four blocks in the 2011 APA Licence Round and, in January 2012, the Ministry notified that this had been successful, with four new licences being offered for award. Three of these licences are in the Central North Sea and one is in mid-Norway.

 

 

 

Three exploration wells (K-25 Dir-A, K-27, and K-28) were drilled in 2011 in the Kadanwari Lease. The Kadanwari K-25 Dir-A well tested 4 mmscfd but, due to tight reservoir conditions, the decision on whether to tie-in this well for production is still pending. However, both K-27 and K-28 exploration wells tested at high flow rates (up to 50 mmscfd in K-27; and approximately 30 mmscfd in K-28). The K-27 well was tied-in to the system in early March 2012 and is expected to add around 8 bcf of reserves, net to Premier. The K-28 well, together with the K-30 well which was successfully drilled in early 2012, will be tied in by mid-year 2012 to produce at maximum available plant capacity.

 

The award of the South Darag Block in the Gulf of Suez is awaiting formal government ratification having been delayed by the Egyptian parliamentary election process.

 

Premier farmed into the non-operated North Red Sea Block 1 in December 2010, taking a 20 per cent interest.  The NRS-2 (Cherry) exploration well was drilled to a target depth of 5,200 metres.  The well encountered hydrocarbon shows whilst drilling, but failed to intersect reservoir quality sandstones.  Geological studies are continuing to assess further prospectivity on the block.

 

In May 2011, Premier made an entry into Kenya with the signing of two PSCs for offshore exploration blocks L10A and L10B.  A 3D seismic data acquisition programme was completed ahead of schedule at year-end and a 2D programme was completed on 15 January 2012. Processing and interpretation will take place in 2012 with exploration drilling provisionally scheduled for 2013.

 

Premier's exploration rights in the Daora, Haouza, Mahbes and Mijek blocks in the Saharawi Arab Democratic Republic (SADR) remain under force majeure while awaiting resolution of sovereignty under a United Nations mandated process. Premier extended its acreage position in the SADR by gaining the Laguara Block as part of the EnCore acquisition.

 

FINANCIAL REVIEW

 

Economic and business background

Oil prices further strengthened during 2011 due to supply concerns and the volatile political situation in the Middle East. Brent crude prices averaged US$111.3/bbl for the year, against US$79.5/bbl in 2010. Premier's portfolio of crudes sells at an average of US$1.5/bbl premium to Brent. Given the timing of our crude oil liftings, average actual realisations (pre-hedge) for the year were US$111.9/bbl (2010: US$79.7/bbl). After taking into account the effect of long-term hedging contracts, the average oil price realised for 2011 was US$89.6/bbl (2010: US$78.3/bbl).

 

In Indonesia, 2011 has seen continuing good production performance from Natuna Sea Block A coupled with strong demand for gas from Singapore. Under the first Gas Sales Agreement (GSA1), out of a total Singapore demand of 364 BBtud (2010: 355 BBtud), gross sales from the Anoa field for the year averaged 152 BBtud, a share of approximately 42 per cent of deliveries against a contractual share of 36.9 per cent. In October, gas production commenced from the Gajah Baru field. Under the second Gas Sales Agreement (GSA2), volumes at Gajah Baru are continuing to increase with current production rates of around 60-90 BBtud (gross).

 

In Vietnam, first oil from the Chim Sáo field was achieved in October 2011 with gas exports commencing in December. Reservoir and well performance has exceeded expectations, though some topside and marine system facility issues remain to be resolved. Excellent pricing has been achieved for oil cargoes sold in 2011, averaging in excess of US$5.50/bbl over Brent prices.

 

In the UK, production from the Balmoral area improved in the second half of 2011, as the immediate issues that affected our production performance in the first half of the year were resolved. A good production result was achieved from the Scott area and Kyle fields.

 

In Pakistan, natural gas is a critical component of the country's energy needs, meeting around 47 per cent of total energy requirements.  Total domestic gas production has remained at around 4 bcf per day, with demand continuing to grow at around 10 per cent per annum due to population growth and usage of natural gas as vehicle fuel. This has created an increased shortfall of gas resulting in supply shortages in the country. With significant gas reserves remaining, we are well placed to maintain or increase production through front-end compression projects and new development drilling.

 

 

Income statement

Production in 2011, on a working interest basis, averaged 40.4 kboepd (2010: 42.8 kboepd). On an entitlement basis, which under the terms of our PSCs allows for additional government take at higher oil prices, production was 37.7 kboepd (2010: 38.3 kboepd). Working interest gas production averaged 153 mmscfd (2010: 156 mmscfd) during the year, or approximately 65 per cent of total production. Average gas prices for the group were US$8.51 per thousand standard cubic feet (mscf) (2010: US$6.26/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$19.5/mscf (2010: US$13.9/mscf) for the year. Average gas prices for Pakistan were US$3.8/mscf (2010: US$3.5/mscf).

 

Total sales revenue from all operations reached a new record level of US$826.8 million (2010: US$763.6 million) driven by higher commodity prices. Cost of sales was lower by US$115.6 million at US$414.9 million (2010: US$530.5 million) mainly reflecting a US$25.9 million impairment reversal against a US$65.3 million charge in 2010, due principally to the sustained high oil price environment, which necessitated an increase in the base price assumption used for the valuation of future cash flows. Unit operating costs were US$15.9 per barrel of oil equivalent (boe) (2010: US$13.9/boe) reflecting higher unit costs in the UK, as production levels declined, and the inclusion of Vietnam operating costs in the last quarter.

 

Underlying unit amortisation (excluding impairment) rose to US$13.8/boe (2010: US$12.6/boe) largely as a result of the addition of Chim Sáo field production in Vietnam.

 

Exploration expense and pre-licence exploration costs amounted to US$187.5 million (2010: US$68.2 million) and US$23.0 million (2010: US$18.9 million) respectively. This includes the write-off of the following exploration wells: Gardrofa and Gnatcatcher in Norway; Cherry in Egypt; Qua Mit Vang in Vietnam; and Gajah Laut Utara and Belut Laut in Indonesia. The decision was also taken to write-off US$31.7 million of costs in relation to the Fyne area, since at this stage potential developments in the Greater Fyne area do not meet the company's project development metrics.

 

Net administrative costs were US$25.8 million (2010: US$18.3 million), with the increase mainly due to transaction costs incurred to acquire EnCore Oil plc.

 

Operating profits were US$175.6 million (2010: US$127.7 million). Finance costs and other charges, net of interest revenue and other gains, were US$68.1 million (2010: US$65.5 million), reflecting lower levels of interest income and increased gross debt levels offset by higher capitalisation of borrowing costs for our development projects in Asia and the UK. The charge arising due to the unwinding of the discounted decommissioning provision increased to US$28.3 million (2010: US$16.2 million) reflecting increased provisions and a higher discount rate.

 

Pre-tax profits of US$141.5 million (2010: US$100.8 million) also reflect a positive adjustment of US$34.0 million in respect of the group's commodity hedge portfolio (2010: US$38.6 million). This was driven by the unwinding of prior year provisions in respect of our oil and gas hedges.

 

The current tax charge for 2011 is US$77.3 million, an effective tax rate of 44 per cent of operating profits. Additionally, US$72.1 million has been provided for potential additional tax charges in Indonesia and Pakistan over fiscal disputes relating to prior years. These disputes are subject to clarification between the host governments and the oil and gas industry.  These charges are offset by a deferred tax credit of US$177.0 million, resulting in a net tax credit of US$29.7 million (2010: US$29.0 million). The deferred tax credit arises mainly in the UK and includes the impact of a 12 per cent increase in supplementary corporation tax for the industry and the availability of Ring Fence Expenditure Supplement (RFES) allowances. In addition, a deferred tax asset of US$87.0 million was recognised. This relates to US$140 million of previously unbooked UK corporation tax allowances which, following the group's acquisition of additional fields in the UK, are now expected to be fully utilised. At year-end the group had an estimated US$1.36 billion of carried forward UK corporation tax allowances which will be utilised against UK ring fence profits over time.

 

Profit after tax is a record US$171.2 million (2010: US$129.8 million) resulting in basic earnings per share of 36.6 cents (2010 restated: 28.0 cents).

 

Cash flow

Cash flow from operating activities was US$485.9 million (2010: US$436.0 million) after accounting for tax payments of US$44.0 million (2010: US$67.9 million).

 

Capital expenditure in 2011 totalled US$660.5 million (2010: US$514.1 million).

 

Capital expenditure ($ million)

2011

2010

Fields/development projects

428.1

347.1

Exploration and evaluation

228.2

164.7

Other

4.2

2.3

Total

660.5

514.1

 

The principal fields and development projects were Chim Sáo, Gajah Baru, Huntington and Rochelle, together with drilling and compression projects in Pakistan. 

 

Exploration and evaluation spend includes costs relating to the Solan, Fyne and Nexen Norway assets which were categorised as pre-development assets at the time of acquisition.

 

Acquisitions

In December, Premier completed the acquisition of an additional 17.715 per cent interest in Wytch Farm for an adjusted consideration of US$89.9 million, taking its total interest to 30.1 per cent.

 

The acquisition of EnCore Oil plc was approved by its shareholders in December and subsequently sanctioned by the court in January 2012. Shareholders representing 93.5 per cent of EnCore's shares elected to take new Premier shares, which began trading in January 2012. Total consideration of US$407.6 million was therefore satisfied by the issuance of 60.9 million new Premier shares and the payment of £14.1 million (US$21.6 million) in cash. As a result of the acquisition, Premier has increased its stake in the Catcher project from 35 per cent to 50 per cent and has assumed operatorship. This acquisition will be accounted for in the group's 2012 financial statements.

 

Balance sheet position

Net debt at 31 December 2011 amounted to US$744.0 million (2010: US$405.7 million), with cash resources of US$309.1 million (2010: US$299.7 million).

 

Net debt ($ million)

2011

2010

Cash and cash equivalents

309.1

299.7

Convertible bonds*

(228.2)

(220.4)

Other debt*

(824.9)

(485.0)

Total net debt

(744.0)

(405.7)

 

*          Convertible bonds have a nominal value of US$250 million, an equity conversion price of £3.39 and a final maturity date of 27 June 2014. Other debt includes €75.0 million of long-term senior notes, which are valued at year-end US$1.296:€ spot rate. However these will be redeemed at US$1.423:€ due to a cross currency swap arrangement.

 

In June 2011, the company issued seven and 10 year senior notes of US$244.0 million and €75.0 million in the private placement market. Total debt facilities therefore increased to US$2,184.9 million (2010: US$1,572 million). As at year-end, drawn borrowings were US$1,053.1 million and issued letters of credit were US$324.7 million. Undrawn facilities were therefore US$807.1 million, which, together with cash in hand, provided available cash funding and letter of credit capacity of US$1,116.2 million.

 

Subsequent to year-end, additional bank facilities of US$350 million were negotiated and a second issue of senior notes was completed.  This second issue, with maturities of seven, 10 and 12 years, amounted to US$202 million and €25.0 million.  A US$175 million term loan has been repaid during March 2012, leaving cash and undrawn facilities of approximately US$1.4 billion.

 

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 into 2012, during which time 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 operating cash flows of the group and the size of the relevant investment programme.

 

At year-end, a total of 1.8 million barrels of Dated Brent oil were hedged via collars for the period to end 2012 with an average floor price of US$40/bbl and an average cap of US$100/bbl. In addition 2.1 million barrels of Dated Brent oil were hedged through forward sales for 2012 at an average price of 105.3/bbl. This volume represents approximately 32 per cent of the group's expected liquids working interest production over the period. 162,000 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 132,000 mt have been sold under monthly forward sales contracts for 2012 at an average price of US$622/mt.  These two hedges cover approximately 28 per cent of our expected Indonesian gas working interest production for 2012.

 

During 2011, embedded oil price collars for 3.2 million barrels and fuel oil collars for 120,000 mt expired at a cost of US$119.1 million (2010: US$8.1 million, including forward sales cost) which has been offset against sales revenue.

 

Oil hedge collars are incorporated within the pricing terms of physical offtake agreements, avoiding the requirement to revalue them. A credit of US$28.0 million (2010: US$18.2 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$6.0 million (2010: US$20.4 million) arises in respect of such mark to market movements, resulting in a total credit to the income statement of US$34.0 million in respect of commodity contracts (2010: US$38.6 million).

 

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 loss of US$0.4 million on such short-term hedging (2010: US$0.4 million). In 2011, the group also issued €75.0 million long-term senior loan notes which have been hedged under a cross currency swap in US dollars at a fixed rate of US$1.423:€.

 

Although the group's borrowing facilities are defined in floating rate terms, substantially all current drawings have effectively 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 5.2 per cent. Mark to market movements on these interest rate swaps amounted to US$6.4 million (2010: US$12.1 million), which was 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 spreading counterparty risks.

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 for a maximum period of 18 months.  Due to exceptionally bad weather in December, the Banff FPSO - which handles Kyle production - lost its anchors and the risers were damaged severely. As a result, the Banff FPSO has been removed from its location while repairs are assessed. It is currently unlikely that production from the Kyle field will recommence in 2012 and a claim for business interruption insurance is being processed.

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

 

Despite economic volatility, the directors consider that the expected operating cash flows of the group and the headroom provided by the available borrowing facilities give them confidence that the group has adequate resources to continue as a going concern. As a result, they continue to adopt the going concern basis in preparing the 2011 Annual Report and Financial Statements.

 

Premier's business may be impacted by various risks leading to failure to achieve strategic targets for growth, loss of financial standing, cash flow and earnings, and reputation. Not all of these risks are wholly within the company's control and the company may be affected by risks which are not yet manifest or reasonably foreseeable.

 

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

 

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

 

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

 

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

 

 

CONSOLIDATED INCOME STATEMENT

For the year ended 31 December 2011

 


2011

2010


$ million

$ million

Sales revenues

826.8

763.6

Cost of sales

(414.9)

(530.5)

Exploration expense

(187.5)

(68.2)

Pre-licence exploration costs

(23.0)

(18.9)

General and administration costs

(25.8)

(18.3)

Operating profit

175.6

127.7

Interest revenue, finance and other gains

5.5

2.5

Finance costs and other finance expenses

(73.6)

(68.0)

Gain on derivative financial instruments

34.0

38.6

Profit before tax

141.5

100.8

Tax

29.7

29.0

Profit after tax

171.2

129.8

Earnings per share (cents):



Basic

36.6

28.0

Diluted

31.5

25.8

 

The results relate entirely to continuing operations.

 

 

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

For the year ended 31 December 2011

 


2011

2010


$ million

$ million

Profit for the year

171.2

129.8

Cash flow hedges on commodity swaps*:



      Losses arising during the period

(24.5)

(2.2)

      Less: reclassification adjustments for losses in the period

17.8

-


(6.7)

(2.2)

Cash flow hedges on interest rate and foreign exchange swaps*

(6.5)

(12.1)

Exchange differences on translation of foreign operations

(3.4)

(1.9)

Actuarial gains on long-term employee benefit plans

1.4

0.6

Other comprehensive expense

(15.2)

(15.6)

Total comprehensive income for the year

156.0

114.2

 

 

*

No deferred tax asset has been recognised on the losses arising on cash flow hedges in either the current or preceding year as insufficient non-ring fence taxable profits are expected to arise in the future against which the deferred tax asset could reverse.

 

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

 

 

CONSOLIDATED BALANCE SHEET

As at 31 December 2011

 


2011

2010


$ million

$ million

Non-current assets:



Intangible exploration and evaluation assets

315.5

310.8

Property, plant and equipment

2,257.8

1,732.8

Deferred tax assets

500.8

285.3


3,074.1

2,328.9

Current assets:



Inventories

27.7

18.6

Trade and other receivables

389.9

245.5

Tax recoverable

39.5

67.5

Derivative financial instruments

49.1

65.7

Cash and cash equivalents

309.1

299.7


815.3

697.0

Total assets

3,889.4

3,025.9

Current liabilities:



Trade and other payables

(381.2)

(314.0)

Current tax payable

(146.5)

(56.4)

Short-term borrowings

(183.7)

-

Provisions

(35.1)

(23.7)

Derivative financial instruments

(154.8)

(109.1)

Deferred revenue

(8.4)

-


(909.7)

(503.2)

Net current (liabilities)/assets

(94.4)

193.8

Non-current liabilities:



Convertible bonds

(226.5)

(218.1)

Other long-term debt

(626.5)

(466.4)

Deferred tax liabilities

(219.1)

(183.7)

Long-term provisions

(565.4)

(473.2)

Long-term employee benefit plan deficit

(18.6)

(15.2)

Deferred revenue

-

(35.9)


(1,656.1)

(1,392.5)

Total liabilities

(2,565.8)

(1,895.7)

Net assets

1,323.6

1,130.2

Equity and reserves:



Share capital

98.8

98.3

Share premium account

274.5

254.8

Retained earnings

922.9

738.7

Other reserves

27.4

38.4


1,323.6

1,130.2

 



 

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

For the year ended 31 December 2011

 





Other reserves



Share capital

Share premium account

Retained earnings

Capital redemption reserve

Translation reserves

Equity reserve

Total


$ million

$ million

$ million

$ million

$ million

$ million

$ million

At 1 January 2010

97.0

223.7

603.2

4.3

7.1

36.0

971.3

Issue of Ordinary Shares

1.3

31.1

(32.1)

-

-

-

0.3

Net purchase of ESOP Trust shares

-

-

(8.3)

-

-

-

(8.3)

Provision for share-based payments

-

-

52.7

-

-

-

52.7

Transfer between reserves*

-

-

7.1

-

-

(7.1)

-

Total comprehensive income

-

-

116.1

-

(1.9)

-

114.2

At 31 December 2010

98.3

254.8

738.7

4.3

5.2

28.9

1,130.2

Issue of Ordinary Shares

0.5

19.7

(20.0)

-

-

-

0.2

Net sale of ESOP Trust shares

-

-

2.6

-

-

-

2.6

Provision for share-based payments

-

-

34.6

-

-

-

34.6

Transfer between reserves*

-

-

7.6

-

-

(7.6)

-

Total comprehensive income

-

-

159.4

-

(3.4)

-

156.0

At 31 December 2011

98.8

274.5

922.9

4.3

1.8

21.3

1,323.6

 

 

*

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 2011

 


2011

2010


$ million

$ million

Net cash from operating activities

485.9

436.0

Investing activities:



Capital expenditure

(660.5)

(514.1)

Pre-licence exploration costs

(23.0)

(18.9)

Acquisition of oil and gas properties

(89.9)

(7.4)

Proceeds from disposal of oil and gas properties

-

20.4

Recovery of cash previously held in a decommissioning trust

-

69.2

Net cash used in investing activities

(773.4)

(450.8)

Financing activities:



Proceeds from issuance of Ordinary Shares

0.2

0.3

Net sale/(purchase) of ESOP Trust shares

2.6

(8.3)

Proceeds from drawdown of long-term bank loans

33.8

310.0

Proceeds from issuance of senior loan notes

350.7

-

Debt arrangement fees

(2.5)

(17.9)

Repayment of long-term bank loans

(35.1)

(178.0)

Interest paid

(54.6)

(40.9)

Net cash from financing activities

295.1

65.2

Currency translation differences relating to cash and cash equivalents

1.8

(1.3)

Net increase in cash and cash equivalents

9.4

49.1

Cash and cash equivalents at the beginning of the year

299.7

250.6

Cash and cash equivalents at the end of the year

309.1

299.7

 

 

 

NOTES TO THE PRELIMINARY FINANCIAL STATEMENTS

For the year ended 31 December 2011

 

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 21 March 2012.

 

The financial information for the year ended 31 December 2011 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 2010 were approved by the Board of Directors on 23 March 2011 and delivered to the Registrar of Companies and those for 2011 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 2012.

 

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 responsibility for the group's activities in Africa was transferred from the former North Sea and West Africa business unit to the Middle East-Pakistan business unit. The segmental information for the comparative year contained within this announcement 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 2010, as described in those annual financial statements. A number of amendments to existing standards and interpretations were applicable from 1 January 2011. The adoption of these amendments did not have a material impact on the group's financial statements for the year ended 31 December 2011.

 

 

2   Operating segments

 

The group's operations are located and managed in three regional business units - North Sea, Asia and Middle East, Africa and Pakistan.  These geographical segments are the basis on which the group reports its segmental information.

 


2011

2010


$ million

$ million

Revenue:



North Sea

253.8

425.4

Asia

421.4

195.7

Middle East, Africa and Pakistan

151.6

142.5

Total group sales revenue

826.8

763.6

Interest and other finance revenue

2.0

2.5

Total group revenue

828.8

766.1

Group operating profit/(loss):



North Sea

(47.9)

(17.4)

Asia

201.1

107.9

Middle East, Africa and Pakistan

62.5

69.0

Unallocated*

(40.1)

(31.8)

Group operating profit

175.6

127.7

Interest revenue, finance and other gains

5.5

2.5

Finance costs and other finance expenses

(73.6)

(68.0)

Gain on derivative financial instruments

34.0

38.6

Profit before tax

141.5

100.8

Tax

29.7

29.0

Profit after tax

171.2

129.8

Balance sheet



Segment assets:



North Sea

1,945.1

1,345.1

Asia

1,439.5

1,142.1

Middle East, Africa and Pakistan

146.6

173.4

Unallocated*

358.2

365.3

Total assets

3,889.4

3,025.9

Liabilities:



North Sea

(775.5)

(584.4)

Asia

(482.4)

(355.5)

Middle East, Africa and Pakistan

(108.9)

(126.7)

Unallocated*

(1,199.0)

(829.1)

Total liabilities

(2,565.8)

(1,895.7)

 

 

 


2011

2010


$ million

$ million

Other information



Capital additions and acquisitions:



North Sea

516.1

352.1

Asia

339.9

352.0

Middle East, Africa and Pakistan

41.6

55.0

Total capital additions and acquisitions

897.6

759.1

Depreciation, depletion, amortisation and impairment:



North Sea

93.3

213.2

Asia

70.6

31.2

Middle East, Africa and Pakistan

16.2

19.2

Total depreciation, depletion, amortisation and impairment

180.1

263.6

 

*

Unallocated expenditure, assets and liabilities include amounts of a corporate nature and not specifically attributable to a geographical segment. These items include corporate general and administration costs, pre-licence exploration costs, cash and cash equivalents, mark to market valuations of commodity contracts and interest rate swaps, convertible bonds and other short-term and long-term debt.

 

 

 

3   Cost of sales

 


2011

2010


$ million

$ million

Operating costs

235.2

217.1

Stock overlift/underlift movement

(22.8)

35.6

Royalties

22.4

14.2

Amortisation and depreciation of property, plant and equipment:



Oil and gas properties

203.2

196.0

Other fixed assets

2.8

2.3

Impairment (reversal)/charge on oil and gas properties

(25.9)

65.3


414.9

530.5

 

 

4   Tax

 


2011

2010


$ million

$ million

Current tax:



UK corporation tax on profits

-

-

UK petroleum revenue tax

17.2

25.9

Overseas tax

60.1

56.9

Adjustments in respect of prior years*

70.0

(21.4)

Total current tax

147.3

61.4

Deferred tax:



UK corporation tax

(222.6)

(73.9)

UK petroleum revenue tax

11.0

(20.8)

Overseas tax

34.6

4.3

Total deferred tax

(177.0)

(90.4)

Tax on profit on ordinary activities

(29.7)

(29.0)

 

*

For 2011, the adjustments in respect of prior years consist principally of additional provisions in Indonesia and Pakistan for fiscal disputes.

 

 

5   Deferred tax

 

 


2011

2010


$ million

$ million

Deferred tax assets

500.8

285.3

Deferred tax liabilities

(219.1)

(183.7)


281.7

101.6

 

 


At 1

January 2010

Exchange  movements

(Charged)/

credited

to income statement

At 31 December 2010


$ million

$ million

$ million

$ million

UK deferred corporation tax:





Fixed assets and allowances

186.9

-

(172.1)

14.8

Decommissioning

116.3

-

72.3

188.6

Deferred petroleum revenue tax

6.9

-

(10.5)

(3.6)

Tax losses and allowances

17.7

-

121.0

138.7

Unrecognised tax losses and allowances

(137.6)

-

67.4

(70.2)

Deferred revenue

14.1

-

(4.2)

9.9

Total UK deferred corporation tax

204.3

-

73.9

278.2

UK deferred petroleum revenue tax1

(13.7)

-

20.8

7.1

Overseas deferred tax2

(179.8)

0.4

(4.3)

(183.7)

Total

10.8

0.4

90.4

101.6

 

 

 


At 1

January

2011

Exchange  movements

(Charged)/

credited

to income statement

At 31 December 2011


$ million

$ million

$ million

$ million

UK deferred corporation tax:





Fixed assets and allowances

14.8

-

(236.0)

(221.2)

Decommissioning

188.6

-

79.7

268.3

Deferred petroleum revenue tax

(3.6)

-

6.0

2.4

Tax losses and allowances

138.7

-

305.4

444.1

Unrecognised tax losses and allowances

(70.2)

-

70.2

-

Deferred revenue

9.9

-

(2.7)

7.2

Total UK deferred corporation tax

278.2

-

222.6

500.8

UK deferred petroleum revenue tax1

7.1

-

(11.0)

(3.9)

Overseas deferred tax2

(183.7)

3.1

(34.6)

(215.2)

Total

101.6

3.1

177.0

281.7

 

1

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

2

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

 

  

The group's unutilised tax losses and allowances at 31 December 2011 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 2011 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, taking into account additional equity acquired in the Wytch Farm and Catcher areas and the inclusion of other additional UK fields, using an oil price assumption equal to the Dated Brent forward curve in 2012 and 2013 and US$75/bbl in 'real' terms thereafter. As a result, the remaining unrecognised deferred tax assets of US$70.2 million have been recognised in 2011. At 31 December 2011, the group UK ring fence deferred tax assets in respect of tax losses and allowances have been recognised in full.

 

In addition to the above, there are non-ring fence UK tax losses of approximately US$181.2 million (2010: US$171.3 million) and current year non-UK tax losses of approximately 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.

 

 

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.

 

In May 2011, the company conducted a 4:1 share split. In accordance with IAS 33 - 'Earnings per Share' the comparatives have been restated accordingly.

 

Basic and diluted earnings per share are calculated as follows:

 


Profit after tax

Weighted average number of shares

Earnings per share

 


2011

2010

2011

2010

(restated)

2011

2010

(restated)


$ million

$ million

 million

 million

cents

Basic

171.2

129.8

467.4

464.0

36.6

28.0

Contingently issuable shares

-

-

75.8

39.6

*

*

Diluted

171.2

129.8

543.2

503.6

31.5

25.8

 

 

*

The inclusion of the contingently issuable shares in the 2011 and 2010 calculations produces diluted earnings per share. The contingently issuable shares include any expected additional share issues due to future share-based payments and for the acquisition of EnCore Oil plc, as detailed in note 14.  At 31 December 2011 37,349,360 (2010 restated: 37,349,360) potential Ordinary Shares in the company that are underlying the company's convertible bonds and that may dilute earnings per share in the future have not been included in the calculation of diluted earnings per share because they are anti-dilutive for the year (2010: anti-dilutive). If the contingently issuable shares for the acquisition of EnCore Oil plc were excluded, diluted earnings per share would increase to 35.5 cents.

 

 

7   Intangible exploration and evaluation (E&E) assets

 


Oil and gas properties


North

Sea

Asia

Middle

East, Africa & Pakistan

Total


$ million

$ million

$ million

$ million

Cost:





At 1 January 2010

111.1

107.7

12.8

231.6

Exchange movements

(1.1)

-

-

(1.1)

Additions during the year

123.7

18.9

30.6

173.2

Transfer to property, plant and equipment

(20.9)

(2.8)

(1.0)

(24.7)

Exploration expense

(50.6)

(0.9)

(16.7)

(68.2)

At 31 December 2010

162.2

122.9

25.7

310.8

Exchange movements

(0.3)

-

-

(0.3)

Additions during the year

175.9

71.6

25.5

273.0

Transfer to property, plant and equipment

(77.1)

-

(3.4)

(80.5)

Exploration expense

(80.7)

(67.1)

(39.7)

(187.5)

At 31 December 2011

180.0

127.4

8.1

315.5

 

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

 


Oil and gas properties

Other

fixed

assets

Total


North

Sea

Asia

Middle

East, Africa & Pakistan


$ million

$ million

$ million

$ million

$ million

Cost:






At 1 January 2010

1,040.0

729.4

315.3

13.5

2,098.2

Exchange movements

-

-

-

(0.2)

(0.2)

Acquisitions

8.3

-

-

-

8.3

Additions during the year*

217.8

332.9

24.3

2.6

577.6

Disposals

-

-

-

(0.2)

(0.2)

Transfer from intangible E&E assets

20.9

2.8

1.0

-

24.7

At 31 December 2010

1,287.0

1,065.1

340.6

15.7

2,708.4

Exchange movements

-

-

-

(0.1)

(0.1)

Acquisitions**

124.0

-

-

-

124.0

Additions during the year*

209.4

268.3

16.0

6.9

500.6

Disposals

-

-

-

(0.1)

(0.1)

Transfer from intangible E&E assets

77.1

-

3.4

-

80.5

At 31 December 2011

1,697.5

1,333.4

360.0

22.4

3,413.3

Amortisation and depreciation:






At 1 January 2010

308.6

160.8

234.9

7.9

712.2

Exchange movements

-

-

-

(0.1)

(0.1)

Charge for the year

145.8

31.1

19.1

2.3

198.3

Impairment charge

65.3

-

-

-

65.3

Disposals

-

-

-

(0.1)

(0.1)

At 31 December 2010

519.7

191.9

254.0

10.0

975.6

Exchange movements

-

-

-

(0.1)

(0.1)

Charge for the year

110.1

70.5

22.6

2.8

206.0

Impairment (reversal)/charge

(19.4)

-

(6.5)

-

(25.9)

Disposals

-

-

-

(0.1)

(0.1)

At 31 December 2011

610.4

262.4

270.1

12.6

1,155.5

Net book value:






At 31 December 2010

767.3

873.2

86.6

5.7

1,732.8

At 31 December 2011

1,087.1

1,071.0

89.9

9.8

2,257.8

 

 

*

Finance costs that have been capitalised within oil and gas properties during the year total US$26.3 million (2010: US$16.9 million), at a weighted average interest rate of 5.44 per cent (2010: 6.34 per cent).

**

Acquisitions in the current year relate to the purchase of the additional equity interest in the Wytch Farm field. The group has assessed this transaction and concluded that it does not constitute a 'business' under IFRS 3 - 'Business Combinations'.

 

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.

 

During the year, a net reversal of previous impairments of producing oil and gas properties was recognised. The main elements were credits of US$33.5 million and US$6.5 million for reversal of previously recorded impairments in respect of the Scott and Chinguetti fields, offset by impairment charges of US$7.3 million and US$6.8 million in respect of the Balmoral and Brenda fields. The reversals resulted from an increased estimate of the quantities of hydrocarbons recoverable from the Scott field coupled with a positive change in the estimates used to determine the assets' recoverable amount since the impairment losses were recognised, most notably an increase in base price assumption for hydrocarbons due to the sustained high oil price environment. The impairment charges arose mainly as a result of reduced estimates of the quantities of hydrocarbons recoverable from the Balmoral and Brenda fields.

 

The impairment charges and reversals were 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 2012 and 2013 and US$75 per barrel (bbl) in 'real' terms  thereafter (2010: fixed price of US$75/bbl) and were discounted using a discount rate of 10 per cent (2010: 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

 


2011

2010


$ million

$ million

Profit before tax for the year

141.5

100.8

Adjustments for:



Depreciation, depletion, amortisation and impairment

180.1

263.6

Exploration expense

187.5

68.2

Pre-licence exploration costs

23.0

18.9

Provision for share-based payments

8.5

13.8

Interest revenue and finance gains

(5.5)

(2.5)

Finance costs and other finance expenses

73.6

68.0

Gain on derivative financial instruments

(34.0)

(38.6)

Operating cash flows before movements in working capital

574.7

492.2

(Increase)/decrease in inventories

(9.1)

16.7

(Increase)/decrease in receivables

(120.2)

18.1

Increase/(decrease) in payables

82.5

(25.8)

Cash generated by operations

527.9

501.2

Income taxes paid

(44.0)

(67.9)

Interest income received

2.0

2.7

Net cash from operating activities

485.9

436.0

 

 

Analysis of changes in net debt:

 


2011

2010


$ million

$ million

a) Reconciliation of net cash flow to movement in net debt:



Movement in cash and cash equivalents

9.4

49.1

Proceeds from drawdown of long-term bank loans

(33.8)

(310.0)

Proceeds from issuance of senior loan notes

(350.7)

-

Repayment of long-term bank loans

35.1

178.0

Non-cash movements on debt and cash balances

1.7

(7.2)

Increase in net debt in the year

(338.3)

(90.1)

Opening net debt

(405.7)

(315.6)

Closing net debt

(744.0)

(405.7)

 

b) Analysis of net debt:



Cash and cash equivalents

309.1

299.7

Borrowings*

(1,053.1)

(705.4)

Total net debt

(744.0)

(405.7)

 

*

Borrowings consist of the short-term borrowings, the convertible bonds and the other long-term debt. The carrying values of the convertible bonds and the other long-term debt on the balance sheet are stated net of the unamortised portion of the issue costs of US$1.7 million (2010: US$2.3 million) and debt arrangement fees of US$14.7 million (2010: US$18.6 million) respectively.

 

10   Dividends

The directors do not propose any dividend (2010: US$nil).

 

11   External audit

This preliminary announcement is consistent with the audited financial statements of the group for the year-ended 31 December 2011.

 

12   Publication of financial statements

A full set of financial statements will be published on or before 18 April 2012. 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.

 

13   Annual General Meeting

The Annual General Meeting will be held at Institute of Directors, 116 Pall Mall, London SW1Y 5ED on Friday 18 May 2012 at 11.00am.

 

14   Events after the balance sheet date

 

Acquisition

Subsequent to year-end, the company completed the acquisition of the entire issued share capital of EnCore Oil plc (EnCore).

 

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

 

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

 

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

 

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

 

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

 

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

 

 

Provisional fair value

 

$ million

Net assts acquired:

 

Intangible exploration and evaluation assets

0.8

Property, plant and equipment

348.1

Investments

7.5

Trade and other receivables

3.4

Restricted cash

7.2

Cash and cash equivalents

19.0

Assets held for sale

54.0

Trade and other payables

(30.4)

Deferred tax liabilities

(189.3)

Long-term provisions

(0.5)

Total identifiable assets

219.8

Goodwill

187.8

Total consideration

407.6

 

Re-financing

The company, together with certain subsidiary undertakings, jointly guarantees the group's borrowing facilities.

 

Subsequent to year-end, the group successfully negotiated a new US$350.0 million revolving credit facility to replace the US$175.0 million term loan. This new facility matures in 2017. In addition, the group completed a private placement of senior notes of US$202.0 million and €25.0 million with maturities between 2019 and 2024.

 

 

 

Proforma working interest reserves at 31 December 20111

 


Working interest basis

 

 

North Sea

Middle East, Africa and Pakistan

Asia

TOTAL


Oil

and NGLs

Gas

Oil

and NGLs

Gas

Oil and NGLs

Gas

Oil

and NGLs

Gas4

Oil, NGLs and gas


mmbbls

bcf

mmbbls

bcf

mmbbls

bcf

mmbbls

bcf

mmboe

Group proved plus probable reserves:









At 1 January 2011

57.1

31

1.3

269

33.6

660

92.0

960

260.8

Revisions

22.6

3

0.5

(8)

1.3

(110)

24.4

(115)

5.6

Discoveries and extensions2

8.2

20

-

10

-

-

8.2

30

13.4

Acquisitions and divestments3

30.3

5

-

-

-

-

30.3

5

31.2

Production

(3.3)

(2)

(0.3)

(35)

(1.5)

(19)

(5.1)

(56)

(14.7)

At 31 December 2011

114.9

57

1.5

236

33.4

531

149.8

824

296.3

Total group developed and undeveloped reserves:





Proved on production

21.8

10

0.7

142

21.3

190

43.8

342

103.6

Proved approved/justified for development

50.1

24

-

17

1.9

203

52.0

244

96.5

Probable on production

12.0

7

0.7

57

9.1

46

21.8

110

40.5

Probable approved/justified for development

31.0

16

0.1

20

1.1

92

32.2

128

55.7

At 31 December 2011

114.9

57

1.5

236

33.4

531

149.8

824

296.3

 

 

 

Notes:

1

The above proforma reserves include the reserves acquired from the EnCore acquisition, excluding Cladhan. This acquisition was completed in January 2012.

2

Includes reserves discovered at Burgman (UK) and Kadanwari (Pakistan) and unitisation at Rochelle (UK).

3

Acquisitions include increased working interests in Wytch Farm, the Catcher area and Solan. 

4

Proved plus probable gas reserves include 97 bcf fuel gas.

 

 

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 263.8 mmboe as at 31 December 2011 (2010: 222.0 mmboe). This was calculated in 2011 using an oil price assumption equal to the Dated Brent forward curve in 2012 and 2013 and US$75/bbl in 'real' terms thereafter (2010: fixed price of US$75/bbl).

 


This information is provided by RNS
The company news service from the London Stock Exchange
 
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