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Premier Oil PLC (PMO)

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Thursday 20 August, 2015

Premier Oil PLC

Half Yearly Report

RNS Number : 5615W
Premier Oil PLC
20 August 2015
 

Half-Yearly Results for the six months to 30 June 2015

 

Tony Durrant, Chief Executive, commented:

"First half operating cash flows increased year-on-year driven by reliable production, our hedging programme and operating cost savings of 30 per cent.  With Solan on-stream later this year and Catcher in 2017, we expect both growing production and reduced debt levels.  Amended financial covenants announced today provide balance sheet flexibility and demonstrate the on-going support of our capital providers. With the optionality in our portfolio, we are well placed for growth in a stronger oil price environment."

 

Operational highlights

·      Production averaged 60.4 kboepd (2014 H1: 64.9 kboepd), despite recent disposals of non-core assets; full year guidance is maintained at 55 kboepd

·      Increased momentum across sanctioned developments; Solan first oil is still targeted for Q4 2015 and Catcher first oil on track for 2017

·      Progressing Vette and Sea Lion for 2016 investment decisions; ongoing engagement with the supply chain indicates significant potential for reduced costs

·      Discoveries at Zebedee and Isobel Deep, Falkland Islands and incremental resource added at Anoa Deep, Indonesia; ongoing programmes in Norway, Falklands

·      New venture focus on building portfolio in Ceará Basin, Brazil and Sureste Basin, Mexico

·      Formal sales process for Pakistan assets initiated 

 

Financial highlights

·      Strong operating cash flow of US$513.0 million (2014 H1: US$499.4 million)

·      Profit before tax and impairments of US$170.6 million (2014 H1: US$194.4 million); non-cash post-tax impairments of US$225.7 million result in loss after tax of US$375.2 million (2014 H1: profit after tax of US$172.7 million)

·      Operating cost and gross G&A savings of 30 per cent and 20 per cent

·      Amendments to Premier's debt covenants secured out to mid-2017

·      c.60 per cent of 2015 H2 liquid volumes hedged at US$92/bbl; c.25 per cent of 2016 liquids hedged at US$69/bbl

·      2015 full year capex guidance unchanged at US$900 million (development) and US$240 million (exploration); US$500 million of total capex expected for 2016

·      Net debt marginally lower at US$2,093 million;  cash and undrawn facilities of US$1.5 billion

 

ENQUIRIES

 

Premier Oil plc

Tel: + 44 (0)20 7730 1111

Tony Durrant

Richard Rose

 

 

 

 

 

Bell Pottinger

Tel: + 44 (0)20 3772 2500

Gavin Davis

Henry Lerwill

 

 

 

There will be a presentation to analysts at the company's Falkland Islands Business Unit Office on Buckingham Palace Road at 09.30am today which will be webcast live on the company's website at www.premier-oil.com.

 

A copy of this announcement is available for download from our website at www.premier-oil.com and hard copies can be requested by contacting the company (e-mail: [email protected] or telephone: +44 (0)20 7730 1111).

 

A video interview with Tony Durrant, CEO, discussing the 2015 Half Year Results is available to watch here  https://vimeo.com/136759897

 

 

 

 

CHAIRMAN'S STATEMENT

Industry context

Considerable volatility in the oil markets persisted in the first half.  This has been driven by a number of factors, including US unconventional and OPEC production holding firm, the anticipated return of Iran to the global oil market and concerns around Chinese economic growth.  While it is generally agreed that the oil price will eventually recover from current levels, as supply is impacted by the significant reduction in capital investment today, a longer period of lower oil prices is now forecast by most. Consequently, the first half has seen the industry focus on re-setting its cost base and adjusting its expenditure plans in order to withstand such an environment.

 

For our part, we have continued to capture sustainable savings in our operating costs, to defer discretionary capex and to actively manage our portfolio.  The weakness in the oil price post period-end serves as an important reminder that we must sustain these efforts.  We remain focused on managing our balance sheet while achieving the highest level of operational and safety performance and maintaining optionality in the portfolio for future growth. 

 

Premier's performance

Premier delivered a robust production performance in the first half averaging 60.4 kboepd (2014 H1: 64.9 kboepd). This was driven by high operating efficiency across our portfolio and outperformance from our operated Chim Sáo field in Vietnam, where our team have adeptly managed reservoir performance and maintained asset integrity while controlling costs.

 

We continue to progress our sanctioned projects which, once-on-stream, will generate important cash flows for the group. Offshore productivity has improved markedly on our operated Solan project and we now have increased confidence around our targeted fourth quarter first oil date. Development drilling and subsea installation work has commenced on schedule for our Catcher project. While progress in the construction of the FPSO hull has been slower than planned, our team, together with our FPSO contractor BW Offshore, are putting in place the appropriate mitigating actions.  The project remains on track to come on-stream in 2017. 

 

The weak order backlog in many segments of the service sector provides an opportunity to reduce costs on our unsanctioned projects, notably Vette in Norway and Sea Lion in the Falkland Islands. In this respect, re-engagement with the supply chain on both projects has been encouraging and the teams continue to progress the projects towards investment decisions in 2016. These decisions will depend upon the oil price outlook at the time, cost reductions secured as well as our ability to fund the projects without putting our balance sheet at risk. 

 

In the first half, important discoveries were made at Zebedee and Isobel Deep in the Falkland Islands and additional resource potential confirmed at Anoa Deep, Indonesia.   Competition for high quality exploration acreage is less intense in the current environment and this presents an opportunity for our Exploration New Ventures team to replenish our portfolio at low cost. We are pleased to have been awarded two blocks in the under-explored but proven Sureste basin in Mexico's Round 1 post period-end. At the same time, we have continued to divest and relinquish our more mature exploration acreage in our legacy areas.

 

Potential acquisition opportunities that enhance our asset base and create synergies with our existing core businesses continue to be evaluated.  We also look to dispose of non-core assets where we can realise appropriate value.  We successfully reduced our balance sheet exposure to the Solan project via an agreement with FlowStream in May. Discussions are also on-going with interested parties about the sale of our Pakistan business with conclusion of the process targeted by year-end. We plan to initiate partnership discussions with potential co-investors in our Sea Lion development once the current round of negotiations with contractors is complete and the four-well exploration campaign in the North Falklands Basin has been executed.

 

I noted in February that, while our long-term unsecured debt structure and supporting banking relationships leave us well placed, we would need to manage our covenant headroom if lower oil prices persisted.  I believe that we have reacted quickly in terms of taking costs out of our business, as evidenced by the significant drop in our operating costs and G&A costs.  This, together with a strong production performance, the benefit of our hedging programme and proceeds from disposals, resulted in over US$400 million of covenant headroom at period-end.  However, like the rest of the industry, we need to be prepared for a period of sustained commodity price weakness. Consequently, post period-end, we have successfully agreed with our banks and bondholders to amend our financial covenants out to mid-2017.  This should ensure sufficient debt headroom in the period prior to first oil from Catcher, even if weak oil prices persist.

 

Health, safety and environmental matters continue to be of paramount importance to us.  We will not compromise on the integrity and safety of our operations, ring-fencing expenditure associated with asset integrity and safety from the on-going cost reduction programmes across the business. We are very pleased to be able to report that our trend of improved safety performance has continued into 2015.  Our Total Recordable Injury Rate in the first half fell further to stand at 1.05 per million man-hours.  Process safety performance was also above expectations with only one Loss of Primary Containment reported from our operated assets over the period.  Environmentally, performance was also good with greenhouse gas intensity at our operated assets showing a reduction compared to 2014. Our production operations management systems at Balmoral in the UK, and at Anoa and Gajah Baru in Indonesia, retained their OHSAS 18001 and ISO 14001 certifications, as did our worldwide drilling management systems.

 

Outlook

Our strong operational performance together with the benefit of our hedging programme and extensive cost savings, have enabled us to deliver strong cash flows in the first half.  In the second half, we will remain focused on managing our balance sheet as we continue to invest in our approved projects. In particular, we look forward to first oil from Solan later this year. 

 

With new, untaxed production from Solan, our aim is to manage the business such that we are able to deleverage the balance sheet while continuing to ensure the integrity of our production assets and to invest in our Catcher project, even in a conservative oil price environment.  These two projects will provide some underlying growth. Beyond that, the extent to which we can invest in new projects for further growth and consider other forms of shareholder return will be determined by the oil price and the level to which we can capture further cost savings.

 

Mike Welton

Chairman

 

OPERATIONAL REVIEW

FALKLAND ISLANDS

Pre-FEED activities and contractor discussions have significantly de-risked the Premier-operated Sea Lion project and confirmed an attractive Phase 1a development.  The capex profile for this fits well with Premier's expected cash flows, and exploration successes at Zebedee and Isobel Deep have highlighted the potential for high value follow-on developments.

 

Development

In November 2014, pre-FEED work commenced on the Sea Lion Phase 1a development, which targets 160 mmbbls of reserves in the north-east of PL032 using a single subsea drill centre and a leased FPSO.  Dynamic modelling studies have shown that the development plan for this fully appraised reservoir is robust and, in particular, the location of the drill centre provides access to reserves in the north west of PL032 should the opportunity arise.

 

After extensive work with leading FPSO and SURF contractors, the surface facilities plan has been simplified and is now well developed.  Key project contractors will be selected ahead of FEED (rather than at the end of FEED) and, to this end, commercial and technical proposals have been received and are being evaluated. The FPSO will be financed by the FPSO provider and Premier is exploring the use of a similar leasing scheme for the subsea system.  Of the remaining project capex, approximately 75 per cent is anticipated to occur in 2018 and 2019 after Catcher is on-stream.

 

Conceptual studies have commenced to examine potential development schemes for the remaining reserves in PL032 (Phase 1b), the satellite accumulations in the north of PL004 (Phase 2) and for the Isobel/Elaine fan complex in the south of PL004 (Phase 3).  Discussions are continuing with other stakeholders to finalise the necessary arrangements to progress the project and, as with all oil projects in attractive tax regimes, the project remains very sensitive to the long term oil price.

 

Exploration

Premier's four-well North Falklands Basin campaign, which is targeting multiple stacked fans in PL004 and PL032, commenced in March. To date, two discoveries have been made from the first two wells.  The Zebedee well in PL004 has added around 50 mmbbls of resource to a potential Phase 2 development.  The Isobel Deep well, which was the first test of the Isobel/Elaine fan complex, encountered oil-bearing sandstone at the prognosed depth and has opened up a new play in the previously unexplored southern part of PL004. The unrisked Pmean resource estimate of the Isobel/Elaine fan complex is 400 mmbbls.

 

Following the suspension of the Isobel Deep well due to unexpected overpressure, the Eirik Raude rig was transferred to another operator in the South Falklands Basin. The rig is expected to return to the North Falklands Basin later this quarter to drill the Jayne East and Chatham wells. Consideration is being given to performing more drilling at Isobel Deep as part of the programme, possibly replacing the Jayne East well.

 

Portfolio management

Premier anticipates initiating discussions with potential co-investors in its Sea Lion development once the current round of negotiations with contractors is complete and the four-well exploration campaign in the North Falklands Basin has been executed.

 

INDONESIA

The Premier-operated Natuna Sea Block A delivered stable production from an operating cost base of around US$7/boe over the period. Premier also successfully appraised the Anoa Deep discovery, adding incremental resource. 

 

Production & Development

Net production from Indonesia in the first six months was 13.2 kboepd (2014 H1: 14.0 kboepd), while there remained a continued focus on optimising the cost base. 

 

Premier sold 208 BBtud (gross) (2014 H1: 228 BBtud) from its operated Natuna Sea Block A in the first half. Singapore demand for gas sold under GSA1 remained robust, averaging 312 BBtud (2014 H1: 300 BBtud).  Premier's Anoa and Pelikan fields delivered 133 BBtud (2014 H1: 144 BBtud) and accounted for 43 per cent of GSA1 deliveries (2014 H1: 48 per cent), against a contractual share of 39.9 percent. Sales of Gajah Baru and Naga gas dedicated to GSA2 averaged 70 BBtud (2014 H1: 81 BBtud).   Deliveries from Gajah Baru and Naga under the Domestic Swap Agreement (DSA) were less than expected due to competition with low price diesel fuel. However, end-users have been making take or pay payments in full as per the terms of the DSA/GSA.

 

Gas sales from the non-operated Kakap field averaged 26 BBtud (gross) (2014 H1: 29 BBtud) over the period. Gross liquids production from the Kakap field averaged 3.7 kbopd (2014 H1: 3.8 kbopd) and 1.4 kbopd from the Anoa field (2014 H1: 1.6 kbopd).

 

The Pelikan field was successfully brought on-stream in March within budget, following first gas from the Naga field in November 2014. This increased deliverability from Natuna Sea Block A allows Premier increased operational flexibility, the ability to fill any shortfall from other suppliers within the existing contracts and the potential to respond to any future increase in Singapore or domestic gas demand.

 

Elsewhere on Natuna Sea Block A, the next generation of developments to backfill our existing Singapore and domestic market contracts continue to progress. FEED has been completed on the Bison and Iguana projects and is nearing completion on the Gajah Puteri field.  An investment decision on these projects will be made in 2016.

 

Evaluation of the potential development scenarios for the 2014 Kuda/Singa Laut discoveries on the Tuna Block remains on-going. Premier is conducting a farm-out process with a view to reducing its 65 per equity interest in the block in order to manage its exposure going forward.

 

Exploration & Appraisal

The Anoa West-1 well successfully appraised the Anoa Deep discovery made by the West Lobe-5X well in 2012, encountering the same fractured gas bearing sandstones.  The well was deepened to explore for additional reservoir sections and encountered further fractured gas-bearing sands.  A drill stem test produced gas to surface but sustained flow was not achieved due to completion issues.  Nonetheless, the well has successfully confirmed the P50 pre-drill estimate of 13 mmboe associated with the Anoa Deep discovery and has added a further 18 bcf of resource to the Lama play. Further potential remains to be tested beneath the depth reached in both this well and beneath the West Lobe-5X well.  Premier continues to mature a number of other leads and prospects elsewhere in the Lama play to drillable status.

 

Portfolio management

In January, Premier successfully completed the sale of its 41.67 per cent non-operated interest in Block A Aceh onshore Indonesia for an after-tax consideration of US$40 million.

 

NORWAY

The development focus in Norway is to push forward the Premier-operated Vette project to an investment decision in 2016.  The exploration team have been preparing for the drilling of the Myrhauk well, which spudded post period-end.

 

Development

In early 2015, Premier elected to defer the submission of the development plan (PDO) for the Vette project following the sharp fall in the oil price.  Since then, Premier has taken the opportunity to re-engage with the supply chain with the aim of securing lower-cost development options.

 

The low oil price environment has resulted in several alternative lower-cost production facilities to the originally envisaged new build FPSO becoming available, which are now being evaluated.  These have the potential to significantly enhance the economics of the Vette project.  A decision on project sanction is expected in 2016. FEED engineering work on the Sevan 650 new build solution has been completed and this option remains viable as a fall back development concept.

 

Work has also progressed to mature the interpretation of the Herring prospect in the neighbouring PL406 licence.  Herring and the adjacent Mackerel discovery are possible future tie-back developments to a Vette facility.

 

Exploration

Premier's immediate exploration focus in Norway is on the Myrhauk well on the south east flank of the Mandal High.  The potentially play opening well spudded in July and is targeting Jurassic sands within a robust four-way dip closure. The results of this well are expected in September.

 

Premier was successful in the APA 2014 Licensing Round with the award of a 20 per cent interest in PL782S which is located in the Norwegian North Sea and will be operated by ConocoPhillips. Work has commenced in the partnership to define the details of the seismic reprocessing and interpretation work programme. There is no well commitment with the award.

 

PAKISTAN

Premier's Pakistan business continues to generate positive and stable net cash flows for the group.  The group's interests are in well-established gas producing fields with proven operational performance. During the first half, the average realised gas price was above US$4/mmscf while operating costs remained low at around US$3/boe.  Following receipt of an indicative offer for the Pakistan assets, Premier has initiated a formal sales process.

 

Production and Development

Production in Pakistan averaged 10.3 kboepd (2014 H1: 12.4 kboepd), from Premier's six non-operated producing gas fields.  These are world-class gas fields which in total produce some 25 per cent of Pakistan's domestic gas production.

 

Production from the Qadirpur and Zamzama fields continues in line with expectation, averaging 2.8 kboepd (2014 H1: 3.3 kboepd) and 2.2 kboepd (2014 H1: 3.5 kboepd) respectively.  Similarly, average production from the Bhit/Badhra fields was 3.3 kboepd (2014: 3.1 boepd), and production from the Kadanwari gas field averaged 2.0 kboepd (2014 H1: 3.5 kboepd). Increased production from the Bhit/Badhra fields was driven by the successful reconfiguration of the Bhit compressors as well as new production from three Badhra wells. 

 

The Zarghun South gas field, which came on-stream in August 2014, produced 86 boepd (net to Premier) over the period.  All costs pertaining to Premier's 3.75 per cent working interest in the field are carried by the Operator.

 

Exploration

Premier drilled one exploration well - Bhit South-1 - in Pakistan during the first six months of the year.  Bhit South-1 spudded in November 2014 and reached target depth in January 2015.  While gas was encountered, the sands were of poor reservoir quality, and the well was subsequently plugged and abandoned.

 

In addition to existing identified conventional targets, Premier continues to evaluate the shale gas potential in its Kadanwari and Qadirpur gas fields.

 

Portfolio management

During the period, Premier received an indicative offer for its Pakistan business. Consequently, Premier has initiated a formal sales process and initial marketing documents have been issued to a number of prospective purchasers.

 

MAURITANIA

Production and development

Production from the Chinguetti field averaged 400 barrels of oil per day (bopd) (2014 H1: 500 bopd) net to Premier during the first six months of the year. The fall in production was driven by natural decline from the existing wells.

 

UNITED KINGDOM

The UK delivered a strong production performance while at the same time operating costs have been reduced significantly, helped by the disposal of the high-cost Scott area in 2014.  Development activity is focussed on delivering the Solan project in the fourth quarter and delivery of the Catcher project in 2017.  Once on-stream, production from these new projects will more than offset natural decline within the group's portfolio underpinning a rising production profile.

 

Production

Production from Premier's UK fields averaged 16.9 kboepd (2014 H1: 19.4 kboepd). The decrease can be attributed to the sale of the high cost Scott area which averaged 3.9 kboepd in 2014 H1.  

 

Production from the Premier-operated Balmoral area averaged 3.4 kboepd (2014 H1: 3.7 kboepd) and was broadly in line with expectations. The non-operated Kyle field, which was reinstated in July 2014, also performed as anticipated delivering 1.8 kboepd.  Production from the non-operated Wytch Farm averaged 5.4 kboepd (2014 H1: 5.8 kboepd), lower than forecast due to several key wells requiring work overs and integrity issues with the water injection line during the second quarter, which have now been rectified.

 

Production from the non-operated Huntington field averaged 6.2 kboepd (2014 H1: 7.8 kboepd). Huntington production was restricted during the first quarter as a result of constraints on the gas export route. This was largely compensated for by higher than forecast production in the second quarter due to the minimal impact of the CATS pipeline summer maintenance period on the field's performance. Amendments to the gas transportation agreement were executed on 12 June providing improved certainty of Huntington gas export volumes going forward. Field facilities production uptime in the last four months has exceeded 90 per cent.

 

UK unit operating costs were US$29/boe in the first half (2014 H1: US$35/boe).  This reduction reflects the disposal of the high-cost Scott area assets at end 2014 but also cost management work across all remaining assets. UK G&A costs have been reduced, reflecting a lower headcount in the business unit. A particular area of focus has been on the allocation of resources to priority areas and optimisation of activities such as efficiency of vessels and helicopter movements, with increasing co-operation with neighbouring operators.

 

Developments

Commissioning of the Solan infrastructure continued over the period with increased productivity realised from May, due to improved weather and organisational changes in the project execution team.  On 10 August, the Regalia flotel was successfully bridge-linked to the Solan facilities, replacing the Siem Spearfish walk-to-work vessel, which provided continuity of people and workflow on the platform following the departure of the Victory flotel in May. The Regalia flotel will facilitate habitation of the platform and completion of the commissioning of the production systems to allow first oil, still targeted for the fourth quarter.  

 

The first pair of producer-injector wells to the Solan platform was successfully tied-in during March.  Commissioning of the subsea infrastructure commenced in June and remains on-track for completion in September. In parallel, drilling of the second pair of producer-injector wells commenced in July.  The second producer is nearing completion with the second injector expected to spud in September. With both pairs of wells on-stream, the field is expected to ramp up to plateau production rates of 20-25 kboepd. Cash spend to end July stood at US$1.65 billion.

 

On the Catcher project, subsea installation work commenced with the successful installation of the pipeline end manifold and two templates at Burgman and Varadero.  In addition, the 60 kilometre gas export pipeline was successfully laid during July with minimal weather downtime. The Ensco 100 rig came on hire in July and batch drilling of the first four development wells has commenced.  Operations are running to plan, within schedule and budget.  Fabrication of the FPSO hull and topsides is on-going in Asia.  While there have been some scheduling issues associated with the construction of the hull, Premier, together with FPSO contractor BW Offshore, is putting in place mitigating actions to safeguard the sail-away date of the FPSO.  The Premier-operated Catcher project remains and on schedule for first oil in 2017.

 

Exploration

Preparations to drill two exploration wells in the UK North Sea in 2016 are underway.  Specifically, Premier plans to drill an exploration commitment well at the Laverda/Slough prospect to the north of the Catcher area and an exploration well targeting the Bagpuss prospect on the Halibut Horst in the first half of 2016.  During the period, Premier continued to high grade and rationalise its UK North Sea exploration portfolio with several licences relinquished or sold.

 

Portfolio management

In May, Premier successfully acquired Chrysaor's 40 per cent interest in the Solan field for nil upfront cash consideration and entered into an agreement with FlowStream whereby a US$100 million payment was received in return for granting FlowStream 15 per cent of production from the field for a period of time. As a result, partner funding concerns around the Solan project have been removed while, at the same time, the group's balance sheet exposure to the project has been reduced.

 

VIETNAM

A robust production performance, together with substantially reduced operating costs and minimal capital expenditure, resulted in the Vietnam business unit generating strong positive net cash flows for the group.

 

Production

Production from the Premier-operated Block 12W, which contains the Chim Sáo and Dua fields, averaged 19.6 kboepd, up 16 per cent (2014 H1: 16.9 kboepd). Dua, which came on-stream in July 2014, has helped extend the plateau from Chim Sáo. However, the main driver behind Block 12W's strong production was high operating efficiency of 95 per cent and better than predicted reservoir performance.  High uptime was achieved as a result of investments, aimed at improving the reliability of the Chim Sáo facilities, made during 2014.  While plateau rates from Block 12W have been maintained for longer and at higher rates than originally envisaged at sanction, some natural decline from the existing wells is now being seen.

 

In response to lower oil prices, operating costs have been proactively managed downwards.  Chim Sáo operating costs were around US$10/bbl, reflecting both savings in expenditure and higher production.  Cost savings have been achieved through a variety of measures: renegotiation of contracts; assumption of direct control of the offshore operations and maintenance services for the Chim Sáo FPSO; operating efficiencies, such as changing crew shift patterns and the use of lower cost and more fuel efficient supply vessels.

 

EXPLORATION

Premier's exploration portfolio has seen significant change over the last few years, moving away from its traditional but now mature areas.  The forward focus is on under-explored but proven hydrocarbon basins that have the potential to develop into new business units in the 2018 and beyond time frame.

 

Premier successfully entered Mexico with the award of a non-operated 10 per cent interest in Blocks 2 and 7 at no upfront cost in Mexico's Round 1 in July 2015.  Premier has the option to increase its interest to 25 per cent prior to drilling.  The Blocks contain numerous leads in established and emerging plays, located in the shallow water Sureste Basin, a proven and prolific hydrocarbon province in the Gulf of Mexico.  Premier is carried on each of the blocks up to the point of the first well, most likely 2017.

 

In April, Premier increased its footprint in the Ceará Basin, our top ranked basin in Brazil, by farming into CE-M-661 for a non-operated 30 per cent equity interest at no upfront cost.  Multi-client 3D seismic acquisition across Premier's operated blocks CE-M-665 and CE-M-717 and non-operated block CE-M-661 (subject to government approval) is expected to commence in the third quarter of 2015.  Interpretation of recently reprocessed 3D seismic surveys, which partly cover block CE-M-717, has indicated the presence of several structures that may form additional targets for the 2017/18  drilling campaign.  Elsewhere in Brazil, fast-track processed data has been received from the 2014 3D multi-client seismic acquisition in the Foz do Amazonas basin where Premier has a non-operated 35 per cent interest in Block FZA-M-90.  Final results from the processing are expected at the end of 2015. 

 

Premier holds a 30 per cent non-operated interest in Block 12, onshore Iraq, in the underexplored western part of one of the world's most prolific oil basins. A 3D seismic survey acquisition programme was completed in the first quarter and the processed products are now being interpreted ahead of selecting a well location for drilling in 2016/17.

 

In Kenya, Premier drilled the unsuccessful Badada-1 well onshore Block 2B (Premier equity 55 per cent) in early 2015. Premier withdrew from the licence at the end of April and consequently no longer has an acreage position in Kenya.

 

FINANCE REVIEW

Income Statement

Despite the continued low oil price environment, Premier continues to generate strong operating cash flows and has made significant progress in reducing its underlying costs of production

 

Group production on a working interest basis averaged 60.4 kboepd in the first half of 2015 compared to 64.9 kboepd in the first half of 2014 and 63.6 kboepd for the full-year 2014. Lower production year-on-year is a result of the Scott area disposal and natural decline in the portfolio, partially offset by increased production from the Chim Sáo field in Vietnam. This was driven by high operating efficiency and better than predicted reservoir performance. Entitlement production for the period was 55.7 kboepd (2014 H1: 59.8 kboepd).

 

Oil and gas prices, which fell steeply in the second half of 2014, have remained low against prices observed in the last four years, with the Dated Brent oil price in the first half of 2015 fluctuating between US$45.2/bbl and US$66.7/bbl and averaging US$57.8/bbl (2014 H1: US$108.9/bbl). Premier's revenues and cashflows were substantially protected by prior period forward sales resulting in our average realised oil price for the period being US$83.7/bbl on a post-hedge basis (2014 H1: US$107.9/bbl).

 

The average realised gas price (post-hedge) for Indonesian production sold into Singapore was US$12.3 per thousand standard cubic feet (mscf) (2014 H1: US$16.9/mscf). In Pakistan, gas prices across all producing fields averaged US$4.4/mscf (2014 H1: US$4.7/mscf). The combined effect of lower realised prices and a slight reduction in production year-on-year saw a 35 per cent decrease in sales revenues to US$577.0 million (2014: US$884.7 million).

 

Cost of sales, excluding impairment charges, in the period were US$298.8 million (2014 H1: US$502.3 million). Underlying operating costs were US$13.7 per barrel of oil equivalent (boe) (2014 H1: US$18.5/boe) with the year-on-year reduction mainly reflecting the sale of the high cost Scott area in the UK as well as significant savings realised in on-going operations across the group.

 

Amortisation of oil and gas properties fell from US$224.0 million to US$170.6 million and on a unit basis from US$19.1/boe to US$15.6/boe. Impairment charges for the period amounted to US$385.3 million (2014: US$144.0 million) on a pre-tax basis and were recognised for the Solan field in the UK. The principal drivers for the impairment charge are increases in the expected cost to complete the project and future decommissioning costs, a reduction in the forecast forward curve used to perform the impairment testing and the recognition of contingent consideration payable to Chrysaor in future periods.

 

Exploration expense and pre-licence exploration costs amounted to US$51.5 million (2014 H1: US$49.8 million) and mainly relates to the unsuccessful Badada-1 well drilling costs in Kenya and a write off of costs held for the Pancing discovery in Indonesia.  Operating loss for the period was US$167.0 million (2014 H1: profit US$92.0 million). The group general and administrative ("G&A") costs on a gross basis were significantly reduced year-on-year at US$115.0 million (2014 H1: US$140.0) million, resulting in net G&A costs to the group of US$8.4 million (2014 H1: US$12.7 million)

 

Net finance costs of US$47.7 million (2014 H1: US$43.5 million) include unwinding of the discount on decommissioning of US$21.5 million, bank fees of US$29.0 million and a net impairment of the interest accrued on the loan due from the Chrysaor, the former joint venture ("JV") partner on the Solan field, of US$5.3 million. Finance costs capitalised during the period totalled US$25.2 million (2014 H1: US$17.0 million).

 

The group has a current tax charge for the period of US$61.7 million (2014: US$150.4 million) and a non-cash deferred tax charge for the period of US$98.8 million (2014: credit of US$272.7 million) which results in a total tax charge for the period of US$160.5 million (2014: credit of US$122.3 million).

 

The total tax charge for the period is distorted by a number of specific tax items arising in the UK. These include the effects of the UK Supplementary Charge to Tax rate reduction from 32 to 20 per cent on the opening deferred tax asset balance (US$119.4 million charge), and the net impact of ring fence expenditure supplement claims in the UK during the period offset by the non-recognition of UK tax losses and small field allowances due to the low prevailing oil price environment (US$105.9 million net charge).  In addition, an element of the group impairment charge for the period was treated as a permanent difference which resulted in a reduction in the impairment deferred tax credit of approximately US$33.0 million. After adjusting for the net impact of these items of US$258.3 million, the underlying group tax during the period was a credit of US$97.8 million, an effective tax rate of 45.6 per cent.

 

Loss after tax for the period to 30 June 2015 was US$375.2 million (2014 H1: profit US$172.7 million). Basic loss per share for the period was 73.5 cents (2014 H1: earnings of 32.8 cents).

 

Acquisitions and disposals

During the period, Premier acquired Chrysaor's 40 per cent interest in the Solan field for nil upfront cash consideration. In return, Chrysaor can potentially receive a number of contingent payments from a notional 40 per cent interest in the field's net operating cash flow.  As a result of this transaction, Premier will recognise 100 per cent of the Solan field's production, revenues and capex in its financial results. The consideration for the transaction, recognised as part of our total development cost for the Solan field (pre-impairment) was US$614.8 million, which included deemed consideration of US$549.0 million for waiving of the outstanding loan balance due from Chrysaor and US$56.0 million for the fair value of the contingent consideration using Premier's long term oil price planning assumptions.

 

Separately, Premier received cash of US$82.7 million from the completion of the disposals of the non-operated Scott area assets in the UK North Sea (completed in December 2014) and the sale of Block A Aceh onshore Indonesia (completed in January 2015).

 

Cash flow

Cash flow from operating activities amounted to US$513.0 million (2014 H1: US$499.4 million). Included within this balance is US$100 million received by Premier from FlowStream Commodities in return for granting FlowStream 15 per cent of production from the Solan field until sufficient barrels have been delivered to achieve the rate of return within the agreement. Capital expenditure in the period was US$439.7 million (2014 H1: US$506.3 million).

 

Capital expenditure

 

2015

Half-year

$ million

2014

Half-year

$ million

Fields/developments *

379.7

469.9

Exploration

137.0

137.7

Other

0.9

3.1

Total

517.6

610.7

* Funding provided to the former JV partner on Solan has been included within development capex above

 

The majority of the development expenditure in the first half was for the Solan field in the UK and the Dua field in Vietnam. Exploration expenditure in the first half was mainly relating to an exploration campaign in the Falkland Islands.

 

Balance sheet

Net debt at 30 June 2015 of US$2,092.5 million (December 2014: US$2,122.2 million) including cash resources of US$372.4 million (December 2014: US$291.8 million) was slightly lower than the year end position primarily due to our strong production performance, Premier's hedging programme, lower operating costs and proceeds received from disposals. Cash received from FlowStream of US$100 million has been recognised as deferred income on the balance sheet and will be released to the income statement once barrels are delivered to FlowStream post first oil from Solan.

 

 

2015

Half-year

$ million

2014

Year-end

$ million

2014

Half-year

$ million

Cash and cash equivalents

372.4

291.8

255.0

Convertible bonds

(230.3)

(228.5)

(226.3)

Other long-term debt

(2,234.6)

(2,185.5)

(1,717.8)

Net debt

(2,092.5)

(2,122.2)

(1,689.1)

 

Long-term borrowings consist of convertible bonds, UK retail bonds, senior loan notes and bank debt. During the period, Premier bought back US$148 million and €40 million of its US private placement notes at a discount to par and repaid a US$300 million term loan maturing in the second quarter of 2015. Premier retains significant cash and undrawn facilities which, at 30 June 2015, were US$372.4 million and US$1.1 billion respectively.

 

Premier has agreed with its lending group to modify its financial covenants until mid-2017.  Under this agreement our financial covenants have been modified as follows:

·     EBITDAX cover ratio increases to 4.75 times until the period ending 31 December 2016 and to 4.5 times for the period ending 30 June 2017, before returning to its pre-modified level of 3.0 times for the period ending 31 December 2017.

·     Interest cover ratio reduced to 3.0 times until the period ending 30 June 2017, before returning to its pre-modified level of 4.0 times for the period ending 31 December 2017.

 

Under the terms of the agreement with our lending group, we are restricted from proposing a dividend to the extent that our projections indicate that our financial covenants will be above their pre-modified levels.  

 

Financial risk management

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

 

At period end, 6.4 mmbbls of Dated Brent oil were hedged through forward sales for the rest of 2015 and full-year 2016. This volume, represents approximately 60 per cent of the group's expected liquids entitlement production in H2 2015 at an average of US$92.3/bbl and 24 per cent of total forecast liquids production for 2016 at an average price of US$68.6/bbl. In addition, 108,000 metric tonnes (MT) of high sulphur fuel oil (HSFO), which drives the group's gas contract pricing in Singapore,  has been sold forward for the rest of 2015 and 2016 representing approximately 17 per cent of our expected Indonesian gas entitlement production for the next 18 months.  For 2015, 36,000 MT have been forward sold at an average price of US$341.8/MT, whilst 72,000 MT have been forward sold for 2016 at an average price of US$400/MT.

 

During the first half of 2015, forward oil sales of 2.7 mmbbls and forward gas sales of 84,000 MT of HSFO matured at a net credit of US$145.0 million (2014: net cost US$8.3 million) which has been included within sales revenue.

 

Premier operates and reports in US dollars. Foreign exchange exposure therefore relates only to certain sterling and other local currency expenditures. These exposures are covered by the purchase of local currency on a spot or short-term forward basis. The average sterling/dollar rate achieved for transactions maturing in the first half of 2015 was US$1.52:£1. Forward foreign exchange contracts outstanding at 30 June amounted to £130 million at an average rate of US$1.53:£1.

 

The group's main debt facilities include both fixed and floating interest rate borrowings. At 30 June, 35 per cent of the group's total debt of US$2.5 billion was denominated in fixed rate instruments, or locked into fixed rate costs using the interest rate swap market.

 

There have been material transactions or changes in transactions with related parties as described in note 24 of the Annual Report and Financial Statements for the year ended 31 December 2014.

 

Going concern

The group monitors its funding position and its liquidity risk throughout the year to ensure it has access to sufficient funds to meet forecast cash requirements.  Cash forecasts are regularly produced based on, inter alia, the group's latest life of field production and expenditure forecasts, management's best estimate of future commodity prices (based on recent forward curves, adjusted for the group's hedging programme) and the group's borrowing facilities. Sensitivities are run to reflect different scenarios including, but not limited to, changes in oil and gas production rates, possible reductions in commodity prices and delays or cost overruns on major development projects.  This is done to identify risks to liquidity and covenant compliance and enable management to formulate appropriate and timely mitigation strategies. 

 

At 30 June 2015, the group had significant headroom on its existing borrowing facilities and related financial covenants, but there was a possible risk that in a period of ongoing sustained low oil prices it might breach one of its financial covenants within the next 12 months. Accordingly, the group has reached agreement with its lending group to modify its financial covenants, as summarised above.  The group's forecasts and projections, indicate that the group will be able to operate within the requirements of its modified financial covenants and within the current level of its borrowing facilities for 12 months from the date of approval of the Interim Report and Accounts. The directors therefore continue to adopt the going concern basis in preparing the financial statements.

 

Business risks

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

 

Effective risk management is critical to achieving our strategic objectives and protecting our personnel, assets, the communities where we operate, those with whom we interact and our reputation. Premier therefore has a comprehensive approach to risk management.

 

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

 

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

 

The group has identified the following principal risk areas for the remaining six months of the year:

health, safety, environment and security (HSES);

production and development delivery;

commodity price volatility;

exploration success and reserves addition;

host government - political and fiscal risks;

organisational capability;

joint venture partner alignment; and

financial discipline and governance

 

Further information detailing the way in which these risks are mitigated is provided on pages 22 to 25 of the 2014 Annual Report and Financial Statements. This information is also available on company's website www.premier-oil.com.


STATEMENT OF DIRECTORS' RESPONSIBILITIES

 

Each of the directors of the company confirms that to the best of his or her knowledge:

 

a)    the condensed set of financial statements, which has been prepared in accordance with International Accounting Standard 34 - 'Interim Financial Reporting' gives a true and fair view of the assets, liabilities, financial position and profit of the company;

 

b)    the Half-Yearly Results statement includes a fair review of the information required by DTR 4.2.7R (indication of important events during the first six months and description of principal risks and uncertainties for the remaining six months of the year); and

 

c)    the Half-Yearly Results statement includes a fair review of the information required by DTR 4.2.8R (disclosure of related parties' transactions and changes therein).

 

On behalf of the Board

 

Richard Rose

Finance Director  

19 August 2015 

 

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.

 

CONDENSED CONSOLIDATED INCOME STATEMENT

 

 

Six months

to 30 June

2015

Unaudited

Six months

 to 30 June

2014

 Unaudited

Year to

31 December

2014

Audited

 

Note

$ million

$ million

$ million

Sales revenues

2

577.0

884.7

1,629.4

Cost of sales

3

(298.8)

(502.3)

(986.6)

Impairment charge on oil and gas properties *

9

(385.3)

(144.0)

(784.4)

Exploration expense

 

(45.3)

(37.4)

(58.5)

Pre-licence exploration costs

 

(6.2)

(12.4)

(25.3)

(Loss)/profit on disposal of assets

 

-

(83.9)

2.7

General and administration costs

 

(8.4)

(12.7)

(25.4)

Operating (loss)/profit

 

(167.0)

92.0

(248.1)

Share of profit in associate

 

-

1.9

1.9

Interest revenue, finance and other gains

4

47.4

24.9

58.5

Finance costs and other finance expenses

4

(95.1)

(68.4)

(196.3)

(Loss)/profit before tax

 

(214.7)

50.4

(384.0)

Tax

5

(160.5)

122.3

173.7

(Loss)/profit for the period/year

 

(375.2)

172.7

(210.3)

(Loss)/earnings per share (cents):

 

 

 

 

Basic

7

(73.5)

32.8

(40.3)

Diluted

7

(73.5)

31.3

(40.3)

* The June 2014 income statement has been restated to disclose separately the impairment charge on oil and gas properties

Notes 1 to 13 form an integral part of these condensed financial statements.

 

CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

 

 

Six months

to 30 June

2015

Unaudited

Six months

 to 30 June

2014

 Unaudited

Year to

31 December

2014

Audited

 

Note

$ million

$ million

$ million

(Loss)/Profit for the period/year

 

(375.2)

172.7

(210.3)

Cash flow hedges on commodity swaps:

 

 

 

      Gains/(losses) arising during the period/year

 

4.8

(17.0)

296.1

      Less:  reclassification adjustments for (gains)/ losses in          the period/year

 

(145.0)

7.6

 

 

(140.2)

(9.4)

250.1

Tax relating to components of other comprehensive income

6

80.9

5.8

(139.0)

Cash flow hedges on interest rate and foreign exchange swaps

(2.8)

                6.2

15.5

Exchange differences on translation of foreign operations

 

(13.4)

3.4

(48.3)

Losses on long-term employee benefit plans*

 

-

-

(0.2)

Other comprehensive (expense)/income

 

(75.5)

6.0

78.1

Total comprehensive expense/income for the period/year

 

(450.7)

178.7

(132.2)

 

*

Not expected to be reclassified subsequently to profit and loss account

 

 

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

 

CONDENSED CONSOLIDATED BALANCE SHEET

 

 

At

30 June

2015

Unaudited

At

30 June

2014

Unaudited

At 31 December

2014

Audited

 

Note

$ million

$ million

$ million

Non-current assets:

 

 

 

 

Goodwill

 

240.8

240.8

240.8

Intangible exploration and evaluation assets

8

910.3

753.5

825.7

Property, plant and equipment

9

2,946.9

2,679.5

2,430.0

Investments

 

7.7

8.4

7.6

Long-term employee benefit plan surplus

 

0.8

1.3

0.8

Other receivables

 

9.1

316.4

494.1

Deferred tax assets

6

945.3

1,057.2

971.7

 

 

5,060.9

5,057.1

4,970.7

Current assets:

 

 

 

 

Inventories

 

29.8

44.7

26.1

Trade and other receivables

 

344.4

473.8

411.0

Tax recoverable

 

41.1

89.0

57.9

Derivative financial instruments

 

96.5

16.3

273.4

Cash and cash equivalents 

 

372.4

255.0

291.8

Assets held for sale

 

-

327.9

56.7

 

 

884.2

1,206.7

1,116.9

Total assets

 

5,945.1

6,263.8

6,087.6

Current liabilities:

 

 

 

 

Trade and other payables

 

(469.2)

(607.3)

(544.5)

Current tax payable

 

(74.5)

(122.6)

(84.2)

Provisions

 

(11.8)

(15.7)

(14.1)

Derivative financial instruments

 

(53.2)

(47.6)

(48.1)

Short-term debt

 

-

-

(300.0)

Deferred income

11

(17.3)

-

-

Liabilities directly associated with assets held for sale

 

-

(235.5)

(1.8)

 

 

(626.0)

(1,028.7)

(992.7)

Net current assets

 

258.2

178.0

124.2

Non-current liabilities:

 

 

 

 

Convertible bonds

 

(230.3)

(225.9)

(228.1)

Other long-term debt

 

(2,211.3)

(1,707.1)

(1,858.1)

Deferred tax liabilities

 

 

6

(244.3)

(296.4)

(254.2)

Deferred income

11

(82.7)

-

-

Long-term provisions

 

(1,100.2)

(753.7)

(864.0)

Long-term employee benefit plan deficit

 

(17.2)

(14.5)

(18.3)

 

 

(3,886.0)

(2,997.6)

(3,222.7)

Total liabilities

 

(4,512.0)

(4,026.3)

(4,215.4)

Net assets

 

1,433.1

2,237.5

1,872.2

Equity and reserves:

 

 

 

 

Share capital

 

106.7

109.2

106.7

Share premium account

 

275.4

275.4

275.4

Merger reserve

 

374.3

374.3

374.3

Retained earnings

 

718.8

1,453.8

1,142.3

Other reserves

 

(42.1)

24.8

(26.5)

 

 

1,433.1

2,237.5

1,872.2

 

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

 

 

____________Attributable to the equity holders of the parent___________

 

 

 

 

 

Other reserves

 

 

Share capital

Share premium account

Retained earnings

 

Merger

reserve

Capital redemption reserve

Translation reserves

Equity reserve

Total

 

$ million

$ million

$ million

$ million

$ million

$ million

$ million

$ million

At 1 January 2014

110.5

275.3

1,342.1

374.3

4.3

(0.4)

18.3

2,124.4

Issue of Ordinary Shares

-

0.1

-

-

-

-

-

0.1

Purchase and cancellation of own shares

(3.8)

 

(93.0)

-

3.8

-

-

(93.0)

Purchase of ESOP Trust shares

-

-

(6.4)

-

-

-

-

(6.4)

Provision for share-based payments

-

-

23.3

-

-

-

-

23.3

Transfer between reserves*

-

-

4.2

-

-

-

(4.2)

-

Dividends paid

-

-

(44.0)

-

-

-

-

(44.0)

Total comprehensive expense

-

-

(83.9)

-

-

(48.3)

-

(132.2)

At 31 December 2014

106.7

275.4

1,142.3

374.3

8.1

(48.7)

14.1

1,872.2

Provision for share-based payments

-

-

11.6

-

-

-

-

11.6

Transfer between reserves*

-

-

2.2

-

-

-

(2.2)

-

Total comprehensive expense

-

-

(437.3)

-

-

(13.4)

-

(450.7)

At 30 June 2015

106.7

275.4

718.8

374.3

8.1

(62.1)

11.9

1,433.1

 

 

 

 

 

 

 

 

 

At 1 January 2014

110.5

275.3

1,342.1

374.3

4.3

(0.4)

18.3

2,124.4

Issue of Ordinary Shares

-

0.1

-

-

-

-

-

0.1

Cancellation of Ordinary Shares

 (1.3)

-

(33.3)

-

1.3

-

-

(33.3)

Provision for share-based payments

-

-

11.6

-

-

-

-

11.6

Dividends paid

          -

          -

(44.0)

          -

          -       

         -          

          -

(44.0)

Transfer between reserves*

-

-

2.1

-

-

-

(2.1)

-

Total comprehensive income

-

-

175.3

-

-

3.4

-

178.7

At 30 June 2014

109.2

275.4

1,453.8

374.3

5.6

3.0

16.2

2,237.5

 

*

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.

 

CONDENSED CONSOLIDATED CASH FLOW STATEMENT

 

 

Six months

to 30 June

2015

Unaudited

Six months

to 30 June

2014

Unaudited

Year to

31 December

2014

Audited

 

Note

$ million

$ million

$ million

Net cash from operating activities

10

513.0

499.4

924.3

Investing activities:

 

 

 

 

Capital expenditure

 

(439.7)

(506.3)

(1,195.5)

Proceeds from disposal of oil and gas properties

 

82.7

-

130.7

Loan to joint venture partner*

 

(77.9)

(104.4)

(318.4)

Net cash used in investing activities

 

(434.9)

(610.7)

(1,383.2)

Financing activities:

 

 

 

 

Proceeds from issuance of Ordinary Shares

 

-

-

0.1

Purchase and cancellation of own shares

 

-

-

(93.0)

Net purchases of ESOP Trust shares

 

-

-

(6.4)

Share buyback

 

-

(33.3)

-

Proceeds from drawdown of bank loans

 

550.0

100.0

655.0

Debt arrangement fees

 

-

(1.7)

(22.1)

Repayment of bank loans and senior notes

 

(500.8)

(70.0)

(100.0)

Dividends paid

 

-

(44.0)

(44.0)

Interest paid

 

(48.7)

(47.2)

(98.1)

Net cash from/(used in) financing activities

 

0.5

(96.2)

291.5

Currency translation differences relating to cash and cash equivalents

2.0

13.6

10.3

Net increase/(decrease) in cash and cash equivalents

 

80.6

(193.9)

(157.1)

Cash and cash equivalents at the beginning of the period/year

 

291.8

448.9

448.9

Cash and cash equivalents at the end of the period/year

10

372.4

255.0

291.8

 

*Funding provided to the former Joint Venture partner until the completion of the asset acquisition of 40 per cent interest in the Solan field (see note 9).

 

NOTES TO THE CONDENSED FINANCIAL STATEMENTS

 

1.    BASIS OF PREPARATION

 

General information

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

 

The condensed financial statements for the six months ended 30 June 2015 were approved for issue in accordance with a resolution of a committee of the Board of Directors on 19 August 2015.

 

The information for the year ended 31 December 2014 contained within the condensed financial statements does not constitute statutory accounts within the meaning of section 434 of the Companies Act 2006. Statutory accounts for the year ended 31 December 2014 were approved by the Board of Directors on 25 February 2015 and delivered to the Registrar of Companies. The auditor reported on those accounts; the report was unqualified, did not draw attention to any matters by way of emphasis and did not contain any statement under section 498(2) or 498(3) of the Companies Act 2006.

 

The financial information contained in this report is unaudited. The condensed consolidated income statement, condensed consolidated statement of comprehensive income, condensed consolidated statement of changes in equity and the condensed consolidated cash flow statement for the six months to 30 June 2015, and the condensed consolidated balance sheet as at 30 June 2015 and related notes, have been reviewed by the auditors and their report to the company is attached.

 

Basis of preparation

The condensed financial statements for the six months ended 30 June 2015 have been prepared in accordance with IAS 34 - 'Interim Financial Reporting', as adopted by the European Union and with the requirements of the Disclosure and Transparency Rules issued by the Financial Conduct Authority. These condensed financial statements should be read in conjunction with the annual financial statements for the year ended 31 December 2014, which have been prepared in accordance with International Financial Reporting Standards as adopted by the European Union.

 

The condensed financial statements have been prepared on the going concern basis. Further information relating to the going concern assumption is provided in the Financial Review.

 

Accounting policies

The accounting policies applied in these condensed financial statements are consistent with those of the annual financial statements for the year ended 31 December 2014, as described in those annual financial statements. A number of new standards, amendments to existing standards and interpretations were applicable from 1 January 2015. The adoption of these amendments did not have a material impact on the group's condensed financial statements for the half-year ended 30 June 2015.

 

2. OPERATING SEGMENTS

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

 

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

 

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

 

 

Six months

to 30 June

2015

Unaudited

Six months

to 30 June

2014

Unaudited

Year to

31 December

2014

Audited

 

$ million

$ million

$ million

Revenue:

 

 

 

Indonesia

124.1

175.9

325.7

Pakistan (including Mauritania)

52.1

77.0

141.6

Vietnam

142.5

241.3

473.3

United Kingdom

258.3

390.5

688.8

Total group sales revenue

577.0

884.7

1,629.4

Interest and other finance revenue

28.6

15.1

39.4

Total group revenue

605.6

899.8

1,668.8

 

 

Group operating (loss)/profit:

 

 

 

Indonesia

59.1

9.9

104.5

Norway

(0.2)

(2.4)

(17.4)

Pakistan (including Mauritania)

17.9

26.0

32.4

Vietnam

37.1

107.7

153.5

United Kingdom

(236.9)

(16.4)

(446.6)

Rest of the World

(29.5)

(11.8)

(23.6)

Unallocated*

(14.5)

(21.0)

(50.9)

Group operating (loss)/profit

(167.0)

92.0

(248.1)

Share of profit in associate

-

1.9

1.9

Interest revenue, finance and other gains

47.4

24.9

58.5

Finance costs and other finance expenses

(95.1)

(68.4)

(196.3)

(Loss)/profit before tax

(214.7)

50.4

(384.0)

Tax

(160.5)

122.3

173.7

(Loss)/profit after tax

            (375.2)

172.7

(210.3)

 

 

 

Six months

to 30 June

2015

Unaudited

Six months

to 30 June

2014

Unaudited

Year to

31 December

2014

Audited 

 

$ million

$ million

$ million

Balance sheet - Segment assets:

 

 

 

Falkland Islands

553.0

358.6

430.6

Indonesia

653.2

765.4

702.0

Norway

189.9

274.2

197.9

Pakistan (including Mauritania)

85.2

132.5

101.7

Vietnam

476.3

659.1

569.9

United Kingdom**

3,442.6

3,787.6

3,428.2

Rest of the World

76.1

79.0

92.1

Unallocated*

468.8

207.4

565.2

Total assets

5,945.1

6,263.8

6,087.6

 

*

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

**

Includes goodwill.

 

3. COST OF SALES

 

Six months

to 30 June

2015

Unaudited

Six months

to 30 June

2014

Unaudited

Year to

31 December

2014

Audited

 

$ million

$ million

$ million

Operating costs

149.8

216.9

436.1

Stock overlift/underlift movement

(39.7)

32.0

48.5

Royalties

12.6

24.7

45.6

Amortisation and depreciation of property, plant and equipment

 

 

 

-  Oil and gas properties

170.6

224.0

446.1

-  Other fixed assets

5.5

4.7

10.3

 

298.8

502.3

986.6

 

4. INTEREST REVENUE AND FINANCE COSTS

 

Six months

to 30 June

2015

Unaudited

Six months

to 30 June

2014

Unaudited

Year to

31 December

2014

Audited

 

$ million

$ million

$ million

Interest revenue, finance and other gains:

 

 

 

Short-term deposits

0.7

1.2

2.1

Gain on forward  contracts

9.9

-

-

Gain on extinguishment of debt

4.1

-

-

Loan to joint venture partner

27.9

12.9

36.8

Exchange differences and others

4.8

10.8

19.6

 

47.4

24.9

58.5

Finance costs:

 

 

 

Bank loans, overdrafts and bonds

(29.0)

(25.8)

(62.1)

Payable in respect of convertible bonds

(5.3)

(5.2)

(10.5)

Payable in respect of senior loan notes

(15.6)

(18.2)

(31.3)

Long-term debt arrangement fees

(4.4)

(3.3)

(7.0)

Loss on forward contracts

(11.3)

-

(18.9)

Exchange differences and others

-

(11.2)

(0.6)

 

(65.6)

(63.7)

(130.4)

Other finance expenses

 

 

 

Unwinding of discount on decommissioning provision

(21.5)

(21.7)

(46.9)

Provision for doubtful loan to joint venture partner

(33.2)

-

(61.2)

 

(54.7)

(21.7)

(108.1)

Gross finance costs and other finance expenses

(120.3)

(85.4)

(238.5)

Finance costs capitalised during the period/year

25.2

17.0

42.2

 

(95.1)

(68.4)

(196.3)

 

5. TAX

 

Six months

to 30 June

2015

Unaudited

Six months

to 30 June

2014

Unaudited

Year to

31 December

2014

Audited

 

$ million

$ million

$ million

Current tax:

 

 

 

UK corporation tax on profits

-

(1.8)

(1.5)

UK petroleum revenue tax

21.3

78.8

65.4

Overseas tax

40.8

71.0

154.1

Adjustments in respect of prior years

(0.4)

2.4

1.9

Total current tax

61.7

150.4

219.9

Deferred tax:

 

 

 

UK corporation tax

117.5

(296.2)

(382.2)

UK petroleum revenue tax

(10.1)

7.1

33.7

Overseas tax

(8.6)

16.4

(45.1)

Total deferred tax

98.8

(272.7)

(393.6)

Tax charge/(credit) on (loss)/profit on ordinary activities

160.5

(122.3)

(173.7)

 

The group has a current tax charge for the period of US$61.7 million (2014: US$150.4 million) and a non-cash deferred tax charge for the period of US$98.8 million (2014: credit of US$272.7 million) which results in a total tax charge for the period of US$160.5 million (2014: credit of US$122.3 million) on a loss before tax for the period US$214.6 million.

 

The total tax charge for the period is distorted by a number of specific tax items arising in the UK. These include the effects of the UK Supplementary Charge to Tax rate reduction from 32 to 20 per cent on the opening deferred tax asset balance (US$119.4 million charge) and the net impact of ring fence expenditure supplement claims in the UK during the period offset by the non-recognition of UK tax losses and small field allowances due to the low prevailing oil price environment (US$105.9 million net charge). In addition, an element of the group's impairment charge for the period was treated as a permanent difference which resulted in a reduction in the impairment deferred tax credit of approximately US$33.0 million. After adjusting for the net impact of these items of US$258.3 million, the underlying group tax during the period was a credit of US$97.8 million, an effective tax rate of 45.6 per cent.

 

6. DEFERRED TAX

 

Six months to

30 June

2015

Unaudited

Six months to

30 June

2014

Unaudited

 Year to 31

December 2014

Audited

 

$ million

$ million

$ million

Deferred tax assets

945.3

1,057.2

971.7

Deferred tax liabilities

(244.3)

(296.4)

(254.2)

 

701.0

760.8

717.5

 

 

 

At

1 January

2015

Exchange

movements

(Charged)/

credited

to income

statement

Credited to retained earnings

At

30 June

2015

 

$ million

$ million

$ million

$ million

$ million

UK deferred corporation tax:

 

 

 

 

Fixed assets and allowances

(756.0)

-

(65.8)

-

Decommissioning

329.8

-

31.3

-

Deferred petroleum revenue tax

15.5

-

(7.2)

-

Tax losses and allowances

1,375.4

-

81.4

-

Small field allowances

157.2

-

(157.2)

-

Derivative financial instruments

(125.1)

-

-

80.9

Total UK deferred corporation tax

996.8

-

(117.5)

80.9

960.1

UK deferred petroleum revenue tax1

(25.0)

-

10.1

-

(14.9)

Overseas deferred tax2

(254.2)

1.3

8.6

-

(244.2)

Total

717.5

1.3

(98.8)

80.9

701.0

 

1

The UK deferred petroleum revenue tax relates mainly to temporary differences associated with fixed assets.

2

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

 

 

 

The group's deferred tax assets at 30 June 2015 are recognised to the extent that taxable profits are expected to arise in the future against which the ring fence tax losses and allowances can be utilised. In accordance with paragraph 37 of IAS 12 - 'Income Taxes' the group re-assessed its deferred tax assets at 30 June 2015 with respect to ring fence tax losses and allowances. The corporate model used to assess whether it is appropriate to recognise all of the group's deferred tax assets was re-run, using an oil price assumption of Dated Brent forward curve in 2H 2015,2016 and H1 2017, and then US$85/bbl in 'real' terms thereafter.  The results of the corporate model demonstrated that it was no longer appropriate to recognise an additional amount of US$49.6 million on (2014: US$86.8 million) in respect of the group's UK ring fence deferred tax assets relating to tax losses and allowances based on expected future profitability.

 

In addition to the above, there are carried forward non-ring fence UK tax losses of approximately US$283.2 million (2014: US$263.1 million) and current year non-UK tax losses of approximately US$34.0 million (2014: US$40.8 million) for which a deferred tax asset has not been recognised.

 

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

 

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

 

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

 

7. (LOSS)/EARNINGS PER SHARE


The calculation of basic earnings per share is based on the profit after tax and on the weighted average number of Ordinary Shares in issue during the period. Basic and diluted (loss)/earnings per share are calculated as follows:

 

 

Six months

to 30 June

2015

Unaudited

Six months

to 30 June

2014

Unaudited

Year to

31 December

2014

Audited

(Loss)/earnings ($ millions):

 

 

 

(Loss)/earnings for the purpose of basic earnings per share being net profit attributable to owners of the company

(375.2)

172.7

(210.3)

Effect of dilutive potential Ordinary Shares:

 

 

 

Interest on convertible bonds

-

5.2

-

(Loss)/earnings for the purposes of diluted (loss) earnings per share

(375.2)

177.9

(210.3)

 

 

 

 

Number of shares (millions):

 

 

 

Weighted average number of Ordinary Shares for the purpose of basic earnings per share

510.8

527.1

521.9

Effects of dilutive potential Ordinary Shares:

 

 

 

Contingently issuable shares

-

40.8

-

Weighted average number of Ordinary Shares for the purpose of diluted earnings per share

510.8

567.9

521.9

 

 

 

 

(Loss)/earnings per share (cents)

 

 

 

Basic

(73.5)

32.8

(40.3)

Diluted

(73.5)

31.3

(40.3)

 

There were 41.3 million anti-dilutive potential Ordinary Shares in the six months to 30 June 2015 mainly compromising of shares to be issued on the conversion of the convertible bond.

 

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

 

 

Oil and gas properties

 

$ million

Cost:

 

At 1 January 2015

825.7

Exchange movements

(12.9)

Additions during the period

142.8

Exploration expense

(45.3)

At 30 June 2015

910.3

 

 

At 30 June 2014

753.5

 

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.

 

9. PROPERTY, PLANT AND EQUIPMENT

 

 

Oil and gas properties

 

Other

fixed assets

Total

 

$ million

$ million

$ million

Cost:

 

 

 

At 1 January 2015

5,498.6

59.9

5,558.5

Solan asset acquisition

614.8

-

614.8

Additions during the period

462.8

0.8

463.6

At 30 June 2015

6,576.2

60.7

6,636.9

Amortisation and depreciation:

 

 

 

At 1 January 2015

3,091.3

37.2

3,128.5

Exchange movements

-

0.1

0.1

Charge for the period

170.6

5.5

176.1

Impairment charge

385.3

-

385.3

At 30 June 2015

3,647.2

42.8

3,690.0

Net book value:

 

 

 

At 30 June 2015

2,929.0

17.9

2,946.9

At 31 December 2014

2,407.3

22.7

2,430.0

At 30 June 2014

2,660.9

18.6

2,679.5

 

During the period, Premier acquired a further 40 per cent interest in the Solan field for nil upfront cash consideration to increase the group's total interest to 100 per cent. Under the terms of the transaction, the group has agreed to make three types of contingent consideration (royalty) payments to Chrysaor which depend on the future profits generated from a notional 40 per cent interest in the Solan field.  The terms of each royalty differ and in certain cases include a fixed monetary cap and in other cases allow for deductions designed to allow Premier to notionally recover the loan previously advanced to Chrysaor and/or a notional 40 per cent share of the total project capex.

 

The consideration for the acquisition was US$614.8 million, representing the fair value of the outstanding loan balance due from Chrysaor which has been waived (US$549.0 million), the fair value of the above contingent consideration due to Chrysaor using Premier's long term planning assumptions (US$56.0 million) and other working capital adjustments (US$10.0 million). This contingent consideration is included in long term provisions at its fair value. The fair value of the contingent consideration has been determined using our long term corporate modelling assumptions consistent with those used for impairment testing purposes, as set out below.

 

Amortisation and depreciation of oil and gas properties is calculated on a unit-of-production basis, using the ratio of oil and gas production in the period to the estimated quantities of proved and probable reserves on an entitlement basis at the end of the period plus production in the period, on a field-by-field basis. Proved and probable reserve estimates are based on a number of underlying assumptions including oil and gas prices, future costs, oil and gas in place and reservoir performance, which are inherently uncertain. Management uses established industry techniques to generate its estimates and regularly references its estimates against those of joint venture partners or external consultants.

 

However, the amount of reserves that will ultimately be recovered from any field cannot be known with certainty until the end of the field's life.           

 

The impairment charge relates entirely to the Solan field in the UK. The carrying amount of the Solan field at 30 June 2015, after the impairment charge, is US$1,334.8 million. The impairment charge was calculated by comparing the future discounted cash flows expected to be derived from production of commercial reserves (the value-in-use) against the carrying value of the asset. The future cash flows were estimated using an oil price assumption equal to the Dated Brent forward curve in H2 2015, 2016 and H2 2017, and US$85/bbl in 'real' terms thereafter and were discounted using a pre-tax discount rate of 10.0 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.  The impairment charge is driven by increases in the total expected costs to complete the project and future decommissioning costs, a reduction in the forecast forward curve and the recognition of contingent consideration payable to Chrysaor as outlined above.

 

10. NOTES TO THE CONDENSED CONSOLIDATED CASH FLOW STATEMENT

 

 

Six months

to 30 June

2015

Unaudited

Six months

to 30 June

2014

Unaudited

Year to

31 December

2014

Audited

 

$ million

$ million

$ million

(Loss)/profit before tax for the period/year

(214.7)

50.4

(384.0)

Adjustments for:

 

 

 

Depreciation, depletion, amortisation and impairment

561.4

372.7

1,240.8

Exploration expense

45.3

37.4

58.5

Provision for share-based payments

5.9

3.2

6.9

Share of profit in associate

-

(1.9)

(1.9)

Interest revenue and finance gains

(47.4)

(24.9)

(58.5)

Finance costs and other finance expenses

95.1

68.4

196.3

Loss/(profit) on disposal of assets

-

83.9

(2.7)

Operating cash flows before movements in working capital

445.6

589.2

1,055.4

(Increase)/decrease in inventories

(3.7)

4.1

23.0

Decrease/(increase) in receivables

15.8

(84.6)

105.3

Increase/(decrease) in payables

112.6

98.1

(53.6)

Cash generated by operations

570.3

606.8

1,130.1

Income taxes paid

(58.0)

(109.5)

(208.5)

Interest income received

0.7

2.1

2.7

Net cash from operating activities

513.0

499.4

924.3

 

Analysis of changes in net debt:

 

Six months

to 30 June

2015

Unaudited

Six months

to 30 June

2014

Unaudited

Year to

31 December

2014

Audited

 

$ million

$ million

$ million

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

 

 

 

Movement in cash and cash equivalents

80.6

(193.9)

(157.1)

Proceeds from drawdown of bank loans and senior loan notes

(550.0)

(100.0)

(655.0)

Repayment of bank loans

500.8

70.0

100.0

Non-cash movements on debt and cash balances

(1.7)

(12.3)

42.8

Decrease/(increase) in net debt in the period/year

29.7

(236.2)

(669.3)

Opening net debt

(2,122.2)

(1,452.9)

(1,452.9)

Closing net debt

(2,092.5)

(1,689.1)

(2,122.2)

 

b) Analysis of net debt:

 

 

 

Cash and cash equivalents

372.4

255.0

291.8

Borrowings*

(2,464.9)

(1,944.1)

(2,414.0)

Total net debt

(2,092.5)

(1,689.1)

(2,122.2)

 

*

Borrowings consist of the short-term borrowings, 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$0.3 million (December 2014: US$0.4 million) and debt arrangement fees of US$23.0 million (December 2014: US$27.4 million) respectively.

 

11. DEFERRED INCOME

 

In June 2015, Premier received US$100.0 million from FlowStream in return for granting them 15 per cent of production from the Solan field until sufficient barrels have been delivered to achieve the rate of return within the agreement.  This has been recognised as deferred income in the balance sheet and will be released to the income statement as barrels are delivered to FlowStream following first oil from Solan.

 

The portion of the deferred income that is expected to be delivered to FlowStream within the next 12 months has been classified as a current liability.

 

12. FINANCIAL INSTRUMENTS

 

Derivative financial instruments

The group held the following financial instruments at fair value at 30 June 2015. The group has no financial instruments with fair values that are determined by reference to significant unobservable inputs i.e. those that would be classified as level 3 in the fair value hierarchy, nor have there been any transfers of assets or liabilities between levels of the fair value hierarchy.

 

There are no non-recurring fair value measurements.

 

 

 

 

 

At 30 June 2015

$ million

Level 2

$ million

Financial assets:

 

 

 

 

Gas forward sale contracts

 

3.7

3.7

Oil forward sales contracts

 

88.3

88.3

Forward foreign exchange contracts

 

4.5

4.5

Total

 

 

 

96.5

96.5

 

 

 

 

 

 

Financial Liabilities:

 

 

 

 

Forward foreign exchange contracts

 

0.6

0.6

Cross currency swaps

 

 

52.6

52.6

Total

 

 

 

53.2

53.2

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

At 30 June

2014

$ million

Level 2

$ million

Financial assets:

 

 

 

 

Gas forward sale contracts

 

0.3

0.3

Forward foreign exchange contracts

 

1.7

1.7

Cross currency swaps

 

 

14.3

14.3

Total

 

 

 

16.3

16.3

 

 

 

 

 

 

Financial Liabilities:

 

 

 

 

Oil forward sales contracts

 

38.7

38.7

Gas forward sale contracts

 

0.5

0.5

Cross currency swaps

 

 

1.2

1.2

Interest rate swaps

 

 

7.2

7.2

Total

 

 

 

47.6

47.6

 

The fair values were determined from counterparties with whom the trades have been entered into. Fair value is the amount at which a financial instrument could be exchanged in an arm's length transaction, other than in a forced or liquidated sale. Where available, market values have been used to determine fair values. The estimated fair values have been determined using market information and appropriate valuation methodologies.  Values recorded are as at the balance sheet date, and will not necessarily be realised.  Non-interest bearing financial instruments, which include amounts receivable from customers and accounts payable are also recorded materially at fair value reflecting their short-term maturity.

 

Fair value of financial assets and financial liabilities

The carrying values and fair values of the group's non derivative financial assets and financial liabilities (excluding current assets and current liabilities for which carrying values approximate to fair values due to their short-term nature) are shown below.

 

 

 

 

 

At 30 June 2015

Fair value amount

$ million

At 30 June 2015 Carrying amount

$ million

Primary financial instruments held or issued to finance the group's operations:

 

 

Bank loans

 

 

 

1,482.0

1,482.0

Senior loan notes

 

 

516.8

516.8

Retail bond

 

 

 

219.2

235.5

Convertible bonds

 

 

217.5

230.6

 

 

13. EVENTS AFTER THE BALANCE SHEET DATE

 

The group has reached agreement with its lending group to modify its financial covenants until mid-2017.  Further details are provided in the Financial Review.

 

INDEPENDENT REVIEW REPORT TO PREMIER OIL PLC

 

We have been engaged by the company to review the condensed set of financial statements in the half-yearly financial report for the six months ended 30 June 2015 which comprises the condensed consolidated income statement, the condensed consolidated statement of comprehensive income, the condensed consolidated balance sheet, the condensed consolidated statement of changes in equity, the condensed consolidated cash flow statement and related notes 1 to 13. We have read the other information contained in the half-yearly financial report and considered whether it contains any apparent misstatements or material inconsistencies with the information in the condensed set of financial statements.

 

This report is made solely to the company in accordance with International Standard on Review Engagements (UK and Ireland) 2410 "Review of Interim Financial Information Performed by the Independent Auditor of the Entity" issued by the Auditing Practices Board. Our work has been undertaken so that we might state to the company those matters we are required to state to it in an independent review report and for no other purpose. To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the company, for our review work, for this report, or for the conclusions we have formed.

 

Directors' responsibilities

 

The half-yearly financial report is the responsibility of, and has been approved by, the directors. The directors are responsible for preparing the half-yearly financial report in accordance with the Disclosure and Transparency Rules of the United Kingdom's Financial Conduct Authority.

 

As disclosed in note 1, the annual financial statements of the group are prepared in accordance with International Financial Reporting Standard (IFRS) as adopted by the European Union. The condensed set of financial statements included in this half-yearly financial report has been prepared in accordance with International Accounting Standard 34, "Interim Financial Reporting," as adopted by the European Union.

 

Our responsibility

 

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

 

Scope of review

 

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

 

Conclusion

 

Based on our review, nothing has come to our attention that causes us to believe that the condensed set of financial statements in the half-yearly financial report for the six months ended 30 June 2015 is not prepared, in all material respects, in accordance with International Accounting Standard 34 as adopted by the European Union and the Disclosure and Transparency Rules of the United Kingdom's Financial Conduct Authority.

 

Deloitte LLP

Chartered Accountants and Statutory Auditor

London, UK

19 August 2015

 

WORKING INTEREST PRODUCTION BY REGION (unaudited)

 

Six months to

30 June

2015

kboepd

Six months to

30 June

2014

kboepd

Year to

31 December

2014

kboepd

UK:

 

 

 

Balmoral area*

3.4

3.7

3.1

Huntington

6.2

7.8

5.7

Scott/Telford/Rochelle

-

3.8

3.5

Wytch Farm

5.4

5.8

5.6

Other UK

1.9

0.2

1.5

 

16.9

21.3

19.4

Indonesia:

 

 

 

Natuna Sea Block A

11.4

12.1

12.4

Kakap

1.8

1.9

2.0

 

13.2

14.0

14.4

Vietnam:

 

 

 

Chim Sáo

19.6

15.8

16.9

 

19.6

15.8

16.9

Pakistan:

 

 

 

Bhit/Badhra

3.3

3.1

3.0

Kadanwari

2.0

3.5

3.2

Qadirpur

2.8

3.3

3.2

Zamzama

2.2

3.4

3.1

 

 

 

 

Mauritania:

 

 

 

Chinguetti

0.4

0.5

0.4

 

10.7

13.8

12.9

 

 

 

 

TOTAL

60.4

64.9

63.6

* Includes Balmoral, Brenda, Nicol and Stirling  fields.


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

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