PMO.L Regulatory News (PMO)

Annual Results for the year ended 31 December 2015

Tony Durrant, Chief Executive, commented:

"Despite the significant reduction in oil and gas prices, reflected in our results today, 2015 was a year in which we exceeded production guidance, added to reserves, achieved notable exploration success and reached agreement on a value-adding acquisition. We also reduced operating costs by over 25 per cent, significantly cut back on current and future development spend and disposed of negative cash flow assets.

Our forward plan includes further actions to reduce debt, positioning ourselves for a prolonged period of lower oil prices, whilst continuing to take actions to build longer-term value for a recovering commodity environment."

Operational highlights

Financial highlights

There will be a presentation to analysts at the Company's office at 157-197 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: premier@premier-oil.com or telephone: +44 (0)20 7730 1111).

Disclaimer

This results announcement contains certain forward-looking statements that are subject to the usual risk factors and uncertainties associated with the oil and gas exploration and production business. Whilst the Group believes the expectations reflected herein to be reasonable in light of the information available to it at this time, the actual outcome may be materially different owing to factors beyond the Group's control or otherwise within the Group's control but where, for example, the Group decides on a change of plan or strategy. Accordingly, no reliance may be placed on the figures contained in such forward-looking statements.

CHAIRMAN'S STATEMENT

The industry context

2015 was another challenging year for the upstream oil and gas sector. The oil price, having started the year around US$55/bbl, fell to a low of US$36/bbl in December. Post the year-end, the price continued to fall reaching a low of US$27/bbl in January. This has been driven by a number of factors, including the effects of significant investment in unconventional resources in the USA, OPEC's strategy of pursuing market share over price, 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 recover from current levels, as supply will be impacted by the significant reduction in capital investment across the sector, the timing and full extent of any such recovery is difficult to forecast. Consequently, 2015 saw the industry focus on re-setting its cost base and adjusting its expenditure plans in order to withstand such an environment.

Premier's reaction to the low oil price environment

Premier's focus is to invest in high quality production and development opportunities, to maintain exposure to upside value through selective exploration, and to build on our core positions through acquisitions when market conditions allow. In the current oil price environment, the Board's priority has been to take measured actions to reset business plans to meet near-term priorities. Cost and capital discipline remain key to ensuring we are well placed to deliver maximum value from our existing production and current sanctioned developments, Solan and Catcher, as well as preserving the option for long-term growth through our Sea Lion project. Exploration activities in 2016 will be reduced, whilst retaining in Brazil, Mexico and the Falklands the potential for material value creation in future years.

In this environment, Premier has been able to capture sustainable savings in operating costs, defer discretionary capital expenditure and actively manage the portfolio. At the same time, Premier delivered a good operational performance during 2015, with strong production across the portfolio, high levels of operating efficiency and declining operating costs. The Solan development project, which has been a challenging project since sanction, will achieve first oil shortly and the Catcher development project is under budget and on schedule for first oil in 2017.

We have continued to execute our strategy of actively managing our asset portfolio to ensure our capital and people are focused on high returning assets and that our forward financial position is appropriate. The proposed acquisition of E.ON's UK North Sea assets announced since the year-end, is in line with this strategy and continues Premier's track record of being able to add long-term value through acquisitions in low oil price environments. We also disposed of our Norwegian business in 2015, realising immediate value for the Company from long-term asset plays which required near-term investment.

We remain focused on managing our financial position and achieving the highest level of operational and safety performance, whilst maintaining optionality in the portfolio for future growth. During the year, we successfully renegotiated our financial covenants with our banks and bondholders. Our long-term, unsecured debt structure and supportive banking relationships provide considerable balance sheet flexibility. However, if current low oil prices persist, then a further relaxation of our main financial covenants may be required, which we are taking pre-emptive action to address. The proposed acquisition of E.ON's UK North Sea assets provides a significant contribution to current cash flow and is materially covenant accretive. We retain strong relationships with our lending group, and we will continue to work closely with them as we have done throughout 2015.

Health, safety and the environment

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 associated expenditure with these areas. We are very pleased to be able to report that our trend of improved safety performance continued in 2015. Our Total Recordable Injury Rate stood at 1.27 per million man hours, significantly better than our target for the year. We are particularly proud of our track record on our operations in Vietnam and Indonesia which, at year-end 2015, had reached two and four million man hours respectively without a lost time injury. 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 for Environmental/Occupational Safety and Health Management, as did our worldwide Drilling Management Systems. In addition, in December, our Chim Sáo facility in Vietnam was awarded the same accreditation which means that all our production and drilling operations are now accredited to these internationally recognised standards.

People and governance

The composition of the Board remained constant throughout the year with the exception of the retirement of Andrew Lodge, Exploration Director, in June.

Premier continues to comply in full with all aspects of the UK Corporate Governance Code and attaches the highest importance to corporate governance matters. During the year we strengthened a number of areas of corporate governance including the Board's succession planning and evaluation of the appropriate skills, knowledge and experience required for future Board appointments. Further details of the Board's activities this year can be found in the Corporate Governance section of the Annual Report.

On behalf of the Board I would like once again to express my appreciation for the hard work and effort put into the business by Premier's staff. Their continued dedication and enthusiasm in what are trying times for the industry should see us well placed amongst our peers to prosper in the future.

Shareholder returns

Our goal remains to deliver long-term capital growth to our shareholders. Over the course of 2015, our share price fell by 70 per cent, as the whole of the sector suffered from the fall in commodity prices. As we enter 2016 with the potential for a prolonged period of lower oil prices, our focus is on maintaining access to liquidity, lowering our cost base and taking actions to allow us to reduce balance sheet debt once we have completed our sanctioned development projects.

Well positioned for future growth

The oil industry is cyclical and few believe that the oil price will not recover from the current low levels as it has done in the past. Significant levels of capital investment across the industry have been deferred or cut back, which will impact future production and ultimately lead to a revival in the oil price. Our portfolio of 758 mmboe of reserves and resources remains a valuable asset and a basis for future growth. In the meantime, we are managing our business to withstand lower oil prices and I am confident that we will emerge from the current down cycle a leaner, more efficient organisation, in better shape to deliver future shareholder value.

Mike Welton

Chairman

CHIEF EXECUTIVE'S REVIEW

Given the macroeconomic backdrop, it was important that in 2015, Premier remained focused on operational delivery and achieving the near-term priorities that we set ourselves.

As we move into 2016 there remains considerable uncertainty over the direction of oil prices. Premier was quick to react to the fall in the oil price, rationalising our business while retaining our core skills and never compromising the safety or performance of our operations. A low operating cost base ensures that we can operate effectively through a period of low oil prices and positions us well to take advantage of any future recovery.

Generating cash flow from our low cost, efficient production

Premier delivered a robust production performance in 2015, averaging 57.6 kboepd (2014: 63.6 kboepd), in line with expectations and above our market guidance of 55 kboepd. This was driven by high operating efficiency of 90 per cent (2014: 84 per cent) across the Group's assets. The reduction year on year largely reflects the sale of the Scott area production, which contributed 3.8 kboepd in 2014.

*Includes production from Scott area disposed of in December 2014

In Asia, our operated Chim Sáo field in Vietnam continued to outperform, with high levels of operating efficiency, good reservoir performance and strong control of costs. Singapore's demand for our Indonesian gas remained strong and our operated Natuna Sea Block A fields captured a market share well in excess of contractual allocation. Our gas contracts into Singapore generate long-term, stable cash flows for the Group, and we retain additional productive capacity as well as future development opportunities to back fill that deliverability, which will enable us to benefit from any contractual supply shortfall from other suppliers or strengthening of Singapore demand for our gas.

In the UK, all fields produced in line with expectations, with good production efficiency across the portfolio, including Huntington which benefitted from an improved CATS export availability from April onwards. The UK business unit's performance was also aided by the first full year of production from the Kyle redevelopment.

In 2016, we expect group production to be around 65-70 kboepd, reflecting some natural decline in our existing portfolio, offset by new production from the Solan field and a contribution from the E.ON UK assets on completion.

At the start of the year Premier set itself the goal of materially reducing operating expenses across the Group. As a result of significant cost saving initiatives and the sale of the high cost Scott area in the UK, underlying operating costs were US$16/boe (2014: US$18.5/boe), a reduction year-on-year of over US$100 million in absolute terms. Cost reduction initiatives have included optimising work programmes, reducing discretionary spend, sharing services with other operators and re-negotiating contracts with existing suppliers. These initiatives continue and it is anticipated that further savings in underlying operating costs of 5-10 per cent can be achieved in 2016.

As at 31 December 2015 proven and probable (2P) reserves, on a working interest basis, were 332 mmboe (2014: 243 mmboe). The increase reflects the booking of 136 mmboe in respect of the first phase of the Sea Lion field in the Falkland Islands following completion of a draft field development plan, which more than offsets the impact of 2015 production and disposals from our reserve base. Disposals comprised the Block A Aceh disposal at the start of the year and the Vette field, sold as part of the sale of our Norwegian business in December. These disposals demonstrate our ability to monetise discovered resources as part of our strategy of active management of our portfolio.

Executing our key sanctioned development projects

In May 2015 we acquired Chrysaor's 40 per cent interest in the Solan field, West of Shetland, for no upfront cash consideration removing partner funding concerns and, as a result, Premier now holds a 100 per cent equity interest. First oil on the Solan project is expected shortly. This has been a challenging project for Premier with the commissioning of the platform taking longer than planned largely due to significantly worse than anticipated weather conditions West of Shetlands. As a result, costs have been higher and first oil is later than originally planned.

Looking to the future, lessons have been learnt and will be applied to future projects. Following first oil from Solan, our efforts will turn to delivering the second pair of wells later in the first half of 2016, in order to ramp up production at Solan to target plateau production of 20-25 kboepd.  

Key milestones have been achieved on our operated Catcher project during the year, and the project is under budget and scheduled to deliver first oil in 2017. The subsea installation work planned for 2015 was successfully completed and fabrication of the critical subsea equipment, due to be installed in the summer of 2016, is on schedule. Initial development drilling has been encouraging with good reservoir results, and construction of the topside modules is progressing well. Construction of the FPSO hull was initially slower than planned but following actions taken by the FPSO contractor to address scheduling issues, the sail-away date from Singapore for a 2017 field start up remains on schedule.

Once fully on-stream, both the Solan and Catcher projects will contribute materially to our cash flows, given our tax advantaged position in the UK.

Progressing future development projects, retaining future optionality and growth opportunities

We have continued to mature the development plan for the first phase of the Sea Lion project in the Falkland Islands and the pre-FEED work is now complete. The project scope has been modified with a lower break even oil price and significantly enhanced economics. We have begun the FEED exercise alongside the set of world class contractors that we have selected, and we anticipate this will last approximately 18 months. A draft Field Development Plan has been completed and submitted to the Falkland Islands Government, and we have entered into new contractual arrangements with our Sea Lion partner. The timing of the final investment decision remains dependent on achieving our target rate of return, the oil price outlook at the time, the level of cost reductions secured and our ability to fund the project without putting our balance sheet at risk. It remains our intention to seek an additional partner ahead of final investment decision.

In Norway, on the Premier-operated Vette project, extensive project re-work and market engagement was carried out during the course of 2015, generating very competitive offers of commercial terms from the supply chain. Two alternative development concepts were validated but rather than continue to prepare the project for a sanction decision, we agreed to sell the whole of our Norwegian business to Det norske oljeselskap ASA in November for $120 million, realising immediate value from the project.

Refocusing the exploration portfolio and success with the drill bit

In 2015, Premier delivered notable exploration successes, with important discoveries at Zebedee and Isobel Deep in the Falkland Islands and additional resource potential confirmed at Anoa Deep, Indonesia. Post year-end, the re-drill of the Isobel/Elaine complex confirmed the results of the original Isobel Deep exploration well and discovered hydrocarbons in additional reservoir horizons. The successes in the Falklands add significant additional resources to the North Falkland Basin, providing further potential for future phases of development and increasing the attractiveness of the Basin to Premier and to potential future partners. During the year, unsuccessful wells were drilled on our acreage onshore Kenya and offshore Norway.

Our Exploration New Ventures team has taken advantage of the reduced competition for high quality exploration acreage in the current environment, to replenish our portfolio at low cost with minimal near-term commitments, focusing on under-explored but proven hydrocarbon basins. We were pleased to have been awarded two blocks in the proven Sureste basin in Mexico's Round 1, with our interests carried through the initial phase of exploration. At the same time, we have continued to divest and relinquish non-core exploration acreage.

Actively managing our asset portfolio

Post the year-end, Premier agreed to purchase E.ON's UK North Sea assets for a net consideration of US$120 million plus a completion adjustment of US$15 million, resulting in an aggregate cash payment payable of US$135 million. The proposed acquisition significantly enhances our core UK business by adding both cash generative production and reserves and resources at a compelling valuation. It adds stable UK gas revenues to the portfolio and increases Premier's presence in the Central North Sea, including a stake in the producing world class Elgin-Franklin asset and related fields. The acquisition offers the potential to generate significant operating and cost synergies across the combined UK North Sea business and allows Premier to accelerate the realisation of our significant tax assets in the UK. The acquisition is a Class 1 transaction, requiring approval from Premier's shareholders, banks and US Private Placement holders. A circular is expected to be issued to shareholders shortly.

During 2015, we completed the sale of our interest in Block A Aceh onshore Indonesia for US$40 million and our Norwegian business for US$120 million. These disposals form part of our strategy to actively manage our portfolio, disposing of non-core assets where we can realise appropriate value. In addition, the formal sales process for the Pakistan business, which was initiated after an unsolicited approach, is ongoing. A number of bids have been achieved which we continue to evaluate.

Financial discipline and balance sheet focus

Our strong production performance in 2015, together with the benefit of our hedging programme and extensive cost savings, has enabled the Group to deliver strong cash flows from operations of US$809.5 million (2014: US$924.3 million), despite the low oil price during the year. The Group is reporting a loss after tax of US$1,103.8 million in 2015 (2014: US$210.3 million loss after tax) largely as a result of impairment charges of US$558.7 million (post-tax) principally on the carrying value of Solan. These were due to the impact of the lower near-term oil price assumptions used in balance sheet tests at the year-end. Capital expenditure in 2015 was US$1,070.1 million (2014: US$1,195.5 million). In 2016 we expect this to reduce significantly to approximately US$700 million reflecting the reduction in committed expenditure now that the Solan project is nearing completion. In 2017, committed capital expenditure is expected to fall further to approximately US$300 million, reflecting primarily remaining development expenditure on the Catcher project.

The continuing low oil price environment has served to highlight the importance of maintaining a strong funding position and a conservative approach to financing. In order to plan and protect our future cash flows, we have continued with our oil price hedging programme and at the year-end we have approximately 30 per cent of 2016 production hedged at US$68/barrel. The proposed acquisition of the E.ON UK assets adds a significant hedging position to our portfolio, which post completion, means that we maintain approximately 30 per cent of the enlarged 2016 oil entitlement production hedged but at US$73/barrel. Approximately 30 per cent of E.ON's UK gas production is sold forward at an average of 63 pence per therm.

We retain significant funding facilities with cash and undrawn facilities of US$1.2 billion at year-end. During the year we renegotiated our principal financial covenants with banks and bondholders. Ongoing continued compliance with our covenants will remain a key priority for Premier in 2016 and beyond, with covenant headroom in excess of US$900 million at year-end. We continue to benefit from the flexibility of our funding arrangements which are structured on a corporate unsecured basis and are not subject to any redeterminations. However, if current oil prices persist, then a further relaxation of our main financial covenants may be required. We are actively working on a number of mitigating initiatives, including the proposed acquisition of E.ON's UK North Sea assets, which is materially accretive to our lending covenants, and we retain strong relationships with our lending group, with whom we will continue to work closely as we have done throughout 2015.

Looking forward, 2016 will see significantly lower capital expenditure as the Solan project is completed, while at the same time delivering production growth. Our aim is to manage the business such that we are able to maintain the integrity of our production assets, continue to execute our Catcher development within budget and on schedule, protect the optionality for future growth in projects such as Sea Lion even in the current oil price environment and start to deleverage the balance sheet as future cash flows allow. The acquisition of the E.ON assets in the North Sea alongside the rationalisation of our portfolio through the sale of our Norway position and the proposed sale of our Pakistan business, will allow us to focus on and grow our UK and South East Asian asset bases where we have competitively advantaged businesses.

Tony Durrant

Chief Executive

OPERATIONAL REVIEW

INDONESIA

The Premier-operated Natuna Sea Block A delivered stable production into the Singapore gas market with gas demand above the contractual share for GSA1. Initiatives to optimise the cost base for Natuna have been delivered during 2015, with sustainable operating costs of US$8.0/boe.

Production & development

Net production from Indonesia in 2015 on a working interest basis was stable at 13.9 kboepd (2014: 14.4 kboepd). A strong operational performance from the Premier-operated Natuna Sea Block A was offset, in part, by lower production from the non-operated Kakap field.

Premier sold an average of 223 BBtud (gross) (2014: 231 BBtud) from its operated Natuna Sea Block A during 2015:

1. includes production from the Pelikan field

2. includes production from the Naga fields

GSA1 deliveries from Block A were 43 per cent (2014: 45 per cent) of all GSA1 deliveries, above the contractual share of 39.9 per cent. In addition Premier continues to provide additional gas sales of up to 40 BBtud from the Gajah Baru field to the domestic market under a Domestic Swap Agreement (GSA5). In 2015, GSA5 sales were less than expected in the first half of the year due to competition from low price diesel fuel, but increased in the second half. End-users continued to make take or pay payments in full as per the terms of the DSA/GSA.

Gross liquids production from the Anoa field averaged 1.4 kbopd (2014: 1.6 kbopd) and gross liquids production from the non-operated Kakap field averaged 3.5 kbopd (2014: 3.9 kbopd).

Cost reduction initiatives have been delivered through optimisation of work programmes, reduction of discretionary spend, efficiencies through shared services with other operators in the area and contract renegotiations with existing suppliers. Based on current production levels, Natuna A is well placed to deliver operating costs of US$8.0/boe into the medium-term.

The Pelikan field was successfully brought on-stream in March within budget, following first gas from the Naga field in November 2014. The Pelikan and Naga gas fields, which contain 150 bcf of reserves, will maintain the production profiles of GSA1 and GSA2 and these fields are now fully tied into the Gajah Baru facilities. This increased deliverability from Natuna Sea Block A also 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, Iguana and Gajah Puteri projects and an investment decision on these projects is targeted for the fourth quarter of 2016.

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

Exploration

The Anoa West-1 well successfully appraised the Anoa Deep discovery made in 2012, encountering the same gas bearing sandstones in the Lama formation as well as exploring additional deeper reservoir sections that were also found to be gas bearing. Premier continues to mature a number of other leads and prospects elsewhere in the Lama play to drillable status.

Portfolio management

In January 2015, 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.

VIETNAM

The Premier-operated Chim Sáo field out-performed expectations in 2015 with a robust production performance together with substantially reduced operating costs, 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, exceeded expectations, averaging 16.9 kboepd (12.8 kbopd of oil and 19.8 mmscfd of gas) net to Premier. A programme of acidising the reservoir to improve its delivery capacity and increasing the use of gas lift in the wells has helped to maintain production levels similar to those achieved in 2014, assisted by continued high operating efficiency of 87 per cent. Contractual changes, which enhanced the alignment between Premier and our Operations and Maintenance subcontractor, resulted in further improvements in plant reliability and improved business efficiency. 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$11.7/boe, reflecting a 20 per cent year-on-year decrease as a result of a rigorous approach to contract management. Cost savings and efficiency improvements 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; and operating efficiencies, such as changing crew shift patterns and the use of lower cost and more fuel efficient supply vessels.

UNITED KINGDOM

Premier's UK business has delivered a strong production performance from its existing asset base whilst implementing significant operating cost reduction measures across both its operated and non-operated asset portfolio. Commissioning of the Solan platform facilities is almost complete and first oil is expected shortly. Post first oil development activity will focus on the ramp up of Solan production and delivery of the Catcher project in 2017. Once on-stream, production from these new projects will add significantly to Premier's production profile in the North Sea.

Production

Production from Premier's UK fields during 2015 averaged 16.7 kboepd (2014: 15.6* kboepd). Good production efficiency across the portfolio and the first full year of Kyle production since the field was redeveloped offset natural field decline across other assets. This production was delivered at reduced cost with UK unit operating costs of US$30/boe during 2015 (2014: US$37.5/boe). This reduction reflects the operating cost savings achieved across all assets as well as the disposal of the high-cost Scott area assets at the end of 2014. UK G&A costs have also been reduced, reflecting a lower headcount in the business unit.

Production from the Premier-operated Balmoral area averaged 3.1 kboepd (2014: 3.2 kboepd). Improved production efficiency which averaged 83 per cent (2014: 73.1 percent), and the reinstatement of the Stirling well 20z for the majority of 2015 (2014: five months) were offset by natural field decline and the loss of the Balmoral B29 well in July 2015 for mechanical reasons. Operating costs were reduced to US$64.4 million (2014: US$88 million), representing savings from cost efficiencies such as the sharing of logistics with other operators plus reduced G&A allocations. These initiatives are all anticipated to deliver further full year benefits during 2016. In addition, the third-party Beauly well was successfully reinstated during October 2015.

The non-operated Huntington field averaged 6.2 kboepd in 2015 (2014: 5.7 kboepd). Production was constrained in the first quarter due to restrictions on exporting gas through the CATS pipeline system following failure of a topside valve on the CATS riser platform during December 2014. On completion of repair work and subsequent agreement being reached for higher gas export volumes through the CATS system, production rates were increased to higher than anticipated levels before reducing as a result of natural field decline. Production efficiency since April has exceeded 90 per cent.

Production from the non-operated Wytch Farm field averaged 5.2 kboepd (2014: 5.6 kboepd) and was stable during the majority of the year. ESP pump failures on key producer wells and operational issues encountered with the Furzey Island water injection line, led to a marginal reduction on the previous year but, at the year-end, production had been fully restored. Significant operating cost savings were delivered by the operator resulting in a decrease in operating costs to US$32.4 million (2014: US$36.9 million) in spite of the need to conduct the ESP well workovers.

Production from the non-operated Kyle field increased to an average of 2.0 kboepd (2014: 1.0 kboepd), reflecting the first full year of Kyle production since severe storm conditions in December 2011 resulted in damage to the subsea infrastructure and the host Banff FSPO facility. Production recommenced in July 2014 following a two and a half year reinstatement project. The main K14 production well has performed strongly in 2015, although the field suffered some unplanned outages due to gas compression issues on the host Banff field FPSO.

*Note comparatives are stated without divested assets: Scott/Telford/Rochelle fields.

DevelopmentSolan

On the Premier-operated Solan project, the unprecedented weather conditions West of Shetlands have continued to impact the final commissioning of the offshore installation systems required for first oil. Despite this, progress continues to be made and first oil is expected shortly. The first pair of subsea producer-injector wells required for first oil were successfully completed and tied back to the Solan platform during the year. During the year all other subsea work required for first oil was completed, including the tie-in of the subsea oil storage tank. Platform commissioning work delivered the minimum systems required to support first oil including the living quarters, firewater deluge system and other safety related systems, and all the utilities including power, fuel supply and air. Export oil tanker trials were completed in November and platform habitation achieved in January 2016.

The Regalia accommodation vessel provided accommodation facilities to support commissioning work and delivered high productivity and good up time from its arrival on location in August 2015 through to the completion of its contract in November. The Regalia was replaced by the Flotel Superior during November 2015, a vessel better suited to operations West of Shetland during winter conditions. Premier has options over the use of the Flotel Superior which potentially extends its hire to the end of May 2016 if required.

In parallel, drilling of the second pair of producer-injector wells has progressed. Drilling of the second producer well (P2) commenced in July completing over 1,000 feet of the reservoir section. However, mechanical problems were encountered which resulted in the well being suspended during September. The Ocean Valiant rig is currently completing the second injector well (W2) after intersecting some 700ft of high quality reservoir sand, before returning to side-track the second producing well in the second quarter of 2016.

The field is expected to achieve initial production rates of 10-12 kboepd following ramp up from the first producer well, with plateau production rates of 20-25 kpoed when the second producer well is completed and tied-in around mid-year. Cash spend to 31 December on the Solan project stood at US$1.88 billion.

An onshore control room to support Solan operations has been established within Premier's Aberdeen office. This will facilitate a future move to a not permanently manned state with resulting lower operating costs, and is currently anticipated to occur approximately one year after first oil.

Catcher

The Premier-operated Catcher project is progressing under budget and is scheduled to deliver first oil in the second half of 2017. Key milestones have been achieved during the year including the subsea installation work planned for 2015, which was completed with the successful installation of the pipeline end manifold and tow templates at Catcher and Burgman. In addition, the 60 kilometre gas export pipeline was successfully laid and tied in during July with minimal weather downtime. Fabrication of the subsea equipment including flowline bundles and associate towheads, the buoy and the mid water arches (riser buoyancy aids), which are all due to be installed in the summer of 2016, is on schedule.

Drilling activities which started in July using the Ensco 100 rig progressed well, with excellent operational performance. The three Catcher wells, two injectors (CTI1 and CCI2) and one producer (CCP3), all met or exceeded pre-drill expectations in terms of reservoir quality and flow rates. In addition, the injection well tests successfully demonstrated that water can be injected into the field. 

Fabrication of the FPSO hull and topsides is ongoing in Asia, and the sail-away date of the FPSO from Singapore for a 2017 field start up remains on schedule following mitigating actions put in place by the FPSO provider BW Offshore to address initial scheduling issues. The first major FPSO hull section was successfully delivered in December to the yard in Japan from South Korea. Topsides module and turret construction continues to progress well in Batam and Singapore. The FPSO contractor currently plans the commencement of hull and integration work in Singapore from summer 2016.

Exploration

No exploration wells were drilled in 2015, however preparations are underway to drill two wells in the UK North Sea in 2016. Drilling of the Bagpuss/Blofeld heavy oil exploration prospect in the Moray Firth, and the near-field Catcher Field prospect at Laverda-Slough are planned for the first half of 2016. Premier is committed to drilling the Bagpuss/Blofeld appraisal well as part of a prior commercial arrangement to farm into the licence, and the Laverda-Slough well is a licence commitment. The Laverda-Slough well will be drilled using the Ensco-100 rig currently working on the Catcher project, whilst negotiations for the Bagpuss rig commitment are currently in progress. During 2015, Premier continued to high grade and rationalise its UK North Sea exploration portfolio with several licences relinquished or sold.

Portfolio management

In May 2015, Premier successfully acquired Chrysaor's 40 per cent interest in the Solan field for no upfront cash consideration and entered into an agreement with FlowStream Commodities whereby a US$100 million payment was received in return for the proceeds from 15 per cent of production from the field for a period of time. These transactions removed partner funding concerns and reduced the Group's balance sheet exposure to the Solan project.

PAKISTAN

Premier's Pakistan business continued to generate positive and stable net cash flows for the Group. During 2015, the average realised gas price was above US$4/mmscf while operating costs remained low at around US$3.7/boe (US$0.58/mscf).

Production and development

Production in Pakistan averaged 9.7 kboepd (60.2 mmscfd), from Premier's six non-operated producing gas fields.

The fall in production reflects natural decline in the Bhit, Qadirpur, Kadanwari, and Zamzama gas fields only partially offset by higher production from the Badhra field.

Higher production was achieved from the Badhra area with three new wells being brought on-stream which performed better than expected, offsetting natural decline from existing wells. The compressor reconfiguration project at Bhit, designed to improve the ultimate recovery by around 54 billion cubic feet (bcf) (gross), was successfully completed and the results are in line with expectations.

Production from the Qadirpur, Kadanwari and Zamzama fields fell over the year, reflecting natural decline in the fields, below-expectation performance of the new infill wells at the Kadanwari field, and deferment of a development well in Zamzama.

All costs pertaining to Premier's 3.75 per cent working interest in the Zarghun South gas field are carried by the Operator.

Exploration

Premier drilled one exploration well - Bhit South-1 - in Pakistan during the first half of the year. Although gas was encountered, the sands were of poor reservoir quality, and the well was subsequently plugged and abandoned.

MAURITANIA

Production and development

Production from the Chinguetti field averaged 414 bopd (2014: 447 bopd) net to Premier during the year. The fall in production was driven by natural decline from the existing wells. In view of the low oil price and resulting negative cash flows, the joint venture partners have decided to cease production from the field by the end of 2016 and proceed to field abandonment during 2017 and 2018. Field decommissioning plans are being finalised for submission to the government for both the Chinguetti field and the previously relinquished Banda and Tiof discoveries.

FALKLAND ISLANDS

Following the decision to progress a phased development of the Sea Lion field, pre-FEED activities and contractor discussions during 2015 significantly de-risked the project and confirmed a robust and commercial Phase 1 development. In addition, exploration successes at Zebedee and Isobel Deep have highlighted the potential for high value subsequent phases of development in the North Falklands basin.

Development

During the course of 2015, Premier continued to mature the development plan for the Sea Lion Phase 1 development and the pre-FEED work, which is now complete, has further optimised the project. As a result, this initial phase will target 220 mmbbls of reserves in the north-east and north-west of PL032.

During the pre-FEED work, the designs of both the FPSO and the Subsea Systems evolved and it is now planned that a leased FPSO with 18 subsea wells (drilled with a conventionally moored mobile offshore drilling unit) from a single drill centre, will recover 220 mmbbls of oil over 20 years (a 37 per cent increase on the 160 mmbbls previously announced). Despite the increase in scope, the estimate of pre-first oil capex requirement remains at US$1.8 billion, reflecting significant cost reductions in the current market, and total expected development capex per barrel has reduced from US$14 to US$11/bbl. The technical and cost improvements and efficiencies identified during pre-FEED work have resulted in a lower break-even oil price for the project and have significantly improved the overall project economics.

As part of the pre-FEED activities, tendering exercises were completed and a set of world class preferred contractors selected for the provision of the FPSO and subsea facilities. Premier has entered into contracts with SBM Offshore covering the FEED for the FPSO, and the subsequent provision of the FPSO on a lease and operate basis (contingent on project sanction being achieved). Contracts have also been awarded to Subsea 7 for SURF Transport and Installation, and to National Oilwell Varco for Flexibles. It is expected that the SPS FEED contract will be awarded during Q1 2016.

It is planned that the FEED programme will last approximately 18 months and during this period Premier will work with these contractors to further optimise the design and fabrication plans for the facilities, and will also select the drilling and well service contractors. The construction of the FPSO will be financed by the FPSO provider and Premier is exploring the use of a similar leasing scheme for the subsea system. The timing of the final investment decision remains dependent on the economics of the project and in particular the oil price outlook.

A draft Field Development Plan has been submitted to the Falkland Islands Government ("FIG") for comment. An application has also been made to FIG to extend the licence for the Sea Lion discovery area in PL032.

Premier and Rockhopper executed an amendment to the 2012 Sale and Purchase Agreement ("SPA") which supersedes the Heads of Agreement announced in November 2014. The terms of this agreement allow Rockhopper to utilise the full exploration carry under the current exploration campaign whereas the development carry of US$674 million will be split equally between phase 1 and the next development phase. Rockhopper will pay a Guarantee Fee to Premier of US $15.9 million per quarter for five years from first oil. Either party may renegotiate this amount at the time of project sanction if they believe it results in an apportionment of value that is significantly different from 50/50. Instead of the financing arrangements in the original SPA, Premier will provide Rockhopper with a Standby Loan Facility of up US$750 million (at a 15 per cent interest rate), although it is anticipated that Rockhopper will continue to review alternative financing sources. Premier will also continue to progress the development financing arrangements during FEED, and this work will include a farm down process to bring in an additional upstream partner.

An overall development strategy for the entire basin has been matured. A subsequent phase 2 will develop the 300 mmbbls remaining reserves in PL032 and the satellite accumulations in the north of PL004. Phase 3 will entail the development of the Isobel/Elaine fan complex in the south of PL004.

Exploration

Premier's four-well North Falklands Basin campaign, targeting multiple stacked fans in PL004 and PL032, commenced in March using the Eirik Raude rig. The Zebedee well in PL004 was declared a discovery having penetrated multiple targets in the Cretaceous F2 and F3 formations with a total hydrocarbon net pay of 136 feet, adding around 60 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 opened up a new play in the previously unexplored southern part of PL004.

Following operational difficulties the Isobel Deep well was suspended and the Eirik Raude rig transferred to another operator in the South Falkland Basin. The rig returned to the North Falkland Basin late in the fourth quarter to complete the final two wells of our programme. Agreement was reached between the joint venture partners and the Falkland Islands Government to replace drilling the Jayne East prospect in PL004 with a re-drill of the Isobel prospect. The well, 14/20-2, confirmed the results of the original Isobel Deep exploration well and in addition discovered hydrocarbons in shallower sandstone units.

As a result of material operational issues experienced with the Eirik Raude rig during its contract, Premier and Noble Energy terminated the contract with Ocean Rig in February 2016. The last well of the four-well campaign, the Chatham exploration well, will no longer be drilled in the current campaign although it is planned that this prospect will be drilled at the same time as the Sea Lion development. 

Portfolio management

Premier anticipates initiating discussions with potential co-investors in its Sea Lion development during the course of the FEED process. .

NEW COUNTRY ENTRY - 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 2018 and beyond. In these new countries Premier has a disciplined approach to investment ensuring that cost exposure in the exploration phase is minimised and only the best opportunities are matured to drill-ready status.

Mexico

In July 2015 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 partnership with Talos Energy (45 per cent operator) and Sierra Oil and Gas (45 per cent). The blocks are located in the shallow water Sureste Basin in the Gulf of Mexico, one of the world's most prolific hydrocarbon provinces and the most important in Mexico's history, having produced nearly 50 billion barrels of oil equivalent to date. Large parts of the basin remain under-explored, particularly in comparison to the US Gulf of Mexico. One such area is the Salinas sub-basin where Blocks 2 and 7 are located and where light oil will be targeted in Tertiary clastic reservoirs. The existing 3D seismic data will be reprocessed in 2016, with new data acquired if necessary in 2017, ahead of exploratory drilling in 2017/18. Premier is carried on each of the blocks up to the point of the first well when it has the option to increase its interest to 25 per cent prior to drilling. 

The award of Blocks 2 and 7 represents the first time in 75 years that Mexico's upstream sector has been open to private investment. Further opportunities are expected to follow in 2016 and beyond, and therefore Premier will be well placed, should it wish to invest and grow further in Mexico in the longer term.

Brazil

In April, Premier increased its footprint in the Ceará Basin, our focus basin in Brazil, by farming into CE-M-661 for a non-operated 30 per cent equity interest at no upfront cost. With its 50 per cent operated interest in CE-M-717 and CE-M-665, Premier is now the largest net-acreage holder in the basin and is well placed to target the emerging Cretaceous play fairway. Multi-client 3D seismic acquisition across all of Premier's blocks was carried out during 2015. Interpretation of these 3D seismic surveys will take place in 2016, in order to identify drilling targets for the end 2017/18 drilling campaign.

In the Foz do Amazonas Basin, where Premier holds a 35 per cent non-operated interest in block FZA-M-90, interpretation of new 3D seismic data continues. Drilling targets will be matured in 2016.

Portfolio management

Premier has continued to divest or relinquish non-core exploration acreage in the UK and internationally. On 14 December 2015, Premier signed an agreement with Bashneft International B.V. whereby Premier will assign its participating interest share in Iraq, Block 12 back to Bashneft, the current operator. Completion of the assignment remains subject to receiving government consents.

In May 2015, Premier withdrew from Block 2B onshore Kenya following the drilling of the unsuccessful Badada-1 well and consequently no longer has an acreage position in Kenya.

FINANCIAL REVIEW

Financial overview

After the sharp fall in crude oil prices in the second half of 2014, oil and gas prices remained low throughout 2015. Brent opened the year at US$55.0/bbl and despite increasing to US65.7/bbl in May 2015, the average for 2015 was US$52.4/bbl against US$98.9/bbl for the prior year, with a closing price of $35.7/bbl at the end of the year. The early part of 2016 has seen oil prices fall to further lows not seen for many years.

Against this economic backdrop our production averaged 57.6 kboepd, ahead of our full year guidance of 55 kboepd per day (2014: 63.6 kboepd), resulting in revenue of US$1,067.2 million compared with US$1,629.4 million in 2014. Revenue for the year includes US$278.9 million (2014: US$46.0 million) for forward sales which have settled in the year.

The deterioration in the oil price environment has led to downward pressure on operating and development costs. Combined with the significant cost saving initiatives launched by Premier, operating costs have reduced by over US$100 million year-on-year to US$323.6 million (2014: US$436.1 million). Gross G&A costs for 2015 were approximately $230 million a reduction from almost US$300 million in 2014, resulting in net G&A costs to Premier of US$14.4 million (2014: US$25.4 million).

EBITDAX for the year was US$751.6 million compared to US$1,073.8 million for 2014 (as previously reported). The lower EBITDAX is mainly due to lower oil prices realised and a reduction in volumes lifted due to the disposal of the Scott area assets in the UK.

Operating cash flows remain strong at US$809.5 million (2014: US$924.3 million). Included within this balance is US$100 million received by Premier from FlowStream Commodities accounted for as deferred revenue 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.

Net debt at 31 December 2015 amounted to US$2,242.2 million (2014: US$2,122.2 million), with cash resources of US$401.3 million (2014: US$291.8 million).

In August 2015, Premier reached agreement with its lending group to modify its financial covenants until mid-2017. Under this agreement our financial covenants have been modified as follows:

These covenants are tested at 30 June and 31 December each year, based on EBITDAX for the previous 12 month period.

Premier does not have any significant debt maturities until late 2017 and all debt is unsecured.

Income statement

Production and revenue

Group production on a working interest basis averaged 57.6 kboepd compared to 63.6 kboepd in 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 53.4 kboepd (2014: 57.5 kboepd).

Premier realised an average price for the year of US$52.6/bbl (2014: US$98.2/bbl) after taking into account timings of actual liftings and export duties paid in Vietnam. Post hedging, realised prices increased to US$79.0/bbl (2014: US$101.0/bbl).

Average gas prices for the group were US$5.9 per thousand standard cubic feet (mscf) (2014: US$8.4/mscf). Gas prices in Singapore, linked to high sulphur fuel oil (HSFO) pricing and in turn, therefore, linked to crude oil pricing, averaged US$9.4/mscf (2014: US$16.8/mscf). The average price for Pakistan gas (where only a portion of the contract formulae is linked to energy prices) was US$3.9/mscf (2014: US$4.6/mscf).

Total sales revenue from all operations fell to US$1,067.2 million (2014: US$1,629 million), due to the fall in average realised prices and the lower year on year production.

Operating costs

Cost of sales comprise cost of operations, change in lifting position, inventory movement, royalties and amortisation and depreciation of property plant and equipment ("PP&E"). Cost of sales for the group was US$661.0 million for 2015, compared to US$986.1 million for 2014.

 The reduction in unit operating costs year on year were due to improved operating efficiency across several of the company's assets, active cost management with our suppliers and disposal of the high cost Scott area of assets. Underlying unit amortisation fell to US$14.8/boe (2014: US$19.9/boe).

Impairment of oil and gas properties

The sustained low in spot and forward oil prices has inevitably had an impact on our reported financial results in respect of the carrying value of certain of our oil and gas assets. An impairment charge has been booked in the income statement relating to several of our fields in the UK North Sea, Indonesia and Pakistan. The total amount for the impairment (pre-tax) is US$1,023.7 million (US$583.5 million post-tax) (2014: US$784.4 million (pre-tax), US$327.8 million (post-tax)).

Impairment charges for the year, relating to UK fields, amounted to US$998.5 million (pre-tax) (2014: US$732.3 million), and were recognised principally for the Solan field in addition to a number of other producing assets in the UK, while the remaining impairment charge of US$25.7 million was recognised in respect of the Kakap field in Indonesia and the Kadanwari field in Pakistan. After the recognition of the impairment charges there is US$2,611.7 million capitalised in relation to PP&E assets and US$240.8 million for goodwill.

The principal cause of the impairment charge is a further reduction in the short to medium-term oil price assumption used in estimating the future discounted cash flows for each field and an increase earlier in the year in the expected cost to complete and future decommissioning costs attributable to the Solan development.

Exploration expenditure and pre-licence costs

Exploration expense and pre-licence expenditure costs amounted to US$109.0 million (2014: US$71.5 million, restated). This includes the write-offs relating to the unsuccessful Badada-1 well drilling costs in Kenya (US$30.9 million), the Bonneville uncommercial discovery in the UK (US$21.0 million) and licence costs held for Iraq (US$20.8 million). After recognition of these expenditures, the exploration and evaluation asset remaining on the balance sheet at 31 December 2015 is US$749.7 million.

General and Administrative Expenses

The group general and administrative ("G&A") costs on a gross basis were significantly reduced year-on-year at US$231.7 million (2014: US$298.5) million, resulting in net G&A costs to the group of US$14.4 million (2014: US$25.4 million).

Finance gains and charges

Interest revenue and finance gains reduced to US$40.7 million from US$57.1 million (restated) in 2014. The principal reason for this reduction is the fall in accrued interest receivable from JV partner for the Solan development, which ceased to be accrued by us on completion of the asset acquisition of Chrysaor's 40 per cent interest in Solan in May 2015. Gross finance costs, before interest capitalisation, which included unwinding of the discount on decommissioning, were reduced to US$221.8 million from US$238.5 million. Interest costs capitalised increased by US$16.6 million to US$58.8 million reflecting increased development expenditure on the Solan and Catcher assets.

Taxation

The group's total tax charge for 2015 is US$241.1 million (2014: US$173.7 million credit as previously reported, US$136.5 million restated) which comprises a current tax charge for the period of US$98.6 million and a non-cash deferred tax charge for the period of US$142.5 million.

The total tax charge for the period includes a number of material tax items arising in the UK. These include the effects of the UK Supplementary Charge to Tax rate reduction from 32 per cent to 20 per cent on the opening deferred tax asset balance (US$167.2 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 allowances due to the prevailing low oil price environment. In addition an element of the group's UK impairment charge for the period is treated as a permanent difference which results in a reduction in the impairment deferred tax credit.. The group has a net deferred tax asset of US$678.3 million at 31 December 2015 (2014: US$717.5 million).  

Discontinued operations

Premier agreed to sell its 100 per cent stake in Premier Oil Norge AS ("PONAS") which comprises all its Norwegian assets, to Det norske oljeselskap ASA for a cash consideration of $120 million, which was received in December 2015 on completion of the transaction.

As Norway was a separate operating segment, the results for this business unit have been presented as a discontinued operation for the year and prior year comparatives restated on the same basis. The loss after tax for the year, including a loss on disposal recognised of US$29.2 million, was US$33.1 million.

Loss after tax

Loss after tax is US$1,103.8 million (2014: US$210.3 million) resulting in a basic loss per share of 216.1 cents from continuing and discontinued operations (2014: 40.3 cents).

Acquisitions and disposals

In May 2015, 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 recognises 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 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.

Under the terms of the transaction, Premier 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 recover the loan previously advanced to Chrysaor and/or a 40 per cent share of the total project capital expenditure.

At year end, using the Group's updated long term planning assumptions, the fair value of the contingent consideration payable to Chrysaor reduced to US$24.1 million. The change in fair value of US$31.9 million has been recognised as other operating income.

Separately, combined cash of US$219.6 million was received from the completion of the disposals of Block A Aceh onshore Indonesia and the Scott area assets in the UK (both of which completed in January 2015) and the sale of the Norway business unit (completed in December 2015).

Cash flow

Cash flow from operating activities was US$809.5 million (2014: US$924.3 million) after accounting for tax payments of US$94.0 million (2014: US$208.5 million).

Capital expenditure in 2015 totalled US$1,070.1 million, including US$77.9 million advanced to Chrysaor prior to the acquisition of their 40 per cent share in Solan (2014: US$1,513.9 million).

The principal development projects were the Solan and Catcher fields in the UK. Exploration expenditure mainly related to our exploration campaign in the Falkland Islands.

Balance sheet position

Net Debt

Net debt at 31 December 2015 amounted to US$2,242.2 million (2014: US$2,122.2 million), with cash resources of US$401.3 million (2014: US$291.8 million).

^ The carrying amounts 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 (2014: US$0.4 million) and debt arrangement fees of US$28.1 million (2014: US$27.4 million) respectively.

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, repaid a US$300 million term loan maturing in the second quarter of 2015 and repaid €20 million of the Schuldschein notes. Premier retains significant cash and undrawn facilities which, at 31 December 2015, were US$401.3 million and c.US$850 million respectively.

Deferred income

Deferred income of US$108.5 million has been recognised on the balance sheet representing the initial US$100.0 million of cash proceeds received from FlowStream and a finance expense of US$8.5 million reflecting the period of time from the completion of the deal until the year end. This deferred income will be released to the income statement as barrels are delivered to FlowStream post first oil from Solan.

Provisions

The group's decommissioning provision increased to US$1,062.6 million at 31 December 2015, up from US$871.3 million at the end of 2014, principally due to an increase in the expected cost of decommissioning the Solan and Chinguetti assets and the recognition of a decommissioning provision on Catcher as the development project has progressed.

In addition, contingent consideration payable to Chrysaor following the asset acquisition of the 40 per cent interest in Solan has been recognised. The fair value of this future payment at 31 December 2015 was US$24.1 million, with the movement since the acquisition date of US$31.9 million being recognised as other operating income in the year.

Financial risk management

Commodity prices

At year-end, 3.7 mmbbls of Dated Brent oil were hedged through forward sales for 2016 at an average price of US$68.3/bbl. This volume represents approximately 27 per cent of the Group's expected liquids entitlement production in 2016. 72,000 metric tonnes (mt) of HSFO, which drives our gas contract pricing in Singapore, has been sold forward for 2016 at an average price of US$400.0/mt. These hedges cover approximately 10 per cent of our expected Indonesian gas entitlement production for 2016.

The year-end fair value on the commodity swaps was an asset of US$114.3 million (2014: US$273.4 million), which is expected to be released to the income statement during 2016 as the related barrels are lifted.

During 2015, forward oil sales of 5.6 mmbbls, and forward fuel oil sales of 120,000 mt expired resulting in a net credit of US$278.9 million (2014: US$46.0 million) which has been included within sales revenue for the year.

Foreign exchange

Premier's functional and reporting currency is US dollars. Exchange rate exposures relate only to local currency receipts, and expenditures within individual business units. Local currency needs are acquired on a short-term basis. At the year-end, the Group recorded a mark-to-market loss of US$19.1 million on its outstanding foreign exchange contracts. The Group currently has £150.0 million retail bonds, €60.0 million long-term senior loan notes and £100.0 million term loan in issuance which have been hedged under cross currency swaps in US dollars at average fixed rates of US$1.64:£ and US$1.37:€.

Interest rates

The Group has various financing instruments including senior loan notes, convertible bonds, UK retail bonds, term loans and revolving credit facilities. As at year-end, 61 per cent of total borrowings is fixed or has been fixed using the interest rate swap markets. On average, the cost of drawn funds for the year was c.3.5 per cent. Mark-to-market credits on interest rate swaps amounted to US$7.7 million (2014: credit of US$6.8 million), which are recorded as movements in other comprehensive income.

Insurance

The Group undertakes a significant insurance programme to reduce the potential impact of physical risks associated with its exploration, development and production activities. Business interruption cover is purchased for a proportion of the cash flow from producing fields for a maximum period of 18 months. During 2015, claims amounting to US$10.2 million were agreed in relation to umbilical damage on Dua (Chim Sáo) and re-drill costs on Rochelle, which occurred in 2013.

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 year-end, the Group had significant headroom on its borrowing facilities and related covenants. However, although the Group expects to have sufficient availability of liquidity under these existing facilities during the next 12 months, the Group's projections currently indicate, unless mitigating actions can be taken, that a breach of one of the financial covenants within the Group's borrowing facilities is likely to arise in respect of the testing period ending 30 June 2016. If an agreement cannot be reached with the Group's principal lenders in relation to the amendment or relaxation of such covenants and a covenant breach therefore occurs then, under the terms of the group's borrowing facilities, the Group's debt holders on all of the Group's facilities will have the right to request re-payment of the outstanding debt from October 2016 onwards and to cancel the relevant facilities.

The Group continues to work towards the completion of the acquisition of the E.ON E&P UK assets. If this transaction completes, it is expected to have a significant positive effect on the Group's near term financial covenant calculations. However, at current oil prices, in the absence of other mitigating actions, this is unlikely to fully mitigate any potential covenant shortfall in respect of the testing period ending 30 June 2016. Therefore, the Group will seek to modify or temporarily waive the existing covenants, ahead of the end of the testing period.

The risk that the Group will be unable to either achieve appropriate mitigating actions prior to 30 June 2016 or secure an appropriate relaxation or amendment of its financial covenants in order to avoid a breach of covenant is a material uncertainty which the Financial Reporting Council Guidance on Risk Management, Internal Control and Related Financial and Business Reporting requires us to report may cast significant doubt upon the Company's ability to continue to apply the going concern basis of accounting.

Nevertheless, after making enquiries and considering the uncertainties described above, the Directors have a reasonable expectation that the Group will avoid a covenant breach. Therefore, the Group and Company are expected to have adequate resources to continue in operational existence for the foreseeable future, being at least the next 12 months from the date of approval of the 2015 Annual Report and Accounts. Accordingly, the Directors continue to adopt the going concern basis of accounting in preparing these consolidated 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 and with whom we interact and our reputation. Premier therefore has a comprehensive approach to risk management.

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

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

The group has identified its principal risks for the next 12 months as being:

· Commodity price volatility;

· Production and development delivery;

· Financial discipline and governance;

· Health, safety, environment and security (HSES);

· Joint venture partner alignment;

· Host government - political and fiscal risks;

· Organisational capability; and,

· Exploration success and reserves addition.

Further information detailing the way in which these risks are mitigated is provided on the company's website (www.premier-oil.com).

CONSOLIDATED INCOME STATEMENT

For the year ended 31 December 2015

*Restated for discontinued operations

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

For the year ended 31 December 2015

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

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

CONSOLIDATED BALANCE SHEET

As at 31 December 2015

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

For the year ended 31 December 2015

* 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 2015

NOTES TO THE PRELIMINARY FINANCIAL STATEMENTS

For the year ended 31 December 2015

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 24 February 2016.

The financial information for the year ended 31 December 2015 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 2014 were approved by the Board of Directors on 25 February 2015 and delivered to the Registrar of Companies and those for 2015 will be delivered following the company's Annual General Meeting (AGM). The auditor has reported on the 2015 accounts; the report was unqualified, but did include a reference to a matter to which the auditor drew attention by way of emphasis of matter around going concern.

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 2016.

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.

The financial statements have been prepared on the going concern basis. Further information relating to the use of the going concern assumption, including details of a related material uncertainty due to the risk of a covenant breach in respect of the testing period ending at 30 June 2016, is provided in the "Going Concern" section of the Financial Review.

Accounting policies

The accounting policies applied in this announcement 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 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 financial statements for the year ended 31 December 2015.

2. Operating segments

The Group's operations are located and managed in six business units; namely the Falkland Islands, Indonesia, Pakistan (including Mauritania), the United Kingdom, Vietnam and the Rest of the World. The results for Norway, which was sold during the year are reported as a discontinued operation for both periods.

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

The Group is engaged in one business of upstream oil and gas exploration and production.

* 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.

Out of the total Group worldwide sales revenues of US$1,067.2 million (2014: US$1,629.4 million), revenues of US$535.1 million (2014: US$688.8 million) arose from sales of oil and gas to customers located in the UK.

Included in assets arising from the United Kingdom segment are non-current assets (excluding deferred tax assets) of US$2,137.5 million (2014: US$2,246.7 million) located in the UK. Included in depreciation, depletion, amortisation and impairment are impairment charges in relation to the UK (US$997.7 million), Pakistan (including Mauritania) (US$7.8 million) and Indonesia (US$17.9 million).

Revenue from two customers (2014: four customers) each exceeded 10 per cent of the Group's consolidated revenue and amounted respectively to US$132.5 million arising from sales of crude oil (2014: US$436.1 million, US$157.2 million and US$204.5 million) and US$166.7 million arising from sales of gas (2014: US$284.3 million) across all operating segments.

3. Cost of sales

4. Tax

* The UK corporation tax current tax credit of US$2.3 million consists of a UK tax refund relating to decommissioning costs incurred in 2015 and carried back to prior periods.

The tax charge for the year can be reconciled to the loss per the consolidated income statement as follows:

^ The 2014 column is as reported in the 2014 Annual Report and has not been restated for the Norway discontinued operation.

The weighted average rate is calculated based on the tax rates weighted according to the profit or loss before tax earned by the Group in each jurisdiction. The change in the weighted average rate year-on-year relates to the mix of profit and loss in each jurisdiction including a reduction in the standard tax rate on UK ring fence profits to 50 per cent (2014: 62 per cent). Tax not related to profit before tax includes the impact of a ring fence expenditure supplement claim in the UK (US$150.8 million), partially offset by the impact of the UK PRT charge.

5. Deferred tax

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

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

The Group's deferred tax assets at 31 December 2015 are recognised to the extent that taxable profits are expected to arise in the future against which tax losses and allowances in the UK can be utilised. In accordance with paragraph 37 of IAS 12 - 'Income Taxes' the group re-assessed its deferred tax assets at 31 December 2015 with respect to ring fence tax losses and allowances. The corporate model used to assess the extent to which it is appropriate to recognise the Group's UK tax losses as deferred tax assets was re-run, using an oil price assumption of Dated Brent forward curve in 2016 and 2017, US$65/bbl in 2018 followed by US$80/bbl 'real' terms thereafter. The results of the corporate model demonstrated that it was appropriate not to recognise deferred tax asset on US$1.1 billion (2014: US$96.0 million) of the group's UK ring fence corporate tax losses at 31 December 2015 based on expected future profitability. The increase in the unrecognised loss amount results in a deferred tax charge of US$95.4 million for the year in respect of losses and allowances that were previously recognised as a deferred tax asset.

In addition to the above, there are carried forward non-ring fence UK tax losses of approximately US$303.5 million (2014: US$263.1 million) and current year non-UK tax losses of approximately US$18.4 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.

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.

During the period the rate of supplementary tax charge on UK ring fence profits was reduced from 32 per cent to 20 per cent with effect from 1 January 2015. Deferred tax balances at 31 December 2015 have been recognised at the reduced rate and a deferred tax charge of US$167.1 million has been recognised in the income statement to reflect the decrease in the opening deferred tax assets at 1 January 2015. Legislation was enacted in the period that will reduce the rate of petroleum revenue tax from 50 per cent to 35 per cent from 1 January 2016, and a credit of US$3.3 million has been recognised in the income statement as a result of the reduction in the deferred petroleum revenue tax liability recognised at 31 December 2015.

6. Loss per share

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

There were 40.7 million anti-dilutive potential Ordinary Shares in 2015 (2014 : 37.1 million) mainly comprising shares to be issued on conversion of convertible bonds.

7. Intangible exploration and evaluation ('E&E') assets

* Disposals in the prior year were for the Group's interest in the PL359 licence in Norway.

^ The 2014 exploration expense has not been restated for the Norway discontinued operation.

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. Assets written off in the year include costs previously capitalised for the Bonneville prospect in the UK (US$21.0million), Block 2B in Kenya (US$30.9 million) and Iraq (US$20.8 million). The outcome of ongoing exploration, and therefore whether the carrying value of E&E assets will ultimately be recovered, is inherently uncertain.

The disposal in 2015 is for E&E costs that were held in relation to the Group's Norway business unit.

8. Property, plant and equipment

* Finance costs that have been capitalised within oil and gas properties during the year total US$58.8million (2014: US$42.2 million), at a weighted average interest rate of 4.4 per cent (2014: 4.4 per cent). Other fixed assets include items such as leasehold improvements, motor vehicles and office equipment.

During the year 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 40 per cent share of the total project capex.

The consideration for the acquisition was US$614.8 million, representing the fair value at the transaction date 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 at the date of the transaction (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 at 31 December 2015. 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 and has been reduced to US$24.1 million at year end. The Group completed the disposal of its interests in Block A Aceh in Indonesia and the Scott area in the UK, receiving total cash of US$82.7 million. 

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.

Impairment

The impairment charge in the current year relates to the Balmoral area (US$4.8 million), Huntington (US$80.5 million), Kyle (US$21.6 million) and Solan (US$891.0 million) fields in the UK, the Kadanwari field in Pakistan (US$7.8 million) and the Kakap field in Indonesia (US$17.9 million). The impairment charge of US$1,023.7 million was calculated by comparing the future discounted pre-tax cash flows expected to be derived from production of commercial reserves (the value-in-use) with 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 2016 and 2017, US$65/bbl in 2018 and US$80/bbl in 'real' terms thereafter and were discounted using a pre-tax discount rate of 8 per cent for the UK assets (2014: 10 per cent) and 12.5 per cent for the non-UK assets (2014: 12.5 per cent). Assumptions involved in impairment measurement include estimates of commercial reserves and production volumes, discount rates, future oil and gas prices and the level and timing of expenditures, all of which are inherently uncertain. The principal cause of the impairment charge being recognised in the year is a reduction in the short to medium term oil price assumption used when determining the future discounted cash flows for each field. In addition to the impact of the reduced oil price assumption, an increase in the expected decommissioning costs for the Solan field in the first half of 2015 has also driven part of the impairment charge, together with an increase in the expected costs to complete the project.

The recoverable amount of the assets that have been impaired in the year, based on the value-in-use assumptions set out above are: Balmoral area US$10.5 million, Solan US$1,106.9 million, Huntington US$12.4 million, Kyle US$15.0 million, Kadanwari US$6.2 million and Kakap US$5.8 million.

Goodwill

Goodwill of US$240.8 million has been specifically assigned to the Catcher field in the UK, which is considered the cash-generating unit for the purposes of any impairment testing of this goodwill. The Group tests goodwill annually for impairment, or more frequently if there are indications that goodwill might be impaired. The recoverable amounts are determined from value-in-use calculations with the same key assumptions as noted for the impairment calculations above. The discount rate used is 8 per cent (2014: 10 per cent). The value-in-use forecast, which is formally approved by management, takes into consideration cash flows which are expected to arise during the life of the Catcher field as a whole, currently expected to be around 2030. This period exceeds five years but is believed to be appropriate as it is underpinned by estimates of commercial reserves provided by our in-house reservoir engineers using industry standard reservoir estimation techniques.

The headroom between the recoverable amount and the carrying amount, including the goodwill, is US$3.5 million. If the long-term oil price assumption used to determine the value-in-use of the Catcher field is reduced from 2017 onwards, the recoverable amount of the Catcher field would be below its carrying value, including the goodwill, and would give rise to an impairment loss.

Sensitivity

A 1 per cent increase in the discount rates used when determining the value-in-use for each asset would result in a further impairment charge of approximately US$60 million and a US$1/bbl reduction to the oil price for the life of field for each asset would trigger an increase in the impairment charge of approximately US$80 million.

9. 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. As this is a contract to deliver a non-financial item, 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. Although no barrels have been delivered to date, under the terms of the deal, the balance had increased by year end to US$108.5 million, with the resulting charge being recorded within finance costs.

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.

10. Notes to the cash flow statement

* 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$0.3 million (2014: US$0.4 million) and debt arrangement fees of US$28.1 million (2014: US$27.4 million) respectively.

11. Subsequent Events

In January 2016, the Group announced it had reached agreement to purchase the Eon E&P UK assets for US$120.0 million. The transaction is subject to shareholder approval, lender consent and regulatory approvals and is expected to complete in 1H 2016.

12 External audit

This preliminary announcement is consistent with the audited financial statements of the group for the year-ended 31 December 2015.

13 Publication of financial statements

It is anticipated that the full Annual Report and Financial Statements will be published in April 2016. Copies will be available from this date at the company's head office, 23 Lower Belgrave Street, London SW1W 0NR, and on the company's website (www.premier-oil.com).

14 Annual General Meeting

The Annual General Meeting will be held at the Institute of Directors, 116 Pall Mall, London SW1Y 5ED on Wednesday 11 May 2016 at 11.00am.

OIL AND GAS RESERVES

Working interest reserves at 31 December 2015

Notes:

1 Includes revisions to reserves based on reevaluation of production performance and drilling results in Chim Sao & Dua (Vietnam); Anoa, Gajah Baru, Pelikan & Naga (Indonesia); Wytch Farm & Huntington (UK); Bhit, Badhra, Kadanwari, Qadipur & Zamzama (Pakistan). Includes downward revisions on Balmoral,Brenda, Nicol and Stirling associated with earlier assumed Cessation of Production. Sea Lion Phase 1 development has been reclassified from Contingent Resource to Reserves ('Justified for Development').

2 Discoveries at Zebedee and Isobel Deep (Falkland Islands) are classifed as contingent resources and do not appear in this table.

3 Divestment of Vette (Norway) and Block A Aceh assets (Indonesia), and the acquisition of the additional 40 per cent equity interest in Solan (UK).

4 Proved plus Probable gas includes 99bcf of fuel gas reserves.

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 315.5 mmboe as at 31 December 2015 (2014: 218.1 mmboe). This was calculated at year-end 2015 using an oil price assumption equal to US$42/bbl in 2016, US$48.5/bbl in 2017, US$65/bbl in 2018 and US$80/bbl in 'real' terms thereafter (2014: Dated Brent 2015: US$61.5/bbl, 2016: US$69/bbl and US$85/bbl in 'real' terms thereafter).