PMO.L Regulatory News (PMO)

PREMIER OIL PLC

("Premier" or "the Company")

Trading and Operations Update

13 January 2016

Premier today provides the following Trading and Operations Update ahead of its 2015 Full Year Results which will be announced on Thursday 25 February 2016.

Highlights

· Proposed acquisition of E.ON's UK North Sea assets for a consideration of $120 million, funded from existing cash resources, announced separately this morning

· Production for 2015 averaged 57.6 kboepd; 2016 guidance of 65-70 kboepd, including the proposed acquisition

· Progress continues on Solan commissioning; platform occupation achieved but first oil now expected in February due to unprecedented weather conditions;

· The Catcher project remains on schedule and on budget; ongoing development drilling results encouraging

· Sea Lion Phase 1a project scope modified with lower break-even oil price; new contractual arrangements agreed with Sea Lion partner, and FPSO FEED contract in place

· Cost reductions of over 25% delivered for 2015 in operating costs and G&A spend; further cuts forecast for 2016

· Significant liquidity with cash and undrawn bank facilities of $1.2 billion; year-end covenant headroom in excess of $900 million; E.ON acquisition will be materially covenant accretive

Tony Durrant, Chief Executive, commented:

"In this challenging macro environment, maximising production whilst cutting costs is critical; both were achieved in 2015 and will continue in 2016. Selling our cash negative Norwegian business and re-investing in cash positive UK assets through the proposed E.ON acquisition, is value accretive and materially improves both our current and future financial position."

Production operations

In 2015, Premier delivered a robust production performance of 57.6 kboepd, in line with expectations and above our 2015 market guidance of 55 kboepd. This strong performance was seen across the Company's existing fields and was driven by further improvements in operating efficiency. The reduction from 2014 principally reflects the sale of the Scott area which contributed 3.8 kboepd in 2014, and natural field decline.

*includes production from Scott field disposed of in December 2014

The Premier-operated Chim Sáo field in Vietnam delivered above expectations, with high uptime and good reservoir performance. In the UK, all fields produced in line with expectations, with good production efficiency across the portfolio, including the Huntington field which performed well after the removal of gas export constraints. In Indonesia, production from the Premier-operated Natuna Sea Block A remains stable with strong gas demand from Singapore, offset in part by lower production from the non-operated Kakap field.

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

Development projects

On the Solan field, progress continues to be made on the final commissioning of the offshore installation systems required for first oil despite the unprecedented weather conditions in the West of Shetlands area. Since our operational update on 23 December, occupation has been successfully achieved with personnel transferring to the asset this week. Commissioning work continues to be supported by the Superior flotel. However, as a result of poor recent connectivity with the flotel, we now expect first oil to be in February.

The first pair of producer-injector wells required for first oil have been successfully tied in. Following completion of the second injector well, the Ocean Valiant rig will side-track the second producing well during Q2 2016. When both pairs of wells are on-stream, expected plateau production will be 20-25 kboepd. Cash spend to 31 December on the Solan project stood at $1.88 billion.

The Catcher project is progressing on budget and is on schedule to deliver first oil in 2017. Following completion of a successful subsea installation programme in 2015, fabrication of subsea equipment including the mooring system, due to be fully installed in the summer of 2016, remains on schedule.

Drilling activities which started in July using the Ensco 100 rig have progressed well. The first two wells (injectors CTI1 and CCI2) have been completed ahead of schedule and under budget. The wells were completed with good operational performance and reservoir results. The third well on Catcher (the first producer CCP3) has been drilled to total depth, encountering good reservoir quality and is now in the final phase of completion.

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 currently remains on schedule. 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 mid-year 2016.

In the Falkland Islands, pre-FEED work on the Sea Lion Phase 1a development has been completed. The conceptual plan has been modified by the addition of the development of the far north west of the Sea Lion field. It is now envisaged that the scheme will utilise 18 wells to recover 220 mmbbls of oil during a 20 year period (a 37% increase on the 160 mmbbls previously announced). Despite the increase in scope, the estimate of pre-first oil capex requirement remains at $1.8 billion, reflecting significant cost reductions in the current market, and total expected development capex per barrel has reduced from $14 to $11/bbl. The technical and cost improvements and efficiencies identified during pre-FEED, have resulted in a lower break-even oil price for the project and significantly improved the overall project economics.

The designs of both the FPSO and the Subsea System have evolved, tendering exercises have been completed and contractors are being selected for the provision of these 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). Contractors are close to being selected to provide the Subsea System and contracts are expected to be completed during Q1 2016. Premier and these contractors will work together during FEED to further optimise the designs and fabrication plans for the facilities. It is planned that the FEED programme will last approximately 18 months and during this period contractors will also be selected for the provision of the drilling rig and associated well services. 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.

In addition, Premier and Rockhopper have now executed an amendment to the 2012 Sale and Purchase Agreement ("SPA") which supersedes the Heads of Agreement announced in November 2014. The key terms of this agreement are:

· Rockhopper will be able to utilise the full $48 million of exploration carry under the original SPA during the current exploration programme

· The development carry which Premier is to provide to Rockhopper will be split $337 million to the Phase 1a development and $337 million to the subsequent phase of development

· Rockhopper will pay a Guarantee Fee to Premier of $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

· Premier will provide Rockhopper with a Standby Loan Facility of up $750 million (at 15% interest rate) instead of the financing arrangements in the original SPA, although it is anticipated that Rockhopper will continue to review alternative financing sources

Exploration and appraisal

In 2015 Premier drilled significant discoveries in the Falkland Islands at Zebedee and Isobel Deep, and in Indonesia confirmed additional resources in the Lama play below Anoa. Drilling continued in the Falklands post year-end and the re-drill of the Isobel/Elaine complex confirmed the results of the original Isobel Deep exploration well and discovered hydrocarbons in additional sandstones. The drilling rig will now move north to complete the drilling of the Chatham exploration well.

During 2016, Premier's exploration programme has been reduced to focus on commitment wells around existing operations in the UK North Sea. In Brazil, PGS has just completed a 3D seismic survey covering our licences in the Ceara Basin, and in Mexico we are moving forward with the detailed technical evaluation of the licences awarded on Blocks 2 and 7. 

Premier has continued to divest or relinquish non-core exploration acreage in the UK and internationally. On 14th 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.

Portfolio Management

As announced this morning, Premier has agreed to purchase E.ON's UK North Sea assets for a consideration of $120 million plus working capital adjustments. The proposed acquisition significantly enhances our core UK business by adding cash generative production, accelerates realisation of Premier's significant tax assets in the UK and is materially accretive to our lending covenants.

During 2015 Premier continued to monetise its non-core assets as part of the strategy to actively manage the portfolio. This included the sale of Premier's Norwegian business for $120 million and completion of the previously announced sale of Premier's non-operated interest in Block A Aceh onshore Indonesia for $40 million. In addition, the formal sales process for the Pakistan business, initiated after an unsolicited approach, is ongoing. A number of bids have been received which we continue to progress.

Finance

The estimated average oil price realised for 2015 was $52.6/bbl (2014: $98.2/bbl) (pre-hedge) and $79.0/bbl (2014: $101.0/bbl) (post-hedge) compared with an average Brent crude price of $52.4/bbl. 

Estimated average gas prices (pre hedge) for our principal gas producing areas for 2015 were: 

For 2016, Premier has sold forward 3.7 mmbbls of dated Brent at an average price of $68.3/bbl and 72,000 mt of high sulphur fuel oil at an average price of and $400/mt.

Total revenues for 2015 will be in the order of $1.1 billion (2014: $1.6 billion). As a result of the low Brent crude oil spot and forward curve price at year-end 2015, there will be a material impairment charge in the second half on certain of our assets, which is currently under review. 

As a result of significant cost saving initiatives, 2015 full year operating costs will be c$16/boe, a reduction of over $100 million year-on-year. In 2016 it is anticipated that further savings in underlying operating costs of 5-10 per cent can be achieved. Gross G&A costs for 2015 were approximately $230 million (a reduction of over $75 million year-on-year) and these are expected to be a further 10 per cent lower in 2016.

Capital spending for the full year 2015 was approximately $845 million (development) and $190 million (exploration, pre-tax). Planned development and exploration spend for 2016 is anticipated to be 32 per cent lower at around $700 million, reflecting the completion of the Solan development, limited committed development expenditure beyond the ongoing Catcher project and the completion of the Falkland Islands drilling programme. Capital expenditure guidance for 2016 is higher than that provided in our Trading Update in November ($650 million) due to additional deferral of costs from 2015 to 2016 and the impact of the weather delays on Solan first oil. 

Premier retains significant cash and undrawn facilities of $1.2 billion as at 31 December with net debt of c$2.2 billion. During the year Premier renegotiated its financial covenants with banks and bondholders and at the year end, the Company's covenant headroom is in excess of $900 million. Due to the potential for ongoing oil price weakness, Premier is actively working on a number of initiatives to preserve covenant headroom in 2016 including the proposed acquisition announced today. Premier does not have any significant debt maturity until late 2017 and our corporate unsecured capital structure means that we are not subject to any reserve base redeterminations.

Premier entered into swap arrangements to fix the interest rate payable on $800 million of the Company's outstanding drawn debt and as a result, 60 per cent of the Company's current drawn debt is now under fixed interest terms.

Premier continues to benefit from its substantial UK corporation tax loss and allowance position with estimated losses and allowances of $3.5 billion carried forward at 31 December 2015. Cash taxes as a percentage of gross operating cash flow in 2015 are estimated at around 11 per cent.