Acquisition of E.ON UK North Sea Assets 13 January 2016
Acquisition background • Premier has agreed to acquire E.ON’s UK North Sea assets for a consideration of $120m plus working capital adjustments; the acquisition will be funded from existing cash resources • Proposed transaction continues Premier’s track record of capturing long term value through acquisition at low points in the oil price cycle • Brings immediate cash generative production, tax synergies and is materially covenant accretive with rapid payback – meeting Premier’s stated acquisition criteria • Adds stable UK gas revenues to the portfolio rebalancing commodity exposure • Following sale of Norwegian North Sea assets this in line with our strategy of focusing on our core regions; further strengthening Premier’s position in UK North Sea with its associated tax benefits • The transaction is subject to shareholder, US Private Placement holder and bank approval Jan 2016 | P1
Rationale for the acquisition • Compelling valuation – c. 15mboepd of net production in 2016 and c.64mmboe of net reserves and resources acquired, at an implied cost of c.$1.9/boe – accelerate Premier’s existing UK tax loss position of c.$3.5 billion – potential to generate significant cost synergies through the merger of the two UK business units • Quality asset base in a core area for Premier – increases Premier’s presence in the Central North Sea including a stake in the world class long- life Elgin/Franklin asset and related fields – consolidates our interest in Huntington (pro-forma 100%) and assume operatorship with potential to reduce costs and optimise production – enlarges Premier’s long -term UK portfolio with the highly attractive Tolmount Area development Jan 2016 | P2
Financial benefits of the acquisition • Strong net cash flow in 2016 and 2017 even at current oil/gas prices – c. 15mboepd of net production and associated cash flow added on completion • Assets being acquired with a valuable hedging portfolio in 2016 and 2017 – 2016: 32% estimated gas production @ 63p/therm, 33% estimated liquids production @ $97/bbl – 2017: 21% estimated gas production @ 57p/therm • Materially covenant accretive (Net Debt to EBITDAX) – Expected additional covenant headroom of c.$5oom at 30 June 2016 and at 31 Dec 2016, at current oil and gas prices • Financed out of existing cash flow with rapid payback period of around 2 years • Share abandonment cost exposure with the seller on Ravenspurn North & Johnston • c.£250m of historic tax paid can be offset against future decommissioning expenditure Jan 2016 | P3
E.ON UK assets • Central North Sea – Producing Fields - Elgin-Franklin (1), Huntington (2), Scoter & Merganser (5) • Southern Gas Basin – Main producing field - Babbage (3) – Late-life - Ravenspurn North & Johnston (3), CMS area (6) – Pre-development - Tolmount (4) – Near-field Exploration - Babbage area (3), Tolmount area (4) • West of Shetlands – Exploration licences, expiry 1/1/2017 (9) Jan 2016 | P4
Elgin-Franklin • 5.2% of Total-operated HPHT gas/condensate fields • Current production: >110kboepd (6kboepd net) • Expected production over 110kboepd through to 2019 • Mid-life asset with 15 years production history and 20 years expected production life • Operating costs of c$8/boe in 2016 World class asset with long-term production Jan 2016 | P5
Huntington • E.ON operated Central North Sea oil field in which Premier has an existing stake Opportunity – Premier interest will now go to 100% to reduce costs and • Produced via a leased FPSO owned and operated enhance by Teekay production – Current Production: c.15kboepd • Value opportunities – Re-negotiate the FPSO lease and reduce other operating costs to extend field life – Incremental production through side- tracking an existing water injector to a more optimal location for pressure support Jan 2016 | P6
Babbage Area • 47% of E.ON operated Babbage dry gas field – Online 2010, currently 5 production wells – Plans to operate unmanned Ravenspurn North – Infill well opportunity Johnston – Near-field exploration portfolio • Decommissioning of Ravenspurn North and Babbage Johnston expected in 2019-21 – Mechanism agreed with E.ON to share decommissioning costs above a threshold level to an agreed cap In-field and near-field growth opportunity Jan 2016 | P7
Tolmount • 50% of E.ON operated Gas discovery • Resources up to 1Tcf (gross) – Main field >500Bcf, East Tolmount 50-450Bcf • Sanction (FID) 2017, First gas 2019/2020* • Two development options being considered, both with access to upside and 3 rd party business • Peak production estimated at 150-200 mmcfd (gross) • Significant industry interest during E.ON sales process Largest Southern Gas Basin discovery in recent years *per current operator development Jan 2016 | P8
Conclusion • Excellent opportunity to capture long-term value in a low oil price environment • Materially covenant accretive, financed out of existing cash resources, and acquiring high quality assets with a valuable hedging position in 2016 and 2017 • Immediate cash generative production, tax synergies and covenant accretion with rapid payback • Continues our focus on our core regions; strengthening Premier’s position in UK North Sea and associated tax benefits • Initial soundings from lender group supportive • Shareholder circular expected to be issued in due course Jan 2016 | P9
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