13 January 2016 Acquisition background Premier has agreed to - - PowerPoint PPT Presentation

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
• n 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

• 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

Rationale for the acquisition

Jan 2016 | P2

• 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

Financial benefits of the acquisition

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

Jan 2016 | P5

World class asset with long-term production

Huntington

• E.ON operated Central North Sea oil field in which

Premier has an existing stake – Premier interest will now go to 100%

• Produced via a leased FPSO owned and operated

by Teekay – Current Production: c.15kboepd

• Value opportunities

– Re-negotiate the FPSO lease and reduce

• ther operating costs to extend field life

– Incremental production through side- tracking an existing water injector to a more

• ptimal location for pressure support

Jan 2016 | P6

Opportunity to reduce costs and enhance production

Babbage Area

Ravenspurn North Johnston Babbage

Jan 2016 | P7

• 47% of E.ON operated Babbage dry gas field

– Online 2010, currently 5 production wells – Plans to operate unmanned – Infill well opportunity – Near-field exploration portfolio

• Decommissioning of Ravenspurn North and

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

• pportunity

• 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 3rd party business

• Peak production estimated at 150-200 mmcfd (gross)
• Significant industry interest during E.ON sales process

Tolmount

Jan 2016 | P8

*per current operator development

Largest Southern Gas Basin discovery in recent years

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