Neptune Energy H1 2018 Results Investor Call 6 th September 2018 - - PowerPoint PPT Presentation

neptune energy h1 2018 results
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Neptune Energy H1 2018 Results Investor Call 6 th September 2018 - - PowerPoint PPT Presentation

Neptune Energy H1 2018 Results Investor Call 6 th September 2018 General & Disclaimer Except as the context otherwise indicates, Neptune or Neptune Energy, Group, we, us, and our, refers to the group


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Investor Call – 6th September 2018

Neptune Energy – H1 2018 Results

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General & Disclaimer

Except as the context otherwise indicates, “Neptune” or “Neptune Energy”, “Group”, “we,” “us,” and “our,” refers to the group of companies comprising Neptune Energy Group Midco Limited (the Company) and its consolidated subsidiaries and equity accounted investments. “EPI” refers to the business of ENGIE E&P International S.A. (now renamed Neptune Energy International S.A.) and its direct or indirect subsidiaries. This presentation includes the results of the acquired EPI business consolidated since 15 February 2018, which is the acquisition date as that is when Neptune acquired control over EPI. Equivalent data for Neptune for the corresponding reporting period ended 30 June 2017, starting when the Company was incorporated on 22 March 2017, are generally not informative, as the Company had minimal activity at the time, principally comprising only minor administration expenses. Therefore, in respect of certain measures, including production, EBITDAX and capital expenditure, we have provided additional approximate pro forma information relating to the acquired EPI business, to enable a comparison of the results for the full six months ended 30 June 2018 (including the period prior to our acquisition on 15 February) with those for the six months ended 30 June 2017. In this presentation, unless otherwise indicated, our production, reserves and resources figures are presented on a basis including our ownership share

  • f volumes of companies that we account for under the equity accounting method, in particular, for the interest held in the Touat project in Algeria through

a joint venture company. The discussion in this presentation includes forward looking statements which, although based on assumptions that we consider reasonable, are subject to risks and uncertainties which could cause actual events or conditions to materially differ from those expressed or implied by the forward looking

  • statements. While these forward-looking statements are based on our internal expectations, estimates, projections, assumptions and beliefs as at the

date of such statements or information, including, among other things, assumptions with respect to production, future capital expenditures and cash flow, we caution you that the assumptions used in the preparation of such information may prove to be incorrect and no assurance can be given that our expectations, or the assumptions underlying these expectations, will prove to be correct. Any forward-looking statements that we make in this presentation speak only as of the date of such statement or the date of this presentation. Unless otherwise indicated, all production figures are presented on a net entitlement basis. Where gross amounts are indicated, they are presented on a total basis—i.e., the actual interest of the relevant license holder in the relevant fields and license areas without deduction for the economic interest of our commercial partners, taxes or royalty interests or otherwise. This presentation presents certain production and reserves related information on an “equivalency” basis. Our conversion of oil and gas data into barrels of oil equivalent may differ from that data used by other companies. This presentation contains non-GAAP and non-IFRS measures and ratios that are not required by, or presented in accordance with, any generally accepted accounting principles (“GAAP”) or IFRS. These non-IFRS and non-GAAP measures and ratios may not be comparable to other similarly titled measures of other companies and have limitations as analytical tools and should not be considered in isolation or as a substitute for analysis of our

  • perating results as reported under IFRS or GAAP. Non-IFRS and non-GAAP measures and ratios are not measurements of our performance or liquidity

under IFRS or GAAP and should not be considered as alternatives to operating profit or profit from continuing operations or any other performance measures derived in accordance with IFRS or GAAP or as alternatives to cash flow from operating, investing or financing activities.

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Outline

Introduction

Sam Laidlaw – Executive Chairman

Operations

Jim House – CEO

Finance

Peter Thomas – CFO

Portfolio & Summary

Sam Laidlaw – Executive Chairman

Highlights

Jim House – CEO

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Introduction

Strong start to 2018

Production Cash Flow Sustainable Growth Organisation and Systems First half production above pre-closing expectations Strong cash flow generation; $487 mm pre-EPI acquisition costs Development projects proceeding; announced two ‘bolt-on’ transactions Significant capacity build Safety Steady improvements

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Highlights

Consolidated results since acquisition of EPI on 15th Feb 2018

Operations

  • HSSE culture and performance improving
  • Strong production performance, averaging 165.6 kboepd production(1)
  • Progressed developments across portfolio and successfully appraised Sigrun in Norway
  • Strengthened business through key senior management appointments and improved processes

Finance Portfolio & Summary

  • $0.74 bn EBITDAX for period to 30 June 2018 and $0.94 bn for full H1 2018(2)
  • $598 mm operating cash flow (post-tax)(3) and operating costs of $10.0 /boe vs. $10.5 /boe in 2017
  • Successful inaugural $550 mm bond issue and long term issuer credit ratings of BB- and Ba3
  • 0.65x net debt to EBITDAX(4)
  • VNG Norge – agreement to acquire oil-weighted assets with operated growth and synergies in Norway
  • Seagull & Isabella – agreement to acquire low-cost, near-term development and high impact exploration in UK
  • Full year production in line with previous guidance
  • H2 focus on operational efficiency, further strengthening the organisation, cost reductions, integration of VNG

and driving forward our developments

1. For the post-acquisition period, 15 February 2018 to 30 June 2018, calculated over 136 days in order to provide data comparable with other periods. Production for the six months to 30 June 2018 for EPI was 166.1 kboepd 1. 2. Pro forma for EPI acquisition, compared with $709 mm for the first 6 months of 2017 3. Adjusted for EPI acquisition-related expenses 4. 12 month pro forma EBITDAX

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Operations

Jim House - CEO

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7 80.2 78.7 77.2 33.6 29.8 30.1 18.8 20.1 20.6 13.3 13.0 13.0 7.2 24.5 24.7 91.6 86.8 87.4 12.2 33.5 33.5 49.3 45.8 44.7 20 40 60 80 100 120 140 160 180 1 2 3 4 5 6 7 8

5.6 7.5 7.6

H1 2017 H1 2018 Feb - Jun '18

5.2 7.1 7.3

H1 2017 H1 2018 Feb - Jun '18

51. 3 69. 4 69. 9

H1 2017 H1 2018 Feb - Jun '18

Production

Strong performance since EPI acquisition closed

+8%

1. Production for the six months to 30 June 2018 pro forma for EPI from 01 Jan 2018 2. Production for this period relates to the post acquisition period only, from 15 February 2018 to 30 June 2018. Average daily production is therefore calculated over 136 days, in order to provide data comparable with other periods. Production of Neptune for 2017 was nil 3. Liquids include oil, condensate and other natural gas liquids 4. Realised other liquids (excluding oil) price of $45.4/bbl in H1 2017, $43.9/bbl in H1 2018 and $43.7/bbl in 15 Feb – 30 June 2018

Realised Gas Price ($/mmbtu) Realised LNG Price ($/mmbtu) Realised Oil Price ($/bbl)(4)

Norway Netherlands UK Germany Outside Europe

2017 H1 Production (kboepd) 2018 H1 Production (kboepd) 15 Feb – 30 June Production (kboepd)

153.1 166.1(1) 165.6(2)

Gas LNG Liquids(3)

+34% +37% +35%

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Fram – 3 wells

  • Onstream 2019-2021
  • ~1.5 kboepd net per well(1)
  • Accelerates production from field

Snohvit – Askeladd development

  • 3 wells + option for four future wells
  • Onstream 2020, ~34 mmscf/d at peak(1)
  • Maintains Snohvit production plateau

Capital Programme

Targeted and disciplined capital deployment

L5a-D Sierra Njord Touat H1 ‘18 Exploration Cara & P1

Status: Onstream H1 2018 prod: 3.2 kboepd Status: 43.6% complete Onstream 2020, prod: 20.9 kboepd(1) Status: 90% complete Onstream H1 2019, prod: 13.9 kboepd(1) Status: FID expected early 2019 Onstream 2021, prod: 9.6 kboepd(1)

  • $36.5 mm E&A expenditure(2)
  • 2 small commercial discoveries in Dutch

sector

  • Successful Sigrun appraisal in Norway
  • Awarded four licences in Norway
  • 2 preliminary licence awards in UK
  • Acquired $10.6 mm of seismic across

new acreage

H1 ‘18 Sanctioned Infills

1. Peak full year net production to Neptune 2. H1 2018 of which $13 mm was exploration capex and $10.6 mm incurred on acquisition of new seismic data in areas where we have recently been awarded new licences and to refresh and revitalise our data library in support of new venture activity

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Organisation

Management and organisation progress through H1 2018

  • Carve out from ENGIE systems almost complete
  • Implemented safety culture program
  • Revised management organisation structure with clear accountabilities
  • Weekly and monthly performance and outlook reviews
  • Improved investment approval process
  • New corporate management and treasury capabilities

Name Position Previous Experience Amanda Chilcott Group HR Director HR Director at Aggreko ; BP ; Ford Andrea Guerra VP Corporate Reservoir Engineering Corporate Manager of Reserves & Economics Apache Gro Haatvedt VP Exploration Exploration VP Aker BP ; Equinor David Hemmings VP Business Development Managing Director at Rothschild & Co Pete Jones Country Manager UK Managing Director Taqa Europe ; Marathon Oil Philip Lafeber VP SE Asia / Africa Norway Manager at DONG Energy ; Hess Corp. Mark Richardson VP Projects Group Projects Manager at Apache ; BP Julian Regan-Mears Director of Corporate Affairs Group Head of External Communications at De Beers ; Centrica ; Britvic Andreas Scheck Country Manager Germany Country Manager Wintershall Bruce Webb VP Operations COO at DNO ; 20 years+ with BP

Strengthened existing EPI Team with additional first class E&P leadership Transitioning organisation to standalone E&P progressing well

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Finance

Peter Thomas - CFO

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Income Statement

6 months to June 2018 US$ mm Notes Revenue 1,033.3 165.6 kboepd production with realised oil price of $69.9 /bbl. Realised gas price of $7.6 /mmbtu and LNG price of $7.3 /mmbtu Operating Costs (245.7) Opex /boe of $10.0 /boe (vs. $10.5 / boe for EPI for FY 2017(1)) Exploration Expense (23.0) High seismic data acquisition costs G&A (31.1) Includes $7 mm non-recurring expenses DD&A (276.7) Reflects fair valuation of acquired assets Equity-accounted investments 7.6 Dutch pipeline Operating profit / loss 464.4 Operating income, reflecting EPI business for 15 Feb – 30 June 2018 Net financial items (61.0) Net of financial expenses and income, mark-to-market on derivatives, other Tax (269.6) Effective tax rate of 67% (79% on non-adjusted pre tax profit, reflecting acquisition expenses) Adjusted Net Income (adj)(2) 133.8 Reported net profit, unadjusted, $70.4 mm

Over $1 bn of revenue and net income of $134 mm

1. Opex per boe based on operating costs adjusted to exclude charge relating to over -and under-lifted production entitlement and tariff and service revenues (total $21 mm) 2. Adjusted for costs relating to the EPI acquisition of $63.4 mm

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598 91 20 487

  • 100

200 300 400 500 600 700

Operating CF Investing CF Finance costs Free CF surplus

Cash Flow

1. Pro forma for EPI acquisition, compared with $709 mm for the first 6 months of 2017. Neptune H1 2018 EBITDAX, excluding EPI, was $0.74 bn

Strong CF generation

Update

  • Operating cash flow $598 mm
  • adjusted for acquisition-related costs of $63 mm
  • includes abex of $15 mm
  • working capital impact of +$137 mm
  • Cash tax rate: 32%
  • Cash capex relatively low due to re-phasing and some

slippage

  • Touat to be reported as equity investment: no new

capital injected to JV since 15 February

  • $1.98 bn equity raised to cover EPI acquisition, plus

$100 mm subordinated loan. Balance from senior debt

H1 2018 Operating CF $0.6 bn

Including:

  • Development capex $80.9 mm
  • E&A capex $10.2 mm

US$ mm

H1 2018 EBITDAX $0.9 bn(1) Cash Flow Summary

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583 550 187 100 72 1,349 375 974 1,207 375 1,582

  • 500

1,000 1,500 2,000 Drawn RBL Senior Notes Touat Project Finance Subordinated NEGL Loan Debt Issuance Costs Total Debt Cash Net Debt Undrawn RBL Cash Headroom

Financial Position

Strong balance sheet and robust level of liquidity

Net Debt : EBITDAX 0.65x(1) Leverage 34% Total Headroom $1.58 bn

US$ mm

Note: Results reflect 15 Feb 2018 – 30 June 2018 1. 12 month pro forma EBITDAX

Corporate Credit Ratings BB- (Stable) / Ba3 (Stable)

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Hedging

Hedging update Weighted Average Swap & Put prices (1,2,3)

1. Oil price hedges include hedges of realisations for gas production sold as LNG and pricing in relation to oil prices 2. Post tax hedge ratios adjust for different tax rates on physical sales and hedge gains and losses, which mean that effective post tax hedges can be achieved through hedging contracts for volumes which may be significantly less than anticipated sales 3. Caps for hedged volumes under collar structures: $73-$75 / barrel for oil and >$7 /mmbtu for gas

Conservative risk management

Aggregate Post-Tax Hedge Ratios (as of 30 June 2018) (1,2,3)

  • Novated hedge book from ENGIE at acquisition

(MtM $53.8 mm liability). Historically based on swaps

  • Continued to add hedges, using mainly option

collar structures

  • Hedge book comprises mostly swaps for legacy

2018 hedges and option collars for future years

  • RBL Facility Agreement minimum commodity

hedging requirement, on 3-year rolling basis of forward looking post-tax production

  • 50% for first year
  • 30% for second year
  • 15% for third year
  • Mark-to-market hedge book liability of $231 mm

pre-tax at 30 June reflects rising prices

26% 46% 8% 0% 73% 52% 23% 3% 2H2018 2019 2020 2021 Oil Gas 52.5 58.0 52.9 5.3 5.9 5.9 2H2018 2019 2020 Brent Oil Price ($/bbl) Gas Price ($/mmbtu)

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FY Guidance

  • No change. FY low single-digit growth on 2017: stronger H1 performance offset by seasonal

maintenance in H2

  • Development capex reduced to approx. $420 mm (incl. Touat) reflecting some re-phasing;

$90 mm E&A; $35 mm abex

  • Plus acquisitions: $430 mm for VNG Norge and $75 mm for Seagull
  • Pro forma to 30 June 2018 for VNG Norge and Seagull: net debt $1.48 bn, leverage 44%
  • Cash flow since EPI acquisition anticipated to cover capex, bolt-on acquisitions and finance

costs, at current commodity prices

  • In line with previous guidance: cash tax as % of pre-tax operating cash flow reducing to below

40% due to higher Norway capex and Algerian future production

1. Excludes VNG contribution, post-closing 2. VNG transaction considered separately due to (i) short term tax cash flows (ii) debt finance contribution for longer term growth

Production Capex FCF Tax Rate

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Portfolio & Summary

Sam Laidlaw – Executive Chairman

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17 FENJA IVAR AASEN BRAGE

VNG Norge AS

Strategic portfolio growth in Norway

SNOHVIT

NJORD BAUGE HYME

GJØA FRAM VEGA GUDRUN

Stavanger Florø DRAUGEN

Neptune Assets VNG Assets Neptune & VNG assets Neptune Offices VNG Offices

Oslo

 $352 mm firm + $50 mm contingent consideration  Adds oil-weighted Norwegian portfolio with growth & synergies  42 licences, five producing fields, three development projects  Incremental 2P reserves + 2C growth of 50 mmboe net  Net production for 2017 of 4,000 boepd with significant increase to approx. 14,000 boepd by 2022  Adds operatorship of flagship Fenja subsea project and consolidates around Njord hub  Respected and skilled local organisation  Closing expected by year-end 2018  Significant tax synergies expected in 2019

Investment Highlights Delivering on strategy and M&A priorities Synergistic bolt-ons Extends reserve life (R/P) Tax synergies Near-field, short-payback developments Growth from exploration & 2C Operational fit Complementary Asset Portfolio

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Seagull & Isabella

Strategic portfolio growth in UK

 $70 mm firm consideration  Leverages Neptune’s UK operational capability  Incremental 2P reserves growth of 13 mmboe net and production growth of up to 12,000 boepd by 2022  Seagull provides attractive development economics at moderate cost with well established export routes  Isabella is a high risk / high reward opportunity with material upside, enhancing Neptune exploration portfolio  Accretive transaction metrics with potential for tax synergies with existing strong UK asset base  Closing expected by year-end 2018

Investment Highlights Delivering on strategy and M&A priorities Synergistic bolt-ons Extends reserve life (R/P) Tax synergies Near-field, short-payback developments Growth from exploration & 2C SEAGULL ISABELLA Cygnus Operational fit Complementary Asset Portfolio

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2018 H2 Priorities

Continuing to deliver against plan

Operational Excellence Further Strengthening the Organisation Integrate VNG Drive Forward Developments Cost Reductions

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Summary and Outlook

H1 production outperformance, safety improving, projects progressing Strong cash flow generation, robust liquidity, disciplined capital allocation Delivered two ‘bolt-on’ transactions, rebuilding exploration inventory Production in-line and disciplined capital programme, sustained cash flow generation

Leading international independent E&P company

Operations Finance Portfolio Outlook

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Glossary

DD&A Depreciation, depletion and amortisation – reflects uplift in asset carrying values as a result of fair valuation of assets required for purchase accounting for the EPI business combination EBITDAX comprises net income for the period before income tax expense, financial expenses, financial income, non-recurring acquisition-related expenses, mark-to-market adjustments on commodity contracts exploration expense and depreciation and amortisation G&A General & Administrative HSSE Healthy, Safety, Security and Environment Kboepd Thousand barrels of oil equivalent. Neptune applies a scf per barrel conversion factor that varies from field to field ranging from 4,400 to 21,050 scf per barrel LNG Liquid Natural Gas Operating costs per boe Operating costs adjusted for under-lifted entitlement to production and to offset income from tariffs and services which serve to recover costs, divided by production in boe RBL Reserves Based Lending Touat Project Finance Facility limited recourse loan agreement between Neptune and ENGIE entered into in connection with the EPI acquisition to finance 50% of future expenses in relation to the Touat Development Project