Neptune Energy H Results Investor Call 6 th September 2018

Transcription

1 Neptune Energy H Results Investor Call 6 th September 2018

2 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 In this presentation, unless otherwise indicated, our production, reserves and resources figures are presented on a basis including our ownership share of 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 operating 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. 2

3 Outline Introduction Sam Laidlaw Executive Chairman Highlights Jim House CEO Operations Jim House CEO Finance Peter Thomas CFO Portfolio & Summary Sam Laidlaw Executive Chairman 3

4 Introduction Strong start to 2018 Safety Steady improvements Production First half production above pre-closing expectations Cash Flow Strong cash flow generation; $487 mm pre-epi acquisition costs Sustainable Growth Development projects proceeding; announced two bolt-on transactions Organisation and Systems Significant capacity build 4

5 Highlights Consolidated results since acquisition of EPI on 15th Feb 2018 Operations HSSE culture and performance improving Strong production performance, averaging kboepd production (1) Progressed developments across portfolio and successfully appraised Sigrun in Norway Strengthened business through key senior management appointments and improved processes Finance $0.74 bn EBITDAX for period to 30 June 2018 and $0.94 bn for full H (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) Portfolio & Summary 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 kboepd Pro forma for EPI acquisition, compared with $709 mm for the first 6 months of Adjusted for EPI acquisition-related expenses month pro forma EBITDAX 5

6 Operations Jim House - CEO 6

7 Production Strong performance since EPI acquisition closed Outside Europe Germany UK +8% (1) (2) Liquids (3) % % +35% Netherlands LNG Norway Gas H1 Production (kboepd) 2018 H1 Production (kboepd) 15 Feb 30 June Production (kboepd) H H Feb - Jun '18 Realised Gas Price ($/mmbtu) H H Feb - Jun '18 Realised LNG Price ($/mmbtu) H H Feb - Jun '18 Realised Oil Price ($/bbl) (4) 1. Production for the six months to 30 June 2018 pro forma for EPI from 01 Jan Production for this period relates to the post acquisition period only, from 15 February 2018 to 30 June 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 H and $43.7/bbl in 15 Feb 30 June

8 Capital Programme Targeted and disciplined capital deployment L5a-D Sierra Njord Touat Status: Onstream H 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) Cara & P1 Status: FID expected early 2019 Onstream 2021, prod: 9.6 kboepd (1) H1 18 Sanctioned Infills Snohvit Askeladd development 3 wells + option for four future wells Onstream 2020, ~34 mmscf/d at peak (1) Maintains Snohvit production plateau Fram 3 wells Onstream ~1.5 kboepd net per well (1) Accelerates production from field H1 18 Exploration $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 1. Peak full year net production to Neptune 2. H 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 8

9 Organisation Management and organisation progress through H Strengthened existing EPI Team with additional first class E&P leadership 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 Transitioning organisation to standalone E&P progressing well 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 9

10 Finance Peter Thomas - CFO 10

11 Income Statement Over $1 bn of revenue and net income of $134 mm 6 months to June 2018 US$ mm Notes Revenue 1, 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 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) Reported net profit, unadjusted, $70.4 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 11

12 US$ mm Cash Flow Strong CF generation Update Cash Flow Summary Operating cash flow $598 mm adjusted for acquisition-related costs of $63 mm includes abex of $15 mm working capital impact of +$137 mm 700 H EBITDAX $0.9 bn (1) H Operating CF $0.6 bn 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 Including: Development capex $80.9 mm E&A capex $10.2 mm Operating CF Investing CF Finance costs Free CF surplus 1. Pro forma for EPI acquisition, compared with $709 mm for the first 6 months of Neptune H EBITDAX, excluding EPI, was $0.74 bn 12

13 US$ mm Financial Position Strong balance sheet and robust level of liquidity Net Debt : EBITDAX Leverage 0.65x (1) 34% Total Headroom $1.58 bn Corporate Credit Ratings BB- (Stable) / Ba3 (Stable) 2, ,582 1, , ,207 1, Drawn RBL Senior Notes Touat Project Finance Subordinated NEGL Loan Debt Issuance Costs Total Debt Cash Net Debt Undrawn RBL Cash Headroom Note: Results reflect 15 Feb June month pro forma EBITDAX 13

14 Hedging Conservative risk management Hedging update Aggregate Post-Tax Hedge Ratios (as of 30 June 2018) (1,2,3) Novated hedge book from ENGIE at acquisition (MtM $53.8 mm liability). Historically based on swaps Continued to add hedges, using mainly option collar structures 26% 73% 46% 52% Oil Gas 23% Hedge book comprises mostly swaps for legacy 2018 hedges and option collars for future years 8% 0% 3% RBL Facility Agreement minimum commodity hedging requirement, on 3-year rolling basis of forward looking post-tax production 50% for first year 30% for second year 15% for third year 2H Weighted Average Swap & Put prices (1,2,3) Brent Oil Price ($/bbl) Gas Price ($/mmbtu) 58.0 Mark-to-market hedge book liability of $231 mm pre-tax at 30 June reflects rising prices H 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 14

15 FY Guidance Production No change. FY low single-digit growth on 2017: stronger H1 performance offset by seasonal maintenance in H2 Capex 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% FCF Cash flow since EPI acquisition anticipated to cover capex, bolt-on acquisitions and finance costs, at current commodity prices Tax Rate 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 15

16 Portfolio & Summary Sam Laidlaw Executive Chairman 16

17 VNG Norge AS Strategic portfolio growth in Norway Investment Highlights Complementary Asset Portfolio $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 NJORD BAUGE HYME FENJA SNOHVIT DRAUGEN Delivering on strategy and M&A priorities GJØA Synergistic bolt-ons Extends reserve life (R/P) Operational fit VEGA FRAM BRAGE Florø Oslo Tax synergies Near-field, short-payback developments Growth from exploration & 2C IVAR AASEN GUDRUN Stavanger Neptune Assets VNG Assets Neptune & VNG assets Neptune Offices VNG Offices 17

18 Seagull & Isabella Strategic portfolio growth in UK Investment Highlights $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 Complementary Asset Portfolio SEAGULL ISABELLA Delivering on strategy and M&A priorities Synergistic bolt-ons Extends reserve life (R/P) Operational fit Cygnus Tax synergies Near-field, short-payback developments Growth from exploration & 2C 18

19 2018 H2 Priorities Continuing to deliver against plan Operational Excellence Further Strengthening the Organisation Cost Reductions Integrate VNG Drive Forward Developments 19

20 Summary and Outlook Leading international independent E&P company Operations H1 production outperformance, safety improving, projects progressing Finance Strong cash flow generation, robust liquidity, disciplined capital allocation Portfolio Delivered two bolt-on transactions, rebuilding exploration inventory Outlook Production in-line and disciplined capital programme, sustained cash flow generation 20

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22 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 22